Registrant’s Telephone Number, including Area Code: (713) 880-6500
The following abbreviations, acronyms or terms used in this Form 10-Q are defined below:
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For definitions of other commonly used terms used in our industry, please refer to the “Glossary” section of our 2003 annual report on Form 10-K (Commission File No. 1-14323).
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See Notes to Unaudited Condensed Consolidated Financial Statements
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ENTERPRISE PRODUCTS PARTNERS L.P. 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 entity names and other capitalized and industry terms are defined within the glossary of this quarterly report on Form 10-Q.
We were formed in April 1998 to own and operate certain NGL-related businesses of EPCO, Inc. (“EPCO,” formerly Enterprise Products Company). We conduct substantially all of our business through a 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.
On September 30, 2004, we completed Step Two and Step Three of the GulfTerra Merger. For additional information regarding these events, please see Note 3.
In the opinion of Enterprise, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a 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 condensed financial statements should be read in conjunction with our annual report on Form 10-K (File No. 1-14323) for the year ended December 31, 2003.
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 Partnership’s debt obligations. See Note 15 for condensed financial information of our Operating Partnership.
The results of operations for the three and nine month periods ended September 30, 2004 are not necessarily indicative of the results to be expected for the full year. For information regarding the pro forma effects of the GulfTerra Merger on our historical results of operations, see Note 3.
Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.
Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation. As a result of the GulfTerra Merger, we have revised and renamed our reportable business segments, as discussed in Note 13. We have revised our prior segment financial information, to the extent practicable, in order to conform to the current business segment presentation.
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CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES represents the combined impact of (1) changing 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 (2) changing the method in which we account for our investment in VESCO from the cost method to the equity method.
Our BEF subsidiary owns an octane additive production facility that undergoes periodic planned outages of 30 to 45 days for major maintenance work. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services, and other related items. BEF used the accrue-in-advance method to record cost estimates for such activities; whereas, the Company’s other operations used the expense-as-incurred method for their planned major maintenance activities. Our BEF subsidiary changed its accounting method on January 1, 2004 to conform to the Company’s accounting for planned major maintenance costs, which better reflects expenses in the period incurred. As such, we believe the change is to a method that is preferable in the circumstances. The cumulative effect of this accounting change for years prior to 2004 resulted in a benefit of $7 million.
EITF 03-16, “Accounting for Investments in Limited Liability Companies,” requires investments in limited liability companies (or “LLCs”) that have separate ownership accounts for each investor be accounted for similar to limited partnerships under SOP No. 78-9, “Accounting for Investments in Real Estate Ventures.” Under this new guidance (applicable for the period beginning July 1, 2004), investors are required to apply the equity method of accounting to their investments at a much lower ownership threshold (typically any ownership interest greater than 3-5%) than the traditional 20% threshold applied under APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”
Prior to July 1, 2004, we accounted for our 13.1% investment in VESCO using the cost method. As a result, we recognized dividend income from VESCO to the extent that we received cash distributions from them. In accordance with the new accounting guidance in EITF 03-16, we recorded a cumulative effect adjustment equal to the difference between (i) equity earnings from VESCO that would have been recorded using the equity method in periods prior to July 1, 2004 and (ii) the dividend income from VESCO we recorded using the cost method in prior periods. The cumulative effect of this accounting change resulted in a benefit of $3.8 million.
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For the periods indicated, the following table shows pro forma net income and earnings per unit amounts assuming the accounting changes noted above were applied retroactively to January 1, 2003. See Note 14 for information regarding the effect of the accounting changes on basic and diluted earnings per unit.
NATURAL GAS IMBALANCES result from differences in gas volumes received from and delivered to our customers and arise when a customer delivers more or less gas into our pipelines than they take out. We estimate the value of our imbalances at prices representing the estimated value of the imbalances upon settlement. Changes in natural gas prices may impact our estimates. We do not value our imbalances based on current month-end spot prices because it is not likely that we would purchase or receive natural gas at that point in time to settle the imbalance. Prior to the GulfTerra Merger, natural gas imbalances were not a significant part of our business.
Natural gas imbalances are reflected in accounts receivable or accounts payable, as appropriate, in our accompanying Unaudited Condensed Consolidated Balance Sheet. At September 30, 2004, our imbalance receivables were $42.5 million and our imbalance payables were $71.4 million.
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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 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.
We recorded compensation expense of $0.1 million during the three and nine months ended September 30, 2004 in connection with our issuance of restricted common units to key management personnel in May and September 2004 (see Note 9).
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FIN 46, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51.” This interpretation of ARB No. 51 addresses requirements for accounting consolidation of a variable interest entity (“VIE”) with its primary beneficiary. In general, if an equity owner of a VIE meets certain criteria defined within FIN 46, the assets, liabilities and results of the activities of the VIE should be included in the consolidated financial statements of the owner. Our adoption of FIN 46 (as amended by FIN 46R) in 2003 has had no material effect on our consolidated financial statements. Due to the complexity of FIN 46 (as amended by FIN 46R and interpreted), the FASB is continuing to provide guidance regarding implementation issues. Since this guidance is still continuing, our conclusions regarding the application of this guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of FIN 46.
EITF 03-06, “Participating Securities and the Two-Class Method under SFAS No. 128.” This accounting guidance, which is applicable for the period beginning April 1, 2004, requires the two-class method for calculating earnings per share for certain securities that are considered to participate in earnings with common shareholders. Under the two-class method, distributions to equity owners are subtracted from earnings, and any remaining earnings would be allocated to the various classes of owners in proportion to their right to receive distributions as if those earnings had been distributed. The total distributions to each class of owner plus the amount allocated to each class would be used to compute earnings per unit for that class. Since our distributions to owners exceeded earnings during the periods presented, as has historically been the case, the two-class method did not produce any change from the way we have traditionally computed earnings per unit. As a result, our adoption of this standard had no effect on our earnings per unit calculations.
General
On September 30, 2004, Enterprise and GulfTerra completed the merger of GulfTerra with a wholly-owned subsidiary of Enterprise, with GulfTerra being the surviving entity thereof. Additionally, Enterprise completed certain other transactions related to the merger, including receipt of Enterprise GP’s contribution of a 50% membership interest in GulfTerra GP, which was acquired by Enterprise GP from El Paso, and the purchase of certain midstream energy assets located in South Texas from El Paso. The aggregate value of the total consideration Enterprise paid or issued to complete the GulfTerra Merger was approximately $4 billion. These transactions were accounted for using purchase accounting.
Our September 30, 2004 Unaudited Condensed Consolidated Balance Sheet reflects the GulfTerra Merger. Since the GulfTerra Merger closed during the day of September 30, 2004, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income do not include any earnings from GulfTerra due to the immateriality of the amounts. Pursuant to written agreements, the effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. Our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2004 include one month of results of operations from the South Texas midstream assets.
As a result of the GulfTerra Merger, GulfTerra and GulfTerra GP became wholly-owned subsidiaries of Enterprise on September 30, 2004. On October 1, 2004, we contributed our ownership interests in GulfTerra and GulfTerra GP to our Operating Partnership, which resulted in GulfTerra and GulfTerra GP becoming wholly-owned subsidiaries of the Operating Partnership.
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Overview of the GulfTerra and South Texas midstream assets
GulfTerra owns or has interests in natural gas pipeline systems extending over 15,650 miles. These pipeline systems include natural gas gathering systems located onshore in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas and offshore in active drilling and development regions in the Gulf of Mexico. GulfTerra also owns interests in five natural gas processing and treating plants in New Mexico, Texas and Colorado.
In addition, GulfTerra has interests in seven multi-purpose offshore hub platforms in the Gulf of Mexico, including the recently completed Marco Polo TLP. These platforms were specifically designed to be used as deepwater hubs and production handling and pipeline maintenance facilities. Many of GulfTerra’s offshore natural gas and oil pipelines utilize these platforms.
GulfTerra also owns two salt dome natural gas storage facilities in Mississippi that are connected to five interstate pipeline systems, have a combined current working capacity of 13.5 Bcf and are capable of delivering in excess of 1.2 Bcf/d of natural gas. In addition, GulfTerra has the exclusive right to use a natural gas storage facility in South Texas under an operating lease that expires in January 2008. This facility has a working gas capacity of 6.4 Bcf and a maximum withdrawal capacity of 0.8 Bcf/d of natural gas.
In addition, GulfTerra owns interests in four offshore crude oil pipeline systems, which extend over 380 miles, and recently completed construction of the 390-mile Cameron Highway oil pipeline. GulfTerra also owns over 1,000 miles of intrastate NGL pipelines and four NGL fractionation plants in Texas; a 3.3 MMBbl propane storage facility in Mississippi; and, owns or leases NGL storage facilities in Louisiana and Texas with aggregate capacity of approximately 21.3 MMBbls. GulfTerra also owns interests in four relatively insignificant oil and natural gas producing properties located in the Gulf of Mexico offshore Louisiana.
The South Texas midstream assets purchased from El Paso consist of nine natural gas processing plants with a combined capacity of 1.9 Bcf/d, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 MMcf/d and a small NGL pipeline.
The GulfTerra Merger transactions
The GulfTerra Merger occurred in several interrelated transactions as described below.
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In connection with the closing of the GulfTerra Merger, on September 30, 2004, our Operating Partnership borrowed an aggregate $2.8 billion under its new revolving credit facilities in order to fund its cash payment obligations under Step Two and Step Three of the GulfTerra Merger and related transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes. See Note 10 and 17 for a description of these new borrowing and debt-related transactions.
The total consideration paid or granted for the GulfTerra Merger is summarized below:
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Other agreements associated with the GulfTerra Merger
Enterprise GP Exchange Agreement with El Paso. An El Paso subsidiary (“El Paso Holdco”) that owns the 9.9% membership interest in Enterprise GP entered into an Exchange and Registration Rights Agreement (the “Exchange Agreement”) with Enterprise and Enterprise GP dated September 30, 2004, pursuant to which El Paso Holdco has the right to deliver its 9.9% membership interest to Enterprise GP at any time after March 31, 2005 in exchange for a number of Enterprise common units that would provide the same cash flow as its 9.9% membership interest in Enterprise GP. Enterprise GP may elect to pay El Paso Holdco cash in lieu of Enterprise common units equal to the market value of such Enterprise common units or a combination of cash and Enterprise common units. If El Paso Holdco has not exercised the foregoing right by March 31, 2008, Enterprise GP can force the exercise of such right at any time thereafter. We have agreed in the Exchange Agreement to file a shelf registration statement covering the resale of any Enterprise common units that may be delivered to El Paso Holdco upon the exercise of the foregoing exchange right. DFI Delaware Holdings L.P., an entity controlled by Dan L. Duncan that owns 115,540,924 Enterprise common units at September 30, 2004, has guaranteed the performance of Enterprise GP’s obligations under the Exchange Agreement pursuant to a Performance Guaranty dated September 30, 2004.
Enterprise Registration Rights Agreement with El Paso. Enterprise and El Paso entered into a Registration Rights Agreement dated September 30, 2004, pursuant to which Enterprise granted to El Paso one demand registration statement and unlimited piggyback registration rights with respect to the 13,454,499 Enterprise common units received by El Paso pursuant to the GulfTerra Merger. The piggyback rights so granted to El Paso are subordinated to the piggyback rights of an affiliate of Shell set forth in the Registration Rights Agreement dated September 17, 1999.
Other business acquisitions completed during the nine months ended September 30, 2004
During the first nine months of 2004, we also acquired an additional 16.7% interest in Tri-States, a 10% interest in Seminole and the remaining 33.3% ownership interest in BEF. Due to the immaterial nature of each these acquisitions, individually and in the aggregate, our discussion of each of these transactions is limited to the following:
Acquisition of 16.7% interest in Tri-States. On April 1, 2004, we acquired an additional 16.7% membership interest in Tri-States, which owns an NGL pipeline located along the Mississippi, Alabama and Louisiana Gulf Coast. This system, in conjunction with the Wilprise and Belle Rose NGL pipelines, transport mixed NGLs to the BRF, Norco and Promix NGL fractionators located in south Louisiana. Due to this acquisition, our ownership interest in Tri-States increased to 66.7% and Tri-States became a majority-owned consolidated subsidiary of ours on April 1, 2004. Previously, Tri-States was accounted for as an equity method unconsolidated affiliate.
Acquisition of 10% interest in Seminole. On May 31, 2004, we acquired an additional 10% interest in Seminole, which owns a regulated 1,281-mile pipeline that transports mixed NGLs and NGL products from the Hobbs hub on the Texas-New Mexico border and the Permian Basin area to southeast Texas. As a result of this acquisition, our ownership interest in Seminole increased to 88.4%. The Seminole pipeline is interconnected with our Mid-America pipeline system at the Hobbs hub. The primary source of throughput for Seminole is volume originating from the Mid-America system.
Acquisition of remaining 33.3% interest in BEF. On September 1, 2004, we acquired the remaining 33.3% ownership interest in BEF, which owns a facility that produces octane additives such as MTBE (a motor gasoline additive that enhances octane and is used in reformulated gasoline). As a result of this acquisition, BEF became a wholly-owned subsidiary of ours.
The GulfTerra Merger transactions and our other business acquisitions completed during the first nine months of 2004 were recorded using the purchase method of accounting. Purchase accounting requires us to allocate the cost of a business combination to the assets acquired and liabilities assumed based on their estimated fair values. Enterprise has engaged an independent third-party business valuation expert to assess the fair value of
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GulfTerra’s and the South Texas midstream assets’ tangible and intangible assets. This information will assist management in the development of a definitive allocation of the overall purchase price of the GulfTerra Merger transactions. Management independently developed the fair value estimates for the other 2004 business acquisitions using recognized business valuation techniques.
The preliminary fair values shown in the following table are initial estimates based on information available to management at September 30, 2004. The tentative fair value conclusions and allocations related to the GulfTerra Merger transactions will be updated when the underlying valuation study is finalized, which is expected to occur during the fourth quarter of 2004 and we have completed our review of all other related information. The valuation estimates shown below will likely change due to this very recent transaction and the refinement of our initial estimates.
As a result of the preliminary purchase price allocation for Steps Two and Three of the GulfTerra Merger, we recorded $705.1 million of amortizable intangible assets, primarily those related to customer relationships and contracts. The remaining preliminary amount represents goodwill of $363.5 million associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry connections. For additional information regarding these intangible assets and goodwill, see Note 7.
The following table presents selected unaudited pro forma financial information incorporating the historical (pre-merger) results of GulfTerra and the South Texas midstream assets. Since the GulfTerra Merger closed during the day on September 30, 2004, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income do not include any earnings from GulfTerra due to the immateriality of the amounts. The effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. As a result, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the three and nine
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months ended September 30, 2004 include one month of results of operations from the South Texas midstream assets. The pro forma impact of our other business acquisitions is not material to this presentation.
The following pro forma information has been prepared as if the GulfTerra Merger and related transactions had been completed on January 1, 2003 as opposed to the actual dates that these acquisitions occurred. Excluded from the 2004 amounts are approximately $20 million of nonrecurring merger-related costs incurred by GulfTerra. The pro forma information is based upon preliminary data currently available and includes certain estimates and assumptions made by management. As a result, this preliminary information is not necessarily indicative of our financial results had the transactions actually occurred on this date. Likewise, the following unaudited pro forma financial information is not necessarily indicative of our future financial results (dollars in millions, except per unit amounts).
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Our inventories (including the preliminary purchase price allocations of $13.8 million from Steps Two and Three of the GulfTerra Merger at September 30, 2004) were as follows at the dates indicated:
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.
Due to fluctuating conditions in the NGL, natural gas and petrochemical industry, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the cost of our inventories exceed their net realizable value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized. For the three months ended September 30, 2004 and 2003, we recognized $0.1 million and $0.7 million, respectively, of LCM adjustments. We recorded $6.1 million and $15.1 million of LCM adjustments for the nine months ended September 30, 2004 and 2003, respectively.
Our property, plant and equipment (including the preliminary purchase price allocations of $4.7 billion from Steps Two and Three of the GulfTerra Merger at September 30, 2004) and accumulated depreciation were as follows at the dates indicated:
Depreciation expense for the three months ended September 30, 2004 and 2003 was $28.6 million and $24.7 million, respectively. We recorded $83.3 million and $73.1 million of such expense for the nine months ended September 30, 2004 and 2003, respectively.
