Exhibit 99.1

news release

Enbridge Energy Partners Declares Cash Distribution and Reports 2003 Second Quarter Results

HOUSTON (July 23, 2003) /PRNewswire/ — Enbridge Energy Partners, L.P. (NYSE:EEP) (“Enbridge Partners” or “the Partnership”) today reported increased net income for the three months ended June 30, 2003 of $23.3 million, or $0.39 per unit, compared to $16.8 million, or $0.39 per unit, for the second quarter of the prior year.  Operating income before depreciation and amortization expense was $66.6 million and $49.0 million for the respective quarters.

For the first half of 2003, net income was $55.9 million, or $1.01 per unit, compared to $34.5 million, or $0.82 per unit, for the first half of 2002.  Operating income before depreciation and amortization expense was $143.9 million and $99.8 million for the respective half years.

Enbridge Partners today also declared a cash distribution of $0.925 per unit payable August 14, 2003 to unitholders of record on August 4, 2003.  Enbridge Energy Management, L.L.C. (NYSE:EEQ) (“Enbridge Management”) declared a corresponding distribution of $0.925 per share payable August 14, 2003 to shareholders of record on August 4, 2003.  The Enbridge Management distribution will be paid in the form of additional shares of Enbridge Management valued at the average closing price of the shares for the ten trading days prior to the ex-dividend date on July 31, 2003.

Dan C. Tutcher, President of the General Partner, commented, “The increases in Enbridge Partners’ second quarter earnings and cash flow were attributable to the systems acquired in the Midcoast transaction last October.  As management expected, per unit earnings for the reported quarter were comparable to last year’s second quarter, giving us an improved first half this year.  We continue to expect additional improvement in the second half for two main reasons.  Crude oil volumes are anticipated to benefit from producers’ new oil sands projects currently being brought on stream and from a refiner’s re-configuration project scheduled for completion later in the year.  Our natural gas volumes are expected to benefit as seasonal demand increases, particularly in the fourth quarter.”

Tutcher continued, “Supply, demand and competitive factors continue to be very positive for the Partnership’s liquid petroleum and natural gas transportation businesses.  As indicated by our recent update for the Western Canadian Sedimentary Basin, crude oil supply is expected to grow significantly over the next several years to the point that it exceeds demand in the traditional US Upper Midwest markets that the Lakehead System serves.  This creates opportunities to work cooperatively with western Canadian producers to access new markets.  The Spearhead Pipeline announcement by our affiliate, Enbridge Inc., to provide access from Chicago to the major Cushing crude oil hub, provides tangible evidence of these opportunities.  Regarding natural gas systems, it has become increasingly evident that additional supply needs to be brought to market to keep up with increasing US demand.  The Partnership has a strong presence in the Mid-

Continent and Gulf Coast region and is exploring several growth opportunities due to increased gas volumes on our East Texas and Anadarko systems.  Finally, following some balance sheet strengthening completed in the second quarter, the Partnership is well positioned financially to pursue expansion and acquisition opportunities that suit its conservative risk profile.”

For 2003, Enbridge Partners estimates that average deliveries on the Lakehead System will increase to between 1.34 and 1.40 million barrels per day (mmbpd) from 1.30 mmbpd in 2002.  The level of increase is less than previously estimated by the Partnership, primarily due to slower production ramp-ups than initially forecasted for new oil sands projects.  Production from the Alberta Oil Sands Project mine/upgrader complex and from a number of Steam Assisted Gravity Drainage (SAGD) projects is expected to increase over the next few months as operations stabilize after initial periods of volatility.

During the second quarter of 2003, natural gas prices were high relative to prices for natural gas liquids, thus making it uneconomic to remove natural gas liquids from the natural gas stream.  As a result, the Partnership reduced its gas processing to that required under contract to meet downstream connected pipeline specifications.  While there has been some recent improvement in the gas processing margin, the Partnership believes the amount of improvement in the second half of 2003 will be less than it previously anticipated.

Considering its revised outlook for Lakehead System deliveries and gas processing margins, the Partnership estimates that operating income for 2003 will be between $195 and $205 million and that depreciation and amortization expense will be approximately $95 million.  Net income is anticipated to improve to between $115 and $125 million for the current year, compared with $78.1 million in 2002.  The foregoing estimates exclude any contribution from potential asset acquisitions during 2003.  The Partnership’s acquisition growth target is approximately $150 million of investment for 2003 which, if completed, would be expected to contribute operating income before depreciation and amortization expense of approximately $20 million on an annualized basis.

