For the quarterly period ended March 31, 2004 or
For the transition period from _______ to _______.
Commission file number: 1-14323
ENTERPRISE PRODUCTS PARTNERS L.P. (Exact name of Registrant as specified in its charters)
Registrant’s Telephone Number, including area code: (713) 880-6500
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YES [X] NO [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
There were 229,661,604 common units and 4,413,549 Class B special units of Enterprise Products Partners L.P. outstanding at May 5, 2003. Enterprise Products Partners L.P.’s Common Units trade on the New York Stock Exchange under symbol “EPD.”
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. including its consolidated subsidiaries is a publicly traded Delaware limited partnership listed on the NYSE under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. Certain abbreviated 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 Enterprise Products Company (“EPCO”). 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”). We and our General Partner are affiliates of EPCO.
In the opinion of Enterprise, the accompanying unaudited 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 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 month period ended March 31, 2004 are not necessarily indicative of the results to be expected for the full year.
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.
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE represents the effect of changing the method our majority owned BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method. These major maintenance costs, which typically result in facility shutdowns for 30 to 45 days, are principally comprised of amounts paid to third parties for materials, contract services, and other related items.
We have historically used the expense-as-incurred method for planned major maintenance activities. The change in accounting for our majority owned BEF subsidiary conforms the Company’s accounting for all planned major maintenance costs and changes the method to better reflect 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, which is shown separately in the Statement of Consolidated Operations and Comprehensive Income for 2004, resulted in a benefit of $7 million. See Note 14 for information regarding the effect of the accounting change on basic and diluted earnings per unit.
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For the periods indicated, the following table shows pro forma net income and earnings per unit amounts assuming the accounting change was applied retroactively to January 1, 2003:
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.
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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 03-16, “Accounting for Investments in Limited Liability Companies.” This accounting guidance requires that investments in limited liability companies (or “LLCs”) that have 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 would be 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.”
Currently, we account for our 13.1% investment in Venice Energy Services Company, LLC (“VESCO”) using the cost method. As a result, we have recognized dividend income from VESCO to the extent that we have received cash distributions from them. In accordance with the new accounting guidance in EITF 03-16, we will record a retroactive cumulative effect adjustment equal to the difference between (i) equity earnings from VESCO that would have been recorded using the equity method in prior periods and (ii) the dividend income from VESCO that was recorded using the cost method. We are currently studying the effect that EITF 03-16 will have on our investment in VESCO; however, based on information available, we do not believe that the implementation of this new accounting guidance will have a material effect on our financial statements.
We did not enter into any business acquisitions during the first quarter of 2004; however, we are still expecting completion of the proposed merger with GulfTerra during the second half of 2004. In general, the proposed merger with GulfTerra involves the following three steps:
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We anticipate that our obligations under Steps Two and Three of the proposed merger to pay El Paso $650 million will be financed initially with a short-term acquisition term loan and with borrowings under our revolving credit facilities.
Our preliminary estimate of the total consideration for Steps One, Two and Three we would pay or issue is approximately $4.0 billion. For a period of three years following the closing of the proposed merger, at our request El Paso will provide certain support services to GulfTerra similar to those provided by El Paso prior to the closing of the merger. GulfTerra will reimburse El Paso for 110% of its direct costs for such services (excluding any overhead costs). El Paso will make transition support payments to us in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. These transition support payments are included in our preliminary estimate of total consideration.
A number of conditions must be satisfied before we can complete the merger, including approval by the unitholders of both Enterprise and GulfTerra and the expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1974. While we cannot predict if and when all of the conditions of the proposed merger will be satisfied, we expect to complete the transaction in the second half of 2004.
To review a copy of the merger agreement and related transaction documents, please read our Current Reports on Form 8-K filed with the SEC on December 15, 2003 and April 21, 2004.
Our inventories were as follows at the dates indicated:
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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 March 31, 2004 and 2003, we recognized $4.2 million and $10.4 million, respectively, of LCM adjustments.
Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:
Depreciation expense for the three months ended March 31, 2004 and 2003 was $26.8 million and $24.1 million, respectively.
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We own interests in a number of related businesses that are accounted for using the equity or cost methods. The investments in and advances to these unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of business segments, see Note 13. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated:
Our initial investment in Promix, La Porte, Dixie, Tri-States, Neptune, Nemo and GulfTerra GP exceeded our share of the historical cost of the underlying net assets of such entities (“excess cost”). The excess cost amounts are reflected in our investments in and advances to unconsolidated affiliates for these entities. That portion of excess cost attributable to tangible or amortizable intangible assets of each entity is amortized over the estimated useful of the underlying asset(s) as a reduction in equity earnings from the investee. That portion of excess cost attributable to goodwill or non-amortizable intangible assets is not amortized. Equity method investments, including their associated excess cost amounts, 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. The following table summarizes our excess cost information at March 31, 2004 and December 31, 2003 by the business segment to which the unconsolidated affiliates relate:
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The Pipelines section in the preceding table includes $337.5 million of excess cost attributable to goodwill, of which $328.2 million results from our December 2003 purchase of a 50% membership interest in GulfTerra GP. The allocation of the $328.2 million of excess cost to goodwill (which represents potential intangible assets, excess of fair values over carrying values of tangible assets, and remaining goodwill, if any) is preliminary pending completion of a fair value analysis which is expected to be completed during the last half of 2004. The table below shows the potential decrease in equity earnings from GulfTerra GP if certain amounts included in this excess cost were ultimately assigned to tangible or amortizable intangible assets. For purposes of calculating this sensitivity, we have applied the straight-line method of cost allocation over an estimated useful life of 20-years to various fair values.
The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:
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The following table presents summarized income statement information for our unconsolidated affiliates accounted for using the equity method (for the periods indicated, on a 100% basis).
Expected change in accounting method for VESCO
As a result of newly issued accounting guidance per EITF 03-16, we expect to change our method of accounting for VESCO from the cost method to the equity method on July 1, 2004. The VESCO investment consists of a 13.1% membership interest in a limited liability company that owns a natural gas processing plant, NGL fractionation facilities, storage assets and gas gathering pipelines located in south Louisiana.