Other long-term liabilities on our September 30, 2004 Unaudited Condensed Consolidated Balance Sheet includes $6.1 million related to historical asset retirement obligations recorded by GulfTerra. These asset retirement obligations have been recorded in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” and relate primarily to plugging abandoned offshore wells located in the Gulf of Mexico offshore Louisiana.
In connection with the GulfTerra Merger, we are required under a consent decree published for comment by the FTC on September 30, 2004 to sell our undivided 50% ownership interest in a Mississippi propane storage
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facility by December 31, 2004. As a result of our initial estimate of this asset’s current anticipated sales price, we recorded a non-cash asset impairment charge of $4 million during the third quarter of 2004, which is a component of operating costs and expenses of our NGL Pipelines & Services business segment. The nominal fair value of this facility was reclassified from “Property, Plant and Equipment” to “Assets Held for Sale” on our Unaudited Condensed Consolidated Balance Sheet at September 30, 2004. The operating results of this facility (including the aforementioned asset impairment charge) are not material to our historical or ongoing operations; therefore, these results have not been presented as discontinued operations in our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income.
In connection with the GulfTerra Merger, we also acquired interests in four relatively insignificant oil and natural gas producing properties located in the Gulf of Mexico offshore Louisiana. Production from these properties is generally gathered, transported, and processed through our pipeline systems and platform facilities, and sold to various third parties. These oil and gas producing properties are not a significant part of our business and we do not expect them to become significant in the future. Our intent is to diminish these activities over time by not acquiring additional properties. We will use the successful efforts method to account for the costs of such oil and natural gas assets. Depletion charges related to these properties will be based on the units-of-production method.
We own interests in a number of related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we own 20% to 50% of its outstanding ownership interests and exercise significant influence over its operating and financial policies. As a result of recently issued accounting guidance under EITF 03-16 (see Note 1), the minimum ownership requirement for an investment organized as a LLC to qualify for the equity method of accounting was lowered to between 3% and 5% from the 20% threshold applied to other types of investments.
On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16. The VESCO investment consists of a 13.1% interest in a LLC that owns a natural gas processing plant, NGL fractionation facilities, storage assets and gas gathering pipelines located in south Louisiana. For additional information regarding this change in accounting method, see Note 1.
As a result of the GulfTerra Merger (see Note 3), we acquired ownership interests in the entities described below, all of which are unconsolidated affiliates accounted for using the equity method of accounting. We do not exercise management control over these entities and are therefore precluded from consolidating their financial statements with those of our own.
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In connection with the GulfTerra Merger, we are required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% interest in Starfish, which in turn owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. The carrying value of this investment was reclassified from “Investments in and Advances to Unconsolidated Affiliates” to “Assets Held for Sale” on our Unaudited Condensed Consolidated Balance Sheet at September 30, 2004. We are required to sell this investment by March 31, 2005.
Our investments in and advances to these unconsolidated affiliates are grouped in the following table according to the new business segment to which they relate. For a general discussion of our business segments, see Note 13.
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The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:
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The following table presents unaudited summarized income statement information for our unconsolidated affiliates from which we have recorded equity earnings (for the periods indicated, on a 100% basis).
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Since the GulfTerra Merger occurred during the day on September 30, 2004, the amount of any equity income (loss) from Cameron Highway, Deepwater Gateway, Poseidon and Coyote was not material. The following unaudited summarized income statement information is presented for informational purposes only (for the periods indicated, on a 100% basis).
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The following table summarizes our intangible assets at the dates indicated:
As a result of Steps Two and Three of the GulfTerra Merger, we made preliminary purchase price allocations of $705.1 million to acquired intangible assets related to customer relationships, storage contracts, and water rights.
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For the remainder of 2004, amortization expense attributable to our intangible assets is currently estimated at $11.8 million. Based on information currently available, we estimate that amortization expense related to existing intangible assets could approximate $47 million during 2005 and 2006, $42 million during 2007 and $39 million during 2008 and 2009.
Our preliminary estimate of goodwill associated with the GulfTerra Merger is $363.5 million, which we allocated between our new business segments in proportion to the tangible and intangible assets we recorded for this transaction in purchase accounting. The “GulfTerra Merger” goodwill is associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry connections. Based on miles of pipelines, GulfTerra is one of the largest natural gas gatherers in the natural gas supply regions offshore in the Gulf of Mexico and onshore in Texas and New Mexico. These regions, especially the deeper water regions of the Gulf of Mexico, offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other energy infrastructure.
The following table summarizes our goodwill amounts at September 30, 2004 and December 31, 2003:
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 our general partner are employees of EPCO, including O.S. Andras who is Chief Executive Officer and a director and Vice Chairman of Enterprise GP. The principal business activity of our general partner is to act as our managing partner. Collectively, EPCO and its affiliates owned a 36.2% equity interest in Enterprise at September 30, 2004, which includes their ownership interest of Enterprise GP (of which EPCO and its affiliates own 90.1%).
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We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. Prior to January 1, 2004, we reimbursed EPCO for the costs of its employees who performed operating functions for us and for costs related to certain of its management and administrative personnel hired in response to the expansion of our business. In addition, we paid EPCO a monthly fee for services provided by its other management and administrative employees. On January 1, 2004, the Administrative Services Agreement was amended to eliminate the fee portion of this reimbursement and to provide that we reimburse EPCO for all such costs, including fringe benefits, related to management or administrative support for us.
On October 22, 2004, the Administrative Services Agreement was amended further to evidence our separateness from other persons and entities, to reflect a five-year license we granted for EPCO’s use of service marks owned by us and to provide for reimbursement of EPCO’s costs of discontinuing the use of those service marks over the term of the license. This amendment also provides that if EPCO and its affiliates are offered by a third party, or discover an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by the Operating Partnership or in a line of business that would be a natural extension of any business then being conducted by the Operating Partnership (a “Business Opportunity”), EPCO shall promptly advise the Board of Directors of Enterprise GP of such Business Opportunity and offer such Business Opportunity to the Operating Partnership. If the Board of Directors of Enterprise GP does not advise EPCO within 10 days following the receipt of such notice that we wish to pursue such Business Opportunity, EPCO shall then be permitted to pursue such Business Opportunity. If the Board of Directors of Enterprise GP advises EPCO within the 10 day period that we want to pursue such Business Opportunity, EPCO shall not be permitted to pursue such Business Opportunity unless the Board of Directors of Enterprise GP subsequently advises EPCO that it has abandoned its pursuit of such Business Opportunity.
We also have entered into an agreement with EPCO to provide trucking services to 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 each separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. EPCO primarily depends on cash distributions it receives as an equity owner in us to fund its other operations and to meet its debt obligations. For the nine months ended September 30, 2004 and 2003, EPCO received $130.6 million and $119.2 million in distributions from us.
We have a significant commercial relationship with Shell as a partner, customer and vendor. At September 30, 2004, Shell owned an approximate 11.1% equity interest in Enterprise. Shell is one of our largest customers. Our revenues from Shell primarily reflect the sale of NGL and petrochemical products to Shell and the fees we charge Shell for natural gas processing, pipeline transportation and NGL fractionation services. Our operating costs and expenses with Shell primarily reflect the payment of energy-related expenses related to the Shell natural gas processing agreement and the purchase of NGL products from Shell.
Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie and purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix and process natural gas at VESCO.
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The following table summarizes our related party revenues, operating costs and expenses, and selling, general and administrative costs for the periods indicated:
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 Enterprise GP, our general partner.
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.
Amendment to Partnership Agreement
On October 1, 2004, we amended and restated our Partnership Agreement by executing the Fourth Amended and Restated Agreement of Limited Partnership. The amended Partnership Agreement makes the following changes: (i) all previous amendments were consolidated into one document, (ii) certain provisions which are no longer applicable to us were deleted (such as those relating to the subordination period and classes of partnership equity securities that are no longer outstanding), and (iii) certain provisions were added to evidence our separateness from other persons and entities. A number of additional immaterial revisions were made in the amended Partnership Agreement, including updating definitions to provide consistency with the above described changes.
Equity interests granted on September 30, 2004 in connection with the GulfTerra Merger
Under Step Two of the GulfTerra Merger (see Note 3), Enterprise issued 1.81 of its common units for each GulfTerra common unit (including restricted common units) remaining after Enterprise’s purchase of 2,876,620
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GulfTerra common units owned by El Paso. The 104,549,823 Enterprise common units (including restricted common units) issued in the conversion were calculated as shown in the following table:
In accordance with purchase accounting rules, the $2.4 billion value of Enterprise’s common units issued in Step Two of the GulfTerra Merger is based on the average closing price of Enterprise’s common units immediately prior to and after the proposed merger was announced on December 15, 2003:
Overall, the fair value of equity interests we issued on September 30, 2004 under Step Two of the GulfTerra Merger was approximately $2.9 billion. The following table shows the detail for this consideration:
Series F2 convertible units assumed in connection with the GulfTerra Merger
In May 2003, GulfTerra issued 80 Series F convertible units in a registered offering to an institutional investor. Each Series F convertible unit was comprised of two separate detachable units – a Series F1 convertible unit and a Series F2 convertible unit – that had identical terms except for vesting and termination dates and the number of common units into which they could be converted. Prior to the GulfTerra Merger, all the Series F1 convertible units were converted to GulfTerra common units by the holder. As a result of the GulfTerra Merger, we assumed GulfTerra’s obligation associated with the 80 Series F2 convertible units. All Series F2 convertible units
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outstanding at the merger date were converted into rights to receive Enterprise common units. The number of Enterprise common units and the price per unit at conversion were adjusted based on the 1.81 exchange ratio. The fair value of the Series F2 convertible units at September 30, 2004 was estimated at $3.4 million.
The Series F2 units were convertible into up to $40 million of Enterprise common units. On October 29, 2004, 60 of the 80 outstanding Series F2 convertible units were converted into 1,458,434 Enterprise common units. On November 8, 2004, the remaining 20 outstanding Series F2 convertible units were converted into 491,883 Enterprise common units. See Note 17 for additional information regarding these conversions.
Restricted common units
In May 2004, EPCO issued 81,500 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 in the Company. The fair market value of the May 2004 restricted units at grant date was $1.7 million. In September 2004, EPCO issued an additional 86,800 time-vested restricted units to key management personnel, including 54,300 restricted units that were carried forward from pre-GulfTerra Merger agreements between GulfTerra and certain of its key employees (who are now EPCO employees as a result of the GulfTerra Merger). The aggregate fair value of the 86,800 time-vested restricted units issued in September 2004 was $1.7 million.
In general, restricted unit awards entitle recipients to acquire the underlying common units (at no cost to them) once the defined vesting period expires, subject to certain forfeiture provisions. The restrictions on these common units lapse four years from the date of grant. Unearned compensation, representing the fair market value of the restricted units at the date of issuance, is charged to earnings as compensation expense on a straight-line basis over the vesting period. During the vesting period, each holder of restricted units is entitled to receive cash distributions per unit in an amount equal to those received by our common unitholders. For basic and diluted earnings per unit purposes, restricted common units are treated as outstanding units.
As a result of the GulfTerra Merger, we exchanged 30,000 GulfTerra performance-based restricted units for Enterprise performance-based restricted units based on the 1.81 exchange ratio, which resulted in our issuance of 54,300 of such units under our 1998 Plan. At the GulfTerra Merger date, we recorded $0.7 million of deferred compensation for these performance-based restricted units, which is reflected as a reduction of partners’ equity and is allocated to our limited and general partners in accordance with their respective ownership interests.
In general, performance-based restricted unit awards entitle recipients to acquire the underlying common units (at no cost to them) if we achieve a specified level of financial performance for certain capital projects during 2007. If we do not reach the specified financial targets by the dates identified within each agreement, these units will be forfeited. Unearned compensation, representing the fair market value of these units at the date of issuance, is charged to earnings as compensation expense on a straight-line basis over the performance period. The performance-based restricted units are not entitled to vote or to receive distributions, until after (and if) we achieve the specified level of target performance. Lastly, performance-based restricted units are counted as outstanding units for dilutive earnings per unit purposes only.
Total unamortized deferred compensation attributable to both classes of restricted units at September 30, 2004 was $4 million. We recorded $0.1 million of compensation expense for the three and nine months ended September 30, 2004 which is reflected as a component of selling, general and administrative expenses. Deferred compensation is reflected as a reduction of partners’ equity and is allocated to our limited and general partners in accordance with their respective ownership interests.
Conversion of Class B special units to common units in July 2004
Upon receipt of unitholder approval on July 29, 2004, our 4,413,549 Class B special units converted to an equal number of common units. Prior to their conversion, the Class B special units entitled the holder to the same rights and privileges (other than voting rights) as common unitholders. This conversion resulted in a reclassification of the $99 million capital account balance for the Class B special units to common units.
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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 offering from January 1, 2004 through September 30, 2004:
During the first nine months of 2004, we reissued 292,600 treasury units at a cost of $6.2 million primarily due to obligations under EPCO employee unit option agreements and recorded a $0.3 million gain on the transactions.
Unit History
The following table details the outstanding balance of each class of units for the periods and at the dates indicated:
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Distributions
As an incentive, Enterprise GP’s percentage interest in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. Enterprise GP’s quarterly incentive distribution thresholds are as follows:
On October 20, 2004, the Board of Directors of Enterprise GP increased the quarterly cash distribution rate by 6% from $0.3725 per common unit to $0.3950 per common unit, or $1.58 per common unit on an annual basis. Further, the Board of Directors also approved the payment of the quarterly distribution for the quarter ended September 30, 2004, which will be paid on November 5, 2004 to unitholders of record at the close of business on October 29, 2004.
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 (“AOCI”) since January 1, 2003. Information for the first nine months of 2004 has been presented by quarter.
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Our debt consisted of the following at the dates indicated:
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On September 30, 2004, we borrowed approximately $2.25 billion under our new 364-Day Acquisition Revolving Credit Facility and $545 million under our new Multi-Year Revolving Credit Facility “B” to (a) fund $655.3 million in cash payment obligations to El Paso under Steps Two and Three of the GulfTerra Merger transactions, (b) escrow $1.1 billion to finance our tender offers for GulfTerra’s senior and senior subordinated notes and (c) extinguish $962 million outstanding under GulfTerra’s revolving credit facility and secured term loans. Our long-term debt at September 30, 2004 includes the remaining debt obligations of GulfTerra as appropriate in consolidation.
In October 2004, we used the $1.1 billion in escrowed funds (classified as a component of “Restricted Cash” on our Unaudited Condensed Consolidated Balance Sheet at September 30, 2004) to complete our cash tender offers for substantially all of GulfTerra’s senior and senior subordinated notes. In addition, we completed our issuance of $2 billion in Rule 144A private placement senior notes (Senior Notes E, F, G, and H) and used the proceeds to reduce borrowings made under our 364-Day Acquisition Revolving Credit Facility on September 30, 2004. See Note 17 for additional information regarding these subsequent events.
The following is a summary of the significant aspects of our debt obligations at September 30, 2004:
Parent-Subsidiary guarantor relationships. We act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Seminole Notes and the senior and 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 86.6% of its capital stock). The senior and senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).
364-Day Acquisition Revolving Credit Facility. In August 2004, our Operating Partnership entered into a new 364-day revolving credit agreement. The $2.25 billion Acquisition Revolving Credit Facility is an unsecured 364-day facility that was used to provide interim financing for certain transactions associated with the GulfTerra Merger, the refinancing of GulfTerra’s existing secured credit facility and term loans and the purchase of GulfTerra’s senior and senior subordinated notes in connection with our tender offers for those notes. This facility became effective concurrent with the closing of the GulfTerra Merger and will mature on September 29, 2005. The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to Enterprise GP. We have guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.
As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate. For information regarding variable interest rates paid under this revolving credit facility, please read “Information regarding variable interest rates paid” within this Note 10.
This credit agreement provides for the mandatory prepayment of loans and termination of commitments equal to the proceeds from and upon the consummation of any public or private debt or equity offerings by us on or after August 15, 2004, excluding equity issued with respect to our DRIP, employee unit purchase plan and the exercise of any outstanding options with respect to our common units. With the completion of our Rule 144A private placement offering of senior notes on October 4, 2004, we repaid approximately $2 billion borrowed under this facility, which reduced our borrowing capacity under this facility by an equal amount.
This revolving credit agreement contains various covenants related to our ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also requires us to satisfy certain financial covenants at the end of each fiscal quarter. If an event of default (as defined in the agreement) occurs, the Operating Partnership is prohibited from making distributions to us, which would impair our ability to make distributions to our partners. As defined in the agreement, we must maintain a specified level of consolidated net worth and certain financial ratios.
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Multi-Year Revolving Credit Facility “B”. In August 2004, our Operating Partnership entered into a five-year $750 million revolving credit agreement that includes a sublimit of $100 million for standby letters of credit. This facility became effective concurrent with the closing of the GulfTerra Merger and will mature on September 30, 2009. This facility replaced our existing $270 million Multi-Year Revolving Credit Facility “A” and $230 million 364-Day Revolving Credit facility, which were terminated upon the effective date of the new facility. The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to Enterprise GP. We have guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.
As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate. We elect the basis of the interest rate at the time of each borrowing. For information regarding variable interest rates paid under this revolving credit facility, please read “Information regarding variable interest rates paid” within this Note 10. This revolving credit agreement contains various covenants similar to those of our 364-Day Acquisition Revolving Credit Facility (please refer to our discussion regarding the restrictive covenants of the 364-Day Acquisition Revolving Credit Facility within this Note 10).
Senior Notes Offering. On September 23, 2004, our Operating Partnership priced a Rule 144A private placement of an aggregate of $2 billion in principal amount of four series of senior unsecured notes in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended. See Note 17 for information regarding our Operating Partnership’s issuance and sale of these senior unsecured notes on October 4, 2004.
GulfTerra’s Senior Subordinated and Senior Notes. At the close of the GulfTerra Merger on September 30, 2004, we recorded in consolidation the outstanding senior subordinated and senior notes of GulfTerra totaling approximately $921.5 million. See Note 17 for information regarding our Operating Partnership’s tender offers for all of GulfTerra’s outstanding senior subordinated and senior notes and its purchase of $915 million of such notes on October 5, 2004.
Industrial Development Revenue Bonds. In April 2004, Petal Gas Storage L.L.C. (“Petal”), a wholly-owned subsidiary of GulfTerra, borrowed $52 million from the Mississippi Business Finance Corporation (“MBFC”) pursuant to a loan agreement between Petal and the MBFC. On the same date, the MBFC issued $52 million in Industrial Development Revenue Bonds to another wholly-owned subsidiary of GulfTerra. The loan agreement and the Industrial Development Revenue Bonds have identical fixed interest rates of 6.25% and maturities of fifteen years. The bonds and the associated tax exemptions are authorized under the Mississippi Business Finance Act. Petal may repay the loan agreement without penalty, and thus cause the Industrial Development Revenue Bonds to be redeemed, any time after one year from their date of issue. We have netted the loan amount and the bond amount of $52 million and the interest payable and interest receivable amount of $1.4 million on our Unaudited Condensed Consolidated Balance Sheet as of September 30, 2004. Beginning in the fourth quarter of 2004, we will also net the interest expense and interest income amounts attributable to these instruments on our Statements of Consolidated Operations. Our presentation of the Industrial Development Revenue Bonds is reflected in accordance with the provisions of FIN No. 39, “Offsetting of Amounts Related to Certain Contracts”, and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities”, since we have the ability and intent to offset these items.
Covenants.We were in compliance with the various covenants of our debt agreements at September 30, 2004 and December 31, 2003.
Loss due to write-off of unamortized debt issuance costs. As a result of terminating our 364-Day Revolving Credit Facility and our Multi-Year Revolving Credit Facility “A” on September 30, 2004, we expensed $0.7 million of unamortized debt issuance costs, which is reflected as a component of interest expense on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income.
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The following table shows the range of interest rates paid and weighted-average interest rates paid on our variable rate debt obligations during the nine months ended September 30, 2004:
The following table shows aggregate maturities of the principal amounts of long-term debt and other financing obligations for the remainder of 2004 and the following 4 years and in total thereafter at September 30, 2004 (i) on an actual basis and (ii) on a pro forma basis adjusted for debt-related subsequent events as described in Note 17.
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As a result of the GulfTerra Merger, we acquired ownership interests in three additional joint ventures having long-term debt obligations. The following table shows (i) our ownership interest in each entity at September 30, 2004, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliates on that date on a 100% basis to the joint venture, (ii) the corresponding scheduled maturities of such long-term debt:
The following is a summary of the significant aspects of the debt obligations of our unconsolidated affiliates. For a description of the business activities of the unconsolidated affiliates acquired as a result of the GulfTerra Merger, see Note 6.
Cameron Highway. At September 30, 2004, long-term debt for Cameron Highway consisted of $197 million outstanding under a construction loan and $100 million of senior secured notes (collectively, the “project loan facility”). Cameron Highway has a borrowing capacity of $225 million under its construction loan.
The construction loan bears interest at a variable rate. Once the Cameron Highway oil pipeline has commenced operations and transported a certain level of volumes (as specified in the credit agreement), the construction loan will convert to a term loan maturing in July 2008, subject to the terms of the loan agreement. At the end of the first quarter following the first anniversary of the conversion into a term loan, Cameron Highway will be required to make quarterly principal payments of $8.1 million, with the remaining unpaid principal amount payable on the maturity date. If the construction loan fails to convert into a term loan by January 2006, the construction loan and senior secured notes become fully due and payable. At September 30, 2004, the average interest rate charged under the construction loan was 4.97%.
The interest rate on Cameron Highway’s senior secured notes is 3.25% over the rate on 10-year U.S. Treasury securities. Principal payments of $4 million are due quarterly from September 2008 through December 2011, $6 million each from March 2012 through December 2012, and $5 million each from March 2013 through the principal maturity date of December 2013. At September 30, 2004, Cameron Highway had $100 million outstanding under its senior secured notes at an average interest rate of 7.4%.
The project loan facility as a whole is secured by (1) substantially all of Cameron Highway’s assets, including, upon conversion to a term loan, a debt service reserve capital account, and (2) all of the equity interest in Cameron Highway. Other than the pledge of our equity interest and our construction obligations under the relevant producer agreements, the debt is non-recourse to us. The construction loan and senior secured notes prohibit Cameron Highway from making distributions to us until the construction loan is converted into a term loan and Cameron Highway meets certain financial requirements.
Deepwater Gateway. At September 30, 2004, long-term debt for Deepwater Gateway consisted of $149.5 million due under a project finance loan used to fund a substantial portion of the cost to construct the Marco Polo TLP and related facilities. Construction of the Marco Polo TLP was completed during the first quarter of 2004, and in June 2004, Deepwater Gateway converted the project finance loan into a term loan which matures in June 2009. The term loan is payable in twenty equal quarterly installments of $5.5 million each (which began on September 30,
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2004), and the remaining outstanding principal of $45 million is due on the maturity date. Interest rates are variable and the loan is collateralized by substantially all of Deepwater Gateway’s assets. If Deepwater Gateway defaults on its payment obligations under the term loan, we would be required to pay the lenders all distributions we or any of our subsidiaries have received from Deepwater Gateway up to $22.5 million. As of September 30, 2004, the average interest rate charged under this term loan was 3.6% and Deepwater Gateway had not paid GulfTerra or any of its subsidiaries any distributions.
Poseidon. At September 30, 2004, long-term debt for Poseidon consisted of $116 million due under a revolving credit facility which matures in January 2008. This credit facility has a borrowing capacity of $170 million. The interest rates Poseidon is charged on balances outstanding under its revolving credit facility are variable and depend on its ratio of total debt to earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. As of September 30, 2004, the average interest rate charged under this facility was 3.7%.
Evangeline. At September 30, 2004, long-term debt for Evangeline consisted of (i) $33.2 million in principal amount of 9.9% fixed-rate Series B senior secured notes that are due in December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service requirement. Scheduled principal repayments on the Series B notes are $5 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios. Evangeline incurred the subordinated note payable in connection with its acquisition of a contract-based intangible asset in the early 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. In general, interest accrues on the subordinated note at a variable-rate based on LIBOR plus ½%. The variable interest rate paid on this debt at September 30, 2004 was 1.8%.
The net effect of changes in operating assets and liabilities is as follows for the periods indicated:
We completed the GulfTerra Merger and a number of other business acquisitions during the first nine months of 2004. These transactions affected a number of balance sheet categories. See Note 3 for the preliminary purchase price allocations related to these transactions which include non-cash consideration for equity interests issued and the fair values of assets acquired and liabilities assumed. In addition, see Note 9 for information regarding changes in our partners’ equity accounts as a result of the GulfTerra Merger transactions, including amounts associated with unit awards and Series F2 convertible units.
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We recorded certain fair value amounts related to our interest rate hedging financial instruments during the first nine months of 2004 that affected various balance sheet accounts. For information regarding our financial instruments, see Note 12.
Restricted cash related to operating activities was $16.9 million at September 30, 2004 and $13.9 million at December 31, 2003. These balances are related to amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for the physical purchase of natural gas made on the NYMEX exchange.
On September 30, 2004, we borrowed $1.1 billion under our 364-Day Acquisition Revolving Credit Facility in anticipation of completing our tender offers for GulfTerra’s senior and senior subordinated notes and placed these funds in escrow. On October 5, 2004, our Operating Partnership purchased the tendered notes for a total price of approximately $1.1 billion, which includes accrued interest and consent payments (see Note 17). The $1.1 billion held in escrow is a component of restricted cash on our September 30, 2004 Unaudited Condensed Consolidated Balance Sheet.
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, cash flows and fair value of certain debt securities caused by changes in commodity prices and interest rates. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.
We recognize our financial instruments on the balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction at arms-length between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings.
To qualify as a hedge, the item to be hedged must be exposed to commodity or interest rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.
Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance regarding the implementation of this accounting standard. Since this guidance is still continuing, our conclusions about the application of SFAS No. 133 may be altered, which may result in adjustments being recorded in future periods as we adopt new FASB interpretations of this standard.
Interest rate risk hedging program
Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We assess the cash flow risk related to interest rates by identifying and measuring changes in our interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. We use analytical
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techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the expected impact of changes in interest rates on our future cash flows. Enterprise GP oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.
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. We believe that it is prudent to maintain an appropriate balance of variable rate and fixed rate debt in the current business climate.
Fair value hedges – Interest rate swaps. On January 8, 2004, we entered into three interest rate swap agreements in which we exchanged the payment of fixed rate interest on a portion of principal outstanding under Senior Notes B and C for variable rate interest. On October 7, 2004, we entered into three additional interest rate swap agreements related to a portion of the principal outstanding under Senior Notes G issued on October 4, 2004.
We have designated these six interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.
These six agreements have a combined notional amount of $550 million and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month LIBOR rates (plus an applicable margin as defined in each swap agreement) and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.
Total fair value of the interest rate swaps in effect at September 30, 2004 was a receivable of approximately $1 million with an offsetting increase in fair value of the underlying debt. Interest expense in our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2004 reflects a $1.7 million and $5.3 million benefit, respectively, from these swaps.
Cash flow hedges – Forward starting interest rate swaps. During the first nine months of 2004, we entered into eight forward starting interest rate swap transactions having an aggregate notional amount of $2 billion in anticipation of our financing activities associated with closing the GulfTerra Merger. Our purpose in entering into these transactions was to effectively hedge the underlying U.S. treasury rate related to our anticipated issuance of $2 billion in principal amount of fixed rate debt. On October 4, 2004, our Operating Partnership issued $2 billion of Rule 144A private placement debt securities under Senior Notes E, F, G and H. Each of the forward starting swaps was designated as a cash flow hedge under SFAS No. 133.
In April 2004, we elected to terminate the initial four forward starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. In September 2004, we settled the remaining four swaps resulting in an $85.1 million
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payment to the counterparties. The net gain of $19.4 million from these settlements will be amortized over the life of the associated debt as a reduction in Accumulated Other Comprehensive Income to interest expense.
The following table shows the notional amount covered by each forward starting swap and the cash gain (loss) associated with each upon settlement:
Commodity risk hedging program
The prices of natural gas, NGLs, petrochemical products and MTBE 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 these risk management activities is to hedge our exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated transactions.
We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by Enterprise GP. We may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. Enterprise GP oversees the strategies associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy. At September 30, 2004, our portfolio consisted primarily of natural gas cash flow and fair value hedges.
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Business segments are components of a business about which separate financial information is available. These components are regularly evaluated by the CEO of our general partner 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.
As a result of the GulfTerra Merger (see Note 3), we have revised and renamed our reportable business segments, as discussed below. We have revised our prior segment information, to the extent practicable, in order to conform to the current business segment presentation.
We have segregated our business activities into four distinct reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services, and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technology or process employed) and products produced and/or sold, as applicable.
The Offshore Pipelines & Services business segment consists of (i) approximately 1,000 miles of natural gas pipelines strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico, (ii) ownership interests in four Gulf of Mexico offshore oil pipeline systems aggregating 419 miles and (iii) ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico. In addition, this segment includes ownership interests in four relatively insignificant oil and natural gas producing properties located in the waters offshore of Louisiana.
The Onshore Natural Gas Pipelines & Services business segment includes natural gas pipeline systems aggregating an approximate 16,100 miles that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. Included in this segment are two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. We also lease a natural gas storage facility located in Texas.
The NGL Pipelines & Services business segment is comprised of (i) our natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating an approximate 11,730 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 our four propylene fractionation facilities, isomerization complex, and octane additive production facility. This segment also includes approximately 330 miles of various propylene pipeline systems and a 70-mile hi-purity isobutane pipeline.
The Other non-segment category is presented for financial reporting purposes only to show the historical equity earnings we received from GulfTerra GP and our underlying investment in this entity at December 31, 2003. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger (see Note 3). 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 segments. Therefore, we have segregated equity earnings from GulfTerra GP apart from our other investments to aid in comparability between the periods presented and future periods.
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The following table shows the major components of each of our four new business segments along with a listing of the significant operating assets included within each component:
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We evaluate segment performance based on the non-GAAP financial measure of 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. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.
We define total (or consolidated) segment gross operating margin as operating income before: (1) depreciation, depletion 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) selling, 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 is our use of the Dixie pipeline to transport propane sold to customers through our NGL marketing activities. See Note 8 for additional information regarding our related party relationships with unconsolidated affiliates.
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 service customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.
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.
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The following table shows our measurement of total non-GAAP segment gross operating margin for the periods indicated:
A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP consolidated income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles (as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income) follows:
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Information by segment, together with reconciliations to the consolidated totals, is presented in the following table:
Our completion of the GulfTerra Merger affected segment assets, investments in and advances to unconsolidated affiliates, intangible assets, goodwill and other accounts. For additional information regarding the merger-related transactions, see Note 3.
Revenues for the third quarter of 2004 increased $805.5 million over those recorded during the same period in 2003. The increase in revenues is primarily due to (i) higher revenues from our NGL and petrochemical marketing activities due to increased sales volumes and prices and (ii) the addition of revenues from our recently acquired South Texas midstream assets.
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Our equity in the earnings of unconsolidated affiliates increased $32.6 million quarter-to-quarter. The equity earnings we recorded for the third quarter of 2003 were impacted by a $22.5 million non-cash asset impairment charge associated with our octane enhancement business. In addition, the third quarter of 2004 includes $10.8 million of equity earnings from GulfTerra GP, which we began consolidating on September 30, 2004 as a result of completing the GulfTerra Merger.
Revenues for the first nine months of 2004 increased $1.5 billion over those recorded during the first nine months of 2003. The increase in revenues is primarily due to (i) higher revenues from our NGL and petrochemical marketing activities due to increased sales volumes and prices and (ii) the addition of revenues from businesses acquired or consolidated since September 30, 2003, including BEF and our recently acquired South Texas midstream assets.
Our equity in the earnings of unconsolidated affiliates increased $58.9 million period-to-period. The equity earnings we recorded for the third quarter of 2003 were impacted by a $22.5 million non-cash asset impairment charge associated with our octane enhancement business. In addition, the first nine months of 2004 includes $32 million of equity earnings from GulfTerra GP, which we began consolidating on September 30, 2004 as a result of completing the GulfTerra Merger.
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 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:
The non-distribution bearing Class A special units were included in the calculation of diluted earnings per unit prior to their conversion to common units. 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. See Note 9 for information regarding our performance-based restricted units issued in September 2004. 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 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.
Beginning in August 2003, we started reissuing treasury units to satisfy our obligations under EPCO unit option agreements. The reissuance of these treasury units to satisfy EPCO’s unit option liability has a dilutive effect on our earnings per unit. Prior to August 2003, EPCO had purchased practically all of the common units associated with its 1998 Plan in the open market. As a result, EPCO’s unit option plan did not have any effect on our fully diluted earnings per unit in prior periods.
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The amount of net income allocated to limited partner interests is derived by subtracting our general partner’s 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:
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The Operating Partnership and its subsidiaries conduct substantially all of our business. Currently, we have no independent operations and no material assets outside of those of the Operating Partnership. Our effective ownership of the Operating Partnership is 100%.
For the day of September 30, 2004 (the date we closed the GulfTerra Merger), GulfTerra and GulfTerra GP were temporarily subsidiaries of ours. On October 1, 2004, we contributed all of our ownership interests in these entities to the Operating Partnership. As a result of this contribution on the day following the GulfTerra Merger, GulfTerra and GulfTerra GP are now wholly-owned subsidiaries of our Operating Partnership.
At September 30, 2004, the Operating Partnership had $1.7 billion in outstanding publicly-traded debt securities represented by its Senior Notes A, B, C and D. On October 4, 2004, the Operating Partnership issued an additional $2 billion in principal amount of Rule 144A private placement debt securities represented by Senior Notes E, F, G and H. We act as guarantor of all of our Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes and any remaining amounts outstanding under GulfTerra’s senior and senior subordinated notes after our Operating Partnership completed its tender offers in October 2004. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. Our guarantee of these debt obligations is full and unconditional. For additional information regarding our consolidated debt obligations, see Notes 10 and 17.
Historically, the number and dollar amount of reconciling items between our consolidated financial statements and those of our Operating Partnership are insignificant. The differences between our statements and those of the Operating Partnership on September 30, 2004 are primarily the result of purchase accounting entries related to the GulfTerra Merger and intercompany debt balances between GulfTerra and the Operating Partnership. These reconciling items were eliminated the following day, October 1, 2004, when we contributed GulfTerra and GulfTerra GP to the Operating Partnership. Excluding the effects of this one day difference, the primary reconciling items between the Unaudited Condensed Consolidated Balance Sheet of the Operating Partnership and our Unaudited Condensed Consolidated Balance Sheet are the treasury units we own directly and minority interest. The differences in consolidated net income are primarily dividends recognized by the 1999 Trust (which are eliminated in consolidation) and minority interest.
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The following tables show unaudited condensed financial information for the Operating Partnership for the periods and at the dates indicated:
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We are sometimes named as a defendant in litigation relating to our normal business operations. Although we insure against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from legal proceedings as a result of ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.
Environmental costs for remediation are accrued at their undiscounted estimated amounts based on known remediation requirements. Such accruals are based on management’s best estimate of the ultimate costs to remediate a given site and take into account the likely effects of inflation and other societal and economic factors, including estimated associated legal costs. We expense amounts for clean up of existing environmental contamination caused by past operations which do not benefit future periods. We expense or capitalize expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. Environmental costs and related accruals were not significant to our historical financial statements prior to the GulfTerra Merger. GulfTerra has an environmental liability initially estimated at $21 million, which is included in other long-term liabilities on our Unaudited Condensed Consolidated Balance Sheet dated September 30, 2004, for remediation costs expected to be incurred over time associated with mercury gas meters.
While the outcome of our outstanding environmental matters cannot be predicted with certainty, based on the information known to date and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, results of operations or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws and regulations and claims for damage to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate.
In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 8). This includes the costs associated with equity-based awards granted to these employees. At September 30, 2004, there were 2,558,000 options outstanding to purchase common units under EPCO’s 1998 Plan that had been granted to employees for which we were responsible for reimbursing EPCO for the costs of such awards. The weighted-average strike price of the unit option awards was $18.53 per common unit. At September 30, 2004, 1,199,000 of these unit options were exercisable. An additional 50,000, 374,000, 25,000 and 910,000 of these unit options will be exercisable during the remainder of 2004 and in 2005, 2006 and 2008, respectively. As these options are exercised, we will reimburse EPCO in the form of a special cash distribution for the difference between the strike price paid by the employee and the actual price paid for the units awarded to the employee.
We conduct a portion of our activities through joint venture business arrangements formed to construct, operate and finance the development of our onshore and offshore midstream energy businesses. We are obligated to make our proportionate share of additional capital contributions to our joint ventures only to the extent that they are unable to satisfy their obligations from other sources including proceeds from credit arrangements. Examples of this
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type of business arrangement include our equity method investments in Cameron Highway, Deepwater Gateway and Poseidon, which were acquired as a result of the GulfTerra Merger.
Long-term debt-related commitments. We have long and short-term payment obligations under credit agreements such as our Senior Notes and revolving credit facilities. See Note 10 for a description of these debt obligations.
Operating lease commitments. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. There has been no material change in our operating lease commitments since December 31, 2003, except for those we assumed in connection with the GulfTerra Merger. The assumed commitments relate to three storage facilities located in Texas (one natural gas facility and two NGL facilities). The future minimum lease payments associated with the assumed operating lease commitments as of September 30, 2004 are as follows: $0.4 million, 2004; $7 million, 2005; $7 million, 2006; $5.8 million, 2007; $3.2 million, 2008; and $1.8 million thereafter.
EPCO contributed various equipment leases to us at our formation in 1998 for which EPCO has retained the cash payment obligations (the “retained leases”). EPCO has assigned to us the purchase options associated with the retained leases. We exercised our options to purchase an isomerization unit and related equipment during the first nine months of 2004 at a cost of $15 million. Should we decide to exercise all of the remaining purchase options associated with the other retained leases (which are also at fair value), an additional $2.8 million would be payable in 2004, $2.3 million in 2008 and $3.1 million in 2016.
Purchase obligations. We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (unconditional) and that specify all significant terms, including (i) fixed or minimum quantities to be purchased; (ii) fixed, minimum or variable pricing provisions; and (iii) the approximate timing of the purchase transactions. Historically, our purchase obligations have resulted primarily from product purchase commitments and to a lesser extent from service contract commitments and capital expenditure commitments. There has been no material change in our product purchase and service contract commitments since December 31, 2003. GulfTerra’s operations are primarily that of a pipeline transportation service provider; therefore, its purchase obligations have been minimal when compared to our forecasted amounts. Our estimated capital expenditures commitments increased to $62 million at September 30, 2004 primarily due to the projects we assumed as a result of the GulfTerra Merger.
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On October 1, 2004, we contributed all of our ownership interests in GulfTerra and GulfTerra GP to our Operating Partnership. As a result of this contribution, GulfTerra and GulfTerra GP are now wholly-owned subsidiaries of our Operating Partnership.
On October 4, 2004, our Operating Partnership issued $2 billion of senior unsecured notes in a Rule 144A private placement offering. The interest rate, principal amount and net proceeds, before expenses, for each senior note in this offering are shown in the following table:
The net proceeds from this offering were used to reduce debt amounts outstanding under the Operating Partnership’s $2.25 billion 364-Day Acquisition Revolving Credit Facility that was used to partially fund the GulfTerra Merger on September 30, 2004.
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 Partnership’s 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.
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Tender offer for GulfTerra senior subordinated and senior notes (see Note 10)
On October 4, 2004, all of the cash tender offers made by our Operating Partnership for any and all of GulfTerra’s outstanding senior subordinated and senior notes expired. As of the expiration time, our Operating Partnership had received tenders of senior subordinated and senior notes aggregating $915 million, or 99.3% of the notes outstanding. On October 5, 2004, our Operating Partnership purchased the notes for a total price of approximately $1.1 billion. The following table shows the four GulfTerra senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by Enterprise to complete the tender offers.
On October 29, 2004, 60 of the 80 outstanding Series F2 convertible units were converted into 1,458,434 Enterprise common units. As a result of this conversion, we received a payment of $30 million from the holder of the Series F2 convertible units (representing a conversion price of $20.57 per Enterprise common unit). Net proceeds from this conversion, including Enterprise GP’s proportionate capital contribution of $0.6 million, were $29.7 million after deducting transaction costs of $0.9 million.
On November 8, 2004, the remaining 20 outstanding Series F2 convertible units were converted into 491,883 Enterprise common units. As a result of this conversion, we received a payment of $10 million from the holder of the Series F2 convertible units (representing a conversion price of $20.33 per Enterprise common unit). Net proceeds from this conversion, including Enterprise GP’s proportionate capital contribution of $0.2 million, were $9.9 million after deducting transaction costs of $0.3 million.
On November 8, 2004, we issued approximately 2.2 million common units in connection with our DRIP, which generated net proceeds of $49.3 million (including our general partner’s proportionate net capital contribution of approximately $1 million). We expect to use these proceeds for general partnership purposes.
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Enterprise Products Partners L.P. 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” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. Certain abbreviated entity names and other capitalized and industry terms are defined within the glossary of this quarterly report on Form 10-Q.
We were formed in April 1998 to own and operate certain NGL-related businesses of EPCO, Inc. (“EPCO,” formerly Enterprise Products Company). We conduct substantially all of our business through wholly- owned subsidiaries, Enterprise Products Operating L.P. (our “Operating Partnership”) and GulfTerra Energy Partners, L.P. (“GulfTerra”). On September 30, 2004, we completed the GulfTerra Merger and related transactions. We are owned 98% by our limited partners and 2% by our general partner (“Enterprise GP”). We and our general partner are also affiliates of EPCO.
The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes included under Item 1 of this quarterly report. Other risks involved in our business are discussed under “Quantitative and Qualitative Disclosures about Market Risk” included under Item 3 of this quarterly report.
This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please read our summarized “Risk Factors” below.
Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:
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We have no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
On September 30, 2004, Enterprise and GulfTerra completed the merger of GulfTerra with a wholly-owned subsidiary of Enterprise, with GulfTerra being the surviving entity thereof. Additionally, Enterprise completed certain other transactions related to the merger, including receipt of Enterprise GP’s contribution of a 50% membership interest in GulfTerra GP, which was acquired by Enterprise GP from El Paso, and the purchase of certain midstream energy assets located in South Texas from El Paso. The aggregate value of the total consideration Enterprise paid or issued to complete the GulfTerra Merger was approximately $4 billion.
In addition, GulfTerra owns interests in four offshore crude oil pipeline systems, which extend over 380 miles, and recently completed construction of the 390-mile Cameron Highway Oil Pipeline. GulfTerra also owns over 1,000 miles of intrastate NGL pipelines and four NGL fractionation plants in Texas; a 3.3 MMBbl propane storage facility in Mississippi; and, owns or leases NGL storage facilities in Louisiana and Texas with aggregate capacity of approximately 21.3 MMBbls. GulfTerra also owns interests in four relatively insignificant oil and natural gas producing properties located in the Gulf of Mexico offshore Louisiana.
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The South Texas midstream assets consist of nine natural gas processing plants with a combined capacity of 1.9 Bcf/d, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 MMcf/d and a small NGL pipeline.
In connection with the closing of the GulfTerra Merger, on September 30, 2004, our Operating Partnership borrowed an aggregate $2.8 billion under its new revolving credit facilities in order to fund its cash payment obligations under Step Two and Step Three of the GulfTerra Merger and related transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes. For additional information regarding the GulfTerra Merger, please see Note 3 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
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The GulfTerra Merger is expected to have the following significant benefits:
Both we and GulfTerra have historically operated our largest natural gas processing and fractionation facilities and most of our pipelines. As the leading provider of NGL-related services, we have established a reputation in the industry as a reliable and cost-effective operator. After the closing of the GulfTerra Merger, affiliates of Dan L. Duncan, our co-founder and the chairman of Enterprise Parent’s general partner, own a 90.1% membership interest in Enterprise GP, and El Paso owns a 9.9% membership interest in Enterprise GP. In addition, after giving effect to the GulfTerra Merger, Mr. Duncan and his affiliates collectively own an approximate 34.4% limited partner interest in Enterprise. The persons that serve as executive officers of the combined company average more than 31 years of industry experience.
Divestitures associated with the GulfTerra Merger
In order to complete the GulfTerra Merger, we are required under a consent decree published for comment by the FTC on September 30, 2004, to sell (i) our 50% interest in Starfish, which in turn owns a 50% interest in the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana by March 31, 2005 and (ii) our undivided 50% interest in a Mississippi propane storage facility by December 31, 2004.
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During the first quarter of 2004, we completed a program to convert essentially all of our traditional keepwhole contracts to other types of processing arrangements where the producer assumes all or most of the direct commodity price risk between NGLs and natural gas. These new arrangements include simple fee-based contracts, hybrid fee-based contracts with margin-sharing provisions and percent-of-liquids agreements. We began this effort in 2003. Prior to starting this effort, approximately 70% of the natural gas we processed was under traditional keepwhole arrangements. Under these arrangements, the volatility in natural gas prices since 2000 created large swings in the operating results of our natural gas processing business, which in turn did not provide us with a consistent return on our investment.
As a result of this effort, approximately 63% of the 2 Bcf/d of natural gas we processed during the second and third quarters of 2004 was under processing agreements containing a fee-based component. This compares to approximately 100 MMcf/d of fee-based volumes prior to amending these agreements. The remaining 750 MMcf/d, or 0.75 Bcf/d, was processed primarily under percent-of-liquids agreements compared to 0.5 Bcf/d under such arrangements previously. The new percent-of-liquids agreements resulted in approximately 1 MBPD of additional equity NGL production during the second and third quarters of 2004.
To provide us with the opportunity to earn additional gross operating margin above that provided by fee-based and percent-of-liquids arrangements and to align our interest with certain producers, some of our contracts provide a mechanism for us to participate in margin-sharing arrangements with the producer (in addition to the fee-based component we would earn) without exposing us to the risk of incremental cash losses. Approximately 50% of the natural gas we expect to process during 2004 is pursuant to these margin-sharing arrangements.
We believe these contract revisions will result in our being fairly compensated for this critical midstream service while providing producers with the assurance that their processing agreements with us are operative regardless of the natural gas price. We also believe that these new agreements will (1) provide us with a more consistent base of revenue and gross operating margin from our natural gas processing business, (2) greatly reduce the direct commodity price risk that previously existed under traditional keepwhole arrangements and (3) provide for a more reliable return on our investment.
In May 2004, we sold 17,250,000 common units to the public at an offering price of $21.00 per unit. Net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution of $7.1 million, were $353.1 million after deducting applicable underwriting discounts, commissions and offering expenses of $16.3 million. The net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution, were used to repay in full our $225 million Interim Term Loan and to temporarily reduce borrowings under our pre-merger revolving credit facilities.
In August 2004, we sold 17,250,000 common units to the public at an offering price of $20.20 per unit. Net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution of $6.8 million, were approximately $341.2 million after deducting applicable underwriting discounts, commissions and offering expenses of $13.9 million. The net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution were used to fund a portion of the purchase price of Steps Two and Three of the GulfTerra Merger transactions and to temporarily reduce borrowings under our pre-merger Multi-Year Revolving Credit Facility “A”.
We have also issued common units in connection with our distribution reinvestment plan, Series F2 convertible units and related programs. For additional information regarding our active registration statements, please read “Liquidity and Capital Resources.”
On October 4, 2004, our Operating Partnership issued $2 billion of senior unsecured notes in a Rule 144A private placement offering. For additional information regarding this debt, please read our “Liquidity and Capital Resources – Our debt obligations.”
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On October 5, 2004, our Operating Partnership completed its cash tender offers for any and all of GulfTerra’s outstanding senior subordinated and senior notes. As of the expiration time, our Operating Partnership had received tenders of senior subordinated and senior notes aggregating $915 million, or 99.3% of the notes outstanding. For additional information regarding the tender offers, please read our “Liquidity and Capital Resources – Our debt obligations.”
Since the GulfTerra Merger closed during the day on September 30, 2004, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income do not include any earnings from GulfTerra due to the immateriality of the amounts. The effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. As a result, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2004 includes one month of results of operations from the South Texas midstream assets.
As a result of the GulfTerra Merger, we have revised and renamed our reportable business segments, as discussed below. We have revised our prior segment information, to the extent practicable, in order to conform to the current business segment presentation.
We have segregated our business activities into four distinct reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services, and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technology or process employed) and products produced and/or sold, as applicable. For a listing of the major components of each of our four new business segments and the principal operating assets included within each of the major components, please see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.
TheOffshore Pipelines & Services business segment consists of (i) approximately 1,000 miles of natural gas pipelines strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico, (ii) ownership interests in four Gulf of Mexico offshore oil pipeline systems aggregating 419 miles and (iii) ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico. In addition, this segment includes ownership interests in four relatively insignificant oil and natural gas producing properties located in the waters offshore of Louisiana.
TheOnshore Natural Gas Pipelines & Services business segment includes natural gas pipeline systems aggregating an approximate 16,100 miles that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. Included in this segment are two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. We also lease a natural gas storage facility located in Texas.
TheNGL Pipelines & Services business segment is comprised of (i) our natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating an approximate 11,730 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.
ThePetrochemical Services business segment includes our four propylene fractionation facilities, isomerization complex, and octane additive production facility. This segment also includes approximately 330 miles of various propylene pipeline systems and a 70-mile hi-purity isobutane pipeline.
The Other non-segment category is presented for financial reporting purposes only to show the historical equity earnings we received from GulfTerra GP and our underlying investment in this entity at December 31, 2003. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the
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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 segments. Therefore, we have segregated equity earnings from GulfTerra GP apart from our other investments to aid in comparability between the periods presented and future periods.
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 suppliers of raw materials or consumers 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 additional information regarding our business segments, please read Note 13 of our Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.
Our gross operating margin amounts were as follows for the periods indicated:
For a reconciliation of non-GAAP gross operating margin to GAAP operating income, please read “Other Items” included within this Item 2.
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The following table illustrates selected average quarterly industry index prices for natural gas, crude oil, selected NGL and petrochemical products and indicative gas processing gross spreads since the beginning of 2003:
Our significant pipeline throughput, plant production and processing volumetric data were as follows for the periods indicated (on a net basis, taking into account our ownership interests):
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The following table summarizes our consolidated revenues, costs and expenses, equity in income of unconsolidated affiliates and operating income for the periods indicated (dollars in thousands):
The strength of the domestic and global economic recoveries continues to drive increased demand for all forms of energy despite higher commodity prices. Our largest NGL consuming customers in the ethylene industry have seen strong demand for their products, which has enabled them to raise prices to mitigate higher fuel and feedstock costs. With the unusually high price of crude oil relative to natural gas, ethane and propane are the preferred feedstocks of the ethylene industry. For the third quarter of 2004, ethane demand by the ethylene industry increased by 22% from the third quarter of 2003 to 809 MBPD and propane demand increased by 23% to 350 MBPD. Early indications are that ethane and propane demand during the fourth quarter of 2004 will also be higher than during the same period in 2003. Even with the ethylene industry currently producing at an annual rate of 58 billion pounds per year, we have not seen a build-up of inventory in either ethane or ethylene supply chains. Our customers are expecting high utilization rates throughout the fourth quarter of 2004 and into 2005. As a result of this strong demand for NGLs, most of our pipelines, fractionators and processing plants realized an increase in volumes.
The effects of Hurricane Ivan, however, have reduced volumes delivered to our facilities in Mississippi and eastern Louisiana since the middle of September 2004. We estimate that this reduction in volumes resulted in a $7 million decrease in gross operating margin for the third quarter of 2004 from what we had expected prior to the storm. We expect that the effects of the hurricane will reduce our previous estimates of gross operating margin for the fourth quarter of 2004 by approximately $18 million. These amounts are prior to any potential reimbursements we may receive from coverage provided by insurance.
As a result of the GulfTerra Merger, we significantly increased our midstream assets located in the Gulf of Mexico. We have several projects that have either recently started operations or are scheduled to become operational soon. Among these are the Marco Polo and Phoenix deepwater projects (began operations during third quarter of 2003), the Front Runner oil pipeline (operations to begin during fourth quarter of 2004) and the Cameron Highway oil pipeline system (started line fill in October 2004). For additional information regarding these projects and our other capital spending, please read “Our Liquidity and Capital Resources – Capital Spending.”
At our Mont Belvieu complex, our NGL fractionators processed on a net basis an average of 139 MBPD during the third quarter of 2004 compared to 133 MBPD during the second quarter of 2004. In October 2004, we started receiving 63 MBPD of new mixed NGL volumes from William’s Rocky Mountain production. Since that time, we have been running at near full capacity and have recently approved a fractionation expansion project that should provide energy efficiencies and increase our capacity at this facility by 15 MBPD.
As a result of global events, we expect that the unusual level of volatility in crude oil, natural gas and NGL prices will continue. The volatility in hydrocarbon prices impacts the prices we charge customers for products and services and those we pay vendors for feedstocks, fuel and other purchases.
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Three months ended September 30, 2004 compared to three months ended September 30, 2003
Costs and expenses increased $775.5 million quarter-to-quarter primarily due to (i) higher product prices and volumes which resulted in an increase in the cost of sales of our NGL and petrochemical marketing activities and (ii) the addition of costs and expenses attributable to our recently acquired South Texas midstream assets. The weighted-average NGL price was 77 CPG for the third quarter of 2004 compared to 54 CPG for the third quarter of 2003.
The following information highlights the significant quarter-to-quarter variances in gross operating margin by business segment:
Offshore Pipelines & Services. Gross operating margin from our Offshore Pipelines & Services segment was $0.7 million for the third quarter of 2004 compared to $1.6 million for the third quarter of 2003. Overall, natural gas throughput volumes were 393 MMBtu/d for the third quarter of 2004 versus 438 MMBtu/d for the same period during 2003. Equity earnings from our Neptune natural gas pipeline investment decreased $0.9 million quarter-to-quarter primarily due to a decrease in volumes from the Brutus and Hickory fields and natural depletion of production fields served by this system.
Onshore Natural Gas Pipelines & Services. Gross operating margin from our Onshore Natural Gas Pipelines & Services segment was $7.2 million for the third quarter of 2004 compared to $5.5 million for the third quarter of 2003. The $1.7 million increase in segment gross operating margin is attributable to higher natural gas prices quarter-to-quarter, which resulted in increased natural gas sales margins for our Acadian subsidiary. Overall, natural gas pipeline throughput volumes were 685 MMBtu/d during the third quarter of 2004 versus 619 MMBtu/d during the same period in 2003. Natural gas prices averaged $5.75 per MMBtu during the third quarter of 2004 compared to $4.97 per MMBtu during the third quarter of 2003.
NGL Pipelines & Services. Gross operating margin from our NGL Pipelines & Services segment was $83.9 million for the third quarter of 2004 compared to $53.3 million for the same period in 2003. Gross operating margin from natural gas processing increased $19.7 million quarter-to-quarter primarily due to improved processing economics in the 2004 period and the addition of $7.8 million of gross operating margin for the month of September 2004 from our newly acquired South Texas midstream assets. Indicative gas processing gross spreads on the U.S. Gulf Coast averaged 26 CPG during the third quarter of 2004 and 10 CPG during the third quarter of 2003, which resulted in an increase in the amount of NGLs extracted. Equity NGL production was 47 MBPD for the third quarter of 2004 compared to 41 MBPD for the third quarter of 2003. Natural gas processing volumes under contracts with fee-based components increased to 1,217 MMcf/d in the third quarter of 2004 from 224 MMcf/d in the third quarter of 2003 reflecting amendments to our natural gas processing contract mix.
Gross operating margin from NGL pipelines increased $3.8 million quarter-to-quarter primarily due to improved results from our Mid-America and Seminole pipelines. Net overall NGL transportation volumes were 1,450 MBPD for the third quarter of 2004 versus 1,323 MBPD during the same period in 2003. Of the 127 MBPD increase in pipeline throughput rates, 120 MBPD of the increase is attributable to Mid-America and Seminole, which experienced stronger demand for services during the 2004 period. Results for the third quarter of 2004 also
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included a $4 million non-cash asset impairment charge associated with our Hattiesburg, Mississippi NGL storage facility.
Gross operating margin from NGL fractionation increased $7.1 quarter-to-quarter primarily due to (i) a 15 MBPD increase in processing volumes at our Norco facility resulting from an expansion we completed in the fourth quarter of 2003 and (ii) the effect of higher prices for NGL volumes sold by Norco that it earns ownership of through percent-of-liquids based fractionation contracts. NGL fractionation volumes were 239 MBPD during the third quarter of 2004 compared to 233 MBPD during the same period in 2003.
Petrochemical Services. Gross operating margin from our Petrochemical Services segment was $35.5 million for the third quarter of 2004 versus $8 million for the third quarter of 2003. The 2003 period includes a non-cash asset impairment charge of $22.5 million related to our investment in BEF, which owns a facility that produces octane additives. Excluding this charge, gross operating margin would have increased $5 million, which was primarily due to a $5.9 million increase in the gross operating margin generated by our octane enhancement business.
Nine months ended September 30, 2004 compared to nine months ended September 30, 2003
Costs and expenses increased $1.5 billion period-to-period primarily due to (i) higher product prices and volumes which resulted in an increase in the cost of sales of our NGL and petrochemical marketing activities and (ii) the addition of costs and expenses attributable to assets and businesses acquired or consolidated since September 30, 2003. The weighted-average NGL price was 68 CPG for the first nine months of 2004 compared to 56 CPG for the same period in 2003.
The following information highlights the significant period-to-period variances in gross operating margin by business segment:
Offshore Pipelines & Services. Gross operating margin from our Offshore Pipelines & Services segment was $2.6 million for the first nine months of 2004 compared to $5.4 million for the same period in 2003. Overall, natural gas throughput volumes were 423 MMBtu/d for the first nine months of 2004 compared to 451 MMBtu/d for the same period in 2003. The $2.8 million decrease in gross operating margin for this segment is attributable to lower equity earnings from our Neptune natural gas pipeline investment.
Onshore Natural Gas Pipelines & Services. Gross operating margin from our Onshore Natural Gas Pipelines & Services segment was $18.9 million for the first nine months of 2004 versus $14.2 million for the same period in 2003. Overall, natural gas pipeline throughput volumes were 650 MMBtu/d during the 2004 period compared to 590 MMBtu/d for the 2003 period. The $4.7 million increase in gross operating margin for this segment is primarily due to higher natural gas transportation and sales volumes for our Acadian subsidiary during the 2004 period. Natural gas prices averaged $5.81 per MMBtu during the first nine months of 2004 compared to $5.65 per MMBtu during the same period in 2003.
NGL Pipelines & Services. Gross operating margin from our NGL Pipelines & Services segment was $231.7 million for the first nine months of 2004 compared to $230.6 million for the same period in 2003. Gross operating margin from natural gas processing increased $11.6 million period-to-period due to improved processing
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economics in the 2004 period; the addition of $7.8 million of gross operating margin for the month of September 2004 from our newly acquired South Texas midstream assets; both partially offset by lower results from our NGL marketing activities in the 2004 period. Indicative gas processing gross spreads on the U.S. Gulf Coast averaged 17 CPG during the first nine months of 2004 compared to 6 CPG during the first nine months of 2003, which resulted in an increase in the amount of NGLs extracted. Equity NGL production was 47 MBPD for the first nine months of 2004 versus 42 MBPD for the same period in 2003. Natural gas processing volumes under contracts with fee-based components increased to 944 MMcf/d for the first nine months of 2004 from 150 MMcf/d in the same period of 2003 reflecting amendments to our natural gas processing contract mix.
Gross operating margin from NGL pipelines decreased $12.6 million period-to-period primarily due (i) a $4 million non-cash asset impairment charge we recognized in the third quarter of 2004 for an NGL storage facility; (ii) a decrease in gross operating margin from our Mid-America and Seminole pipelines primarily due to increased repair, maintenance and fuel costs, including $6.5 million associated with our pipeline integrity inspection program; and (iii) lower gross operating margin from our Lou-Tex NGL pipeline resulting from a 47% decrease in throughput rates. Net NGL transportation volumes were 1,358 MBPD for the first nine months of 2004 versus 1,273 MBPD for the same period in 2003.
Gross operating margin from NGL fractionation increased $2.1 million period-to-period. NGL fractionation volumes were 235 MBPD during the first nine months of 2004 compared to 223 MBPD for the same period in 2003. Gross operating margin from our Norco facility increased by $14.5 million primarily due to (i) a 25 MBPD increase in volumes at our Norco facility resulting from an expansion completed in the fourth quarter of 2003 and (ii) the effect of higher prices for NGL volumes sold by Norco that it earns ownership of through percent-of-liquids based fractionation contracts. The improved results from Norco were partially offset by a $10.6 million decrease in gross operating margin period-to-period from our Mont Belvieu NGL fractionator attributable to the timing of gains and losses associated with the measurement of NGLs in storage pending fractionation. The 2004 period includes $3.5 million in measurement losses versus $4.3 million in measurement gains for the 2003 period.
Petrochemical Services. Gross operating margin from our Petrochemical Services segment was $90.8 million for the first nine months of 2004 versus $51.2 million for the first nine months of 2003. The 2003 period includes a non-cash asset impairment charge of $22.5 million related to our investment in a facility that produces octane additives. Gross operating margin from propylene fractionation increased $9.5 million period-to-period primarily due to higher petrochemical marketing sales volumes, which benefited from the effects of higher polymer grade propylene prices during 2004. Propylene fractionation volumes were 58 MBPD for the first nine months of 2004 versus 57 MBPD during the same period in 2003. Gross operating margin from isomerization decreased by $3.1 million period-to-period primarily due to lower volumes. Isomerization volumes were 73 MBPD for the first nine months of 2004 versus 80 MBPD for the first nine months of 2003.
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As noted under “Recent Developments,” GulfTerra is one of the premier midstream energy companies in the United States. The following information is presented to assist the reader in identifying the magnitude of GulfTerra’s historical results of operations. When considered along with our historical results of operations, we believe this information is useful as an indicator of potential future trends in our combined results of operations now that the GulfTerra Merger is completed. To aid in comparability with our information, we have reclassified GulfTerra’s historical income statement amounts to conform to our method of financial statement presentation.
The following discussion is an analysis of the changes in GulfTerra’s operating income for the periods presented in the preceding table.
GulfTerra’s operating income was $78.3 million for the third quarter of 2004 in comparison to $95.3 million for the third quarter of 2003. The decrease in operating income is primarily attributable to the $19 million gain that GulfTerra recognized in July 2003 on the sale of a 50% interest in Cameron Highway to Valero Energy Corporation. Additionally, operating income decreased quarter-to-quarter due to merger-related costs of $14.4 million that were recognized during the third quarter of 2004. These merger-related costs were primarily for advisory fees, retention bonuses and the repurchase of employee and director unit options. These decreases are offset by increased operating income associated with assets placed in service during the third quarter of 2004, primarily the Marco Polo natural gas and oil pipelines, the Marco Polo TLP and the Phoenix natural gas gathering system. Additionally, operating income increased as a result of a rise in natural gas and NGL prices quarter-to-quarter and increased volumes associated with new production in 2004.
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GulfTerra’s operating income was $252 million for the first nine months of 2004 in comparison to $254.6 million for the first nine months of 2003. The decrease in operating income is partially attributable to the $19 million gain that GulfTerra recognized in July 2003 on the sale of a 50% interest in Cameron Highway to Valero Energy Corporation. Additionally, operating income decreased due to merger-related costs of $22.2 million that were recognized during the first nine months of 2004. These merger-related costs were primarily for advisory fees, retention bonuses and the repurchase of employee and director unit options. These decreases are offset by increased operating income associated with assets placed in service during the third quarter of 2004, primarily the Marco Polo natural gas and oil pipelines, the Marco Polo TLP and the Phoenix natural gas gathering system. Additionally, operating income increased as a result of a rise in natural gas and NGL prices period-to-period and increased volumes associated with new production in 2004. Operating income on the Texas intrastate pipeline system increased period-to-period primarily as a result of increased fee based revenues and the revaluation of natural gas imbalances, and operating income for the NGL pipeline systems increased period-to period due to increased volumes as one of the pipelines was down for maintenance through the third quarter of 2003.
Pro Forma Financial Information
Please read Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements for information regarding the pro forma effects of the GulfTerra Merger and related transactions on our historical earnings.
Our primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures, business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources (either separately or in combination) including cash flows from operating activities, borrowings under commercial bank credit facilities, the issuance of additional partnership equity and public or private placement debt. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.
As noted above, certain of our liquidity and capital resource requirements are fulfilled by borrowings made under debt agreements and/or proceeds from the issuance of additional partnership equity. On September 30, 2004, we had approximately $5.6 billion in principal outstanding under various debt agreements, including $921.5 million of GulfTerra senior and senior subordinated notes consolidated on that date as a result of completing the GulfTerra Merger. Our September 30, 2004 Unaudited Condensed Consolidated Balance Sheet also reflects $1.1 billion of cash held in escrow (classified as a component of “Restricted Cash” on that date) that was used on October 5, 2004 to complete our tender offers for GulfTerra’s senior and subordinated notes. For additional information regarding our debt, please read “– Our debt obligations.”
Effective registration statements
We have on file with the SEC a $1.5 billion universal shelf registration statement covering the issuance of an unallocated amount of partnership equity or public debt obligations (separately or in combination). Since June 2003, we have sold 48,410,317 common units under this registration statement. In May 2004, we sold 17,250,000 common units under this registration statement from which we received net proceeds of $353.1 million, including Enterprise GP’s proportionate net capital contribution of $7.1 million. In August 2004, we sold 17,250,000 common units under this registration statement from which we received net proceeds of $341.2 million, including Enterprise GP’s proportionate net capital contribution of $6.8 million. In October and November 2004, we sold 1,950,317 common units under this registration statement from which we received net proceeds of $39.6 million, including
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Enterprise GP’s proportionate net capital contributions. After deducting for these 2003 and 2004 equity offerings, the amount available for future offerings under this shelf registration statement is approximately $480 million.
In April 2004, we filed a new registration statement with the SEC covering an additional 10,000,000 common units issuable under our Distribution Reinvestment Plan (or “DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional common units. The new registration statement increased the number of common units issuable under the DRIP from 5,000,000 to 15,000,000. We expect to use the cash generated from this reinvestment program primarily for general partnership purposes. Since its inception in August 2003 through September 30, 2004, we have issued 5,794,624 common units under this and a related program generating net proceeds (including Enterprise GP’s proportionate net capital contributions) of approximately $122 million. This amount includes 1,053,510 common units issued in February 2004, 1,729,904 common units issued in May 2004 and 173,033 common units issued in August 2004, which together generated proceeds of approximately $61 million. In November 2004, we issued an additional 2.2 million common units under this program, which generated net proceeds of approximately $49.3 million (including Enterprise GP’s proportionate net capital contribution).
To support our growth objectives and financial flexibility, EPCO has reinvested approximately $105 million of its cash distributions since August 2003 through the DRIP (including $50 million during the first nine months of 2004). In addition, EPCO has announced that it expects to reinvest an additional $60 million of its anticipated quarterly distributions through the first quarter of 2005.
As a result of our growth objectives, we expect to access debt and equity capital markets from time-to-time and we believe that additional financing arrangements to support our goals can be obtained on reasonable terms. Furthermore, we believe that maintenance of an investment grade credit rating combined with continued ready access to debt and equity capital at reasonable rates and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and short-term liquidity and capital resource requirements.
In May 2003, GulfTerra issued 80 Series F convertible units in a registered offering to an institutional investor. Each Series F convertible unit is comprised of two separate detachable units – a Series F1 convertible unit and a Series F2 convertible unit – that have identical terms except for vesting and termination dates and the number of common units into which they may be converted. Prior to the GulfTerra Merger, all the Series F1 convertible units were converted. As a result of the GulfTerra Merger, we assumed GulfTerra’s obligations associated with the 80 Series F2 convertible units. All Series F2 convertible units outstanding at the merger date were converted into rights to receive Enterprise common units. The number of Enterprise common units and the price per unit at conversion were adjusted based on the 1.81 exchange ratio. The Series F2 convertible units were convertible into up to $40 million of Enterprise common units.
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The following discussions highlight significant period-to-period comparisons in consolidated operating, investing and financing cash flows:
Cash flows from operating activities primarily reflect net income adjusted for depreciation, amortization and similar non-cash amounts; equity earnings and cash distributions from unconsolidated affiliates and changes in operating accounts. The net effect of changes in operating accounts is generally the result of timing of cash receipts from sales and cash payments for purchases and other expenses near the end of each period. In addition, operating cash inflows and outflows related to increases or decreases in inventory are influenced by changes in commodity prices and our marketing activities. Cash flow from operations is primarily based on earnings from our business activities. As a result, these cash flows are exposed to certain risks.
We operate predominantly in the midstream energy sector, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. In general, we provide services for producers and consumers of natural gas, NGLs and crude oil from the wellhead to the end user. The products that we process, sell or transport are principally used as fuel for residential, agricultural and commercial heating, feedstocks in petrochemical manufacturing, and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products or increased competition from other service providers or producers due to pricing differences or other reasons could have a negative impact on our earnings and thus the availability of cash from operating activities. Other risks include fluctuations in oil, natural gas and NGL prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. For additional information regarding
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risk factors pertinent to our business, please read “Cautionary Statement Regarding Forward-Looking Information and Risk Factors” on page 54 of this quarterly report.
Operating activities. For the nine months ended September 30, 2004 and 2003, cash provided by operating activities was $33 million and $222.7 million, respectively. As shown in the preceding table, cash flow before the net effect of changes in operating accounts was an inflow of $273.5 million for the 2004 period versus $218.7 million for the 2003 period. We believe that cash flow from operating activities before the net effect of changes in operating accounts is an important measure of our ability to generate core cash flows from our assets and other investments. The period-to-period fluctuation in the net effect of changes in operating accounts primarily reflects increased expenditures for inventories, which are mainly attributable to significantly higher commodity prices and slightly higher volumes held in inventory.
Distributions received from our equity method unconsolidated affiliates were $54.6 million for the 2004 period compared to $25.7 million for the 2003 period and equity income received from our equity method unconsolidated affiliates was $42.2 million for the 2004 period compared to a loss of $16.6 million for the 2003 period. The increases in these components of our cash flows is primarily due to cash distributions and equity income received from GulfTerra GP and VESCO, offset by the effects of consolidating former equity method investments as a result of acquisitions. As a result of the GulfTerra Merger, GulfTerra GP became a wholly-owned subsidiary of the Operating Partnership (see Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report). On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16 (See Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report). The period-to-period fluctuation in the restricted cash balance is primarily due to the timing of physical purchases of natural gas on the NYMEX exchange.
Investing activities. For the nine months ended September 30, 2004 and 2003, we used $734.7 million and $153.5 million, respectively, for investing activities. During 2004, we used $637.3 million to complete the GulfTerra Merger. Additionally, during 2004, we used $57.9 million to purchase an additional 16.7% membership interest in Tri-States, a 10% equity interest in Seminole and the remaining 33.3% ownership interests in BEF. The 2003 period included our purchases of the Port Neches Pipeline, the remaining 50% ownership interest in EPIK and an additional 33.33% interest in BEF. Capital expenditures were $38.9 million for the 2004 period versus $98 million for the 2003 period. For additional information regarding our capital expenditures, please read “Capital Spending” on page 79. Our investments in and advances to unconsolidated affiliates for the 2003 period included amounts we contributed to our Gulf of Mexico natural gas pipeline investments for their expansion capital projects.
Financing activities. Our financing activities were a cash inflow of $817.9 million during the first nine months of 2004 versus a cash outflow of $42.8 million during the first nine months of 2003. During the first nine months of 2004, we had net borrowings under our debt agreements of $1.4 billion compared to net repayments of $356.8 million for the same period in 2003. On September 30, 2004, we borrowed approximately $2.8 million under our new 364-Day Acquisition Revolving Credit Facility and Multi-Year Revolving Credit Facility “B” to (a) fund $655.3 million in cash payment obligations to El Paso under Steps Two and Three of the GulfTerra Merger transactions, (b) escrow $1.1 billion to finance our tender offers for GulfTerra’s senior and senior subordinated notes and (c) extinguish $962 million outstanding under GulfTerra’s revolving credit facility and secured term loans. Our repayments of debt during the first nine months of 2004 reflect the use of proceeds from our May 2004 and August 2004 equity offerings to repay the $225 million Interim Term Loan and to temporarily reduce amounts outstanding under our pre-merger revolving credit facilities. The 2003 period reflects our issuance of Senior Notes C ($350 million in principal amount) and Senior Notes D ($500 million in principal amount) and the final repayment of $1 billion that was outstanding under the bridge loan financing we used to purchase interest in the Mid-America and Seminole pipelines. Repayments of debt during the first nine months of 2003 also reflect the use of proceeds from our January 2003 and June 2003 equity offerings.
Cash distributions to partners increased from $223.4 million during the first nine months of 2003 to $278.6 million during the same period in 2004. The increase in cash distributions is primarily due to an increase in both the declared quarterly distribution rates and the number of units eligible for distributions. We expect that future cash distributions to partners will increase as a result of our periodic issuance of common units under the DRIP and other equity offerings.
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Net proceeds from the sale of common units were $755.9 million for the first nine months of 2004 compared to $540.2 million for the same period in 2003. Both amounts include Enterprise GP’s net proportionate capital contributions. In May 2004, we sold 17,250,000 common units to the public (including the underwriters’ overallotment amount of 2,250,000 common units) at an offering price of $21.00 per unit. Net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution of $7.1 million, were $353.1 million after deducting applicable underwriting discounts, commissions and offering expenses of $16.3 million. In August 2004, we sold 17,250,000 common units to the public (including the underwriters’ overallotment amount of 2,250,000 common units) at an offering price of $20.20 per unit. Net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution of $6.8 million, were approximately $341.2 million after deducting applicable underwriting discounts, commissions and offering expenses of $13.9 million. The 2004 period also includes $61.9 million in proceeds from the sale of 2,912,864 common units in connection with our DRIP, the proceeds of which were primarily used for working capital purposes. Proceeds from the issuance of common units during the first nine months of 2003 were $540.2 million and reflect the sale of 14,662,500 and 11,960,000 common units in our January 2003 and June 2003 equity offerings, respectively, and the sale of 1,268,404 common units in connection with our DRIP.
On September 30, 2004, we borrowed approximately $2.8 billion under revolving credit facilities to (a) fund $655.3 million in cash payment obligations to El Paso under Steps Two and Three of the GulfTerra Merger transactions, (b) escrow $1.1 billion to finance our tender offers for GulfTerra’s senior and senior subordinated notes and (c) extinguish $962 million outstanding under GulfTerra’s revolving credit facility and secured term loans. Our long-term debt at September 30, 2004 includes the remaining debt obligations of GulfTerra as appropriate in consolidation.
On October 4, 2004, we completed our issuance of $2 billion in Rule 144A private placement senior notes (Senior Notes E, F, G, and H) and used the proceeds to reduce borrowings made under our new revolving credit facilities on September 30, 2004. On October 5, 2004, we used the $1.1 billion in escrowed funds to complete our cash tender offers for substantially all of GulfTerra’s senior and senior subordinated notes. As a result of the significant changes in the composition of our long-term debt between September 30 and October 5, the following discussion of our debt obligations is focused on our current obligations.
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The following summarizes significant aspects of our debt obligations at September 30, 2004 and October 5, 2004:
GulfTerra’s Senior Subordinated and Senior Notes. As a result of completing the GulfTerra Merger on September 30, 2004, we recorded in consolidation GulfTerra’s $921.5 million of outstanding senior and senior subordinated notes. Of this amount, $915 million was purchased on October 5, 2004 by our Operating Partnership pursuant to its tender offers. The note holders also approved amendments in connection with accepting the tender offers that removed all restrictive covenants governing the notes. For additional information regarding the tender offers, please read ” – 364-Day Acquisition Revolving Credit Facility – Tender offers for GulfTerra senior and senior subordinated notes” within this general description of debt.
364-Day Acquisition Revolving Credit Facility. In August 2004, our Operating Partnership entered into a new 364-day revolving credit agreement. The $2.25 billion Acquisition Revolving Credit Facility is an unsecured 364-day facility that was used to provide interim financing for certain transactions associated with the GulfTerra Merger, the refinancing of GulfTerra’s existing secured credit facility and term loans and the purchase of GulfTerra’s senior and senior subordinated notes in connection with our Operating Partnership’s tender offers for those notes. This facility became effective concurrent with the closing of the GulfTerra Merger and will mature on September 29, 2005. The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to Enterprise GP. We have guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.
As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate.
This credit agreement provides for the mandatory prepayment of loans and termination of commitments equal to the proceeds from and upon the consummation of any public or private debt or equity offerings by us on or after August 15, 2004, excluding equity issued with respect to our distribution reinvestment plan, employee unit purchase plan and the exercise of any outstanding options with respect to our common units. With the completion of our Rule 144A private placement offering of senior notes on October 4, 2004, we repaid approximately $2 billion borrowed under this facility, which reduced our borrowing capacity under this facility by an equal amount.
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Tender offers for GulfTerra senior and senior subordinated notes
On August 4, 2004, in anticipation of completing the GulfTerra Merger, our Operating Partnership commenced four cash tender offers to purchase any and all of the outstanding senior and senior subordinated notes of GulfTerra having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, GulfTerra executed supplements to the indentures governing these notes that eliminated certain restrictive covenants and default provisions contained in those indentures upon our purchase of more than a majority in principal amount of each series of the outstanding senior and senior subordinated notes.
Substantially all of the GulfTerra notes ($915 million of $921.5 million) were tendered pursuant to the tender offers. On September 30, 2004, we borrowed $1.1 billion under our 364-Day Acquisition Revolving Credit Facility in anticipation of completing the tender offers and placed these funds in escrow. On October 5, 2004, our Operating Partnership purchased the notes for a total price of approximately $1.1 billion, which included $27 million related to consent payments.
The following table shows the four GulfTerra senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by Enterprise to complete the tender offers.
Multi-Year Revolving Credit Facility “B.” In August 2004, our Operating Partnership entered into a five-year $750 million revolving credit agreement that includes a sublimit of $100 million for standby letters of credit. This facility became effective concurrent with the closing of the GulfTerra Merger and will mature on September 30, 2009. This facility replaced our existing $270 million Multi-Year Revolving Credit Facility “A” and $230 million 364-Day Revolving Credit Facility, which were terminated upon the effective date of the new facility. The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to Enterprise GP. We have guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.
As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate. This revolving credit agreement contains various covenants similar to those of our 364-Day Acquisition Revolving Credit Facility.
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Senior Notes issued on October 4, 2004. On September 23, 2004, our Operating Partnership priced a Rule 144A private placement 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. On October 4, 2004, these notes were issued. The interest rate, principal amount and net proceeds, before expenses, for each senior note in this offering are shown in the following table:
Industrial Development Revenue Bonds. In April 2004, Petal Gas Storage L.L.C.(“Petal”), a wholly-owned subsidiary of GulfTerra, borrowed $52 million from the Mississippi Business Finance Corporation (“MBFC”) pursuant to a loan agreement between Petal and the MBFC. On the same date, the MBFC issued $52 million in Industrial Development Revenue Bonds to another wholly-owned subsidiary of GulfTerra. The loan agreement and the Industrial Development Revenue Bonds have identical fixed interest rates of 6.25% and maturities of fifteen years. The bonds and the associated tax exemptions are authorized under the Mississippi Business Finance Act. Petal may repay the loan agreement without penalty, and thus cause the Industrial Development Revenue Bonds to be redeemed, any time after one year from their date of issue. We have netted the loan amount and the bond amount of $52 million and the interest payable and interest receivable amount of $1.4 million on our Unaudited Condensed Consolidated Balance Sheet as of September 30, 2004. Beginning in the fourth quarter of 2004, we will also net the interest expense and interest income amounts attributable to these instruments on our Statements of Consolidated Operations. Our presentation of the Industrial Development Revenue Bonds is reflected in accordance with the provisions of FIN No. 39, “Offsetting of Amounts Related to Certain Contracts”, and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities”, since we have the ability and intent to offset these items.
