HOUSTON, Oct. 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 November 14, 2006 to unitholders of record on November 6, 2006. The Partnership also reported net income for the three months ended September 30, 2006 of $82.2 million, or $1.03 per unit, compared with net loss of $(14.4) million, or $(0.32) per unit, for the third quarter of 2005. For the first nine months of 2006, net income was $233.7 million, or $3.11 per unit, compared with $39.5 million, or $0.37 per unit, in the first nine months of 2005.
Eliminating the impact of noncash mark-to-market gains and losses, the Partnership's adjusted net income for the third quarter of 2006 was $58.5 million, or $0.70 per unit, up from $38.2 million, or $0.52 per unit, in third quarter 2005. Adjusted EBITDA increased to $121.8 million in the third quarter of 2006 from $103.1 million in the same quarter last year. For the first nine months of 2006, adjusted net income was $180.6 million, or $2.34 per unit, compared with $106.8 million, or $1.44 per unit in the first nine months of 2005. Noncash mark-to-market gains and losses 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.)
Terrance L. McGill, president of the Partnership's management company and of its general partner, explained, "The Partnership's strong performance this year continued in the third quarter. As expected, increased systems utilization was a major contributor. Volumes on our three crude oil systems increased 150,000 barrels per day, or about 9 percent, compared with the third quarter last year. At the same time, volumes on our three largest natural gas systems increased 292,000 MMBtu per day, or about 18 percent. Natural gas processing also contributed to profitability as processing margins remained historically strong. The additional 295 MMcfd of processing capacity that we've added since early 2005, boosts our active plant capacity to approximately 1 Bcfd and provides greater ability to process when margins are favorable."
McGill continued, "We are making excellent progress on our major capital expansion program, which we anticipate will increase the Partnership's earnings and cash flow as the various projects commence service over the next few years. In particular, the $610 million extension and expansion of our East Texas System will be completed in stages next year and it will contribute to results partially in 2007 and fully in 2008. The first stage of our $1.3 billion expansion of the Lakehead crude oil system is on target to add 190,000 barrels per day of capacity by early 2008. The second stage of the project will add further capacity of 210,000 barrels per day in early 2009. Under the full cost of service tariff agreement that applies to the Lakehead expansion, the Partnership will start to earn its regulated return as the respective stages are placed in service."
During the third quarter, the Partnership progressed on a number of key crude oil transportation and storage projects, as follows:
-- The $1.3 billion Southern Access Expansion is proceeding on schedule. 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, in two stages. Procurement of pipeline, execution of construction contracts and negotiation of rights-of-way are substantially complete for the first stage that will provide approximately 190,000 bpd of the capacity increase by early 2008. Pipeline construction for this stage is expected to commence in the fourth quarter this year. -- After receiving strong producer support, Enbridge Inc. filed a proposed agreement with the Federal Energy Regulatory Commission (FERC) in September with respect to its planned Southern Access Extension. The new pipeline would provide 400,000 bpd of crude oil transport capacity between the Partnership's future terminal at Flanagan, Illinois, and the pipe line hub at Patoka, Illinois, starting in early 2009. Enbridge is currently awaiting the FERC decision. -- The Partnership and Enbridge Inc. are in discussions with western Canadian producers regarding crude oil transportation infrastructure requirements beyond 2009. The Alberta Clipper project has emerged as a very cost-effective alternative and has significant industry support to proceed as either an expansion of the existing common carrier mainline system or as a contract pipeline. The proposed new pipeline between Hardisty, Alberta, and Superior, Wisconsin, would initially increase capacity by at least 400,000 bpd. The Partnership would undertake the U.S. portion of Alberta Clipper, together with addition of pumping power to the Southern Access pipeline to extend the additional capacity through to Flanagan, at an estimated cost of $750 million (in 2006 dollars, excluding capitalized interest). -- The $70 million expansion of the North Dakota System has commenced and the results of hydrostatic tests of existing pipelines to support the 30,000 bpd capacity increase have been favorable. The project is scheduled to be completed in the latter half of 2007. -- Construction is underway on projects totaling $53 million to add 3.3 million barrels of commercial crude oil storage at the Cushing, Oklahoma, terminal for service in late 2006. Additional projects totaling $66 million have commenced to add 2.2 million barrels of commercial storage by mid 2008 at three of the Partnership's terminals.
The Partnership is also developing a number of organic growth opportunities on its natural gas systems and significant recent developments include:
-- The $610 million East Texas System expansion and extension has been
under construction since January and is on schedule for completion
in three stages during 2007. The extension component of the project
involves a new 36-inch diameter 700 MMcfd pipeline to transport
growing natural gas production in East Texas to markets in
southeastern Texas and to interconnects with several interstate
pipelines. The expansion component of the project involves treating
facilities and connecting pipelines to support the new intrastate
pipeline. Final or near-final volume commitments and acreage
dedications for the new system currently exceed 550 MMcfd.
