Enterprise Products Partners L.P. 10-Q 2005
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005 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: 1-14323
ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of Registrant as specified in its Charter)
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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
YES x NO o
There were 383,265,385 unrestricted common units of Enterprise Products Partners L.P. outstanding at May 4, 2005. Enterprise Products Partners L.P.s common units trade on the New York Stock Exchange under the symbol EPD.
ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION.
ITEM 1. FINANCIAL STATEMENTS.
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
See Notes to Unaudited Condensed Consolidated Financial Statements
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS
AND COMPREHENSIVE INCOME
(Dollars in thousands, except per unit amounts)
See Notes to Unaudited Condensed Consolidated Financial Statements
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)
See Notes to Unaudited Condensed Consolidated Financial Statements
ENTERPRISE PRODUCTS PARTNERS L.P.
UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS EQUITY
(See Note 9 for Unit History and Detail of Changes in Limited Partners Equity)
(Dollars in thousands)
See Notes to Unaudited Condensed Consolidated Financial Statements
ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Enterprise Products Partners L.P., including its consolidated subsidiaries, is a publicly traded Delaware limited partnership listed on the NYSE under the ticker symbol EPD. Unless the context requires otherwise, references to we, us, our, the Company or Enterprise are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. Certain abbreviated names, acronyms and other capitalized and industry terms are defined within the glossary following the Table of Contents of our Annual Report on Form 10-K for the year ended December 31, 2004. This glossary is incorporated by reference herein and is filed as Exhibit 99.1 to this quarterly report on Form 10-Q.
We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating L.P. (our Operating Partnership). We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as Enterprise GP). We and Enterprise GP are affiliates of EPCO, Inc. (EPCO).
In the opinion of Enterprise, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. These unaudited financial statements should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2004 (Commission File No. 1-14323).
Essentially all of our assets, liabilities, revenues and expenses are recorded at the Operating Partnership level in our consolidated financial statements. We act as guarantor of certain of our Operating Partnerships debt obligations. See Note 15 for condensed consolidated financial information of our Operating Partnership.
The results of operations for the three months ended March 31, 2005 are not necessarily indicative of results expected for the full year.
Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
Certain reclassifications have been made to the prior years financial statements to conform to the current year presentation. In accordance with SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, we have reclassified amounts related to our adoption of EITF 03-16, Accounting for Investments in Limited Liability Companies, on July 1, 2004. Our adoption of EITF 03-16 on that date required us to change our method of accounting for our 13.1% investment in VESCO to the equity method from the cost method. Since this change in accounting principle was made during the third quarter of 2004, our statement of consolidated operations and statement of consolidated cash flows for the first quarter of 2004 has been recast for comparability purposes.
The cumulative effect of changes in accounting principles represents the combined impact of changing (i) the method our BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (ii) the method we used to account for our investment in VESCO.
In accordance with GAAP, we use estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Our actual results could differ from these estimates.
Our unit option plan accounting is based on the intrinsic-value method described in APB No. 25, Accounting for Stock Issued to Employees. Under this method, no compensation expense is recorded related to options granted when the exercise price is equal to or greater than the market price of the underlying equity on the date of grant. In accordance with SFAS No. 148, Accounting for Stock-Based Compensation Transition and Disclosure, we disclose the pro forma effect on our earnings as if the fair-value method of SFAS No. 123, Accounting for Stock-Based Compensation had been used instead of the intrinsic-value method of APB No. 25. The effects of applying SFAS No. 123 in the following pro forma disclosure may not be indicative of future amounts as additional awards in future years are anticipated. The following table shows the pro forma effects for the periods indicated.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model and various assumptions. For those options granted during 2005, we used the following assumptions to develop our Black-Scholes model estimates: (i) expected life of options of 7 years; (ii) risk-free interest rate of 3.9%, (iii) expected dividend yield of 9.48% and (iv) expected unit price volatility of 28%.
2. RECENTLY ISSUED ACCOUNTING STANDARDS
SFAS No. 123(R), Share-Based Payment. This accounting guidance, which is applicable for public companies the first fiscal year beginning on or after June 15, 2005, replaces SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB No. 25, Accounting for Stock Issued to Employees. This Statement eliminates the ability to account for share-based compensation transactions using APB No. 25, and generally requires instead that such transactions be accounted for using a fair-value-based method. We are continuing to evaluate the provisions of SFAS No. 123(R) and will adopt the standard on January 1, 2006. Upon the required effective date, we will apply this statement using a modified version of prospective application as described in the standard.
