Enbridge Energy Partners Declares Cash Distribution and Reports 2005 Third Quarter Results

HOUSTON 10/26/2005 06:00 AM GMT (TransWorldNews)

Enbridge Energy Partners, L.P. (NYSE:EEP) ("Enbridge Partners" or "the Partnership") today declared a cash distribution of $0.925 per unit payable November 14, 2005 to unitholders of record on November 3, 2005. The Partnership also reported a net loss for the three months ended September 30, 2005 of $(14.4) million, or $(0.32) per unit, compared with net income of $27.6 million, or $0.39 per unit, for the third quarter of the prior year.

Eliminating the impact of noncash mark-to-market charges, the Partnership's adjusted net income for the third quarter of 2005 was $38.2 million, or $0.52 per unit, increased from $27.3 million, or $0.39 per unit, in third quarter 2004. Adjusted EBITDA increased to $103.1 million in the third quarter of 2005 from $81.2 million in the same quarter last year. The noncash charges arise from valuing, on a mark-to-market basis, certain of the Partnership's hedging transactions that do not qualify for hedge accounting treatment under Statement of Financial Accounting Standard No. 133. (See Non-GAAP Reconciliations section below.)

"Overall, the Partnership's third quarter financial results were on target. Better-than-expected contributions from our natural gas systems compensated for somewhat lower-than-expected volumes on our largest crude oil system and mitigated a modest earnings impact from two major hurricanes during the quarter," commented Dan C. Tutcher, president of the Partnership's management company and general partner. "Looking ahead to the short term, it is welcome news that the major oil sands plant damaged by fire in January, completed repairs and commissioned a sizable expansion late in the third quarter. It is also encouraging to see steady progress being made in restoring third-party energy infrastructure in the U.S. Gulf Coast region that was damaged by the hurricanes."

Tutcher added, "We continue to have a positive long-term outlook for both the Partnership's crude oil transportation and natural gas midstream businesses. We are currently finalizing commercial terms with western Canadian producers in order to proceed with the Southern Access Expansion, which will add 400,000 barrels per day of capacity to our Lakehead crude oil system as early as 2009. On the natural gas side, we're continuing to develop a steady flow of midstream infrastructure projects to keep pace with growing production in the major basins that we serve. The growth profile for these basins over the next several years is very strong. As a result, we are in discussions with producers to provide access to additional markets; similar to the way our East Texas transmission line, which started up in June, has enhanced access to the Carthage, Texas market."

Other key developments with respect to the Partnership's capital expansion projects included:

-- The Partnership expects to finalize commercial terms of its $760 million Southern Access Expansion and file agreed tolling principles with the Federal Energy Regulatory Commission within the next few months. The 400,000 barrel per day expansion is intended to maintain capacity on the Lakehead crude oil system ahead of demand for transportation to key U.S. markets that will be required by projected growth in oil sands production in western Canada. Based on customer requirements, capacity could be added in phases before 2009 at an increased capital cost of up to $120 million.
-- Growing natural gas production in the Anadarko and East Texas regions continues to create demand for treating and processing capacity. In addition to the new Zybach plant started earlier this year, the Partnership has approved projects totaling approximately $150 million to add 80 and 320 MMcfd of treating and processing capacity, respectively, in these regions over the next 18 months.
-- The North Texas Link is on schedule to provide an avenue for 100,000 MMBtu/d of production from North Texas to access the Carthage Hub, starting in the first quarter next year. The project entails $20 million of facilities to deliver production to an Atmos pipeline on which the Partnership has a firm transportation commitment and, in turn, to connect Atmos with the Partnership's new transmission line in East Texas.
-- The $28 million Mid-Continent System project to add 2.3 million barrels of commercial crude oil storage at Cushing, Oklahoma is scheduled for completion late this year.


Three Months Ended Nine Months Ended
September 30, September 30,
(unaudited, dollars in ------------------ -----------------
millions except per unit
amounts) 2005 2004 2005 2004
-------- ------- ------- --------
Segmented operating income:
-Liquids $ 30.7 $ 37.8 $ 90.8 $103.8
-Natural Gas 21.6 23.4 68.7 67.1
-Marketing (39.8) 1.7 (41.5) 4.6
-Corporate (0.6) (1.3) (2.3) (3.3)
Operating income $ 11.9 $ 61.6 $115.7 $172.2
Interest expense (28.4) (22.2) (79.6) (65.8)
Rate Refunds 0.0 (12.0) 0.0 (12.0)
Interest and other income 2.1 0.2 3.4 2.2
Net (loss) income $(14.4) $ 27.6 $ 39.5 $ 96.6
Allocations to General
Partner (5.1) (5.5) (16.9) (16.5)
Net income allocable to
Limited Partners $(19.5) $ 22.1 $ 22.6 $ 80.1
Weighted average units
(millions) 62.1 55.7 61.5 55.1
Net income per unit
(dollars) $(0.32) $ 0.39 $ 0.37 $ 1.45