-- The $20 million North Texas Link commenced service in the third
quarter. The new service increases market optionality for up to
100,000 MMBtu/d of gas production from North Texas by providing
a link to the Partnership's East Texas transmission line.
-- A $74 million East Texas Treating and Processing project was
completed late in the third quarter, which included commercial
startup of the 120 MMcfd Henderson processing plant. Projects totaling
approximately $80 million are underway to add 125 MMcfd of processing
capacity for the Anadarko System and 35 MMcfd for the North Texas
System in the first quarter of 2007.
COMPARATIVE EARNINGS STATEMENT
(unaudited, dollars in millions except per unit amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2006 2005 2006 2005
--------- --------- --------- ---------
Operating revenue $ 1,532.3 $ 1,809.6 $ 4,845.6 $ 4,392.4
Operating expenses:
Cost of natural gas (1,265.9) (1,659.8) (4,099.2) (3,882.4)
Operating and
administrative (95.1) (82.4) (256.3) (237.2)
Power (27.8) (19.0) (78.3) (53.2)
Depreciation and
amortization (34.8) (36.5) (101.5) (103.9)
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Operating income 108.7 11.9 310.3 $ 115.7
Interest expense (28.5) (28.4) (84.0) (79.6)
Interest and
other income 2.0 2.1 7.4 3.4
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Net income (loss) $ 82.2 $ (14.4) $ 233.7 $ 39.5
Allocations to
General Partner (8.7) (5.1) (23.1) (16.9)
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Net income allocable
to Limited Partners $ 73.5 $ (19.5) $ 210.6 $ 22.6
Weighted average
units (millions) 71.7 62.1 67.8 61.5
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Net income per
unit (dollars) $ 1.03 $ (0.32) $ 3.11 $ 0.37
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Liquids - Comparing year-over-year Liquids segment results for the third quarter, operating income increased $16.7 million to $47.4 million. This was driven by a $23.1 million rise in operating revenue, which was mostly attributable to higher volumes on the Lakehead system. The increased volumes stemmed from growing oil sands production and from production restored at an oil sands facility that was out-of-service for the first nine months of 2005. An increase in average tariffs, primarily due to the annual index rate increase that became effective on July 1, 2006, contributed to higher revenues, as did longer hauls on the Lakehead system and higher fees on contract storage.
Power costs were $8.8 million higher due to increased volumes on the Lakehead system and, to a lesser extent, an increase in power rates. Deliveries for the three Liquids systems were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
(thousand barrels per day) 2006 2005 2006 2005
----- ----- ----- -----
Lakehead 1,450 1,290 1,480 1,318
Mid-Continent 244 259 247 225
North Dakota 89 84 90 87
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Total 1,783 1,633 1,817 1,630
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Natural Gas - Year-over-year third quarter results for the Natural Gas segment saw an increase of $10.1 million in adjusted operating income to $41.2 million (operating income is reconciled to adjusted operating income below):
Three Months Ended Nine Months Ended
September 30, September 30,
--------------- ---------------
(unaudited, dollars in millions) 2006 2005 2006 2005
------ ------ ------ ------
Operating income $ 43.0 $ 21.6 $118.9 $ 68.7
Noncash derivative fair
value losses (gains) (1.8) 9.5 0.1 22.6
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Adjusted operating income $ 41.2 $ 31.1 $119.0 $ 91.3
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On an adjusted basis, operating revenue less cost of natural gas increased $23.3 million, partially due to new processing capacity on the Anadarko system and improved gas processing margins. Also contributing to the increase was 16 percent growth in average daily volumes on the major natural gas systems. Strong drilling activity in the Anadarko Basin, East Texas Bossier trend and North Texas Barnett Shale continue to drive throughput growth on our natural gas systems.