Intangible assets
The following table summarizes our amortizable intangible assets at the dates indicated:
All of the intangible assets noted in the preceding table are subject to amortization. Amortization expense for the three months ended March 31, 2004 and 2003 was $3.8 million and $3.6 million, respectively. For the remainder of 2004, amortization expense attributable to these intangible assets is currently estimated at $11.5 million.
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Goodwill
The following table summarizes our goodwill amounts at March 31, 2004 and December 31, 2003 (excluding amounts included in the carrying value of unconsolidated affiliates – See Note 6).
Relationship with EPCO
We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is also a director (and Chairman of the Board of Directors) of our General Partner. In addition, the remaining executive and other officers of our General Partner are employees of EPCO, including O.S. Andras who is President and Chief Executive Officer and a director of the General Partner. The principal business activity of the General Partner is to act as our managing partner. Collectively, EPCO and its affiliates owned 56.6% of Enterprise at March 31, 2004, which includes the 2% ownership interest of our General Partner (of which EPCO and its affiliates own 100%).
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 costs related to management or administrative support for us.
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.
Relationship with Shell
We have a significant commercial relationship with Shell as a partner, customer and vendor. At March 31, 2004, Shell owned an approximate 18.3% equity interest in Enterprise. Shell is our largest customer. 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.
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Relationship with unconsolidated affiliates
Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie and purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix.
The following table summarizes our related party revenues, operating costs and expenses, and selling, general and administrative costs for the periods indicated:
Our common and Class B special 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 Third Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”). Our common units trade on the NYSE under the ticker symbol “EPD.” We are managed by our General Partner.
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 the General Partner in its sole discretion (subject, under certain circumstances, to the approval of our unitholders). In February 2004, we issued 1,053,861 common units primarily in connection with our distribution reinvestment plan (“DRIP”) for which we received net proceeds of approximately $23.1 million, including our General Partner’s proportionate net capital contribution of $0.5 million. We used the proceeds from the February 2004 DRIP offering for general partnership purposes. See Note 16 for information regarding our May 2004 equity offering of 15,000,000 common units. During the first quarter of 2004, we reissued 240,983 treasury units at a cost of $5.1 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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Our debt consisted of the following at the dates indicated:
Scheduled future maturities of long-term debt. We have long and short-term payment obligations under credit agreements such as our Senior Notes and revolving credit facilities. Scheduled future maturities of debt at March 31, 2004 were: $240 million due in 2004; $615 million due in 2005; $54 million due in 2010; $450 million due in 2011; $350 million due in 2013; and $500 million due in 2033. On May 5, 2004, we used $307 million in net proceeds from our May 2004 equity offering to repay the $225 million Interim Term Loan and approximately $80 million to temporarily reduce debt outstanding under our revolving credit facilities.
Parent-Subsidiary guarantor relationships. We act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Seminole Notes. If the Operating Partnership were to default on any debt we
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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 78.4% of its capital stock).
Covenants. We were in compliance with the various covenants of our debt agreements at March 31, 2004 and December 31, 2003.
Information regarding variable interest rates paid
The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable rate debt obligations for the three months ended March 31, 2004:
The net effect of changes in operating assets and liabilities is as follows for the periods indicated:
Cash and cash equivalents (as shown on our Statements of Consolidated Cash Flows) excludes restricted cash 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. The restricted cash balance at March 31, 2004 and December 31, 2003 was $8.0 million and $13.9 million, respectively.
We recorded certain fair value amounts related to our interest rate hedging financial instruments during the first quarter of 2004 that affected various balance sheet accounts. For information regarding our financial instruments, see Note 12.
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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 and cash flows 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 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 the Statement of Operations and Comprehensive Income for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses on a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.
To qualify as a hedge, the item to be hedged must expose us to price risk, interest rate risk or changes in fair value 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 is recorded into earnings immediately.
Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance about implementation issues. Since this guidance is still continuing, our conclusions regarding the application of guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of this guidance.
Interest rate risk hedging program
Our interest rate exposure results from variable and fixed rate borrowings under debt agreements (see Note 10). 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 to estimate the expected impact of changes in interest rates on our future cash flows. The General Partner 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 risks by utilizing interest rate swaps and similar arrangements. The objective of entering into this type of arrangement is to manage debt service costs by converting a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. In general, an interest rate swap requires one party to pay a fixed interest rate on a defined (or “notional”) amount while the other party pays a variable rate based on the same notional amount. The notional amount specified in an interest rate swap agreement does not represent exposure to credit loss. We monitor our positions and the credit ratings of counterparties. Management believes the risk of incurring a credit loss on these financial instruments is remote, and that if incurred, such losses would be minimal. We believe that it is prudent to maintain an appropriate balance of variable rate and fixed rate debt.
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Fair value hedges – Interest rate swaps. On January 8, 2004, we entered into three interest rate swap agreements under 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:
We have designated these 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. These agreements have a combined notional amount of $250 million and match the maturity dates of the underlying debt being hedged. Under the swap agreements, we pay the counterparty a variable rate based on LIBOR (plus an applicable margin) and receive back from the counterparty a fixed rate payment equal to the stated interest rate of the debt being hedged, based on the notional amounts for each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”).
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. However, the interest rate swaps effectively converted a portion of the underlying fixed rate debt (i.e., the notional amounts hedged for Senior Notes B and C) into variable rate debt. As a result, interest expense will vary depending on the variable rates payable by us under terms of the swap agreements at the end of each settlement period. To the extent that the variable rate amount payable by us at the end of each settlement period is less than the fixed rate amount receivable from the counterparty, we will amortize the difference ratably to earnings as a reduction in interest expense over the settlement period. If the variable rate payable by us at the end of each settlement period is more than the fixed rate amount receivable from the counterparty, we would amortize this difference ratably to earnings as an increase in interest expense over the settlement period.