Liquids -- Operating income from the Liquids segment was $30.7 million for the third quarter, a decrease of $7.1 million over the same period in 2004. Deliveries on the Lakehead system were 104,000 barrels per day, or 7.5 percent, lower than in third quarter 2004. This was attributable to the partial outage of a major oil sands plant damaged by a fire in early January, lower bitumen supply due to the cyclical nature of thermal recovery techniques and additional takeaway capacity from western Canada available on a third-party pipeline. The damaged oil sands plant returned to full production and started up a 35,000 barrel per day expansion in September. As a result, we expect deliveries on the Lakehead system to increase in the fourth quarter.

The Lakehead volume shortfall was partially offset by higher average tariffs on all three Liquids systems. With the current oil price environment, drilling continues to be strong in Montana resulting in longer hauls on our North Dakota system. The Liquids segment also experienced an increase in operating and administrative expenses in the current quarter in relation to the corresponding period of 2004, resulting from increases in workforce related costs coupled with a decrease in capital project recoveries. Deliveries on the three Liquids systems were as follows:

Three Months Ended      Nine Months Ended
September 30, September 30,
------------------ -----------------
(thousand barrels per day) 2005 2004 2005 2004
----- ----- ----- -----
Lakehead 1,290 1,394 1,318 1,419
Mid-Continent(a) 259 264 225 236
North Dakota 84 85 87 81
Total 1,633 1,743 1,630 1,736

(a) Mid-Continent results are for 9 months in 2005, compared with
7 months in 2004.

Natural Gas -- The Natural Gas segment contributed $31.1 million to adjusted operating income in the third quarter of 2005, an increase of $7.7 million over the same period in 2004 (operating income is reconciled to adjusted operating income below):

Three Months Ended      Nine Months Ended
September 30, September 30,
------------------ -----------------
(unaudited, dollars
in millions) 2005 2004 2005 2004
----- ----- ----- -----
Operating income $21.6 $23.4 $68.7 $67.1
Noncash derivative
fair value losses 9.5 -- 22.6 --
Adjusted operating income $31.1 $23.4 $91.3 $67.1

Average daily volumes on our major natural gas systems increased 17 percent principally due to additional wellhead supply contracts on our East Texas and Anadarko systems, in addition to the contribution of the North Texas gathering and processing assets we acquired in January 2005. Drilling activity continues to be strong in the Anadarko basin and Bossier trend areas, which has produced higher volumes on the Anadarko, and East Texas systems. In addition, stronger natural gas liquids prices enhanced processing returns on the Anadarko System. Average daily volumes for the major natural gas systems were as follows:

 Three Months Ended     Nine Months Ended
September 30, September 30,
-------------------- --------------------
(MMBtu per day) 2005 2004 2005 2004
--------- --------- --------- ---------
East Texas 904,000 693,000 841,000 643,000
Anadarko(a) 489,000 388,000 473,000 334,000
North Texas 267,000 196,000 264,000 192,000
South Texas 31,000 38,000 34,000 42,000
UTOS 154,000 259,000 181,000 227,000
Midla 129,000 103,000 113,000 106,000
AlaTenn 42,000 47,000 59,000 60,000
KPC 8,000 20,000 29,000 45,000
Bamagas 110,000 55,000 44,000 33,000
Other Major Intrastates(a) 164,000 167,000 197,000 174,000
Major Systems Total 2,298,000 1,966,000 2,235,000 1,856,000
(a) Anadarko includes Palo Duro volumes formerly included with
Other Major Intrastates

Marketing -- The Marketing segment had adjusted operating income of $3.3 million in the third quarter of 2005, compared with $1.4 million in the corresponding period in 2004 (operating income is reconciled to adjusted operating income below):

 Three Months Ended     Nine Months Ended
September 30, September 30,
---------------- -----------------
(unaudited, dollars
in millions) 2005 2004 2005 2004
------ ------ ------ ------
Operating income $(39.8) $ 1.7 $(41.5) $ 4.6
Noncash derivative fair
value losses (gains)(a) 43.1 (0.3) 44.7 1.4
Adjusted operating income $ 3.3 $ 1.4 $ 3.2 $ 6.0
(a) Excludes $2.1 million in cash losses recognized in second
quarter 2005.

Supply disruptions in the Gulf of Mexico region caused by hurricanes Katrina and Rita during the third quarter created greater demand for natural gas from onshore production areas that we serve, increasing the ability of the Partnership to optimize its firm transportation contracts.