For the second quarter of 2003, the Lakehead and North Dakota systems, which comprise the Partnership’s Liquids Transportation segment, generated operating income of $27.4 million, compared with $28.4 million in the second quarter of last year.  The decline was primarily related to pipeline leak remediation costs for the Lakehead System.  Lakehead deliveries averaged 1.294 mmbpd in the second quarter, compared with 1.310 mmbpd in the second quarter of the prior year; however, the decrease in deliveries was offset by modestly higher tolls.

The Gathering and Processing (G&P) segment contributed $11.5 million to operating income in the second quarter of 2003.  The major G&P assets are the East Texas, Northeast Texas, Anadarko and Tilden natural gas systems and the DPI truck and rail energy transportation unit.  In the second quarter of 2002, the Partnership’s only G&P asset was the East Texas System, which contributed $3.2 million of operating income at that time.  Aggregate throughput for the four major G&P natural gas systems was 866 MMBtu/d, which was higher than typically expected in the second quarter because strong natural gas prices sustained active producer drilling programs.  However, increased throughput on the systems was offset by negative gas processing margins during the quarter.

The Natural Gas Transportation systems, which were acquired by the Partnership in October 2002, generated operating income of $3.0 million in the second quarter this year.  Aggregate throughput for the major systems - Kansas, Midla, AlaTenn, UTOS, Bamagas and six intrastate pipelines - was 646 MMBtu/d in the second quarter.  The results reflected lower seasonal demand typical in the second and third quarters of the year relative to the first and fourth quarters.  Although a significant portion of these systems’ capacity is reserved by customers under term contracts, some of these contracts allow for higher toll rates or higher volume reservations in the peak quarters.  Utilization of unreserved capacity further contributes to seasonality.

The Marketing segment contributed $1.8 million to operating income in the second quarter of 2003 and was not owned by the Partnership in the comparative quarter.  Marketing services include purchase of natural gas from producers and marketers; sale of natural gas to wholesale customers; and transportation arrangements for the related natural gas volumes.  Second quarter results reflected typical lower seasonal margins for these services.

Interest expense increased to $21.6 million in the second quarter this year, compared with $13.5 million in the second quarter last year, due to additional debt incurred by the Partnership to finance recent system expansion projects and acquisitions.  Principally, these included Phase III of the Terrace Expansion Program, the Griffith Lateral project and the Midcoast acquisition.  Similarly, weighted average units outstanding increased to 46.8 million from 35.2 million due to additional partners capital raised for the projects and acquisitions.

Enbridge Partners will be hosting an investment conference call at 2:30 p.m. Eastern Time on Thursday, July 24, to discuss its second quarter 2003 financial results.  Interested parties may listen to a live Internet broadcast of the call at the link provided below, or to a replay that will be available on the web site for a limited period following the call.  The call is also accessible by telephone at (800) 915-4836 and can be replayed until August 7, 2003 by calling (800) 428-6051 and entering code 298329.

Webcast URL Link:

www.corporate-ir.net/ireye/ir_site.zhtml?ticker=EEP&script=1100

Enbridge Energy Partners, L.P. (www.enbridgepartners.com) indirectly owns the US portion of the world’s longest liquid petroleum pipeline and is active in natural gas gathering, processing and transmission.  Enbridge Energy Management, L.L.C. (www.enbridgemanagement.com) manages the business and affairs of the Partnership, and its principal asset is an approximate 19% interest in the Partnership.

Enbridge Energy Company, Inc., an indirect wholly owned subsidiary of Enbridge Inc. of Calgary, Alberta, is the General Partner of Enbridge Partners and holds an approximate 13% effective interest in Enbridge Partners.  Enbridge Inc. (www.enbridge.com) common shares are traded on the Toronto Stock Exchange and on the New York Stock Exchange under the symbol “ENB.”

This news release includes forward-looking statements and projections, which are statements that do not relate strictly to historical or current facts.  These statements frequently use the following

words, variations thereon or comparable terminology:  “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “strategy” or “will.”  Forward-looking statements involve risks, uncertainties and assumptions and are not guarantees of performance.  Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements.  Many of the factors that will determine these results are beyond Enbridge Partners’ ability to control or predict.  Specific factors that could cause actual results to differ from those in the forward-looking statements, include (1) changes in the demand for or the supply of, and price trends related to, crude oil, liquid petroleum, natural gas and NGLs; (2) changes in or challenges to Enbridge Partners’ tariff rates; (3) Enbridge Partners’ ability to successfully identify and consummate strategic acquisitions, make cost saving changes in operations and integrate acquired assets or businesses into its existing operations; (4) shut-downs or cutbacks at facilities of Enbridge Partners or refineries, petrochemical plants, utilities or other businesses for which Enbridge Partners transports products or to whom Enbridge Partners sells products; (5) changes in laws or regulations to which Enbridge Partners is subject; (6) the effects of competition, in particular, by other pipeline systems; (7) hazards and operating risks that may not be covered fully by insurance; (8) the condition of the capital markets in the United States; (9) loss of key personnel and (10) the political and economic stability of the oil producing nations of the world.