Total fair value of the interest rate swaps at March 31, 2004 was approximately $6.4 million with an offsetting increase in fair value of the underlying debt. Interest expense in our Statement of Consolidated Operations and Comprehensive Income for the three months ended March 31, 2004 reflects a $1.7 million benefit from these swaps.
Cash flow hedges – Forward starting interest rate swaps. On March 17, 2004, we entered into four forward starting interest rate swap transactions with original maturities of September 30, 2004. A forward starting swap is an agreement that effectively hedges the price on a specific U.S. treasury security for an established period of time. The purpose of these transactions was to effectively hedge the underlying U.S. treasury interest rate associated with our anticipated issuance of debt to refinance the existing debt of GulfTerra after the proposed merger is completed (see Note 3). The forward starting interest rate swaps have been designated as cash flow hedges under SFAS No. 133. The notional amount of the anticipated debt issuances was $2 billion.
On April 23, 2004, we elected to terminate these financial instruments in order to monetize the then current value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. This amount will be amortized over the life of the anticipated debt (when issued) as a reduction to interest expense. The following table shows the portfolio of forward starting swaps categorized by the term of the underlying anticipated debt offering:
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The non-cash fair value of the forward starting interest rate swaps at March 31, 2004 was $17.0 million and was recorded as a component of AOCI in our Statement of Consolidated Partners’ Equity and as an addition to comprehensive income in our Statement of Consolidated Operations and Comprehensive Income for the three months ended March 31, 2004. When the $104.5 million cash settlement is recorded during the second quarter of 2004, it will replace the $17.0 non-cash fair value amount in AOCI and comprehensive income.
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 our Processing segment activities, we may enter into various 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. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.
We do not hedge our exposure related to MTBE price risks. In addition, we generally do not hedge risks associated with the petrochemical marketing activities that are part of our Fractionation segment. In our Pipelines segment, we utilize a limited number of commodity financial instruments to manage the price Acadian Gas charges or pays certain of its customers for natural gas. Lastly, we do not employ commodity financial instruments in our fee-based marketing business classified under the Other segment.
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 the General Partner. We 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. The General Partner oversees our 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.
Our commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133 (as amended and interpreted). In those situations where the financial instrument does not qualify for hedge accounting treatment, the instrument is accounted for using mark-to-market accounting, which results in a degree of non-cash earnings volatility that is dependent upon changes in the commodity prices underlying these financial instruments. Even though these financial instruments may not qualify for hedge accounting treatment under SFAS No. 133, we view such contracts as hedges since this was the intent when we entered into such positions. Upon entering into such positions, our expectation is that the economic performance of these instruments will mitigate (or offset) the commodity risk being addressed. The specific accounting for these contracts; however, is consistent with the requirements of SFAS No. 133.
The fair value of our commodity financial instrument portfolio at March 31, 2004 and December 31, 2003 and the results of our commodity hedging activities for the three months ended March 31, 2004 and 2003 were both
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nominal amounts. During both the first quarter of 2004 and the first quarter of 2003, we utilized a limited number of commodity financial instruments.
Operating segments are components of a business about which separate financial information is available. These components are regularly evaluated by the chief operating decision maker 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.
We have five reportable business (or operating) segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. Our reportable segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the CEO of the General Partner. Pipelines consists of NGL, petrochemical and natural gas pipeline systems, storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization, and propylene fractionation services. Processing includes the natural gas processing business and its related NGL marketing activities. Octane Enhancement represents our investment in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE and isobutylene). The Other business segment consists of fee-based marketing services and various operational support activities.
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 segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. 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 primarily along the western Gulf Coast in Texas, Louisiana and Mississippi. Our pipelines and related operations are in a number of regions of the United States including the
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Gulf of Mexico offshore Louisiana (certain natural gas pipelines); the south and southeastern United States (primarily in the Texas, Louisiana and Mississippi regions); and certain regions of the central and western United States. The Mid-America pipeline system extends from the Hobbs hub located on the Texas-New Mexico border to Wyoming along one route and to Minnesota, Wisconsin and Illinois along other routes. 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 property is construction-in-progress. Segment property represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not generally contribute to segment gross operating margin, these assets are not included in the operating segment totals until they are deemed operational. Consolidated intangible assets and goodwill are allocated to the segments based on the classification of the assets to which they relate.
The following table shows our measurement of total segment gross operating margin for the periods indicated:
A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP consolidated operating income (as shown on our Statements of Consolidated Operations and Comprehensive Income) follows:
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Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table:
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Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of common and subordinated units and Class B special units outstanding during a period. In general, diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the sum of:
In a period of net operating losses, the Class A special units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. Treasury units are not considered to be outstanding units; therefore, they are excluded from the computation of both basic and diluted earnings per unit.
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.
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:
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The following table shows 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. We have no independent operations and no material assets outside of those of the Operating Partnership. In December 2003, we restructured our General Partner’s ownership interest in us and the Operating Partnership from a 1% ownership in us and 1.0101% ownership in the Operating Partnership to a 2% ownership in us. As a result, our effective ownership in the Operating Partnership increased from 98.9899% to 100%.
The Operating Partnership has outstanding publicly traded debt securities consisting of its Senior Notes A, B, C and D. We act as guarantor of all of our Operating Partnership’s consolidated debt obligations (including its publicly-traded debt securities), with the exception of the Seminole Notes. 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 the Operating Partnership’s debt obligations is full and unconditional. For additional information regarding our consolidated debt obligations, see Note 10.
The number and dollar amount of reconciling items between our consolidated financial statements and those of our Operating Partnership are insignificant. The primary reconciling items between the consolidated balance sheet of the Operating Partnership and our 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. The minority interest differences are attributable to the General Partner’s 1.0101% ownership of the Operating Partnership prior to December 2003.
