UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x                              QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

OR

o                                 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                   

Commission file number 1-10934

ENBRIDGE ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

1100 Louisiana
Suite 3300
Houston, TX 77002

(Address of principal executive offices and zip code)

(713) 821-2000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Large Accelerated Filer x Accelerated Filer o Non-Accelerated Filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No x

The Registrant had 55,238,834 Class A common units outstanding as of July 30, 2007.

ENBRIDGE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

 

In this report, unless the context requires otherwise, references to “we”, “us”, “our”, or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. This Quarterly Report on Form 10-Q contains forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “strategy,” “could,” “would,” or “will” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. 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 our ability to control or predict. For additional discussion of risks, uncertainties and assumptions, see “Risk Factors” included in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 and in Part II, Item 1A of our quarterly reports on Form 10-Q.

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PART I—FINANCIAL INFORMATION

Item 1.                        Financial Statements

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

 

The accompanying notes are an integral part of these consolidated financial statements.

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

The accompanying notes are an integral part of these consolidated financial statements.

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

The accompanying notes are an integral part of these consolidated financial statements.

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

The accompanying notes are an integral part of these consolidated financial statements.

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ENBRIDGE ENERGY PARTNERS, L.P.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1.                 BASIS OF PRESENTATION

We have prepared the accompanying unaudited interim consolidated financial statements in accordance with accounting principles generally accepted in the United States of America for interim consolidated 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 our financial position at June 30, 2007 and December 31, 2006; our results of operations and comprehensive income for the three and six month periods ended June 30, 2007 and 2006; and our cash flows for the six month periods ended June 30, 2007 and 2006. We derived the Consolidated Statement of Financial Position as of December 31, 2006, from the audited financial statements included in our 2006 Annual Report on Form 10-K.

The results of operations for the three and six month periods ended June 30, 2007, 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, timing and completion of our construction projects, maintenance activities and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting. Our consolidated statements of cash flows for the period ended June 30, 2006 include reclassifications that were made to present changes in environmental liabilities separately from changes in Accounts payable and other, consistent with our current period presentation. Additionally, we reclassified $6.4 million from “Other assets, net” to “Intangibles, net” in our December 31, 2006 consolidated statement of financial position related to rights we received for contributions we made in aid of construction projects, consistent with our current period presentation. These reclassifications have no effect on previously reported results of operations, comprehensive income or partners’ capital. Our interim consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

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2.                 NET INCOME PER LIMITED PARTNER UNIT

Net income per limited partner 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 our limited partner 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 its 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. We have no dilutive securities. Net income per limited partner unit was determined as follows:

 

3.                 CASH AND CASH EQUIVALENTS

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have issued check payments that have not yet been presented to the financial institution of approximately $31.8 million at June 30, 2007 and $46.9 million at December 31, 2006, are included in Accounts payable and other on the Consolidated Statements of Financial Position.

4.                 INVENTORY

Inventory is comprised of the following:

 

Our inventory at June 30, 2007 is net of charges of $1.5 million we recorded to reduce the cost basis of our natural gas and natural gas liquids, or NGLs, inventory to reflect market value. The lower of cost or market adjustments are included in Cost of natural gas on our Consolidated Statements of Income.

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5.                 PROPERTY, PLANT AND EQUIPMENT

Property, Plant and Equipment is comprised of the following:

 

6.                 INCOME TAXES

We are not a taxable entity for U.S. federal income tax purposes, or for the majority of states that impose income tax. These taxes on our net income are generally borne by our unitholders through the allocation of taxable income. In May 2006, the State of Texas enacted substantial changes to its tax structure to impose a new tax based on modified gross margin, which began in 2007. Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, we have determined that this tax is an income tax. Our income tax expense is $1.3 million  and $2.4 million for the three and six month periods ended June 30, 2007, which we computed by applying a 0.56% apportioned state income tax rate to taxable margin, as defined in the State of Texas statutes. At June 30, 2007 we have included a current income tax payable of $2.4 million in Property and other taxes payable and a deferred income tax asset of $0.4 million in Other assets, net on our Consolidated Statements of Financial Position.

7.                 DEBT

Credit Facility

At June 30, 2007 and December 31, 2006, we had no amounts outstanding under our Credit Facility and had letters of credit totaling $90.0 million and $59.3 million, respectively. The amounts we may borrow under the terms of our Credit Facility are reduced by the principal amount of our commercial paper issuances and the balance of our letters of credit outstanding. At June 30, 2007, we could borrow $765.0 million under the terms of our Credit Facility without consideration to additional borrowings under our commercial paper program.