On March 29, 2005, the SEC issued Staff Accounting Bulletin ("SAB") 107 to provide public companies additional guidance in applying the provisions of SFAS No. 123(R). Among other things, SAB 107 describes the SEC staffs expectations in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123(R) with certain existing SEC guidance. The guidance is also beneficial to users of financial statements in analyzing the information provided under SFAS No. 123(R). We will apply the provisions of SAB 107 upon the adoption of SFAS No. 123(R).
FIN 46(R)-5, Implicit Variable Interests Under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities. On March 3, 2005, the FASB issued this guidance to address whether a reporting enterprise has an implicit variable interest in a variable interest entity or potential variable interest entity when specific conditions exist. FIN 46(R)-5 covers issues that commonly arise in leasing arrangements among related parties, as well as other types of arrangements involving both related and unrelated parties. Implicit variable interests are implied financial interests in an entitys net assets exclusive of variable interests. An implicit variable interest acts the same as in an explicit variable interest except it involves the absorbing and (or) receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. This guidance is effective for our fiscal quarter ending June 30, 2005. We are continuing to evaluate the provisions of FIN 46(R)-5, which may affect certain non-material leases of office space from a related party.
FIN 47, Accounting for Conditional Asset Retirement Obligations. Under SFAS No. 143, Accounting for Asset Retirement Obligations, a company must record a liability for its legal obligations resulting from the eventual retirement of its tangible long-lived assets, whether that obligation results from the acquisition, construction, or development of the asset. However, many companies have not recorded a liability, concluding that either (1) the conditional nature of the obligation does not create a liability until the retirement activity occurs or (2) the timing and/or the method of settling the obligation is unknown. FIN 47 concludes otherwise. If required legally, an obligation associated with the assets retirement is inevitable even though uncertainties exist about the timing and/or method of settling the obligation. According to FIN 47, these uncertainties affect the fair value of the liability, rather than prevent the need to record one at all. Additionally, the ability of a company to postpone indefinitely the settlement of the obligation, or to sell the asset prior to its retirement, does not relieve a company of its present duty to settle the obligation. We are currently studying the effects of FIN 47 on our accounting policy for asset retirement obligations. We will adopt FIN 47 in December 2005.
3. BUSINESS COMBINATIONS
Indian Springs acquisition in January 2005. In January 2005, we paid El Paso $74.5 million for their membership interests in Teco Gas Gathering, LLC and Teco Gas Processing, LLC. As a result of this acquisition, we indirectly own an 80% equity interest in the 89-mile Indian Springs Gathering System and a 75% equity interest in the Indian Springs natural gas processing facility, both of which are located in East Texas. The Indian Springs processing facility has capacity to process up to 120 MMcf/d of natural gas and there is an idle 20 MMcf/d production train available for restart to support increases in natural gas volumes. The natural gas processed at the Indian Springs processing facility is sourced from the Indian Springs Gathering System, as well as our nearby Big Thicket Gathering System.
Acquisition of additional interests in Dixie in January and February 2005. We purchased an approximate 20% interest in Dixie from an affiliate of ConocoPhillips in January 2005 for $31 million and an approximate 26% interest in Dixie from an affiliate of ChevronTexaco in February 2005 for $40 million. As a result of these acquisitions, our ownership interest in Dixie increased to approximately 66% and Dixie became a consolidated subsidiary of ours in February 2005. Dixie owns and operates the 1,301-mile Dixie Pipeline, which transports propane from supply areas in Texas, Louisiana and Mississippi to markets throughout the southeastern United States. The Dixie Pipeline is regulated by the FERC and transports an average of approximately 100 MBPD of propane.
GulfTerra Merger purchase price and purchase price allocation adjustments. During the first quarter of 2005, we made purchase price adjustments related to the GulfTerra Merger, and we revised our preliminary purchase price allocation related to the GulfTerra Merger. The purchase price adjustments of $6.5 million were primarily attributable to merger-related financial advisory services and involuntary severance costs, both of which were attributable to the GulfTerra Merger.