The following tables show condensed financial information for the Operating Partnership for the periods and at the dates indicated:
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Interest Rate Hedging Program
In March 2004, we entered into forward starting interest rate swaps in anticipation of entering into permanent debt financing for the proposed merger with GulfTerra. In late April 2004, we terminated these arrangements and received approximately $104.5 million in cash. This amount will be amortized as a reduction in interest expense over the life of the future planned debt issuances, which are forecasted to take place during the second half of 2004. Please see Note 12 for additional information regarding these financial instruments.
May 2004 equity offering
In May 2004, we sold 15,000,000 common units to the public at an offering price of $21.00 per unit. Net proceeds from this offering, including our General Partner’s proportionate net capital contribution of $6 million, were approximately $307 million after deducting applicable underwriting discounts, commissions and offering expenses of $14.3 million. The net proceeds from this offering, including our General Partner’s proportionate net capital contribution, were used to repay in full our $225 million Interim Term Loan and to temporarily reduce borrowings under our revolving credit facilities.
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Enterprise Products Partners L.P. including its consolidated subsidiaries is a publicly traded Delaware limited partnership listed on the NYSE under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our” 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.
The following discussion and analysis should be read in conjunction with our unaudited 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.
Cautionary Statement regarding Forward-Looking Information and Risk Factors
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.
Risk Factors
Among the key risk factors that may have a direct impact on our results of operations and financial condition are:
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Proposed merger with GulfTerra
We expect to complete the proposed merger with GulfTerra in the second half of 2004. A number of conditions must be satisfied before we can complete the merger, including approval by the unitholders of both Enterprise and GulfTerra and the expiration or termination of applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1974. While we cannot predict if and when all of the conditions of the proposed merger will be satisfied, we expect to complete the transaction in the second half of 2004.
In April 2004, we and El Paso agreed to amend certain terms of the merger agreement. In the original transaction, in connection with Step Two of the proposed merger (as described below), El Paso was to exchange its 50% membership interest in GulfTerra GP for a 50% membership interest in our General Partner. Under the amended transaction, in connection with Step Two of the proposed merger, El Paso will still contribute its 50% membership interest in GulfTerra GP to our General Partner, but in exchange will receive a 9.9% membership interest in our General Partner and $370 million in cash. The remaining 90.1% membership interest in our General Partner will continue to be owned by affiliates of EPCO. The funds for the $370 million payment to El Paso will be provided by affiliates of EPCO.
El Paso, through its 9.9% membership in our General Partner, will have protective veto rights on certain transactions, such as any merger of our General Partner or any merger involving and resulting in a change of control of us. In addition, commencing six months after the closing of the proposed merger, or earlier in certain circumstances, El Paso will have the right to exchange its 9.9% membership interest in our General Partner for a number of common units equal to 9.9% of the aggregate quarterly distribution paid by us to our General Partner divided by the preceding quarterly distribution per unit paid to the holders of our common units. Our General Partner may elect to deliver (i) Enterprise common units owned by our General Partner (which it may acquire from an affiliate of EPCO), (ii) an equivalent cash amount or (iii) a combination of cash or common units. Three and a half years after closing of the proposed merger, the affiliates of EPCO that own the 90.1% membership interest in our General Partner can require El Paso to contribute all of its membership interest in our General Partner to the General Partner.
In general, the proposed merger with GulfTerra involves the following three steps:
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Recontracting of natural gas processing agreements
We recently 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 the recontracting effort, approximately 70% of the natural gas we processed was done so 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.
Beginning in the second quarter of 2004, approximately two-thirds of the 2.1 Bcf/d natural gas we expect to process will be done so under contracts containing a fee-based component. This compares to 50 MMcf/d of fee-based volumes prior to recontracting. Approximately one-third of the natural gas we expect to process, or 0.7 Bcf/d, will be under percent-of-liquids contracts compared to 0.5 Bcf/d processed under such arrangements previously. We forecast that our share of NGLs earned under percent-of-liquids contracts will increase to approximately 5 MBPD from the 4 MBPD earned prior to restructuring our processing agreements.
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To provide our partnership with the opportunity to earn additional gross operating margin above that provided by the 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 fees we would earn) without exposing our partnership to the risk of incremental cash losses. Approximately 50% of the natural gas we expect to process during 2004 is under 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 March 2004, we entered into forward starting interest rate swaps in anticipation of entering into permanent debt financing for the proposed merger with GulfTerra. In late April 2004, we terminated these arrangements and received approximately $104.5 million in cash. For additional information regarding these financial instruments, please read “Interest rate risk” included under Item 3 of this quarterly report.
In May 2004, we sold 15,000,000 common units to the public at an offering price of $21.00 per unit. Net proceeds from this offering, including our General Partner’s proportionate net capital contribution of $6 million, were $307 million after deducting applicable underwriting discounts, commissions and offering expenses of $14.3 million. The net proceeds from this offering, including our General Partner’s proportionate net capital contribution, were used to repay in full our $225 million Interim Term Loan and to temporarily reduce borrowings under our revolving credit facilities.
We have five reportable business (or operating) segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. Pipelines consists of NGL, petrochemical and natural gas pipeline systems, storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization and propylene fractionation. Processing includes our natural gas processing business and related NGL marketing activities. Octane Enhancement represents our investment in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE and isobutylene). The Other business segment consists of fee-based marketing services and various operational support activities.
We define total segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. 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
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intercompany transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation.
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 additional information regarding our business segments, please read Note 13 of our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
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):
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 Statements of Consolidated Operations and Comprehensive Income) treat the lease payments being made by EPCO as a non-cash related party operating expense, with the offset to Partners’ Equity on the 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.
EPCO also assigned to us the purchase options associated with these leases. We notified the lessor of the isomerization unit associated with the retained leases of our intent to exercise the purchase option relating to this equipment in 2004. Under the terms of the lease agreement for the isomerization unit, we have the option to purchase the equipment at the lesser of fair value or $23.1 million. Should we decide to exercise all of the remaining purchase options associated with the retained leases (which are also at fair value), up to an additional $2.8 million would be payable in 2004, $2.3 million in 2008 and $3.1 million in 2016.