Loss due to write-off of unamortized debt issuance costs. As a result of terminating our 364-Day Revolving Credit Facility and our Multi-Year Revolving Credit Facility “A” on September 30, 2004, we expensed $0.7 million of unamortized debt issuance costs.
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The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable rate debt obligations during the nine months ended September 30, 2004:
The following table shows aggregate maturities of the principal amounts of long-term debt and other financing obligations for the remainder of 2004 and the following 4 years and in total thereafter at September 30, 2004 (i) on an actual basis and (ii) on a pro forma basis adjusted for debt-related subsequent events as described in the footnotes thereto.
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Please read Note 10 of our Unaudited Condensed Consolidated Financial Statements for additional information regarding the joint venture debt obligations.
In May 2004, Moody’s Investors Service lowered its corporate credit ratings on Enterprise from Baa2 (investment grade) with a stable outlook to Baa3 (investment grade) with a negative outlook. In September 2004, Moody’s Investor Service affirmed its rating on our outstanding senior unsecured notes of Baa3 (investment grade) and changed its rating outlook on us from negative to stable.
In May 2004, Standard & Poor’s lowered its corporate credit ratings on Enterprise from BBB- (investment grade) with a negative outlook to BB+ (non-investment grade) with a stable outlook. It reaffirmed these ratings in September 2004.
In August 2004, Fitch Ratings initiated ratings coverage of our outstanding senior unsecured notes. Fitch assigned a rating to our notes of BBB- (investment grade) with a stable outlook.
Depending on our future operating results, these credit rating agencies may view our current levels of debt negatively. If one or more of these credit rating agencies were to downgrade our credit standing, we could experience an increase in our borrowing costs, difficulty accessing capital markets or a reduction in the market price of our common units. Such a development could adversely affect our ability to obtain financing for working capital, capital expenditures, acquisitions and to refinance indebtedness.
The May 2004 downgrade of our credit ratings resulted in an increase in our short-term borrowing costs. Our revolving credit facilities contain applicable margin provisions that can increase the interest rates and facility fees we pay our lenders when certain credit rating criteria are lowered. In general, the May 2004 downgrades increased the Eurodollar-based interest rates we were paying by 0.2% and facility fees by 0.05%. Our other borrowing interest rates were not affected.
Additionally, if our credit rating by Moody’s declines below Baa3 in combination with our credit rating at Standard & Poor’s remaining at BB+ or below, the $54 million principal balance of our MBFC Loan, and all related accrued and unpaid interest would become immediately due and payable 120 days following such event. If such an event occurred, we would have to redeem the MBFC Loan or provide an alternative credit agreement to support our obligation under the MBFC Loan.
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As a result of the GulfTerra Merger and related transactions, our material contractual obligations associated with debt, operating leases and other long-term liabilities increased significantly from the levels shown in our Annual Report on Form 10-K for the year ended December 31, 2003. Our debt obligations increased as a result of borrowings made to complete the GulfTerra Merger, including the issuance of $2 billion in senior notes on October 4, 2005. Our operating lease commitments increased as a result of assuming the payment obligations relating to three storage facilities located in Texas (one natural gas and two NGL facilities). We also consolidated $42.4 million of other long-term liabilities of GulfTerra, which includes an estimated $21 million environmental reserve for remediation costs expected to be incurred over time associated with mercury gas meters. As of September 30, 2004, we had approximately $62 million in outstanding purchase commitments related to our share of capital projects, the majority of which pertain to pipeline and platform growth projects in the Gulf of Mexico. There was no material change in our other product purchase and service contract commitments as a result of the GulfTerra Merger.
The following table summarizes our current material contractual obligations related to debt and operating leases:
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For the nine months ended September 30, 2004 and 2003, our capital spending for business combinations (including non-cash consideration amounts), property, plant and equipment and our unconsolidated affiliates was $3.6 billion and $145.4 million, respectively. The following table summarizes our capital spending by activity for the periods indicated:
We are committed to the long-term growth and viability of the Company. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. In recent years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which we operate. We forecast that this trend will continue, and expect independent oil and natural gas companies to consider similar divestitures. Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. We believe that the Company is positioned to continue to grow through acquisitions that will expand its platform of assets and through growth capital projects. The combination of our operations with those of GulfTerra provide us with incremental growth opportunities for both onshore and offshore projects. We currently estimate that our capital spending over the next two to three years could approximate up to $2 billion, primarily for growth projects in the Gulf of Mexico and Western regions of North America.
For the remainder of 2004, we estimate our capital spending for property, plant and equipment at $124 million. We have a number of ongoing capital projects, including those we assumed as a result of the GulfTerra Merger (see the following discussion, “Growth Capital Projects of GulfTerra”). Our expenditure forecast of $124 million reflects $58 million in onshore and offshore natural gas pipeline and storage projects and $51 million in NGL pipeline and plant projects. An additional $20 million is expected to be spent to modify our octane additive production facility to produce iso-octane. We also expect to invest approximately $38 million in the capital projects of our unconsolidated affiliates during the remainder of 2004. As of September 30, 2004, we had approximately $62 million in outstanding purchase commitments related to our share of capital projects, the majority of which pertain to pipeline and platform growth projects in the Gulf of Mexico.
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Growth Capital Projects of GulfTerra
Prior to the merger, GulfTerra had a number of midstream energy projects underway. The following information provides an update on these projects.
Cameron Highway oil pipeline. In September 2004, Cameron Highway, our 50% owned equity method investment, completed construction of the Cameron Highway oil pipeline. This 390-mile crude oil pipeline system has a transport capacity of approximately 500 MBPD and connects various designated crude oil receipt points extending from Ship Shoal Block 332 in the Gulf of Mexico to onshore delivery points located in the state of Texas. In July 2003, GulfTerra sold a 50% interest in Cameron Highway, which owns the Cameron Highway oil pipeline, to Valero for $86 million, forming a joint venture with Valero. Pursuant to the joint venture agreements, Valero is obligated to pay $5 million to GulfTerra now that the system is completed and another $11 million by the end of 2006.
Additionally, in July 2004, Cameron Highway executed an agreement with Kerr-McGee for the dedication and movement of crude oil production from the Constitution and Ticonderoga fields, along with other future production from several undeveloped blocks in the south Green Canyon area of the deepwater trend of the Gulf of Mexico. Under the terms of the agreement, production from Kerr-McGee’s interest in Constitution, Ticonderoga and surrounding undeveloped blocks is dedicated to the Cameron Highway oil pipeline system for the life of the reserves. Cameron Highway expects volumes from these fields in the first half of 2006.
Marco Polo TLP and related oil and natural gas pipelines. The Marco Polo TLP was installed in the first quarter of 2004 and commenced operations in July 2004. The Marco Polo TLP has a maximum handling capacity of 120 MBPD of oil and 300 MMcf/d of natural gas. This TLP was designed and located to process oil and natural gas from Anadarko Petroleum Corporation’s Marco Polo field located in Green Canyon Block 608. Deepwater Gateway, our 50% owned equity method investment which owns the Marco Polo TLP, began receiving monthly demand payments of $2.1 million in April 2004 and volumetric payments started in July 2004. We expect that the Marco Polo TLP will begin receiving production volumes from the K2 and K2 North Fields in the Green Canyon Block during the first quarter of 2005.
In addition to our 50% ownership interest in the Marco Polo TLP, we own 100% of the Marco Polo oil and natural gas export pipelines that transport production processed on the Marco Polo TLP to downstream markets. Construction on these export lines was completed in July 2004. The Marco Polo oil pipeline is a 36-mile, 14-inch oil pipeline with a transport capacity of 120 MBPD that interconnects with our Allegheny oil pipeline in Green Canyon Block 164. The Marco Polo natural gas pipeline is a 75-mile, 18-inch to 20-inch natural gas pipeline with a capacity of 400 MMcf/d that interconnects with our Typhoon natural gas pipeline in Green Canyon Block 236.
Phoenix gathering system. In July 2004, GulfTerra commenced operations of its 78-mile, 18-inch Phoenix natural gas gathering system, which has a transport capacity of 450 MMcf/d that interconnects with El Paso’s ANR Pipeline system at Vermillion Block 397. The Phoenix natural gas gathering system gathers production from the Red Hawk Field, in which Kerr-McGee and Devon Energy Corporation each hold a 50% working interest. Kerr-McGee and Devon have dedicated multiple blocks at and in the proximity of the Red Hawk Field to this pipeline system for the life of the reserves, subject to certain release provisions.
Constitution gathering system. In July 2004, GulfTerra entered into a definitive agreement to construct, own, and operate oil and natural gas pipelines to provide production gathering services for the Constitution field, which is 100% owned by Kerr-McGee Oil & Gas Corporation. The Constitution field is located in 5,300 feet of water in Green Canyon Blocks 679 and 680 in the Central Gulf of Mexico. The new natural gas pipeline will be a 32-mile, 16-inch pipeline with a transport capacity of up to 200 MMcf/d and will connect to our existing Anaconda Gathering System (the combination of our Marco Polo natural gas pipeline and our Typhoon natural gas pipeline). The new oil pipeline will be a 70-mile, 16-inch pipeline with a minimum transport capacity of 80 MBPD that will connect with the Cameron Highway oil pipeline and Poseidon oil pipeline systems at the new Ship Shoal 332B platform. These pipelines are expected to cost $130 million to construct, and we plan to start construction in early 2005, with the first transportation volumes scheduled for the first half of 2006. We expect to fund this construction project through internally generated funds and borrowings under our revolving credit facilities. As of September 30, 2004, GulfTerra had spent $2.1 million related to the construction of this new system.
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Front Runner oil pipeline. In July 2004, Poseidon, our 36% owned equity method investment, completed construction of its 36-mile, 14-inch Front Runner oil pipeline. We expect that this system will transport its first volumes late in the fourth quarter of 2004. The new oil pipeline has a capacity of 65 MBPD and connects the Front Runner platform with Poseidon’s existing pipeline system at Ship Shoal Block 332. In October 2003, Poseidon began withholding distributions to their partners to fund its capital expenditures related to the Front Runner oil pipeline. Since Poseidon has completed construction of this pipeline, we expect to start receiving distributions again in late 2004 or early 2005.
Petal conversion project. In the third quarter of 2004, GulfTerra began to convert an existing brine well at its propane storage complex in Hattiesburg, Mississippi to natural gas service. This conversion will cost approximately $17 million and will create a new 1.8 Bcf natural gas storage cavern that will be integrated with our Petal natural gas storage facility. We expect to have the cavern in service during the first quarter of 2005. In the second quarter of 2004, GulfTerra executed long-term storage agreements with BP Energy Company for the entire capacity of the new natural gas cavern. As of September 30, 2004, GulfTerra had spent $1 million on this conversion project.
San Juan optimization project. In May 2003, GulfTerra commenced a $43 million project relating to the San Juan Basin assets. This project is expected to be completed in stages through 2006 and will result in increased capacity of up to 130 MMcf/d on the San Juan gathering system and increased market opportunities through a new interconnect at the tailgate of the Chaco plant. As of September 30, 2004, GulfTerra had spent $9.7 million on this project.
Purchase options associated with retained leases
EPCO contributed various equipment leases to us at our formation in 1998 for which EPCO has retained the cash payment obligations (the “retained leases”). EPCO has assigned to us the purchase options associated with the retained leases. During 2003, we exercised our option to purchase an isomerization unit and in October 2004 purchased the unit at a cost of $15 million, which approximated fair value. Should we decide to exercise the remaining purchase options associated with the retained leases (which are also at fair value), an additional $2.8 million would be payable in 2004, $2.3 million in 2008 and $3.1 million in 2016.
Pipeline Integrity Costs
Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs. In connection with the new regulations for hazardous liquid pipelines, we developed a pipeline integrity management program in 2002. We are currently preparing an integrity management program for our natural gas pipelines, which must be completed by December 2004.
During the first nine months of 2004, we spent approximately $11.5 million to comply with these new regulations, of which $6.8 million was recorded as an operating expense of our NGL Pipelines & Services segment. Based on information currently available, our cash outlays for this program (on a post-merger basis) through 2008 are estimated as follows: $5 million for remainder of 2004; $58 million for 2005; $50 million for 2006; $73 million for 2007; and $62 million for 2008.
These forecasted costs for 2005 and 2006 are net of an indemnification GulfTerra received from El Paso prior to the GulfTerra Merger. In April 2002, GulfTerra acquired several midstream assets located in Texas and New Mexico from El Paso (the “EPN Holdings” acquisition). These assets included the Texas Intrastate Pipelines, the Permian Basin gas gathering system and the Indian Basin gas plant. Pursuant to the purchase and sale agreement between GulfTerra and El Paso for these assets, El Paso agreed to indemnify GulfTerra against any and all pipeline integrity costs incurred (whether paid or payable) with respect to the EPN Holding assets for each year through December 31, 2006, to the extent that such annual costs exceed $5 million.
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EITF 03-06, “Participating Securities and the Two-Class Method under SFAS No. 128.”This accounting guidance, which is applicable for the period beginning April 1, 2004, requires the two-class method for calculating earnings per share for certain securities that are considered to participate in earnings with common shareholders. Under the two-class method, distributions to equity owners are subtracted from earnings, and any remaining earnings would be allocated to the various classes of owners in proportion to their right to receive distributions as if those earnings had been distributed. The total distributions to each class of owner plus the amount allocated to each class would be used to compute earnings per unit for that class. Since our distributions to owners exceeded earnings during the periods presented, as has historically been the case, the two-class method did not produce any change from the way we have traditionally computed earnings per unit. As a result, our adoption of this standard had no effect on our earnings per unit calculations.
EITF 03-16, “Accounting for Investments in Limited Liability Companies.”This accounting guidance requires that an investment in a LLC that has separate ownership accounts for each investor be accounted for similar to a limited partnership investment under SOP No. 78-9, “Accounting for Investments in Real Estate Ventures.” Under this new guidance (applicable for the period beginning July 1, 2004), investors are required to apply the equity method of accounting to their investments at a much lower ownership threshold (typically any ownership interest greater than 3-5%) than the 20% threshold applied under APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” Our implementation of this accounting guidance is discussed under Note 1 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.
In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect.
As a result of the GulfTerra Merger, we have modified our critical accounting policies to include certain policies that we deemed to be critical in the financial reporting process of the combined company. The following information summarizes the estimation risk underlying our most significant financial statement items:
Depreciation methods and estimated useful lives of property, plant and equipment
In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. We use the straight-line method to depreciate the majority of our property, plant and equipment. Our estimate of an asset’s useful life is based on a number of assumptions including technological changes that may affect the asset’s usefulness and the manner in which we intend to physically use the asset. If we subsequently change our assumptions regarding these factors, it would result in an increase or decrease in depreciation expense.
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At September 30, 2004 and December 31, 2003, the net book value of our property, plant and equipment was $7.7 billion and $3 billion. For additional information regarding our property, plant and equipment, please read Note 5 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.
Measuring recoverability of long-lived assets and equity method investments
Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Long-lived assets with recorded values that are not expected to be recovered through future expected cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the existing asset. Our estimates of such undiscounted cash flows are based on a number of assumptions including anticipated margins and volumes; estimated useful life of the asset or asset group; and salvage values. An impairment charge would be recorded for the excess of the long-lived asset’s carrying value and its fair value, which is based on a series of assumptions similar to those used to derive undiscounted cash flows but incorporating probabilities that reflect a range of possible outcomes and market value and replacement cost estimates.
Equity method investments are evaluated for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is an other than temporary decline. Examples of such events or changes include continued operating losses of the investee or long-term negative changes in the investee’s industry. The carrying value of an equity method investment is not recoverable if it exceeds the sum of discounted estimated cash flows expected to be derived from the investment. This estimate of discounted cash flows is based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful life of the investment.