The GulfTerra Merger was completed on September 30, 2004, when GulfTerra merged with a wholly owned subsidiary of Enterprise. The aggregate value of total consideration Enterprise paid or issued to complete the GulfTerra Merger was approximately $4 billion. Our purchase price allocations related to the GulfTerra Merger remain preliminary and could change due to the refinement of our estimates.
Allocation of purchase price for 2005 business combinations and
The acquisitions and post-closing purchase price adjustments described previously were accounted for under the purchase method of accounting and, accordingly, the cost of each has been allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows:
The purchase price allocations shown in the preceding table for the recent Indian Springs and Dixie business combinations are preliminary. Enterprise has engaged an independent third-party business valuation expert to assess the fair values of the tangible and intangible assets of these entities. This information will assist management in the development of definitive allocations of the overall purchase prices for these transactions.
Our regular trade (or working) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale or used in the provision of services. The forward sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of forward-sales contracts. Both inventories are valued at the lower of average cost or market.
Costs and expenses, as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income, includes cost of sales related to inventories. For the three months ended March 31, 2005 and 2004, such consolidated cost of sales amounts were $2.1 billion and $1.5 billion, respectively.
Due to fluctuating prices in the NGL, natural gas and petrochemical industry, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceed their net realizable value. These non-cash adjustments are charged to cost of sales within operating costs and expenses in the period they are recognized. For the three months ended March 31, 2005 and 2004, we recognized $9.6 million and $4.2 million, respectively, of such adjustments.
5. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:
Depreciation expense for the three months ended March 31, 2005 and 2004 was $78.9 million and $26.8 million, respectively. Capitalized interest on our construction projects for the three months ended March 31, 2005 and 2004 was $4.4 million and $0.3 million, respectively.
6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
We own interests in a number of related businesses that are accounted for using the equity method. Our investments in and advances to our unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of our business segments, see Note 13. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated.
In connection with obtaining regulatory approval for the GulfTerra Merger, we were required by the FTC to sell our ownership interest in Starfish by March 31, 2005. The $36.6 million carrying value of this investment was classified as "Assets held for sale" on our balance sheet at December 31, 2004. On March 31, 2005, we sold this asset to a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.
On occasion, the price we pay to acquire an investment exceeds the carrying value of the underlying historical net assets (i.e., the underlying equity account balances on the books of the investee) that we purchase. These excess cost amounts are a component of our investments in and advances to unconsolidated affiliates. At March 31, 2005, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. At March 31, 2005, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $49.7 million, which was attributed to tangible assets. Amortization of our excess cost amounts attributed to tangible assets was $0.7 million and $0.5 million during the three months ended March 31, 2005 and 2004, respectively.
The following table shows our equity in income of unconsolidated affiliates by business segment for the periods indicated:
Summarized financial information of unconsolidated affiliates
The following table presents unaudited income statement data for our unconsolidated affiliates, aggregated by business segment, for the periods indicated (on a 100% basis).
7. INTANGIBLE ASSETS AND GOODWILL
The following table summarizes our intangible assets (which primarily consist of contracts and customer relationships) at the dates indicated by segment:
The following table shows amortization expense associated with our intangible assets for the periods indicated by segment:
For the remainder of 2005, amortization expense associated with these intangible assets is currently estimated at $63.9 million.
The following table summarizes our goodwill amounts by segment at the dates indicated. Of the $456.7 million of goodwill we have recorded at March 31, 2005, $374.3 million relates to goodwill we recorded in connection with the GulfTerra Merger.
8. RELATED PARTY TRANSACTIONS
Historically, Shell was considered a related party because it owned more than 10% of our limited partner interests and, prior to September 2003, it owned a 30% ownership interest in Enterprise GP. As a result of Shell selling a portion of its limited partner interests in us to a third party in December 2004 and March 2005, Shell now owns less than 10% of our common units. Shell sold its 30% interest in Enterprise GP to an affiliate of EPCO in September 2003. As a result of Shell's reduced equity interest in us and its lack of control of Enterprise, Shell ceased to be considered a related party beginning in the first quarter of 2005.
