Enbridge Energy Partners 8-K Regulation FD Disclosure

Enbridge Energy Partners 3rd Quarter 2007 Earnings Release October 30, 2007

#2 #2 Certain information during this presentation will constitute forward-looking statements. These will include, but are not necessarily limited to, throughput volumes, financial projections, expansion or acquisition projects, external economics and competitive factors. These statements are based on certain assumptions made by management. Accordingly, actual results may differ materially from current estimates. You are referred to the Enbridge Energy Partners' SEC filings, including the annual Form 10-K, for a more detailed discussion of risk factors. This presentation will make reference to certain financial measures, such as adjusted net income, which are not recognized under GAAP. Reconciliations to the most closely related GAAP measures are available in the investor section of the Partnership's website at enbridgepartners.com. Legal Notice

#3 Ottawa Saint John Kansas City Superior Clearbrook Zama Fort McMurray Montreal Toronto Buffalo Regina Hardisty Patoka Casper Salt Lake City Houston Toledo Edmonton Norman Wells Fort St. John Cushing Inuvik Chicago Wood River El Dorado Natural Gas Distribution Liquids Systems Natural Gas Systems Detroit Strategy focused on North American energy delivery Enbridge Inc. (ENB), as parent of general partner, is strong and supportive sponsor Enbridge Energy Partners (EEP) is primary vehicle for mature energy transportation infrastructure in US ENB 5-year capital forecast is >$12 billion (excluding EEP) - several projects will benefit EEP Enbridge Continental Focus

#4 #4 EEP 2007 Third Quarter EEP Liquids Systems EEP Gas Systems Enbridge Liquids Systems Buffalo Toledo Patoka Cushing Wood River Chicago Houston Quarterly distribution raised to $0.95 per unit Increased liquids segment earnings from increased delivery volumes and annual toll adjustments Strong natural gas segment results from utilization of expanded processing plant capacity, favorable processing margins and increased systems throughputs Steady progress in developing and financing major expansion projects

#5 #5 Acquisitions shown as of date announced $2.1B Southern Access Expansion estimated capex pattern is approx. 5%-60%-27%-8% for 2006 through 2009 $635MM East TX Expansion & Extension estimated capex pattern is approx. 47%-47%-6% for 2006 through 2008 $1.0B Alberta Clipper estimated capex pattern is 1%-18%-77%-4% for 2007 through 2010 (preliminary estimate) Investment in Growth Opportunities Capex program for 2007 to 2010 estimated to exceed $5 billion. $0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 $1,800 $2,000 $2,200 2006 2007E 2008E 2009E 2010E Capital Expenditures Acquisitions Millions

#6 #6 Natural Gas Market Development LNG C B Waha Henry Hub Katy Rockies Gas Carthage Houston Perryville Bethel A Processing Plant Additions (MMcfd) Year Ended December 31 2005 2006 2007E Plant Additions 105,000 195,000 195,000

#7 Natural Gas Production Source: PIRA (August, 2007) East Texas Fort Worth Western Anadarko 0 3 6 9 12 15 1999 2001 2003 2005 2007 2009 2011 2013 2015 Bcf/d 0 3 6 9 12 15

#8 #8 East Texas Extension & Expansion $635 million project to add 700 MMcfd intrastate transmission capacity and associated gathering and treating facilities Increases market access for producers in East and North Texas to large industrial base in SE Texas and several interstate pipelines Two stages currently in-service - final stage will be complete in early 2008 Current throughput ~200 MMcfd – project near capacity by end of 2008 Estimated first full year (2009) EBITDA multiple is 6.5 to 7.5 times Stage 1 Extension Stage 2 Extension Stage 3 Extension Treating Facility To Gulf South, Kinder Morgan & NGPL To Trunkline To Florida Gas & Wholesale Customers

#9 Crude Oil Market Development Cushing Montreal Toronto Hardisty Patoka Wood River Catlettsburg Casper Mandan Clearbrook Superior Salt Lake City Sinclair Cheyenne Denver McPherson Ponca City Tulsa El Dorado Coffeyville Ardmore Memphis Billings Great Falls Toledo Detroit Chicago Robinson Corpus Christi Houston Port Arthur New Orleans Lake Charles Texas City Freeport Puget Sound San Francisco Bakersfield Los Angeles Borger/Sunray Artesia El Paso Big Spring St. Paul Lima Buffalo Canadian Supplied Limited/No Cdn Supply Enbridge/Lakehead System Other Pipelines Refineries: Tanker Port Zama Norman Wells Fort McMurray Edmonton Canton In 2006 Canada emerged as largest supplier of crude oil to US - Lakehead System delivered approximately 11% of total US crude oil imports Alberta Oil Sands estimated to contain 174 billion barrels of recoverable reserves (assuming current technology and economics) US PADD II (Midwest) and PADD III (Gulf Coast) have approximately 70% of US refining capacity