Operating costs increased by $12.6 million over the third 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 Nine Months Ended
September 30, September 30,
-------------------- ---------------------
(MMBtu per day) 2006 2005 2006 2005
--------- --------- --------- ----------
East Texas 1,062,000 904,000 998,000 841,000
Anadarko 588,000 489,000 573,000 473,000
North Texas 302,000 267,000 288,000 264,000
South Texas -- 31,000 -- 34,000
UTOS 205,000 154,000 197,000 181,000
Midla 144,000 129,000 119,000 113,000
AlaTenn 32,000 42,000 40,000 59,000
KPC 19,000 8,000 31,000 29,000
Bamagas 162,000 110,000 94,000 44,000
Other Major Intrastates 158,000 164,000 156,000 197,000
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Major Systems Total 2,672,000 2,298,000 2,496,000 2,235,000
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Marketing - The Marketing segment reported an adjusted operating loss of $2.5 million in the third quarter, compared with adjusted operating income of $3.3 million in the third quarter of 2005 (operating income is reconciled to adjusted operating income below):
Three Months Ended Nine Months Ended
September 30, September 30,
-------------- ---------------
(unaudited, dollars in millions) 2006 2005 2006 2005
----- ------ ----- ------
Operating income $19.4 $(39.8) $45.0 $(41.5)
Noncash derivative fair
value (gains) losses(a) (21.9) 43.1 (53.2) 44.7
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Adjusted operating income (loss) $(2.5) $ 3.3 $(8.2) $ 3.2
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(a) Excludes $2.1 million in cash losses on financial instruments
recognized in second quarter 2005.
The results this quarter included a $6.6 million write-down of natural gas inventory which was partially offset by approximately $2.0 million of gains realized upon settlement of derivative financial instruments hedging our natural gas inventory. The write-down was precipitated by a sharp decline in natural gas prices, which resulted in the market value of natural gas in storage being less than its recorded value using the weighted average price of gas purchases. Accordingly, we reduced the value of our inventory to market. Since future sales are hedged, the majority of this loss is expected to be recovered when the natural gas inventory is sold in the future.
Partnership Financing - Comparing third quarter 2006 with the same quarter in 2005, interest expense increased by $0.1 million, to $28.5 million. Debt balances and interest rates were higher than one year ago; however, this was offset by $2.3 million of interest capitalized to construction projects during the quarter compared with $0.2 million in the year-ago quarter. Weighted average units outstanding for the third quarter increased to 71.7 from 62.1 million units, due to additional partners' capital raised for acquisitions and expansions over the past year, including a private issuance of approximately 10.9 million Class C units in mid August.
ENBRIDGE ENERGY MANAGEMENT DISTRIBUTION
Enbridge Energy Management, L.L.C. (NYSE:EEQ) declared a distribution of $0.925 per share payable November 14, 2006 to shareholders of record on November 6, 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 November 2, 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 Monday, October 30, 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/IC/CEPage.asp?ID=109912
The audio portion of the presentation will be accessible by telephone at (877) 407-0782 and can be replayed until November 13, 2006 by calling (877) 660-6853 and entering Conference Account 286, ID 216461. 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."
(unaudited, dollars in millions except per unit amounts)
Three Months Ended Nine Months Ended
September 30, September 30,
----------------- -----------------
2006 2005 2006 2005
------- ------- ------- -------
Net income (loss) $ 82.2 $ (14.4) $ 233.7 $ 39.5
Noncash derivative fair value
(gains) losses
-Natural Gas (1.8) 9.5 0.1 22.6
-Marketing(a) (21.9) 43.1 (53.2) 44.7
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Adjusted net income 58.5 38.2 180.6 106.8
Allocations to General Partner (8.2) (6.1) (22.0) (18.2)
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Adjusted net income allocable
to Limited Partners 50.3 32.1 158.6 88.6
Weighted average units
(millions) 71.7 62.1 67.8 61.5
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Adjusted net income per
unit (dollars) $ 0.70 $ 0.52 $ 2.34 $ 1.44
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(a) Excludes $2.1 million in cash losses on financial instruments
recognized in second quarter 2005.
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.
(unaudited, dollars in millions)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2006 2005 2006 2005
-------- -------- -------- --------
Net cash provided by
operating activities $ 62.9 $ 84.5 $ 229.9 $ 208.2
Changes in operating
assets and liabilities,
net of cash acquired 34.5 (9.6) 57.3 4.5
Interest expense 28.5 28.4 84.0 79.6
Other(a) (4.1) (0.2) (5.1) (2.0)
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Adjusted EBITDA $ 121.8 $ 103.1 $ 366.1 $ 290.3
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(a) Includes $2.1 million in cash losses on financial instruments
recognized in second quarter 2005.
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) Enbridge Partners' ability to successfully complete and finance its capital expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (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) hazards and operating risks that may not be covered fully by insurance; (6) changes in or challenges to Enbridge Partners' tariff rates; (7) changes in laws or regulations to which Enbridge Partners is subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance.
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 sole asset is an approximate 16 percent interest in the Partnership. Enbridge Energy Company, Inc., an indirect wholly owned subsidiary of Enbridge Inc. of Calgary, Alberta, (NYSE:ENB) (TSX:ENB) (www.enbridge.com) is the general partner and holds an approximate 17 percent effective interest in the Partnership.