Relationship with EPCO. We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise GP, our general partner. In addition, the executive and other officers of Enterprise GP are employees of EPCO, including Robert G. Phillips who is President and Chief Executive Officer and a director of Enterprise GP. The principal business activity of Enterprise GP is to act as our managing partner.
Collectively, EPCO and its affiliates owned a 38.6% equity interest in Enterprise at March 31, 2005, which includes their ownership interest in Enterprise GP. In January 2005, an affiliate of EPCO acquired El Pasos 9.9% membership interest in Enterprise GP and 13,454,498 of our common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and affiliates own 100% of the membership interests of our general partner and El Paso no longer owns an interest in us or Enterprise GP.
We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees. We also have entered into an agreement with EPCO to provide trucking services for us for the transportation of NGLs and other products. In addition, we also buy from and sell to EPCO's Canadian affiliate certain NGL products.
We and Enterprise GP are both separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. Historically, EPCO depended on cash distributions it received as an equity owner in us to fund most of its other operations and to meet its debt obligations. For the three months ended March 31, 2005 and 2004, EPCO affiliates received $46.8 million and $43.4 million in distributions from us, respectively.
Relationship with TEPPCO. On February 24, 2005, an affiliate of EPCO acquired Texas Eastern Products Pipeline Company, LLC ("TEPPCO GP"), the general partner of TEPPCO Partners, L.P. (TEPPCO), and 2,500,000 common units of TEPPCO from Duke Energy Field Services, LLC ("Duke Energy") for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of
TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP and Dr. Ralph Cunningham (a former independent director of Enterprise GP) was named Chairman of TEPPCO GP. Due to EPCO's actions to reconstitute the board of directors of TEPPCO GP and TEPPCO GP's ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO and EPD during the first quarter of 2005.
On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to EPCOs legal advisor that it was conducting a non-public investigation to determine whether EPCOs acquisition of TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCOs purchase of TEPPCO GP. EPCO and its affiliates, including us, may receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, we may be required to divest certain assets. In the event we are required to divest significant assets, our financial condition could be affected.
Relationship with unconsolidated affiliates. Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie (prior to its consolidation with our results beginning in February 2005, see Note 3) and the purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix and process natural gas at VESCO.
9. CAPITAL STRUCTURE
Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Fourth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the Partnership Agreement). Our common units trade on the NYSE under the ticker symbol EPD. We are managed by our general partner, Enterprise GP.
Capital accounts, under the Partnership Agreement, are maintained for our general partner and our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.
Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and general partner will receive. The Partnership Agreement also contains provisions for the allocation of net earnings and losses to our limited partners and general partner. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests. Normal income and loss allocations according to percentage interests are done only after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated 100% to our general partner.
March 2005 universal shelf registration statement. In March 2005, we filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, we also registered for resale 35,368,522 common units currently owned by Shell and 5,631,478 common units that had been sold by Shell to Kayne Anderson MLP Investment Company ("Kayne Anderson") in December 2004 and March 2005. We are obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999.
Equity offerings. Our Partnership Agreement generally authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by Enterprise GP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders). The following table reflects the number of common units issued and the net proceeds received from each public offering from January 1, 2005 through March 31, 2005:
Restricted units. At March 31, 2005, we had 501,417 restricted units outstanding. In February 2005, EPCO issued 12,892 time-vested restricted units to key management personnel of EPCO (who work on our behalf) as a means of retaining and compensating them for long-term performance and to increase their ownership interest in Enterprise. The fair value of the restricted units issued in February 2005 at grant date was $0.3 million.
The total unamortized deferred compensation balance at March 31, 2005 for our restricted units outstanding was $10.3 million. We reclassified $0.8 million of such compensation expense to earnings during the three months ended March 31, 2005, which is reflected as a component of general and administrative expenses. Deferred compensation is reflected as a reduction of partners' equity and allocated to our partners in accordance with their respective ownership interests.
Changes in limited partners' equity. The following table details the changes in limited partners' equity since December 31, 2004:
Distributions. As an incentive, Enterprise GPs percentage interest in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. Enterprise GPs quarterly incentive distribution thresholds are as follows:
On April 15, 2005, the Board of Directors of Enterprise GP announced that our quarterly distribution rate with respect to the first quarter of 2005 would be $0.41 per common unit, or $1.64 on an annualized basis. This distribution will be paid on May 10, 2005, to unitholders of record at the close of business on April 29, 2005.