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Our gross operating margin amounts by segment were as follows for the periods indicated (dollars in thousands):
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 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 2002:
As a result of continued improvement of the economy, we have experienced an increase in demand for our midstream energy services when compared to the second half of 2003. Our largest NGL customers are experiencing stronger demand for their products and expect that this demand will be sustainable throughout 2004. In addition, natural gas prices have decreased relative to other forms of energy. This has made NGLs more competitive versus crude oil derivatives such as naphtha and gas oil for use as a feedstock in ethylene production. As a result, demand for ethane has increased. Average ethane demand by the ethylene industry for the first quarter of 2004 was 718 MBPD, which is comparable to the fourth quarter of 2003 and represents a 13% increase over ethane demand rates of the second and third quarters of 2003. The five-year average demand for ethane by the ethylene industry is approximately 750 MBPD.
Three months ended March 31, 2004 compared to three months ended March 31, 2003
Revenues for the first quarter of 2004 increased $223.3 million over those recorded during the same period in 2003 primarily due to higher NGL marketing revenues resulting from an increase in sales volumes. Likewise, operating costs and expenses increased $234.8 million quarter-to-quarter primarily due to an increase in cost of sales related to NGL marketing activities. The weighted-average NGL price was 64 CPG during the first quarter of 2004 compared to 63 CPG during the first quarter of 2003. Natural gas prices averaged $5.69 per MMBtu during the 2004 period versus $6.58 per MMBtu during the 2003 period.
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Earnings from equity method unconsolidated affiliates increased $11.8 million quarter-to-quarter primarily due to $10.6 million recorded from GulfTerra GP in the first quarter of 2004. We acquired a 50% membership interest in GulfTerra GP from El Paso in December 2003. Selling, general and administrative costs decreased $2 million quarter-to-quarter. The first quarter of 2003 includes amounts paid to Williams for transition services that were discontinued in February 2003 when we began operating the Mid-America and Seminole pipeline systems. As a result of the aforementioned results, operating income increased $2.3 million quarter-to-quarter.
Interest expense decreased $9.3 million quarter-to-quarter primarily due to $11.3 million of unamortized loan costs which were expensed during the first quarter of 2003 when we repaid the bridge loan financing associated with our acquisition of interests in the Mid-America and Seminole pipelines. When compared to the first quarter of 2003, dividend income was $1.4 million lower due to a decrease in dividends received from VESCO.
The $7.0 million benefit recorded as a cumulative effect of change in accounting principle is due to our BEF subsidiary changing its method of accounting for planned major maintenance activities. For additional information regarding this non-cash item, please read ”– Other items – Cumulative effect of change in accounting principle recorded in first quarter of 2004” on page 47. Including this adjustment, net income was $58.5 million for the first quarter of 2004 compared to $40.5 million for the first quarter of 2003.
The following information highlights the significant quarter-to-quarter variances in gross operating margin by business segment:
Pipelines. Gross operating margin from our Pipelines segment was $83.0 million for the first quarter of 2004 compared to $71.9 million for the first quarter of 2003. On an energy-equivalent basis, net pipeline throughput was 1,706 MBPD for the 2004 period versus 1,585 MBPD for the 2003 period. Gross operating margin for the first quarter of 2004 includes $10.6 million of equity earnings from GulfTerra GP. On a quarter-to-quarter basis, our Mid-America and Seminole pipelines experienced a $4.5 million decrease in gross operating margin despite a 15 MBPD increase in volumes. Gross operating margin for these systems was affected by lower revenues in connection with incentive tariffs granted to certain customers to ship NGLs on these systems.
As a result of stronger demand for natural gas, gross operating margin from Acadian Gas increased $1.4 million quarter-to-quarter. Natural gas throughput on this system increased 85 BBtu/d. Gross operating margin from our NGL and petrochemical storage business was $3.5 million higher quarter-to-quarter as a result of lower storage well charges. Our NGL import facility posted a $1.4 million increase in gross operating margin quarter-to-quarter primarily due to a 48 MBPD increase in import volumes. Gross operating margin on our Lou-Tex NGL pipeline decreased $3.0 million quarter-to-quarter as a result of a 21 MBPD decrease in volumes attributable to reduced NGL shipments from Louisiana to Texas.
Fractionation. Gross operating margin from our Fractionation segment was $30.3 million for the first quarter of 2004 compared to $29.0 million for the first quarter of 2003. Gross operating margin from NGL fractionation increased $0.8 million quarter-to-quarter. NGL fractionation volumes were 229 MBPD during the first quarter of 2004 versus 235 MBPD during the same period in 2003. Gross operating margin from our Norco facility increased $3.1 million quarter-to-quarter primarily due to a 30 MBPD increase in volumes. Norco volumes increased during the first quarter of 2004 as a result of an expansion of the facility completed during the fourth quarter of 2004. This expansion allowed Norco to fractionate volumes that had been processed at either our Toca-Western facility or transported on our Lou-Tex NGL pipeline to Mont Belvieu for fractionation. Gross operating margin from our Mont Belvieu facility decreased by $1.5 million quarter-to-quarter on a 20 MBPD decrease in volumes primarily due to competitive pressures at this industry hub.
Gross operating margin from propylene fractionation increased $4.9 million quarter-to-quarter due to an increase in petrochemical marketing sales margins. Propylene fractionation volumes were 54 MBPD during the 2004 period compared to 60 MBPD during the 2003 period. Gross operating margin from isomerization decreased $2.6 million quarter-to-quarter primarily due to lower processing volumes and by-product revenues. Isomerization volumes were 60 MBPD in the first quarter of 2004 compared to 80 MBPD in the first quarter of 2003. The decrease in isomerization volumes is attributable to maintenance and other downtime at a large third party isomerization customer and at BEF.
