HOUSTON, April 27, 2006 (PRIMEZONE) -- Enbridge Energy Partners, L.P. (NYSE:EEP) ("Enbridge Partners" or "the Partnership") today declared a cash distribution of $0.925 per unit payable May 15, 2006 to unitholders of record on May 5, 2006. The Partnership also reported net income for the three months ended March 31, 2006 of $81.1 million, or $1.12 per unit, compared with net income of $28.2 million, or $0.37 per unit, for the first quarter of the prior year.
Eliminating the impact of noncash mark-to-market charges and credits, the Partnership's adjusted net income for the first quarter of 2006 was $53.4 million, or $0.71 per unit, up from $35.2 million, or $0.48 per unit, in first quarter 2005. Adjusted EBITDA increased to $114.0 million in the first quarter of 2006 from $94.1 million in the same quarter last year. Noncash mark-to-market charges and credits arise from valuing 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.)
"We were pleased with the stronger-than-expected results Enbridge Partners reported for the first quarter this year and are encouraged by progress on projects that bode well for the Partnership's long-term financial performance," stated Dan C. Tutcher, President of the Partnership's management company and of its general partner. "Crude oil deliveries on our Lakehead System climbed above 1.5 million barrels per day for the first time since 1998. We expect the supply of oil available to this key system will increase over the next few years, since a number of major projects in the Alberta oil sands are scheduled to start up in that time frame. Volumes available to our natural gas systems have also been increasing as continuing historically high gas prices have increased the reserves that producers can economically recover. Natural gas processing margins have also remained strong, which affords us the opportunity to capture attractive returns by fully utilizing our gas processing plants. In light of our strong first quarter results, we expect our full year adjusted net income to be in the range of $180 to $200 million."
Tutcher continued, "Looking ahead, the Partnership has an unprecedented number of internal growth opportunities available. This translates into a capital investment program that we expect will top $3 billion over the next four years. Two higher profile projects head the list -- the Southern Access crude oil system expansion and the East Texas natural gas system extension and expansion. These projects, and a variety of smaller capital projects, will start coming on stream in 2007."
The Partnership also reported steady progress on a number of crude oil transportation and storage projects:
-- In March, the Southern Access expansion received approval from
the Federal Energy Regulatory Commission for its tariff
principles, which were previously agreed upon with customers.
The expansion is designed to add 400,000 barrels per day (bpd) of
capacity on the Lakehead system for delivery of heavy crude oil to
the Chicago area. Nearly one-half of the incremental capacity
will be available in early 2008, with the remainder available in
early 2009.
-- The Partnership announced in February that the pipe size for the
Southern Access expansion project would be increased from
30 to 36 inches in diameter. In anticipation of long term
demands for pipeline capacity driven by oil sands production, the
Partnership has decided to further increase the pipe size to 42
inch diameter, bringing the estimated capital cost of the Southern
Access expansion project to approximately $1.3 billion. The pipe
diameter increase will provide immediate benefits to the project
by lowering power costs and position the system for low-cost
future expansion after 2009 to provide a further 800,000 bpd,
bringing the total incremental capacity potential into the
Chicago hub to 1.2 million bpd over capacity available today.
-- In January, Enbridge Inc. unveiled the Alberta Clipper project,
a proposed new pipeline between Hardisty, Alberta and Superior,
Wisconsin that is subject to ongoing discussions with customers.
The new line is expected to have ultimate capacity of at least
800,000 bpd. Assuming Alberta Clipper garners sufficient support,
the Partnership would undertake the U.S. portion at an estimated
cost of $570 million (in 2005 dollars).
-- The Lakehead System stands to benefit from pipeline reversals
recently completed by Enbridge Inc. and ExxonMobil that enable
Canadian crude oil to access two significant new markets.
Enbridge's Spearhead Pipeline now provides service to Cushing,
Oklahoma from a takeoff connection with the Lakehead System near
Chicago. Spearhead has initial long-term commitments of 60,000
bpd and Enbridge forecasts filling the 125,000 bpd capacity and
expanding the system within the next few years. ExxonMobil has
reversed a 66,000 bpd pipeline to now serve the U.S. Gulf Coast
refining center from the pipeline hub at Patoka, Illinois.
Lakehead accesses the Patoka hub via a joint tolling arrangement
with the Mustang Pipeline.
-- Subject to support of shippers, a $70 million expansion of the
North Dakota System is planned to add 30,000 bpd of mainline
throughput capacity and expand the system's feeder segment in
the latter half of 2007. The expansion is supported by
increasing crude oil production from the Williston Basin.
-- The Partnership began construction on three projects totaling
$53 million to add 3.2 million barrels of commercial crude oil
storage at its Cushing terminal for service in late 2006.