On April 4, 2007 we entered into the Second Amended and Restated Credit Agreement (Credit Facility) which among other things: (i) increases the maximum principal amount of credit available to us at any one time from $1 billion to $1.25 billion; (ii) gives us the right to request increases in the maximum principal amount of credit available at any one time from $1.25 billion to $1.5 billion; (iii) eliminates the sublimit on letters of credit; (iv) provides for a five-year facility that matures April 4, 2012 and grants us the option to request annual extensions of maturity and a one-year term out period upon maturity; (v) modifies our leverage ratio to include in the calculations of EBITDA (as defined in the Second Amended and Restated Credit Agreement) pro forma adjustments for material projects and to exclude from the calculation of Consolidated Funded Debt (as defined in the Second Amended and Restated Credit Agreement) certain amounts of preferred securities and subordinated debt that we or our

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designated subsidiaries may issue in the future; and (vi) eliminates our coverage ratio financial covenant. Our Credit Facility continues to support our commercial paper program.

Commercial Paper Program

Under the terms of our commercial paper program, we can issue up to $600 million of commercial paper. At June 30, 2007, we had outstanding $393.3 million of commercial paper, net of unamortized discount of $1.7 million, bearing interest at a weighted average rate of 5.48%. At December 31, 2006, we had $443.7 million of commercial paper outstanding, net of $1.3 million of unamortized discount, at a weighted average interest rate of 5.45%. At June 30, 2007, we could issue an additional $205.0 million in principal amount under the terms of our commercial paper program.

8.                 PARTNERS’ CAPITAL

The following table sets forth the distributions, as approved by the Board of Directors of Enbridge Energy Management, L.L.C. (“Enbridge Management”) during the six months ended June 30, 2007:

(1)            During 2007, in lieu of cash distributions, the Partnership issued 433,926 i-units to Enbridge Management.

(2)            During 2007, in lieu of cash distributions, the Partnership issued 458,503 Class C units to our Class C unitholders.

(3)            The Partnership retains an amount equal to two percent of the i-unit and Class C unit distribution from the General Partner in respect of its two percent general partner interest.

Issuance of Class A common units

In May 2007, we issued 5.3 million Class A common units at a price of $58.00 per unit, for proceeds of approximately $301.9 million, net of underwriters’ discounts, commissions and issuance costs. In addition, our general partner contributed approximately $6.1 million to us to maintain its two percent general partner interest. We used the proceeds from this offering partially to reduce outstanding commercial paper we previously issued to finance a portion of our capital expansion projects. We invested the remaining amount in short-term commercial paper for use in future periods to fund additional expenditures under our capital expansion projects.

Private Placement of Class C Units

In April 2007, we issued and sold 4.7 million Class C units at a price of $53.11 per Class C unit to CDP Infrastructure Fund G.P. (“CDP”), 0.9 million Class C units to Tortoise Infrastructure Corporation and 0.3 million Class C units to Tortoise Energy Capital Corporation.  We sold the Class C units in a private transaction exempt from registration under Section 4(2) of the Securities Act. We received proceeds of approximately $314.4 million, net of expenses associated with the private placement. In addition, our general partner contributed approximately $6.4 million to us to maintain its two percent general partner interest. We used the proceeds from this offering partially to reduce outstanding commercial paper we previously issued to finance a portion of our capital expansion program, including the East Texas and Southern Access expansion projects.

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9.                 COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to the gathering, transportation, storage and processing of liquid hydrocarbon and natural gas products and we could, at times, be subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.

As of June 30, 2007 and December 31, 2006, we have recorded $2.7 million and $4.1 million, respectively, in current liabilities and $3.7 million and $3.3 million, respectively, in long-term liabilities, primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, and outstanding air quality measures for certain of our liquids and natural gas assets.

In January 2007, we detected a leak on Line 14 of our Lakehead system, near the Owen, Wisconsin pump station. We immediately shut the pipeline down and dispatched emergency response crews to oversee containment, cleanup and repair of the pipeline. We spent approximately $0.9 million to recover the barrels released, complete excavation, clean-up and repairs to return the line to service. We have applied pressure restrictions to the line as we work with federal and state environmental and pipeline safety regulators to investigate the cause of the rupture. Such pressure restrictions have not materially affected throughput on the system. We have the potential of incurring additional expenditures to remediate any condition on the line that is determined to have caused the rupture.

In February 2007, a contractor undertaking work in Rusk County, Wisconsin on the Enbridge Southern Lights project punctured the adjacent Line 14 pipeline, resulting in a release of crude oil estimated at 3,000 barrels.  As the spill was largely contained within the ditch used for construction, environmental impact was minimized.   Impact to customers was also minimized as the line was repaired and returned to service in less than two days. We continue investigating this incident and have spent approximately $1.4 million of the estimated $2.6 million associated with the repair and cleanup, which we recorded as a liability and a receivable, since we will recover these cost from the parties responsible for the damage. Any further exposure or impact related to this incident is not believed to be material.

Legal Proceedings

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We believe that the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition.