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Processing. Gross operating margin from our Processing segment was $18.1 million for the first three months of 2004 compared to $30.0 million for the first three months of 2003. Gross operating margin from our gas processing plants increased $4.9 million quarter-to-quarter, but was offset by a $16.6 million decrease in margin from our NGL marketing activities. NGL marketing results for the 2003 period benefited from unusually strong demand for propane and normal butane. Commodity hedging results for both periods were insignificant. Equity NGL volumes for the first quarter of 2004 were 64 MBPD compared to 54 MBPD during the first quarter of 2003. Fee-based processing volumes were 362 Mmcf/d for the 2004 period compared to 65 Mmcf/d for the 2003 period.
We recently 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. For additional information regarding the restructuring of our natural gas processing mix, please read “– Recent Developments – Recontracting of natural gas processing agreements.”
Octane enhancement. Gross operating margin for the Octane Enhancement segment was a loss of $1.3 million for the first quarter of 2004 versus a loss of $3.4 million for the first quarter of 2003. Upon our acquisition of an additional 33.3% partnership interest in BEF on September 30, 2003, it became a majority owned consolidated subsidiary of ours. Prior to this date, BEF was accounted for as an equity method unconsolidated affiliate. The quarter-to-quarter improvement in underlying operating results is primarily due to increased sales margins during the periods in which the facility was operational during each quarter. In addition, BEF changed the method it uses to account for planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method effective January 1, 2004. As a result of this change, turnaround-related operating expenses decreased $2.2 million quarter-to-quarter.
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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 including (either separately or in combination) 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. At March 31, 2004, we had approximately $2.2 billion in principal outstanding under various debt agreements. On that date, total borrowing capacity under our revolving commercial bank credit facilities was $500 million of which $248.7 million was unused. For additional information regarding our debt, please read ” – Our debt obligations.”
We currently 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). In June 2003, we sold 11,960,000 common units under this registration statement which reduced the amount available for future offerings to approximately $1.2 billion. In May 2004, we sold 15,000,000 common units under this registration statement from which we received net proceeds of $307 million, including our General Partner’s proportionate net capital contribution of $6 million. As a result of our May 2004 offering, the amount available for future offerings under this shelf registration statement was reduced to $0.9 billion.
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 for general partnership purposes. Since its inception in August 2003, we have issued 3,891,687 common units under this program generating net proceeds (including our General Partner’s proportionate net capital contributions) of approximately $84 million. This amount includes 1,053,510 common units issued under this program in February 2004 which generated proceeds of approximately $23 million.
To support our growth objectives and financial flexibility, EPCO has reinvested approximately $75 million of its cash distributions since August 2003 through the DRIP (including $20 million in February 2003). In addition, EPCO has announced that it expects to reinvest an additional $120 million of its anticipated quarterly distributions through the first quarter of 2005.
If deemed necessary, we believe that additional financing arrangements can be obtained on reasonable terms. Furthermore, we believe that maintenance of our investment grade credit ratings combined with a 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.
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The following discussions highlight significant quarter-to-quarter comparisons in consolidated operating, investing and financing cash flows:
Operating activities cash flows 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 sales and purchases near the end of each period. Cash flow from operations is primarily based on earnings from our business activities. As a result, these cash flows are exposed to certain risks. The products that we process, sell or transport are principally used as feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential, agricultural and commercial heating. Reduced demand for our products or services by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products or increased competition from petroleum-based products 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 NGL and energy prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. For additional information regarding risk factors pertinent to our business, please read “Cautionary Statement Regarding Forward-Looking Information and Risk Factors” on page 29 of this quarterly report.
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Operating activities cash flows. Cash flow from operating activities was $29.6 million during the first three months of 2004 compared to $141.5 million for the same period in 2003. As shown in the preceding table, cash flow before the net effect of changes in operating accounts was an inflow of $98 million for the 2004 period versus $91 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 $7 million increase in this element of our operating cash flows is primarily due to (i) a decrease in restricted cash and (ii) our receipt of a special distribution in the first quarter of 2003 of approximately $5 million from our Starfish unconsolidated affiliate in connection with the settlement of a tariff rate case. The $7.9 million decrease in depreciation and amortization is primarily due to unamortized loan costs we expensed during the first quarter of 2003 when we repaid the bridge loan financing associated with our acquisition of interests in the Mid-America and Seminole pipelines. Earnings from equity method unconsolidated affiliates increased $11.8 million quarter-to-quarter primarily due to the $10.6 million we recorded during the first quarter of 2004 from our investment in GulfTerra GP. The $7.0 million benefit, recorded as a cumulative effect of change in accounting principle, is due to our consolidated BEF subsidiary changing its method of accounting for planned major maintenance activities. For additional information regarding this non-cash item, please read ” – Other items – Cumulative effect of change in accounting principle recorded in first quarter of 2004” on page 47. The quarter-to-quarter fluctuation in the restricted cash balance is primarily due to physical purchases of natural gas on the NYMEX exchange.
The net effect of changes in operating accounts is generally the result of timing of cash receipts from sales and cash payments for inventory, purchases and other expenses near the end of each period. Approximately two-thirds of the change in this component of our cash flows relates to net cash inflows from inventory reductions during the first quarter of 2003 versus modest net cash outlays for inventory during the first quarter of 2004. An increase in NGL prices during the first quarter of 2003 relative to our cost of inventory led us to monetize a portion of our inventory.
Investing activities cash flows. For the three months ended March 31, 2004 and 2003, we used $15.8 million and $73.1 million in cash, respectively, for investing activities. Capital expenditures were $15.0 million for the 2004 period versus $23.8 million for the 2003 period. For additional information regarding our capital expenditures, please read ” – Capital spending” on page 43. During the first quarter of 2003, we used $28.8 million to purchase the Port Neches Pipeline and the remaining 50% ownership interests in EPIK. Our investments in and advances to unconsolidated affiliates for the first three months of 2003 included amounts we contributed to our Gulf of Mexico natural gas pipeline investments for their expansion capital projects.