Unit history. The following table details the outstanding balance of each class of units for the periods and at the dates indicated:
Accumulated other comprehensive income. The following table summarizes the effect of our cash flow hedging financial instruments (see Note 12) on accumulated other comprehensive income since December 31, 2004.
During the remainder of 2005, we will reclassify a combined $3.1 million from accumulated other comprehensive income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps. In addition, we reclassified an approximate $1.4 million gain into income from accumulated other comprehensive income related to a commodity cash flow hedge acquired in the GulfTerra Merger. This gain is primarily due to an increase in fair value from that recorded for the commodity cash flow hedge at September 30, 2004.
10. DEBT OBLIGATIONS
Parent-Subsidiary guarantor relationships. We act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Seminole Notes, Dixie commercial paper obligations and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 88.4% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).
Senior Notes E, F, G and H. In September 2004, our Operating Partnership priced a private offering of an aggregate of $2 billion in principal amount of senior unsecured notes in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended, and in October 2004, these notes were issued. On January 24, 2005, we filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms. The exchange of notes was completed in March 2005.
Senior Notes I and J. On February 15, 2005, our Operating Partnership sold $500 million in principal amount of senior notes in a Rule 144A private placement offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes ("Senior Notes I") were issued at 99.379% of their principal amount and have annual fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes ("Senior Note J") were issued at 98.691% of their principal amount and have annual fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A which was due on March 15, 2005, and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility.
These fixed-rate notes are unsecured obligations of our Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnerships borrowings under these notes are non-recourse to Enterprise GP. We have guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.
Dixie short-term commercial paper debt obligations. Dixie has short-term commercial paper obligations that are supported by a $28 million senior unsecured revolving credit facility. The credit facility primarily serves as a backup to the Dixie commercial paper program and may also be used for general corporate purposes. At March 31, 2005, Dixie had an aggregate of $14 million in commercial paper debt obligations outstanding and none under its senior unsecured revolving credit facility. The senior unsecured revolving credit facility contains certain restrictive covenants, which Dixie was in compliance with at March 31, 2005. Both the Dixie commercial paper program and the senior unsecured revolving credit facility are non-recourse to Enterprise.
Covenants. We are in compliance with the various covenants of our debt agreements at March 31, 2005 and December 31, 2004.
Information regarding variable interest rates paid. The following table shows the range of interest rates paid and weighted-average interest rate paid on our significant consolidated variable-rate debt obligations during the three months ended March 31, 2005.
Consolidated debt maturity table. The following table shows scheduled maturities of the principal amounts of our debt obligations for the next 5 years and in total thereafter.
Joint venture debt obligations. We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at March 31, 2005, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at March 31, 2005, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt.
In accordance with terms of its credit agreement, Deepwater Gateway had the right to repay the principal amount plus any accrued interest due under its term loan at any time without penalty. During the first quarter of 2005, Deepwater Gateway exercised this right and extinguished its term loan. We and our 50% joint venture partner in Deepwater Gateway, Cal Dive, made equal cash contributions of $72 million to Deepwater Gateway to fund the repayment of the $144 million in principal amount owed under Deepwater Gateway's term loan.
11. SUPPLEMENTAL CASH FLOWS DISCLOSURE
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of the capital expenditures associated with such projects. As a result of completing the GulfTerra Merger, the number of such arrangements has increased, particularly for projects involving pipeline construction and production well tie-ins. These reimbursements for the three months ended March 31, 2005 and 2004, were $8.9 million and $0.2 million, respectively, and are reflected as a source of investing cash inflows under the caption "Contributions in aid of construction costs" on our Unaudited Condensed Statements of Consolidated Cash Flows.
Net income for the first quarter of 2005 includes a gain on the sale of assets of $5.4 million (recorded as a reduction in operating costs and expenses), which is primarily related to the sale of our 50% interest in Starfish. In connection with gaining regulatory approval for the GulfTerra Merger, we were required to sell our 50% interest in Starfish by March 31, 2005.