#10 #10 Crude Oil Pipeline Export Capacity (vs. Forecast Growth in WCSB Crude Oil Exports) Forecast exports include condensate volumes used as diluent for heavy crude oil *Includes Southern Access Expansion (400 Kbpd) and two modest TMPL increases (85 Kbpd) **Capacity available on Alberta Clipper and Southern Access Expansion by adding pump stations (350 Kbpd) Unutilized Export Capacity Approved Expansions* Alberta Clipper 2007 Enbridge Forecast ABC/SA Available** Keystone 0 400 800 1200 1600 2000 2400 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 (000 BPD) 0 400 800 1200 1600 2000 2400 (000 BPD)

#11 #11 Southern Access Expansion Minneapolis Clearbrook Superior Toronto Buffalo Sarnia Toledo Canton Lima Robinson Patoka Chicago Catlettsburg Cushing Corsicana Houston Beaumont New Orleans Enbridge Partners Enbridge Interests Southern Access Expansion Delavan Flanagan $2.1 billion project to build 42-inch pipeline from Superior to Chicago with ultimate capacity of 1.2 million bpd Stage 1 adds 190,000 bpd in early 2008 (est. 55% of capex) Stage 2 adds 210,000 bpd in early 2009 (est. 45% of capex) 30-year agreement with utility style Trended Original Cost model passes costs through to shippers and earns 9% real return on equity plus inflation Tariff surcharge based on actual throughput largely eliminates supply risk Tax allowance based on FERC policy at time of annual tariff filings Estimated first full year EBITDA multiple for each stage is 7.5 to 8.5 times Wood River Southern Access Expansion

#12 #12 Alberta Clipper Expansion Minneapolis Wood River Clearbrook Superior Toronto Buffalo Sarnia Toledo Canton Lima Robinson Patoka Chicago Catlettsburg Cushing Corsicana Houston Beaumont New Orleans Delavan Flanagan New 36 inch pipeline on existing right of way to initially add 450,000 bpd capacity between Hardisty, Alberta, and Superior by mid-2010 Complementary capacity to Chicago to be obtained by adding pump stations to Southern Access Expansion EEP responsible for estimated $1 billion US portion of project Tariff principals recently settled with shippers – 15 year cost of service type agreement (NEB + 2.25% ROE + tax allowance, indexed cost recovery, no supply risk) Estimated first full year (2011) EBITDA multiple is 7 to 8 times Enbridge Partners Enbridge Interests Southern Access Expansion Alberta Clipper Expansion Alberta Clipper Expansion

#13 North Dakota System Expansion Minneapolis Wood River Clearbrook Superior Toronto Buffalo Sarnia Toledo Canton Lima Robinson Patoka Chicago Catlettsburg Cushing Corsicana Houston Beaumont New Orleans Delavan Flanagan Enbridge Partners Enbridge Interests Southern Access Expansion Alberta Clipper Expansion North Dakota Expansion North Dakota System Expansion $78 MM Phase 5 Expansion to add 30,000 bpd capacity to be complete by end of 2007. Tariff agreement recovers capital over 5 years – first full year (2008) EBITDA multiple estimated at 4 to 5 times Phase 6 Expansion design proceeding for further ~50,000 bpd expansion by late 2009 at estimated cost of $150 million. Tariff agreement recovers capital over 7 years

#14 Crude Oil Downstream Extensions Minneapolis Wood River Clearbrook Superior Toronto Buffalo Sarnia Toledo Canton Lima Robinson Patoka Chicago Catlettsburg Cushing Corsicana Houston Beaumont New Orleans Delavan Flanagan Enbridge Spearhead Pipeline opened access to Cushing Hub (March 2006) ExxonMobil Pegasus Pipeline opened access to Gulf Coast (April 2006) Planned Enbridge Inc. Southern Access Extension will increase access to Patoka Hub by 400,000 bpd in early 2009 Proposed new pipeline from Patoka to Beaumont and Houston (Enbridge and Exxon- Mobil joint venture) Numerous additional reversal and new build concepts from Enbridge and competitors EEP continuing to develop merchant storage opportunities at Cushing crude oil terminal Enbridge Partners Enbridge Interests Southern Access Expansion Enbridge S.A. Extension Alberta Clipper Expansion ExxonMobil Pegasus Proposed ENB-XOM Proposed ENB-XOM ExxonMobil Pegasus Enbridge S.A. Extension Enbridge Spearhead