Reference should also be made to Enbridge Partners’ filings with the US Securities and Exchange Commission, including its Annual Report on Form 10-K for the most recently completed fiscal year, for additional factors that may affect results.  These filings are available to the public over the Internet at the SEC’s web site (www.sec.gov) and via the Partnership’s web site (www.enbridgepartners.com).

Investor Relations Contact:

Tracy Barker

Toll-free: (866) EEP INFO or (866) 337-4636

Facsimile: (713) 821-2230

E-mail: investor@enbridgepartners.com

Media Contact:

Denise Hamsher

Telephone: (713) 821-2089

Facsimile: (713) 821-2230

E-mail: media@enbridgepartners.com

###

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(unaudited; dollars in millions, except per unit amounts)

	Three months ended June 30,						Six months ended June 30,
	2003			2002			2003			2002
Operating revenue	$	755.3		$	223.1		$	1,651.4		$	404.9
Operating Expenses
Cost of natural gas	623.4			130.8			1,376.9			220.4
Operating and administrative	52.3			30.9			104.9			58.7
Power	13.0			12.4			25.7			26.0
Depreciation and amortization (Note 7)	23.5			18.6			46.9			36.9
	712.2			192.7			1,554.4			342.0
Operating income	43.1			30.4			97.0			62.9
Interest and other income (expense)	1.8			0.1			1.8			0.2
Interest expense	(21.6		)	(13.5		)	(42.9		)	(28.2		)
Minority interest	—			(0.2		)	—			(0.4		)
Net income	$	23.3		$	16.8		$	55.9		$	34.5
Net income per unit (Note 2)	$	0.39		$	0.39		$	1.01		$	0.82
Weighted average units outstanding (millions)	46.8			35.2			45.7			34.4

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited; dollars in millions)

Six months ended June 30,	2003			2002
Cash provided by operating activities
Net income	$	55.9		$	34.5
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	46.9			36.9
Hedge transactions ineffectiveness (Note 6)	0.5			—
Payments made upon termination of derivative (Note 6)	(6.1		)	—
Other	0.3			0.2
Changes in operating assets and liabilities,
Receivables, trade and other	(87.1		)	(20.9		)
Other current assets	(6.0		)	(3.2		)
General Partner and affiliates	(11.1		)	15.1
Accounts payable and other	(17.9		)	29.9
Oil shortage balance	8.2			(7.9		)
Accrued gas purchases	91.0			—
Interest payable	2.7			0.3
Property and other taxes	(1.7		)	(3.9		)
Cash provided by operating activities	75.6			81.0
Investing activities
Repayments from affiliate	—			0.2
Additions to property, plant and equipment	(45.6		)	(102.6		)
Changes in construction payables	(5.4		)	2.4
Asset acquisitions, net of cash acquired	(0.4		)	(3.7		)
Cash used in investing activities	(51.4		)	(103.7		)
Financing activities
364-day facility, net	(132.0		)	137.0
Three-year term, net	(52.0		)	7.0
Issuance of senior unsecured notes (Note 5)	396.3			—
Loans from Enbridge Energy Company, Inc., net	(316.0		)	(117.7		)
Proceeds from unit issuance, net (Note 4)	168.2			93.2
Distributions to partners	(74.3		)	(67.3		)
Other	(0.5		)	(1.8		)
Cash (used in) provided by financing activities	(10.3		)	36.4
Net increase in cash and cash equivalents	13.9			13.7
Cash and cash equivalents at beginning of period	60.3			40.2
Cash and cash equivalents at end of period	$	74.2		$	53.9

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(dollars in millions)