12. FINANCIAL INSTRUMENTS
We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to the variability of future earnings, fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices. As a matter of policy, we do not use financial instruments for speculative (or trading) purposes.
Interest rate risk hedging program. Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. As summarized in the following table, we had nine interest rate swap agreements outstanding at March 31, 2005 that were accounted for as fair value hedges.
The total fair value of these nine interest rate swaps at March 31, 2005, was a liability of $18.7 million, with an offsetting decrease in the fair value of the underlying debt. At December 31, 2004, the total fair value of these nine interest rate swaps was an asset of $0.5 million, with an offsetting increase in the fair value of the underlying debt. Interest expense for the three months ended March 31, 2005 and 2004 reflects a benefit of $4.6 million and $1.7 million, respectively, from interest rate swap agreements.
During 2004, we entered into two groups of four forward-starting interest rate swap transactions having an aggregate notional amount of $2 billion each in anticipation of our financing activities associated with the closing of the GulfTerra Merger. These interest rate swaps were accounted for as cash flow hedges and were settled during 2004 at a net gain to us of $19.4 million, which will be reclassified from accumulated other comprehensive income to reduce interest expense over the life of the associated debt.
Commodity risk hedging program. The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with natural gas and NGLs, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs.
At March 31, 2005 and December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. The fair value of our commodity financial instrument portfolio at March 31, 2005 and December 31, 2004 was a liability of $0.5 million and an asset of $0.2 million, respectively. We recorded nominal amounts of earnings from our commodity financial instruments during the three months ended March 31, 2005 and 2004.
13. BUSINESS SEGMENT INFORMATION
Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by the CEO of Enterprise GP in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. Our business
segments are generally organized and managed according to the type of services rendered and products produced and/or sold, as applicable. We have revised our prior segment information in order to conform to the current business segment operations and presentation.
We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services and Petrochemical Services. The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico.
The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.
The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminaling operations.
The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex and an octane additive production facility. This segment also includes various petrochemical pipeline systems.
The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.
Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Most of our plant-based operations are located either along the western Gulf Coast in Texas, Louisiana and Mississippi or in New Mexico. Our natural gas, NGL and oil pipelines and related operations are in a number of regions of the United States including the Gulf of Mexico offshore Texas and Louisiana; the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and certain regions of the central and western United States. Our marketing activities are headquartered in Houston, Texas, at our main office and serve customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.
We evaluate segment performance based on segment gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.
We define total (or consolidated) segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest,
extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.
Segment revenues and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of all material intercompany (both intersegment and intrasegment) transactions.
We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. For example, we use the Promix NGL fractionator to process a portion of the mixed NGLs extracted by our gas plants. Another example was our use of the Dixie pipeline to transport propane sold to customers through our NGL marketing activities (prior to the consolidation of Dixies results with ours beginning in February 2005, see Note 3). See Note 8 for additional information regarding our related party relationships with unconsolidated affiliates.
Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset's or investment's principal operations. The principal reconciling item between consolidated property, plant and equipment and segment assets is construction-in-progress. Segment assets represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction generally do not contribute to segment gross operating margin, these assets are excluded from the business segment totals until they are deemed operational. Consolidated intangible assets and goodwill are allocated to each segment based on the classification of the assets to which they relate.
The following table shows our measurement of total segment gross operating margin for the periods indicated:
A reconciliation of our measurement of total segment gross operating margin to operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles follows:
Information by segment, together with reconciliations to the consolidated totals, is presented in the following table:
14. EARNINGS PER UNIT
Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of distribution-bearing units (i.e., common and restricted common units) outstanding during a period. The distribution-bearing Class B special units were included in the calculation of basic earnings per unit prior to their conversion to common units in July 2004.
In general, diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the sum of:
Treasury units are not considered to be outstanding units; therefore, they are excluded from the computation of both basic and diluted earnings per unit.
In a period of net operating losses, the performance-based restricted units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. The dilutive incremental option units are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the beginning of each period are used to repurchase common units at an average market value during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.
The amount of net income allocated to limited partner interests is derived by subtracting our general partners share of our net income from net income. The following table shows the allocation of net income to our general partner for the periods indicated:
The following tables show our calculation of limited partners interest in net income, basic earnings per unit and diluted earnings per unit for the periods indicated: