UNITED STATESSECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________.
Commission file numbers: 1-14323 333-93239-01
Indicate by check mark whether the registrants: (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.
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).
There were 167,062,202 Common Units, 21,409,868 Subordinated Units and 10,000,000 Special Units of Enterprise Products Partners L.P. outstanding at May 1, 2003. Enterprise Products Partners L.P.'s Common Units trade on the New York Stock Exchange under symbol "EPD."Enterprise Products Operating L.P. is owned 98.9899% by its parent, EPD, and 1.0101% by the General Partner. No common equity securities of Enterprise Products Operating L.P. are publicly traded.
This report constitutes a combined quarterly report on Form 10-Q for Enterprise Products Partners L.P. (the "Company")(Commission File No. 1-14323) and its 98.9899% owned subsidiary, Enterprise Products Operating L.P. (the "Operating Partnership")(Commission File No. 333-93239-01). Since the Operating Partnership owns substantially all of the Company's consolidated assets and conducts substantially all of the Company's business and operations, the information set forth herein, except for Part I, Item 1, constitutes combined information for the Company and the Operating Partnership. In accordance with Rule 3-10 of Regulation S-X, Part I, Item 1 contains separate financial statements for the Company and the Operating Partnership.
ENTERPRISE PRODUCTS PARTNERS L.P.ENTERPRISE PRODUCTS OPERATING L.P.TABLE OF CONTENTS
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In the opinion of Enterprise Products Partners L.P., the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of its consolidated financial position as of March 31, 2003 and consolidated results of operations and cash flows for the three months ended March 31, 2003 and 2002. Within these footnote disclosures of Enterprise Products Partners L.P., references to “we”, “us”, “our” or “the Company” shall mean the consolidated financial statements of Enterprise Products Partners L.P.
References to “Operating Partnership” shall mean the consolidated financial statements of our primary operating subsidiary, Enterprise Products Operating L.P., which are included elsewhere in this combined report on Form 10-Q. We own 98.9899% of the Operating Partnership and act as guarantor of certain debt obligations of the Operating Partnership. Our General Partner, Enterprise Products GP, LLC, owns the remaining 1.0101% of the Operating Partnership. Essentially all of our assets, liabilities, revenues and expenses are recorded at the Operating Partnership level in our consolidated financial statements.
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 generally accepted accounting principles 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/A (File No. 1-14323) for the year ended December 31, 2002.
The results of operations for the three months ended March 31, 2003 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 abbreviated entity names and other capitalized terms are described within the glossary of this quarterly report on Form 10-Q.
Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of consolidated operations.
See Note 14 for the pro forma effects to net income and earnings per Unit as if we had used the fair-value based method of accounting for Unit options.
The following recently issued accounting standards have been adopted and implemented by us:
We are currently evaluating the provisions of FIN No. 46, Consolidation of Variable Interest Entities.
SFAS No. 143. We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of a liability for an asset
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retirement obligation (“ARO”) and the associated asset retirement cost. Under the provisions of this standard, we reviewed our long-lived assets for ARO liabilities and identified such liabilities in several operational areas. These include ARO liabilities related to (i) easements over property not currently owned by us and (ii) statutory regulatory requirements for abandonment or retirement of certain currently operated facilities.
As a result of our analysis of the identified AROs, we were not required to recognize such potential liabilities. Our rights to the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently plan to renew all such easement agreements and use these properties indefinitely. Therefore, the ARO liability is not estimable for such easements. If we decide to not renew these agreements, an ARO liability would be recorded at that time. ARO liabilities related to statutory regulatory requirements for abandonment or retirement of certain currently operated facilities were also identified. We currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement occurred. Certain Gulf of Mexico natural gas pipelines, in which we have an equity interest, have identified ARO’s relating to regulatory requirements. There is no current intention to abandon or retire these pipelines. If these pipelines were abandoned or retired, an ARO liability would then be disclosed.