Partnership Financing -- The increase in interest expense to $28.4 million for the third quarter this year, compared with $22.2 million in the third quarter last year, was due to higher interest rates and additional debt incurred by the Partnership to finance recent acquisitions and system expansions. Principally, these include the gathering and processing assets acquired in January 2005, the East Texas expansion, and construction of the processing facilities on our Anadarko System. Similarly, weighted average units outstanding increased to 62.1 million units for the third quarter of 2005 from 55.7 million units in 2004, due to additional partners' capital raised for the acquisitions and expansions.


Enbridge Energy Management, L.L.C. (NYSE:EEQ) declared a distribution of $0.925 per share payable November 14, 2005 to shareholders of record on November 3, 2005. The distribution will be paid in the form of additional shares of Enbridge Energy Management valued at the average closing price of the shares for the ten trading days prior to the ex-dividend date on November 1, 2005.


Enbridge Partners will review its quarterly financial results and business outlook in an Internet presentation, commencing at 10 a.m. Eastern Time on Thursday, October 27, 2005. Interested parties may watch the live webcast, or a replay that will be available shortly after the presentation, at the link provided below. Presentation slides and condensed unaudited financial statements will be available at the link ahead of the web presentation.

EEP Earnings Release: www.enbridgepartners.com/q/
Alternate Webcast Link: www.vcall.com/CEPage.asp?ID=96063

The audio portion of the presentation will be accessible by telephone at (416) 640-3405 and can be replayed until November 6 by calling (402) 220-0893 and entering code 1385667. The audio replay will also be available for download in MP3 format from either of the website addresses above.


Adjusted net income is provided to illustrate trends in net income excluding derivative fair value losses and gains that affect earnings but do not impact cash flow. These noncash losses and gains result from marking-to-market certain financial derivatives used by the Partnership for hedging purposes that, nevertheless, do not qualify for hedge accounting treatment as prescribed by Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."

Three Months Ended        Nine Months Ended
September 30, September 30,
--------------------- -------------------
(unaudited, dollars
in millions except 2005 2004 2005 2004
per unit amounts) ------- ------- -------- -------

Net (loss) income $ (14.4) $ 27.6 $ 39.5 $ 96.6
Noncash derivative
fair value losses
-Natural Gas 9.5 -- 22.6 --
-Marketing(a) 43.1 (0.3) 44.7 1.4
Adjusted net income 38.2 27.3 106.8 98.0
Allocations to
General Partner 6.1 5.5 18.2 16.6
Adjusted net income
allocable to
Limited Partners 32.1 21.8 88.6 81.4
Weighted average
units (millions) 62.1 55.7 61.5 55.1
Adjusted net income
per unit (dollars) $ 0.52 $ 0.39 $ 1.44 $ 1.48
(a) Excludes $2.1 million in cash losses recognized in second
quarter 2005.

Adjusted EBITDA (adjusted earnings before interest, taxes, depreciation and amortization) is used as a supplemental financial measurement to assess liquidity and the ability to generate cash sufficient to pay interest costs and make cash distributions to unitholders. The following reconciliation of net cash provided by operating activities to adjusted EBITDA is provided since EBITDA is not a financial measure recognized by generally accepted accounting principles.

 Three Months Ended   Nine Months Ended
September 30, September 30,
------------------ -----------------
(unaudited, dollars
in millions) 2005 2004 2005 2004
------- ------- ------- -------
Net cash provided by
operating activities $ 84.5 $ 71.8 $ 208.2 $ 225.9
Changes in operating assets
and liabilities, net of
cash acquired (9.6) (12.6) 4.5 (40.5)
Interest Expense 28.4 22.2 79.6 65.8
Other(a) (0.2) (0.2) (2.0) 1.8
Adjusted EBITDA $ 103.1 $ 81.2 $ 290.3 $ 253.0
(a) Includes $2.1 million in cash losses recognized in the second
quarter 2005.


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, including the rate of development of the Alberta Oil Sands; (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 U.S. 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.


Enbridge Energy Partners, L.P. (www.enbridgepartners.com) owns and operates a diversified portfolio of crude oil and natural gas transportation systems in the United States. Its principal crude oil system delivers crude oil received primarily from western Canada to refining centers in the U.S. Midwest, accounting for approximately 10 percent of total U.S. crude oil imports, and to Ontario, Canada. The Partnership's natural gas gathering, treating, processing and transmission assets are principally onshore systems located in the active U.S. Mid-Continent and Gulf Coast regions.

Enbridge Energy Management, L.L.C. (www.enbridgemanagement.com) manages the business and affairs of the Partnership and its principal asset is an approximate 18 percent interest in the Partnership. Enbridge Energy Company, Inc., an indirect wholly owned subsidiary of Enbridge Inc. of Calgary, Alberta, (www.enbridge.com) is the general partner and holds an approximate 11 percent effective interest in the Partnership.

Enbridge Energy Partners, L.P.
Investor Relations Contact:
Tracy Barker
Toll-free: (866) EEP INFO or (866) 337-4636

Media Contact:
Denise Hamsher
(713) 821-2089



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