Definitive agreements are in place to add a further, combined
2.5 million barrels of crude oil storage at the Cushing;
Superior and Griffith, Indiana terminals by mid 2007 at an
estimated cost of $60 million.
The Partnership's natural gas operations are also generating a number of organic growth opportunities and key recent developments include:
-- In January, a $530 million expansion and extension of the East
Texas System was announced and field work has started on the
project. The key feature of the project is a new 700 MMcfd
intrastate pipeline to transport East Texas natural gas
production to large markets in southeastern Texas, as well as
to interconnects with several interstate pipelines. The project,
which will be completed in stages during 2007, currently has
volume or production dedications in excess of 500 MMcfd.
-- The North Texas Link is scheduled to commence within the next few
weeks, providing a route for 100,000 MMBtu/d of gas from North
Texas to access the Carthage Hub. The Partnership invested
approximately $20 million to link its North Texas facilities and
East Texas transmission line via a third-party pipeline on which
the Partnership has a firm transportation commitment.
-- Recently, $55 million of processing plant expansions were
completed to add 70 MMcfd of capacity on the Anadarko System.
An additional 250 MMcfd of processing capacity and 80 MMcfd of
treating capacity for the Anadarko and East Texas systems is
under development, for completion over the next 12 months at an
approximate cost of $130 million.
COMPARATIVE EARNINGS STATEMENT
Three Months Ended
March 31,
--------------------
(unaudited, dollars in millions
except per unit amounts) 2006 2005
--------- ---------
Operating revenue $ 1,888.6 $ 1,250.1
Operating expenses:
Cost of natural gas (1,647.7) (1,072.2)
Operating and administrative (73.9) (74.4)
Power (26.3) (17.0)
Depreciation and amortization (32.7) (33.3)
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Operating income $ 108.0 $ 53.2
Interest expense (27.9) (25.6)
Interest and other income 1.0 0.6
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Net income $ 81.1 $ 28.2
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Allocations to General Partner (7.2) (6.0)
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Net income allocable to Limited Partners $ 73.9 $ 22.2
Weighted average units (millions) 65.7 60.6
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Net income per unit (dollars) $ 1.12 $ 0.37
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Liquids -- Comparing year-over-year Liquids segment results for the first quarter, operating income increased $21.8 million to $51.8 million. This was driven by a $26.1 million rise in operating revenue, which was mostly attributable to higher volumes on the Lakehead system now that crude supply has been restored with the completed repair and expansion of a major oil sands plant that was damaged by a fire in early January 2005. Gulf of Mexico oil production shut in due to Hurricanes Katrina and Rita caused refinery procurement patterns to shift, which continue to increase volumes on our Mid-Continent System. Also contributing to the increase in operating revenues was an increase in average tariffs primarily due to the annual index rate increase, which became effective on July 1, 2005, and longer hauls.
Power costs were $9.3 million higher due to increased volumes on the Lakehead system and to a lesser extent an increase in mill rates. A $3.3 million decrease in operating expenses was due to a decrease in oil measurement losses, partially offset by higher workforce related costs. Deliveries for the three Liquids systems were as follows:
Three Months Ended
March 31,
------------------
(thousand barrels per day) 2006 2005
------ ------
Lakehead 1,509 1,336
Mid-Continent 237 189
North Dakota 90 89
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Total 1,836 1,614
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Natural Gas -- Year-over-year first quarter results for the Natural Gas segment saw an increase of $4.6 million in adjusted operating income to $35.4 million (operating income is reconciled to adjusted operating income below):
Three Months Ended
March 31,
------------------
(unaudited, dollars in millions) 2006 2005
------ ------
Operating income $ 37.2 $ 22.4
Noncash derivative fair value (gains) losses (1.8) 8.4
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Adjusted operating income $ 35.4 $ 30.8
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On an adjusted basis, operating revenue less cost of natural gas increased approximately $8.2 million, partially due to new processing capacity on the Anadarko system and improved gas processing margins. Also contributing to the increase was a 5 percent growth in average daily volumes on the major natural gas systems. The throughput growth was due to additional wellhead supply contracts on the East Texas and Anadarko systems. The increase in contracts stemmed from strong drilling activity in the Anadarko Basin and East Texas Bossier trend. These increases were partially offset by the sale of nonstrategic midstream assets in December 2005. Operating costs increased by $2.6 million over the first quarter of 2005. The increase came from those costs which are mostly variable with higher volumes including increased workforce-related costs. Average daily volumes for the major natural gas systems were:
Three Months Ended
March 31,
---------------------
(MMBtu per day) 2006 2005
--------- ---------
East Texas 921,000 787,000
Anadarko 563,000 452,000
North Texas 279,000 265,000
South Texas -- 38,000
UTOS 199,000 198,000
Midla 83,000 105,000
AlaTenn 54,000 83,000
KPC 47,000 59,000
Bamagas 37,000 13,000
Other Major Intrastates 158,000 220,000
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Major Systems Total 2,341,000 2,220,000
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Marketing -- The Marketing segment reported an adjusted operating loss of $6.3 million in the first quarter, compared with breakeven in the first quarter of 2005 (operating income is reconciled to adjusted operating income below):
Three Months Ended
March 31,
------------------
(unaudited, dollars in millions) 2006 2005
------ ------
Operating income $ 19.6 $ 1.4
Noncash derivative fair value gains (25.9) (1.4)
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Adjusted operating income (loss) $ (6.3) $ --
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The results this year included an $8.0 million write-down of natural gas inventory. This was precipitated by a decline in natural gas prices during the first quarter, which resulted in the market value of gas in storage being less than its recorded value using the weighted average price of gas purchases. Accounting rules require that inventory be valued at the lower of cost or market, therefore, the inventory value was written down. Since future sales are hedged, the majority of this loss is expected to be recovered when the natural gas inventory is sold at various future dates.