Financing activities cash flows. Our financing activities were a cash inflow of $0.5 million during the first three months of 2004 compared to an outflow of $59.7 million for the same period during 2003. For the first quarter of 2004, our net borrowings under debt agreements were $65 million compared to net repayments of $244.8 million during the first quarter of 2003. During the 2003 period, we made net repayments on our debt obligations using proceeds from our January 2003 common unit offering. The 2003 period also reflects the Operating Partnership’s issuance of Senior Notes C ($350 million in principal amount) and Senior Notes D ($500 million in principal amount) and the repayment of $1.0 billion that was outstanding under the bridge loan financing we used to purchase interests in the Mid-America and Seminole pipelines.
Cash distributions to partners increased from $69.2 million during the first quarter of 2003 to $91.3 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. Future cash distributions to partners will increase as a result of our periodic issuance of common units under the DRIP and equity offerings.
Net proceeds from the sale of common units were $23.1 million during the first quarter of 2004 compared to $258.1 million for the same period in 2003. Both amounts include our General Partner’s net proportionate capital contributions. In May 2004, we sold 15,000,000 common units from which we received net proceeds of $307 million, including our General Partner’s proportionate net capital contribution of $6 million. We used the proceeds
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from our May 2004 public offering to completely repay the $225 million Interim Term Loan and to temporarily reduce debt outstanding under our revolving credit facilities.
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Parent-Subsidiary guarantor relationships. We act as guarantor of the debt obligations of our Operating Partnership, with the exception of the Seminole Notes. 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 78.4% of its capital stock).
Our current senior unsecured credit ratings are Baa2 as rated by Moody’s Investor Services and BBB- as rated by Standard and Poor’s, both are investment grade. In December 2003, as a result of our execution of definitive agreements with GulfTerra and El Paso to merge with GulfTerra, Moody’s put our rating under review for possible downgrade and Standard and Poor’s placed our rating on credit watch with negative implications. Both debt rating agencies will be reviewing the credit attributes and the risk profile of the merged partnership as well as the execution risk of the permanent financing of the proposed merger.
We believe that the maintenance of an investment grade credit rating is important in managing our liquidity and capital resource requirements. We maintain regular communications with these ratings agencies, each of which independently judges our creditworthiness based on a variety of quantitative and qualitative factors.
With regards to our material contractual obligations, there have been no significant changes outside of the ordinary course of business since December 31, 2003 with the exception that we used net proceeds from our May 2004 equity offering to repay the $225 million Interim Term Loan and approximately $80 million to temporarily reduce debt outstanding under our revolving credit facilities.
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For the three months ended March 31, 2004 and 2003, we spent $15 million and $23.8 million on capital projects recorded as property, plant and equipment. The following table summarizes our capital expenditures for the periods indicated:
For the remainder of 2004, we expect our share of capital expenditures to approximate $62 million, of which $29 million is forecast to be spent on Pipelines segment projects and approximately $19 million on modifications to the BEF facility to produce iso-octane. We expect to invest approximately $7 million in the capital projects of our unconsolidated affiliates during the remainder of 2004, of which $5.9 million is attributable to projects of our Gulf of Mexico natural gas pipeline investments. At March 31, 2004, we had approximately $3 million in outstanding purchase commitments related to capital projects.
Retained Leases
In 1998, EPCO assigned to us the purchase options associated with certain operating leases that it contributed to us at our formation (the “retained leases”). We have notified the lessor of an isomerization unit covered under the retained leases of our intent to exercise the purchase option relating to this equipment in 2004. Under the terms of the lease agreement for the isomerization unit, we have the option to purchase the equipment at the lesser of fair value or $23.1 million. Should we decide to exercise all of the remaining purchase options associated with the retained leases (which are also at fair value), up to an additional $2.8 million would be payable in 2004, $2.3 million in 2008 and $3.1 million in 2016. These cash outlays would be in addition to the $68 million in forecasted capital project spending for 2004 as discussed in the previous paragraph.
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
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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 three months of 2004, we spent approximately $1.9 million to comply with these new regulations, of which $1.2 million was recorded as an operating expense of our Pipelines segment. Based on information currently available, our cash outlays for this program are estimated at $15.5 million for the remainder of 2004 and in the range of $9 million to $19 million for each of the years 2005 through 2008. At present, we expect that approximately 90% of our pipeline integrity management program costs will be recorded as operating expenses within our Pipelines segment. The remainder will be classified as sustaining capital expenditures.
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.
In general, there have been no significant changes in our critical accounting policies since December 31, 2003. For a detailed discussion of these policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our critical accounting policies” in our annual report on Form 10-K for 2003. The following information summarizes the estimation risk underlying our most significant financial statement items:
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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 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.
At March 31, 2004 and December 31, 2003, the net book value of our property, plant and equipment was $2.9 billion and $3.0 billion, respectively. For additional information regarding our property, plant and equipment, please read Note 5 of the Notes to Unaudited 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 (such as our investments in GulfTerra GP and Promix) 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 including 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.
Our investment in certain unconsolidated affiliates includes excess cost amounts that have been attributed to goodwill. For GulfTerra GP, the excess cost amount attributed to goodwill at March 31, 2004 and December 31, 2003 is $328.2 million. The goodwill amount (which represents potential intangible assets, excess of fair values over carrying values of tangible assets, and remaining goodwill, if any) for GulfTerra GP represents our preliminary allocation of the purchase price pending completion of a fair value analysis which is expected to be completed during the second half of 2004. To the extent that our preliminary allocation of the excess cost of GulfTerra GP is ultimately attributed to depreciable or amortizable assets, our equity earnings from GulfTerra GP will be reduced from what it otherwise would be. For a table showing the impact of potential reclassification of the GulfTerra GP excess cost amount, please read Note 6 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
For the three months ended March 31, 2004 and 2003, we did not record any impairment charges related to our long-lived assets or equity method investments.
Amortization methods and estimated useful lives of qualifying intangible assets
Our recorded intangible assets primarily consist of the estimated value assigned to certain contract-based assets representing 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
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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.