	June 30, 2003			December 31, 2002
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	74.2		$	60.3
Receivables, trade and other, net of allowance for doubtful accounts of $3.4 in 2003 and $3.7 in 2002	305.1			217.9
Other current assets	25.6			19.3
	404.9			297.5
Property, plant and equipment, net	2,253.1			2,253.3
Goodwill	239.3			241.1
Other assets, net	45.1			43.0
	$	2,942.4		$	2,834.9
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Due to General Partner and affiliate	$	52.0		$	63.1
Accounts payable and other	80.8			95.9
Oil shortage balance	11.4			3.2
Accrued gas purchases	233.1			142.1
Interest payable	9.7			7.0
Property and other taxes payable	14.6			16.3
Current maturities and short-term debt (Note 5)	111.0			31.0
	512.6			358.6
Long-term debt (Note 5)	1,146.7			1,011.4
Loans from General Partner and affiliates	128.1			444.1
Environmental liabilities	5.6			5.6
Deferred credits	71.1			23.2
Minority interest	—			0.4
	1,864.1			1,843.3
Partners’ capital
Class A common units (Units authorized and issued – 35,166,134 in 2003 and 31,313,634 in 2002)	729.8			604.8
Class B common units (Units authorized and issued – 3,912,750 in 2003 and 2002)	55.3			48.7
i-units (Units authorized and issued – 9,673,843 in 2003 and 9,228,655 in 2002)	350.0			335.6
General Partner	22.6			18.8
Accumulated other comprehensive loss	(79.4		)	(16.3		)
	1,078.3			991.6
	$	2,942.4		$	2,834.9

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1.Basis of Presentation

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X.  Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly the financial position as at June 30, 2003 and December 31, 2002; the results of operations for the three and six month periods ended June 30, 2003 and 2002; and cash flows for the six month period ended June 30, 2003 and 2002.  The results of operations for the three and six months periods ended June 30, 2003 should not be taken as indicative of the results to be expected for the full year, due to seasonality of portions of the natural gas business and maintenance activities.  The interim consolidated financial statements should be read in conjunction with Enbridge Energy Partners, L.P.’s (the “Partnership”) consolidated financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002.

2.Net Income per Unit

Net income per unit is computed by dividing net income, after deduction of Enbridge Energy Company, Inc.’s (the “General Partner”) allocation, by the weighted average number of Class A and Class B Common Units and i-units outstanding.  The General Partner’s allocation is equal to an amount based upon its general partner interest, adjusted to reflect an amount equal to incentive distributions and an amount required to reflect depreciation on the General Partner’s historical cost basis for assets contributed on formation of the Partnership.  Net income per unit was determined as follows:

	Three months ended June 30,						Six months ended June 30,
(in millions; except per unit amounts)	2003			2002			2003			2002
Net income	$	23.3		$	16.8		$	55.9		$	34.5
Net income allocated to General Partner	(0.4		)	(0.2		)	(1.1		)	(0.4		)
Incentive distributions and historical cost depreciation adjustments	(4.3		)	(2.8		)	(8.5		)	(5.8		)
	(4.7		)	(3.0		)	(9.6		)	(6.2		)
Net income allocable to Common Units and i-units	$	18.6		$	13.8		$	46.3		$	28.3
Weighted average units outstanding	46.8			35.2			45.7			34.4
Net income per unit	$	0.39		$	0.39		$	1.01		$	0.82

3.Distributions

On April 24, 2003, the Partnership’s Board of Directors declared a distribution payable on May 15, 2003, to unitholders of record as of April 30, 2003, of its available cash of $45.9 million or $0.925 per common unit, including $8.7 million relating to the i-units that was retained by the Partnership for its use in its business.

On January 23, 2003, the Partnership’s Board of Directors declared a distribution payable on February 14, 2003, to unitholders of record as of January 31, 2003, of its available cash of $46.1 million or $0.925 per common unit, including $8.5 million relating to the i-units that was retained by the Partnership for its use in its business.

4.Equity Unit Issuance

On May 12, 2003, the Partnership issued 3.35 million Class A Common Units at $44.79 per unit, which generated proceeds, net of underwriters’ fees and discounts, commissions and issuance expenses, of approximately $143.5 million.  Proceeds from this offering were used to reduce borrowings under the Partnership’s credit facility and an affiliate loan from Enbridge (U.S.) Inc.  On May 15, 2003, the Partnership issued an additional 502,500 Class A Common Units to the underwriters pursuant to the exercise of their over-allotment option, resulting in additional proceeds to the Partnership, net of underwriters’ fees and discounts, commissions and issuance expenses, of approximately $21.3 million.  In addition to the proceeds generated from the unit issuances, the General Partner contributed $3.5 million to the Partnership to maintain its 2% general partner interest in the Partnership.