Partnership Financing -- Comparing first quarter 2006 with the comparable quarter in 2005, interest expense increased by $2.3 million, to $27.9 million. This is primarily due to modestly higher debt balances and less interest capitalized to construction projects during the first quarter of 2006. Weighted average units outstanding increased to 65.7 from 60.6 million units, due to additional partners' capital raised for acquisitions and expansions over the past year.
ENBRIDGE ENERGY MANAGEMENT DISTRIBUTION
Enbridge Energy Management, L.L.C. (NYSE:EEQ) declared a distribution of $0.925 per share payable May 15, 2006 to shareholders of record on May 5, 2006. 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 May 3, 2006.
MANAGEMENT REVIEW OF QUARTERLY RESULTS
Enbridge Partners will review its quarterly financial results and business outlook in an Internet presentation, commencing at 10 a.m. Eastern Time on Friday, April 28, 2006. Interested parties may watch the live webcast at the link provided below. A replay will be available shortly afterward. Presentation slides and condensed unaudited financial statements will be available at the link below, ahead of the web presentation.
EEP Earnings Release: www.enbridgepartners.com/Q/ Alternate Webcast Link: www.vcall.com/CEPage.asp?ID=103556
The audio portion of the presentation will be accessible by telephone at (877) 407-0782 and can be replayed until May 12, 2006 by calling (877) 660-6853 and entering Conference Account 286, ID 199412. An audio replay will also be available for download in MP3 format from either of the website addresses above.
NON-GAAP RECONCILIATIONS
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
March 31,
----------------------
(unaudited, dollars in millions
except per unit amounts) 2006 2005
---------- ----------
Net income $ 81.1 $ 28.2
Noncash derivative fair value (gains)
losses
-Natural Gas (1.8) 8.4
-Marketing (25.9) (1.4)
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Adjusted net income 53.4 35.2
Allocations to General Partner (6.7) (6.1)
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Adjusted net income allocable to
Limited Partners 46.7 29.1
Weighted average units (millions) 65.7 60.6
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Adjusted net income per unit (dollars) $ 0.71 $ 0.48
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Adjusted EBITDA (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 because EBITDA is not a financial measure recognized by generally accepted accounting principles.
Three Months Ended
March 31,
------------------
(unaudited, dollars in millions) 2006 2005
------ ------
Net cash provided by operating activities $ 96.4 $ 89.3
Changes in operating assets and
liabilities, net of cash acquired (11.4) (21.1)
Interest expense 27.9 25.6
Other 1.1 0.3
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Adjusted EBITDA $114.0 $ 94.1
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LEGAL NOTICE
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.
PARTNERSHIP INFORMATION
Enbridge Energy Partners, L.P. (www.enbridgepartners.com) owns and operates a diversified portfolio of crude oil and natural gas transportation systems in the U.S. Its principal crude oil system is the largest transporter of growing oil production from western Canada. The system's deliveries to refining centers in the U.S. Midwest account for approximately 10 percent of total U.S. oil imports; while deliveries to Ontario, Canada satisfy approximately 60 percent of refinery demand in that region. The Partnership's natural gas gathering, treating, processing and transmission assets, which are principally located onshore in the active U.S. Mid-Continent and Gulf Coast area, deliver more than 2 billion cubic feet of natural gas daily.
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, (NYSE/TSX:ENB) (www.enbridge.com) is the general partner and holds an approximate 11 percent effective interest in the Partnership.