Due to a deteriorating business environment, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of its long-lived assets exceeded their collective fair value, which resulted in a non-cash impairment charge of $67.5 million. Since BEF was one of our equity investments at that time, our share of this loss was $22.5 million and was recorded as a component of “Equity in income (loss) of unconsolidated affiliates” in our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2003. As a consolidated subsidiary, BEF continues to review its operations on quarterly basis due to the challenging and uncertain business environment in which it operates.
In order to complete the GulfTerra Merger, we are required under a consent decree published for comment by the FTC on September 30, 2004 to sell our undivided 50% interest in a Mississippi propane storage facility by December 31, 2004. As a result of our determination of this long-lived asset’s current market value, we recorded a non-cash $4 million asset impairment charge during the third quarter of 2004 that is a component of operating costs and expenses. The nominal fair value of this facility was reclassified from “Property, Plant and Equipment” to “Assets Held for Sale” on our Unaudited Condensed Consolidated Balance Sheet at September 30, 2004. The operating results of this facility (including the recent asset impairment charge) are not material to our historical or ongoing operations; therefore, these results have not been presented as discontinued operations in our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income.
Amortization methods and estimated useful lives of qualifying intangible assets
At September 30, 2004 and December 31, 2003, the carrying value of our intangible asset portfolio was $961.9 million and $268.9 million. As a result of the GulfTerra Merger, the preliminary value allocated to intangible assets was $705.1 million. Our intangible assets primarily consist of the estimated value assigned to certain customer relationships and contract-based assets.
Our customer relationship intangible assets represent the customer base that GulfTerra and the South Texas midstream assets serve through providing services, including natural gas gathering and processing, NGL fractionation and pipeline transportation. These businesses conduct the majority of their business through the use of
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written contracts; thus, the customer relationships represent the rights we own arising from those contractual agreements. The value of these customer relationships are being amortized on a straight-line basis over the estimated economic life of the resource base to which they relate, which we estimate could range from 18 to 43 years depending on the asset. Our estimate of the economic life of each resource based is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other factors.
Our contract-based intangible assets represent the rights we own arising from contractual agreements. A contract-based intangible asset with a finite useful life is amortized over its estimated useful life. Our estimate of useful life is based on a number of factors, including the expected useful life of related assets (i.e., fractionation facility, pipeline, etc.) and the effects of obsolescence, demand, competition and other factors.
If our underlying assumptions regarding the useful life of an intangible asset change, we then might need to adjust the amortization period of such asset which would increase or decrease amortization expense. Additionally, if we determine that an intangible asset’s unamortized cost may not be recoverable due to impairment, this would result in a charge against earnings. For additional information regarding our intangible assets, please read Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.
Methods we employ to measure the fair value of goodwill
Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired. Goodwill is not amortized. Instead, goodwill is tested for impairment at a reporting unit level annually, and more frequently, if circumstances warrant. This testing involves calculating the fair value of a reporting unit, which in turn is based on our assumptions regarding the future economic prospects of the reporting unit. If the fair value of the reporting unit (including related goodwill) is less than its book value, a charge to earnings would be required to reduce the carrying value of goodwill to its implied fair value. If our underlying assumptions regarding the future economic prospects of a reporting unit change, this could further impact the fair value of the reporting unit and result in an additional charge to earnings to reduce the carrying value of goodwill.
At September 30, 2004 and December 31, 2003, the carrying value of our goodwill was $445.9 million and $82.4 million. As a result of the GulfTerra Merger, we recorded a preliminary estimate of $363.5 million for goodwill. For additional information regarding our goodwill, please read Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.
Our revenue recognition policies and use of estimates for revenues and expenses
In general, we recognize revenue from our customers when all of the following criteria are met: (i) firm contracts are in place, (ii) delivery has occurred or services have been rendered, (iii) pricing is fixed and determinable and (iv) collectibility is reasonably assured. When contracts settle (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), we determine if an allowance is necessary and record it accordingly. Historically, the consolidated revenues we recorded were not materially based on estimates.
However, we expect our use of estimates for revenues, as well as our use of estimates for operating costs and other expenses to increase as a result of the GulfTerra Merger and related transactions and as a result of SEC regulations which require us to submit financial information on increasingly accelerated time frames. Such estimates are necessary due to the timing of compiling actual billing information and receiving third-party data needed to record transactions for financial reporting purposes. One example of such use of estimates would be the accrual of an estimate of revenue and the cost of natural gas for a given month (prior to receiving actual customer and vendor-related information for the subject period). This accrual would reverse in the following month and be offset by the corresponding actual customer billing and vendor-invoiced amounts. Accordingly, there would always be one month of estimated data in results of operations. Such estimates are generally based on actual volume and price data through the first part of the month and then extrapolated to the end of the month, adjusted accordingly for any known or expected changes in volumes or rates through the end of the month. If the basis of our estimates proves incorrect, it could result in material adjustments in results of operations between periods.
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Reserves for environmental matters
Each of our business segments is subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations are applicable to each segment and require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. We currently have a reserve for environmental matters related to remediation costs expected to be incurred over time associated with mercury meters. We assumed this liability in connection with the GulfTerra Merger. New environmental developments, such as increasingly strict environmental laws and regulations and new claims for damages to property, employees, other persons and the environment resulting from current or past operations, could result in substantial cost and future liabilities. We accrue reserves for environmental matters when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Our assessments are based on studies, as well as site surveys, to determine the extent of any environmental damage and the necessary requirements to remediate this damage. Our actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon the outcome or expectations based on the facts surrounding each exposure.
As of September 30, 2004, our Onshore Natural Gas Pipelines & Services segment had a liability for environmental remediation of $21 million, which was derived from a range of reasonable estimates based upon GulfTerra’s previous studies and site surveys. In accordance with Statement of Financial Accounting Standards No. 5 “Accounting for Contingencies” and FASB Interpretation No. 14, “Reasonable Estimation of the Amount of a Loss,” we recorded our best estimate of the loss.
Natural gas imbalances
Natural gas imbalances result from differences in gas volumes received from and delivered to our customers and arise when a customer delivers more or less gas into our pipelines than they take out. We estimate the value of our imbalances at prices representing the estimated value of the imbalances upon settlement. Changes in natural gas prices may impact our estimates. We do not value our imbalances based on current month-end spot prices because it is not likely that we would purchase or receive natural gas at that point in time to settle the imbalance. Prior to the GulfTerra Merger, natural gas imbalances were not a significant part of our business.
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 O.S. Andras who is Chief Executive Officer and a director and Vice Chairman of Enterprise GP. The principal business activity of Enterprise GP is to act as our managing partner. Collectively, EPCO and its affiliates owned a 36.2% equity interest in Enterprise at September 30, 2004, which includes their ownership interest of Enterprise GP (of which EPCO and its affiliates own 90.1%).
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On October 22, 2004, the Administrative Services Agreement was amended further to evidence our separateness from other persons and entities, to reflect a five-year license we granted for EPCO’s use of service marks owned by us and to provide for reimbursement of EPCO’s costs of discontinuing the use of those service marks over the term of the license. This amendment also provides that if EPCO and its affiliates are offered by a third party, or discover an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by the Operating Partnership or in a line of business that would be a natural extension of any business then being conducted by the Operating Partnership (a “Business Opportunity”), EPCO shall promptly advise the Board of Directors of Enterprise GP of such Business Opportunity and offer such Business Opportunity to the Operating Partnership. If the Board of Directors of Enterprise GP does not advise EPCO within 10 days following the receipt of such notice that we wish to pursue such Business Opportunity, EPCO shall then be permitted to pursue such Business Opportunity. If the Board of Directors of Enterprise GP advises EPCO within such 10 day period that we want to pursue such Business Opportunity, EPCO shall not be permitted to pursue such Business Opportunity unless the Board of Directors of Enterprise GP subsequently advises EPCO that it has abandoned its pursuit of such Business Opportunity.
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Non-GAAP reconciliation
A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles (as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income included under Item 1 of this quarterly report) follows:
EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100 railroad tankcars for $1 dollar per year. These subleases (the “retained lease expense” in the previous table) are part of the Administrative Services Agreement that we executed with EPCO in connection with our formation in 1998. EPCO holds these items pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. Operating costs and expenses (as shown in the Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income included under Item 1 of this quarterly report) treat the lease payments being made by EPCO as a non-cash related party operating expense, with the offset to Partners’ Equity on the Unaudited Condensed Consolidated Balance Sheets recorded as a general contribution to the Company. Apart from the partnership interests we granted to EPCO at our formation, EPCO does not receive any additional ownership rights as a result of its contribution to us of the retained leases.
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EPCO has assigned to us the purchase options associated with the retained leases. We exercised our options to purchase an isomerization unit and related equipment during the first nine months of 2004 at a cost of $15 million. Should we decide to exercise all of the remaining purchase options associated with the other retained leases (which are also at fair value), an additional $2.8 million would be payable in 2004, $2.3 million in 2008 and $3.1 million in 2016.
Cumulative effect of changes in accounting principles
As shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income, the cumulative effect of changes in accounting principles represent the combined impact of (i) changing 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) changing the method in which we account for our investment in VESCO from the cost method to the equity method.
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For the periods indicated, the following table shows pro forma net income and earnings per unit amounts assuming the accounting changes noted above were applied retroactively to January 1, 2003.
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We recognize our financial instruments on the balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We assess the cash flow risk related to interest rates by identifying and measuring changes in our interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the expected impact of changes in interest rates on our future cash flows. Enterprise GP oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.
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Total fair value of the interest rate swaps in effect at September 30, 2004 was a receivable of approximately $1 million with an offsetting increase in fair value of the underlying debt. Interest expense in our Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2004 reflects a $1.7 million and $5.3 million benefit, respectively, from these swaps.
The following tables show the effect of hypothetical price movements on the estimated fair value (“FV”) of our interest rate swaps and the related change in fair value of the underlying debt at the dates indicated (dollars in thousands):
The fair value of the interest rate swaps excludes the benefit we have already recorded in earnings. The change in fair value between September 30, 2004 and October 19, 2004 is primarily due to a decrease in market interest rates. The underlying floating LIBOR interest rates used to determine the October 19, 2004 values ranged from approximately 2% to 5.7% using 6-month reset periods ranging from October 2004 to October 2014.
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In April 2004, we elected to terminate the initial four forward starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. In September 2004, we settled the remaining four swaps resulting in an $85.1 million payment to the counterparties. The net gain of $19.4 million from these settlements will be amortized over the life of the associated debt as a reduction in Accumulated Other Comprehensive Income to interest expense.
The following table shows the notional amount covered by each forward starting swap and the cash gain (loss) associated with each swap upon settlement (dollars in thousands):
We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by Enterprise GP. We may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. Enterprise GP oversees the strategies associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.
We had a limited number of commodity financial instruments in our portfolio at September 30, 2004. The following tables show the effect of hypothetical price movements on the estimated fair value (“FV”) of this portfolio at the dates indicated (dollars in thousands):
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At September 30, 2004, our portfolio primarily consisted of natural gas cash flow and fair value hedges. The change in fair value of the portfolio between September 30, 2004 and October 15, 2004 was primarily due to an increase in natural gas prices. The underlying forecasted settlement prices for natural gas reflected in the October 15, 2004 values ranged from approximately $5.70 per MMBtu to $8.50 per MMBtu for settlement periods ranging from the fourth quarter of 2004 through March 2005.
Effect of financial instruments on AOCI
The following table summarizes the effect of our cash flow hedging financial instruments on Accumulated Other Comprehensive Income (“AOCI”) since January 1, 2003. Information for the first nine months of 2004 has been presented by quarter (dollars in thousands).
Our management, with the participation of the CEO and CFO of Enterprise GP, has evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting, as of the end of the period covered by this report. Collectively, these disclosure controls and procedures are designed to provide us with a reasonable assurance that the information required to be disclosed in periodic reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including Enterprise GP’s CEO and CFO, as appropriate to allow such persons to make timely decisions regarding required disclosures.
Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of the end of the period covered by this report, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.
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Based on their evaluation, the CEO and CFO of Enterprise GP have concluded that our disclosure controls and procedures are effective to ensure that material information relating to our partnership is made known to management on a timely basis. The CEO and CFO noted no material weaknesses in the design or operation of our internal controls over financial reporting that are likely to adversely affect our ability to record, process, summarize and report financial information. Also, they detected no fraud involving management or employees who have a significant role in our internal controls over financial reporting.
Other than the events discussed under “The GulfTerra Merger transactions” below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) or in other factors that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
On September 30, 2004, we completed the GulfTerra Merger. Since the GulfTerra Merger closed during the day on September 30, 2004, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income do not include any earnings from GulfTerra because the amounts were immaterial. The effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. Our Unaudited Condensed Consolidated Balance Sheet at September 30, 2004 includes the accounts of both GulfTerra and the South Texas midstream assets that we recorded in purchase accounting. In recording the GulfTerra Merger, we followed our normal accounting procedures and internal controls. Our management also reviewed the one month of operations of the South Texas midstream assets that are included in our earnings for the third quarter of 2004. In addition, we solicited disclosure information from former GulfTerra (now Enterprise) employees using our Section 302 procedures regarding the current business environment in which GulfTerra and the South Texas midstream assets operate. We are continuing to integrate our internal controls into these operations and it is contemplated that this effort will continue during the remainder of 2004 and into future fiscal quarters of 2005. As described below, these businesses will be excluded from our fiscal 2004 internal control assessment.
The certifications of our general partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this quarterly report on Form 10-Q.
Fiscal 2004 Sarbanes-Oxley Section 404 Internal Control Assessment
As noted above, we completed the GulfTerra Merger on September 30, 2004, which on a combined basis met the criteria of being a material acquisition for us.
On June 22, 2004, the Office of the Chief Accountant of the SEC issued guidance regarding the reporting of internal controls over financial reporting in connection with a major acquisition. On October 6, 2004, the SEC revised its guidance to include expectations of quarterly reporting updates of new internal controls and the status of the controls regarding any exempted businesses.
On October 18, 2004, the Disclosure Committee of Enterprise GP met and voted to recommend the exclusion of GulfTerra and the South Texas midstream assets from the scope of Enterprise’s Sarbanes-Oxley Section 404 report on internal controls over financial reporting for the year ended December 31, 2004 which is due in March 2005. A summary of the reasons for exclusion follow:
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See Part I, Item 1, Financial Statements, Note 16, “Litigation,” which is incorporated herein by reference.
We did not repurchase any of our common units during the three and nine month period ended September 30, 2004. As of September 30, 2004, we and our affiliates are authorized to repurchase up to 618,400 common units under the December 1998 common unit repurchase program. Any common units repurchased under this publicly announced program are classified as treasury units.
None.
On December 15, 2003, the board of directors of Enterprise GP and the board of directors of GulfTerra GP agreed to combine the businesses of Enterprise and GulfTerra by merging a wholly-owned subsidiary of Enterprise into GulfTerra. As a result of the GulfTerra Merger, GulfTerra became a wholly-owned subsidiary of Enterprise. The issuance of Enterprise common units pursuant to the GulfTerra Merger agreement required the approval of Enterprise common unitholders. In addition, we solicited approval from our unitholders to convert our Class B special units to common units on a one-for-one basis.
We held a special meeting of our common unitholders to vote on these matters in Houston, Texas on July 29, 2004. The proxy solicitation materials were first mailed to unitholders on or about June 24, 2004. GulfTerra also held a special meeting of its unitholders in Houston, Texas on July 29, 2004. At this meeting, GulfTerra’s common and Series C unitholders were asked by the board of directors of GulfTerra’s general partner to approve and adopt the GulfTerra Merger agreement with Enterprise.
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The following table summarizes the results of these special meetings:
As a result of votes tabulated at the Enterprise special meeting held on July 29, 2004, both measures were approved by our common unitholders.
As a result of the votes tabulated at the GulfTerra special meeting held on July 29, 2004, GulfTerra’s common and Series C unitholders approved and adopted the GulfTerra Merger agreement with Enterprise.
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# Filed with this report.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this quarterly report on Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on November 9, 2004.
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