5.Debt

On May 27, 2003, the Partnership issued $200.0 million in aggregate principal amount of its 4.75% Notes due 2013 and $200.0 million in aggregate principal amount of its 5.95% Notes due 2033 (the “Notes”) in a private placement.  The Partnership used the proceeds of approximately $396.3 million, net of expenses of approximately $3.0 million, to repay loans from affiliates of the Partnership and other bank debt.  The Partnership recorded a discount of $0.7 million in connection with the issuance of the Notes.  On June 30, 2003, the Partnership filed a Form S-4 with the Securities and Exchange Commission (the “SEC”) to register the exchange the unregistered Notes for publicly registered Notes.

On January 24, 2003, the Partnership amended and restated the terms of its two unsecured revolving credit facilities.  The new facilities consist of the amended and restated $300.0 million three-year facility, which matures in 2006, subject to extension as provided in the facilities, and the amended and restated $300.0 million 364-day facility, which matures in 2004, subject to a one-year term out option and extension as provided in the facility.  The Partnership is the sole borrower under the new facilities and there are no guarantees of the obligations under either facility.  The amended and restated terms of the facilities are substantially similar to the original facilities with the exception of certain amendments to the covenants.  Among other changes under the new facilities, the Partnership must maintain a minimum interest coverage ratio as defined in the amended and restated terms of the facilities, of 2.75 to 1.00 as of the end of each fiscal quarter and is no longer required to maintain a particular credit rating.  Although subsidiaries may incur debt subject to certain restrictions and limitations under the new facilities, the Partnership expects to provide funding to its subsidiaries.  As of June 30, 2003, $80.0 million and $200.0 million were outstanding under the 364-day and three-year facilities, respectively.

6.Derivative Instruments and Hedging Activities

In May 2003 prior to the issuance of the Notes, the Partnership entered into 10 year and 30 year treasury lock agreements (the “agreements”) to hedge the fluctuations in the U.S. Treasury bond interest rates between the execution date of the swaps and the issuance date of the fixed rate debt.  The agreements were designated as cash flow hedges of future interest expense.  Upon issuance of the Notes, the agreements were terminated and their aggregate mark to market value of $6.1 million was paid and recorded in accumulated other comprehensive income and is being amortized to interest expense over the term of the Notes.

In May 2003, the Partnership entered into a treasury lock contract, maturing on October 1, 2003, for the purpose of locking in the U.S. Treasury bond interest rate on anticipated debt offerings.  As of June 30, 2003, the lock totaled $0.3 million and is deemed fully effective.  All changes to the market value of the derivative instrument have been recorded in accumulated other comprehensive income.

The changes in the market value of natural gas hedging instruments that are attributable to hedge ineffectiveness, measured on a quarterly basis, are included in cost of natural gas expense in the period in which they occur.  During the second quarter 2003, the Partnership recorded $0.5 million in cost of natural gas expense to reflect the ineffective portion of certain hedge transactions.

7.Depreciation

Based on a third-party study commissioned by management, revised depreciation rates for the Lakehead System were implemented effective January 1, 2003, which represent the expected remaining service life of the pipeline system.  The third-party study will be filed with the Federal Energy Regulatory Commission (“FERC”) to conform regulatory and financial accounting depreciation rates of the Lakehead System.  Depreciation expense for the six months ended June 30, 2003, was $46.9 million, $6.1 million lower than it would have been using previous depreciation rates.  The annual composite rate changed from 3.9% to 3.22%.

8.Segment Information

The Partnership’s business is divided into operating segments, defined as components of the enterprise about which financial information is available and evaluated regularly by the Partnership in deciding how to allocate resources to an individual segment and in assessing performance of the segment.

The Partnership’s reportable segments are based on the types of business activity and management control. Each segment is managed separately because each business requires different operating strategies.  The Partnership has five reportable business segments: Liquids Transportation, Gathering and Processing, Natural Gas Transportation, Marketing and Corporate.

Due to the purchase of natural gas assets in October 2002, the Partnership changed the organization of its business segments effective in the fourth quarter of 2002.  Prior to the fourth quarter of 2002, the Partnership reported Transportation as one segment, which consisted of receipt and delivery of crude oil, liquid hydrocarbons, natural gas and natural gas liquids.  These activities are now reported within 3 segments — Liquids Transportation, Natural Gas Transportation and Gathering and Processing.  Prior period segment results have been restated to conform to the Partnership’s current organization.

The following tables present certain financial information relating to the Partnership’s business segments.