At March 31, 2004 and December 31, 2003, the carrying value of our intangible asset portfolio was $265.1 million and $268.9 million. For additional information regarding our intangible assets, please read Note 7 of the Notes to Unaudited 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 March 31, 2004 and December 31, 2003, the carrying value of our goodwill was $82.4 million. For additional information regarding our goodwill, please read Note 7 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
Our revenue recognition polices
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, as SEC regulations require us to submit financial information on increasingly accelerated timeframes, our use of estimates will increase. We believe the assumptions underlying any revenue estimates that we might use will not prove to be materially different from actual amounts due to our development and implementation of a fully integrated volume management system that is inclusive of operational activities through financial accounting.
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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.
Cumulative effect of change in accounting principle recorded in first quarter of 2004
On January 1, 2004, our majority owned BEF subsidiary changed its method of accounting for planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method. These major maintenance costs, which typically result in facility shutdowns for 30 to 45 days, are principally comprised of amounts paid to third parties for materials, contract services, and other related items.
We have historically used the expense-as-incurred method for planned major maintenance activities. The change in accounting for our majority owned BEF subsidiary conforms the Company’s accounting for all planned major maintenance costs and changes the method to better reflect expenses in the period incurred. As such, we believe the change is to a method that is preferable under the circumstances.
The cumulative effect of this accounting change for years prior to 2004, which is shown separately in the Statement of Consolidated Operations and Comprehensive Income, resulted in a gross benefit of $7 million being recorded on January 1, 2004. After adjusting for the minority interest portion, the net effect on our earnings is $4.7
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million. For information regarding the effect of this change on basic and diluted earnings per unit, please read Note 14 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
For the periods indicated, the following table shows pro forma net income, basic earnings per unit and diluted earnings per unit amounts assuming the accounting change was applied retroactively to January 1, 2003:
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To qualify as a hedge, the item to be hedged must expose us 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 is recorded into earnings immediately.
Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance about implementation issues. Since this guidance is still continuing, our conclusions regarding the application of guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of this guidance. For additional information regarding our financial instruments, please read Note 12 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
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 to estimate the expected impact of changes in interest rates on our future cash flows. The General Partner oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.
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. However, the interest rate swaps effectively converted a portion of the underlying fixed rate debt (i.e., the notional amounts hedged for Senior Notes B and C) into variable rate debt. As a result, interest expense will vary depending on the variable rates payable by us under terms of the swap agreements at the end of
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each settlement period. To the extent that the variable rate amount payable by us at the end of each settlement period is less than the fixed rate amount receivable from the counterparty, we will amortize the difference ratably to earnings as a reduction in interest expense over the settlement period. If the variable rate payable by us at the end of each settlement period is more than the fixed rate amount receivable from the counterparty, we would amortize this difference ratably to earnings as an increase in interest expense over the settlement period.
The following tables shows the effect of hypothetical price movements on the fair value (“FV”) of our interest rate swaps and potential change in the fair value of the debt at the dates indicated:
The fair value of the interest rate swaps excludes the benefit we have already recorded in earnings. The change in fair value between March 31, 2004 and April 22, 2004 is primarily due to an increase in market interest rates.
Cash flow hedges – Forward starting interest rate swaps. On March 17, 2004, we entered into four forward starting interest rate swap transactions with original maturities of September 30, 2004. A forward starting swap is an agreement that effectively hedges the price on a specific U.S. treasury security for an established period of time. The purpose of these transactions was to effectively hedge the underlying U.S. treasury interest rate associated with our anticipated issuance of debt to refinance the existing debt of GulfTerra after the proposed merger is completed. The forward starting interest rate swaps have been designated as cash flow hedges under SFAS No. 133. The notional amount of the anticipated debt issuances was $2 billion.
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The non-cash fair value of the forward starting interest rate swaps at March 31, 2004 was $17.0 million and was recorded as a component of AOCI in our Statement of Consolidated Partners’ Equity and as an addition to comprehensive income in our Statement of Consolidated Operations and Comprehensive income for the three months ended March 31, 2004. When the $104.5 million cash settlement is recorded during the second quarter of 2004, it will replace the $17.0 non-cash fair value amount in AOCI and comprehensive income.
The fair value of our commodity financial instrument portfolio at May 1, 2004, March 31, 2004 and December 31, 2003 and the results of our commodity hedging activities for the three months ended March 31, 2004 and 2003 were all nominal amounts. During both the first quarter of 2004 and the first quarter of 2003, we utilized a limited number of commodity financial instruments.
Our management, with the participation of the CEO and CFO of our General Partner, have evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting. 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 our General Partner’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
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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 that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.
Based on their evaluation, the CEO and CFO of our General Partner 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 significant deficiencies or 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. There have been no significant 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.
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.
We did not repurchase any of our common units or Class B special units during the three month period ended March 31, 2004. As of March 31, 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.
(a) Exhibits
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(b) Reports on Form 8-K.
January 6, 2004 filing, Items 5 and 7. On January 6, 2004, we filed as an exhibit the unaudited balance sheet of our General Partner dated September 30, 2003.
February 3, 2004, Items 7 and 12. On February 3, 2004, we issued a press release regarding our financial results for the three and twelve-month periods ended December 31, 2003 and 2002. A copy of the earnings press release and related financial information was filed as an exhibit.
February 10, 2004, Items 5 and 7. On February 10, 2004, we filed updates to our partnership agreement and common unit description, various credit facilities and the administrative services agreement with EPCO. Our Third Amended and Restated Agreement of Limited Partnership, Interim Term Loan Agreement and related Guaranty Agreement, First Amendment to 364-Day Revolving Credit Facility, Fifth Amendment and Supplement to Multi-Year Revolving Credit Facility and the Amended and Restated Administrative Services Agreement were attached as exhibits thereto.
March 22, 2004 filing, Items 5 and 7. On March 22, 2004, we filed as an exhibit the audited balance sheet of our General Partner dated December 31, 2003.
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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 May 10, 2004.
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