#15 #15 Third Quarter Earnings (Adjusted) Unaudited, $ in millions, except per unit in dollars; average units in millions *Excludes FAS 133 noncash adjustments – see non-GAAP reconciliations 2007 2006 Change Segmented operating income (loss): - Liquids $57.6 $47.4 $10.2 - Natural Gas* 48.0 41.2 6.8 - Marketing* 0.3 (2.5) 2.8 - Corporate 0.5 (1.1) 1.6 Operating income* $106.4 $85.0 $21.4 Other income 0.4 2.0 (1.6) Interest expense (23.4) (28.5) 5.1 Income tax expense (1.3) - (1.3) Net income* $82.1 $58.5 $23.6 Allocations to General Partner (9.5) (8.2) (1.3) Net income allocable to Limited Partners* $72.6 $50.3 $22.3 Weighted average units outstanding 90.0 71.7 18.3 Net income per unit* $0.81 $0.70 $0.11 EBITDA $151.8 $121.8 $30.0

#16 #16 Unaudited, $ in millions Liquids 2007 2006 Change Operating revenue $138.1 $127.2 $10.9 Power (29.7) (27.8) (1.9) Operating and administrative (33.9) (36.0) 2.1 Depreciation and amortization (16.9) (16.0) (0.9) Operating income $57.6 $47.4 $10.2 Quarter Ended Sep 30 Contribution to Total Adjusted Operating Income 0% 10% 20% 30% 40% 50% 60% Q3-06 Q3-07 Lakehead North Dakota Mid-Continent

#17 #17 Unaudited, $ in millions *Table and chart exclude FAS 133 noncash adjustments – see non-GAAP reconciliations Natural Gas & Marketing (Adjusted) 2007 2006 Change Natural Gas Gross Margin* $143.8 $116.8 $27.0 Operating and administrative (68.1) (56.9) (11.2) Depreciation and amortization (27.7) (18.7) (9.0) Operating income* $48.0 $41.2 $6.8 Marketing Operating income* $0.3 ($2.5) 2.8 $ Quarter Ended Sep 30 Contribution to Total Adjusted Operating Income -5% 5% 15% 25% 35% 45% Q3-06 Q3-07 East Texas Anadarko North Texas Other Marketing

#18 #18 Unaudited, $ in millions, except as noted. *Anadarko and East Texas systems plant inlet volumes subject to Keep-Whole and POL contracts **Average composite NGL barrel is roughly 40% Ethane, 30% Propane, 30% Butanes Plus ***Excludes quarter-to-quarter true-ups (+$1.8mm in 2007 Q3, immaterial for other periods shown) Keep Whole Natural Gas Processing 2007 Q3 2007 Q2 2006 Q3 Processed Volume* (MMcfd) 702 646 438 NGL Production** (Mbpd) 43 36 26 KW Processed Volume (MMcfd) 353 294 231 KW Before Hedging - Processing Margin $46.6 $22.4 $28.4 - Average Margin ($/Mcf) $1.44 $0.84 $1.34 KW After Hedging - Processing Margin*** $30.6 $13.5 $16.0 - Average Margin ($/Mcf) $0.94 $0.51 $0.76

#19 #19 Distribution Coverage Unaudited, $ in millions 2007 Q3 2007 YTD 2007 Q3 2007 YTD Net Income $77.3 $185.0 $77.3 $185.0 MTM Hedge Adjustments 4.8 17.4 4.8 17.4 Adjusted Net Income 82.1 202.4 82.1 202.4 Depreciation 45.0 121.3 45.0 121.3 Maintenance Capex (13.9) (40.3) (13.9) (40.3) Distributable Cash Flow $113.2 $283.4 $113.2 $283.4 Cash Distributions 65.9 187.8 63.7 179.5 PIK Distributions (gross)* 30.1 87.4 28.9 79.7 Total Distributions $96.0 $275.2 $92.6 $259.2 Coverage Ratio 1.18 1.03 1.22 1.09 Distributions per unit $0.950 $2.800 $0.925 $2.775 * notional value of Paid In Kind distributions As Declared As Paid

#20 #20 Capital Expenditures Unaudited, $ in millions YTD 2007 Enhancement Expenditures included: Southern Access - $717.6 Million ETX Extension - $235.7 Million Weatherford Plant Expansion - $ 58.2 Million North Dakota Expansion - $41.1 Million 2007 YTD 2007 Q3 Maintenance Capex $40.3 $13.9 Enhancement Capex $1,388.1 $523.0 Ending PP&E, net $5,134.7 Ending CWIP $1,422.1