	As of and for the Three Months Ended June 30, 2003
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Operating revenues	$	81.8	$	441.7	$	35.0	$	196.8	$	—		$	755.3
Cost of natural gas	—		405.6		23.3		194.5		—			623.4
Operating and administrative	26.9		19.1		5.3		0.4		0.6			52.3
Power	13.0		—		—		—		—			13.0
Depreciation and amortization	14.5		5.5		3.4		0.1		—			23.5
Operating income	27.4		11.5		3.0		1.8		(0.6		)	43.1
Interest and other income	—		—		—		—		1.8			1.8
Interest expense	—		—		—		—		(21.6		)	(21.6		)
Net income	$	27.4	$	11.5	$	3.0	$	1.8	$	(20.4	)	$	23.3
Total assets	$	1,498.5	$	746.5	$	417.8	$	225.0	$	54.6		$	2,942.4
Goodwill	$	—	$	146.1	$	72.9	$	20.3	$	—		$	239.3
Capital expenditures (excluding acquisitions)	$	15.1	$	10.1	$	1.1	$	0.1	$	0.9		$	27.3

	As of and for the Three Months Ended June 30, 2002
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Operating revenues	$	81.0	$	142.1	$	—	$	—	$	—		$	223.1
Cost of natural gas	—		130.8		—		—		—			130.8
Operating and administrative	24.1		5.6		—		—		1.2			30.9
Power	12.4		—		—		—					12.4
Depreciation and amortization	16.1		2.5		—		—		—			18.6
Operating income	28.4		3.2		—		—		(1.2		)	30.4
Interest and other income	—		—		—		—		0.1			0.1
Interest expense	—		—		—		—		(13.5		)	(13.5		)
Minority interest	—		—		—		—		(0.2		)	(0.2		)
Net income	$	28.4	$	3.2	$	—	$	—	$	(14.8	)	$	16.8
Total assets	$	1,451.9	$	286.5	$	—	$	—	$	2.2		$	1,740.6
Goodwill	$	—	$	15.0	$	—	$	—	$	—		$	15.0
Capital expenditures (excluding acquisitions)	$	70.2	$	2.4	$	—	$	—	$	—		$	72.6

	As of and for the Six Months Ended June 30, 2003
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Operating revenues	$	167.2	$	944.0	$	64.5	$	475.7	$	—		$	1,651.4
Cost of natural gas	—		870.6		38.7		467.6		—			1,376.9
Operating and administrative	53.3		38.1		11.0		0.8		1.7			104.9
Power	25.7		—		—		—		—			25.7
Depreciation and amortization	28.9		11.1		6.8		0.1		—			46.9
Operating income	59.3		24.2		8.0		7.2		(1.7		)	97.0
Interest and other income	—		—		—		—		1.8			1.8
Interest expense	—		—		—		—		(42.9		)	(42.9		)
Net income	$	59.3	$	24.2	$	8.0	$	7.2	$	(42.8	)	$	55.9
Total assets	$	1,498.5	$	746.5	$	417.8	$	225.0	$	54.6		$	2,942.4
Goodwill	$	—	$	146.1	$	72.9	$	20.3	$	—		$	239.3
Capital expenditures (excluding acquisitions)	$	20.0	$	21.3	$	2.4	$	0.1	$	1.8		$	45.6

	As of and for the Six Months Ended June 30, 2002
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Operating revenues	$	163.6	$	241.3	$	—	$	—	$	—		$	404.9
Cost of natural gas	—		220.4		—		—		—			220.4
Operating and administrative	46.7		10.6		—		—		1.4			58.7
Power	26.0		—		—		—		—			26.0
Depreciation and amortization	32.0		4.9		—		—		—			36.9
Operating income	58.9		5.4		—		—		(1.4		)	62.9
Interest and other income	—		—		—		—		0.2			0.2
Interest expense	—		—		—		—		(28.2		)	(28.2		)
Minority interest	—		—		—		—		(0.4		)	(0.4		)
Net income	$	58.9	$	5.4	$	—	$	—	$	(29.8	)	$	34.5
Total assets	$	1,451.9	$	286.5	$	—	$	—	$	2.2		$	1,740.6
Goodwill	$	—	$	15.0	$	—	$	—	$	—		$	15.0
Capital expenditures (excluding acquisitions)	$	96.8	$	5.8	$	—	$	—	$	—		$	102.6

9.Comparative Amounts

Certain reclassifications have been made to the prior period’s reported amounts to conform to the classifications used in the 2003 consolidated financial statements.  These reclassifications have no impact on net income.