10.          DERIVATIVE FINANCIAL INSTRUMENTS—COMMODITY PRICE RISK

Our net income and cash flows are subject to volatility stemming from changes in commodity prices of natural gas, NGLs, condensate and fractionation margins (the relative price differential between NGL sales and the offsetting natural gas purchases).  Our exposure to commodity price risk exists within our Natural Gas and Marketing segments.  To mitigate the volatility of our cash flows, we use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices.  Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

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Accounting Treatment 

All derivative financial instruments are recorded in the consolidated financial statements at fair market value and are adjusted each period for changes in the fair market value (“mark-to-market”).  The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay or receive, other than in a forced or liquidation sale, to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts.  We use actively traded external market quotes and indices to value substantially all of the derivative financial instruments we utilize.

Under the guidance of SFAS No. 133, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is adjusted to its fair market value, or marked-to-market, each period with the increases and decreases in fair value recorded in our Consolidated Statements of Income as increases and decreases in Cost of natural gas for our commodity-based derivatives.  Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract.  Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

If a derivative financial instrument qualifies and is designated as a cash flow hedge, a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in Accumulated other comprehensive income (“AOCI”), a component of Partners’ Capital, until the underlying hedged transaction occurs.  To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement.  At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items.  Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings.  Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in Cost of natural gas in the period the hedged transaction occurs.  Gains and losses deferred in AOCI related to cash flow hedges, for which hedge accounting has been discontinued, remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period, or within an additional two-month period of time thereafter.  Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible, to mitigate the non-cash earnings volatility that arises under mark-to-market accounting treatment.  To qualify for cash flow hedge accounting as set forth in SFAS No. 133, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Non-Qualified Hedges

Many of our derivative financial instruments qualify for hedge accounting treatment under the specific requirements of SFAS No. 133.  As discussed in Note 15 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006, we have four transaction types where the hedge structure does not meet the requirements to permit application of hedge accounting and are referred to as “non-qualified.”  Non-qualified derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in Cost of natural gas in our Consolidated Statements of Income.  These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices.  The cash flow impact occurs when the underlying physical transaction takes place in the future and when the associated financial instrument contract settlement is made.

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The following table presents the mark-to-market gains and losses associated with changes in the fair value of our commodity price derivative financial instruments, which are recorded as an element of Cost of natural gas in our Consolidated Statements of Income and disclosed as a reconciling item on our Statements of Cash Flows:

 

We record the change in fair value of our cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified from AOCI to earnings. Also included in AOCI are unrecognized losses of approximately $3.4 million associated with cash flow hedges that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. For the three and six month periods ended June 30, 2007, we reclassified losses of $21.0 million and $37.2 million, respectively, from AOCI to Cost of natural gas on our Consolidated Statements of Income for the fair value of derivative financial instruments that were settled.  For the three and six month periods ended June 30, 2006, we reclassified losses of $14.9 million and $39.7 million, respectively, from AOCI to Cost of natural gas on our Consolidated Statements of Income for the fair value of derivative financial instruments that were settled.

Derivative Positions

Our derivative financial instruments are included at their fair values in the Consolidated Statements of Financial Position as follows:

 

The increase in our obligation associated with derivative activities is primarily due to the increase in forward natural gas prices from December 31, 2006 to June 30, 2007. The Partnership’s portfolio of derivative financial instruments is largely comprised of long-term fixed price natural gas sales and purchase agreements.

We do not require collateral or other security from the counterparties to our derivative financial instruments, all of which were rated “BBB+” or better by the major credit rating agencies.

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11.          SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker in deciding how resources are allocated and performance is assessed.

Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We have segregated our business activities into three distinct operating segments:

·       Liquids;

·       Natural Gas; and

·       Marketing.

The following tables present financial information about our business segments:

(1)                Corporate consists of interest expense, interest income and certain other costs such as franchise and income taxes, which are not allocated to our business segments.

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(1)                Corporate consists of interest expense, interest income and certain other costs such as franchise and income taxes, which are not allocated to our business segments.

(1)                Corporate consists of interest expense, interest income and certain other costs such as franchise and income taxes, which are not allocated to our business segments.

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(1)                Corporate consists of interest expense, interest income and certain other costs such as franchise and income taxes, which are not allocated to our business segments.

12.          SUBSEQUENT EVENT

Distribution to Partners

On July 27, 2007, the Board of Directors of Enbridge Management declared a distribution payable to our partners on August 14, 2007. The distribution will be paid to unitholders of record as of August 6, 2007, of our available cash of $92.6 million at June 30, 2007, or $0.925 per common unit. Of this distribution, $63.7 million will be paid in cash, $12.1 million will be distributed in i-units to our i-unitholder, $16.2 million will be distributed in Class C units to the holders of our Class C units and $0.6 million will be retained from the General Partner in respect of the i-unit and Class C unit distributions.

13.          RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In February 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 159, The Fair Value Option for Financial Assets and Liabilities. This statement provides companies with an option to report certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to reduce the volatility in earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The provisions of SFAS No. 159 are effective at the beginning of our first fiscal year that begins after November 15, 2007 as we have elected not to early adopt the provisions of SFAS No. 159. We do not expect our adoption of SFAS No. 159 to have a material affect on our Consolidated Financial Statements.

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