#21 #21 Book Capitalization Floating Debt $200MM in principal amount of borrowings under commercial paper and $120MM of credit facility borrowings at 9/30/2007 5.76% weighted average interest rate at 9/30/2007 Unaudited, $ in millions. Partners Capital excludes Accumulated Other Comprehensive Loss (OCI). *Debt reduced and Partners Capital increased by $200MM for Jr. Subordinated Notes’ equity credit. 9/30/2007 12/31/2006 Loans from Affiliates $143.1 $136.2 Short-term Debt 31.0 31.0 Long-term Debt* 2,341.2 2,066.1 Total Debt $2,515.3 $2,233.3 Partners Capital* 3,067.3 2,233.0 Total Capitalization $5,582.6 $4,466.3 Total Debt / Total Capitalization 45% 50%

#22 Total Requirement $ 2.20 Less: Term Debt Raised in 2007 (0.20) Less: Debt Portion of Hybrid Raised in 2007 (0.20) To Be Funded* $ 1.80 Funding Requirements 2007-2010 Total Capital Expenditures $ 5.3 Less: Internal Cash Flow (0.9) Net Funding Requirement $ 4.4 Total Requirement $ 2.20 Less: PIK Equity (0.40) Less: Equity Raised in 2007 (0.63) Less: Equity Credit from 2007 Hybrid (0.20) To Be Funded* $ 0.97 DEBT EQUITY $ in billions *Potential future Hybrid Securities would decrease both debt and equity requirements

Enbridge Energy Partners 3rd Quarter 2007 Earnings Release October 30, 2007

#24 Third Quarter Earnings (GAAP) Unaudited, $ in millions, except per unit in dollars; average units in millions 2007 2006 Change Segmented operating income: - Liquids $57.6 $47.4 $10.2 - Natural Gas 40.3 43.0 (2.7) - Marketing 3.2 19.4 (16.2) - Corporate 0.5 (1.1) 1.6 Operating income $101.6 $108.7 ($7.1) Other income 0.4 2.0 (1.6) Interest expense (23.4) (28.5) 5.1 Income tax expense (1.3) 0.0 (1.3) Net income $77.3 $82.2 ($4.9) Allocations to General Partner (9.4) (8.7) (0.7) Net income allocable to Limited Partners $67.9 $73.5 ($5.6) Weighted average units outstanding 90.0 71.7 18.3 Net income per unit $0.75 $1.03 ($0.28) Quarter Ended Sep 30

#25 Derivative Fair Value Gains (Losses) Unaudited, $ in millions Q3 2007 Q3 2006 FY 2007 FY 2006 Natural Gas Hedge ineffectiveness ($0.5) ($1.4) ($0.2) ($1.5) Non-qualified hedges (7.2) 3.2 (13.2) 1.4 Marketing Non-qualified hedges 2.9 21.9 (4.0) 53.2 Derivative FV gains (losses) ($4.8) $23.7 ($17.4) $53.1

#26 The foregoing presentation makes reference to adjusted net income in order to exclude the impact of noncash derivative fair value gains and losses. A reconciliation to net income per GAAP is provided below. Adjusted Earnings Unaudited, $ in millions Q3 2007 Q3 2006 FY 2007 FY 2006 Adjusted net income 82.1 $ 58.5 $ 202.4 $ 180.6 $ Noncash derivative FV gains (losses) (7.7) 1.8 (13.4) (0.1) 2.9 21.9 (4.0) 53.2 Net income 77.3 82.2 185.0 233.7 Allocations to General Partner 9.4 8.7 26.4 23.1 Net income allocable to Limited Partners $ 67.9 73.5 $ $ 158.6 210.6 $ Weighted average units (millions) 90.0 71.7 84.8 67.8 Net income per unit (dollars) $ 0.75 1.03 $ $ 1.87 $ 3.11 - Marketing - Natural Gas

#27 The foregoing presentation makes reference to adjusted operating income, which combines certain GAAP measures as shown below. Adjusted Segment Operating Income Unaudited, $ in millions Q3 2007 Q3 2006 Q3 2007 Q3 2006 Operating Income $ 40.3 $ 43.0 $ 3.2 $ 19.4 Noncash derivative fair value (gains) losses Adjusted operating income $ 48.0 $ 41.2 $ 0.3 $ (2.5) Natural Gas Marketing (21.9) (2.9) (1.8) 7.7

#28 The foregoing presentation makes reference to gross margin for the Natural Gas segment, which combines certain GAAP measures as shown below. Unaudited, $ in millions Adjusted Gross Margin Natural Gas Q3 2007 Q3 2006 Operating Revenues $ 847.3 $ 686.6 Cost of natural gas Noncash derivative fair value losses Adjusted gross margin $ 143.8 $ 116.8 (1.8) 7.7 (568.0) (711.2)

Enbridge Energy Partners 3rd Quarter 2007 Earnings Release October 30, 2007