SFAS No. 146. We adopted this standard as of January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to exit or disposal plan. We determined that this standard had no material impact on our financial statements.
SFAS No. 148. We adopted this standard as of December 31, 2002. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. We have provided the information required by this statement under Note 14.
SFAS No. 149. On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 20, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We will adopt SFAS No. 149 on a prospective basis at its effective date on July 1, 2003. We are currently evaluating the impact that SFAS No. 149 will have on our financial statements.
FIN 45. We implemented this FASB interpretation as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We have provided the information required by this interpretation under Note 8.
FIN 46. In January 2003, FIN 46, an interpretation of ARB No. 51, Consolidated Financial Statements, was issued to address perceived weaknesses in accounting for entities commonly known as special-purpose or off-balance-sheet entities, but the guidance applies to a larger population of entities. FIN 46 provides guidance for identifying the party with a controlling financial interest resulting from arrangements or financial interests rather than from voting interests. FIN 46 defines the term “variable interest entity” (or “VIE”) and is based on the premise that if a business enterprise has a controlling financial interest in a VIE, the assets, liabilities, and results of the activities of the VIE should be included in the consolidated financial statements of the business enterprise. FIN 46 applies immediately to VIEs created after January 31, 2003 and to VIEs in which an enterprise obtains an interest after that date. For variable interests in VIEs created before February 1, 2003, FIN 46 applies to public enterprises no later than the beginning of the first interim or annual period beginning after June 15, 2003. This FIN may be applied prospectively with the cumulative-effect adjustment as of the date on which it is first applied or by restating previously issued financial statements for one
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or more years with the cumulative-effect adjustment as of the beginning of the first year restated. We are currently studying the provisions of FIN 46. Based upon our initial interpretation of FIN 46, we do not believe that this guidance will have a material effect on our financial statements.
During the three months ended March 31, 2003, we acquired entities owning the Port Neches Pipeline and purchased the remaining 50% ownership interest in EPIK. We also made minor adjustments to the allocation of the purchase price we paid to acquire indirect interests in the Mid-America and Seminole pipelines. Due to the immaterial nature of each, individually and in the aggregate, our discussion of each of these transactions is limited to the following:
Acquisition of Port Neches Pipeline. In March 2003, we acquired two entities owning the Port Neches Pipeline (formerly known as the Quest Pipeline) for $14.2 million. The 70-mile Port Neches Pipeline transports high-purity grade isobutane produced at our facilities in Mont Belvieu to consumers in Port Neches, Texas.
Acquisition of remaining 50% interest in EPIK. In March 2003, we purchased the remaining 50% ownership interests in EPIK for $14.4 million (which is net of cash received of $4.6 million). EPIK owns an NGL export terminal located in southeast Texas. As a result of this acquisition, EPIK became a wholly-owned subsidiary of ours (previously, it had been an unconsolidated affiliate).
Our preliminary allocation of the purchase price of each transaction is as follows:
Our inventories were as follows at the dates indicated:
Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale by our marketing activities. The forward sales inventory was comprised of segregated NGL volumes dedicated to the fulfillment of forward sales contracts.
Due to fluctuating market conditions in the midstream energy industry in which we operate, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the costs 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 three months ended March 31, 2003 and 2002, we recognized $10.4 million and $0.1 million, respectively, of such LCM adjustments. The majority of these write-downs were taken against NGL inventories.
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Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:
Depreciation for the three-month periods ended March 31, 2003 and 2002 was $27.7 million and $17.2 million, respectively.
We own interests in a number of related businesses that are accounted for under the equity or cost methods. The investments in and advances to these unconsolidated affiliates are grouped according to the operating segment to which they relate. For a general discussion of our business segments, see Note 12. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated:
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The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:
The following tables represent summarized income statement information for our unconsolidated affiliates accounted for under the equity method (for the periods indicated on a 100% basis). We have grouped this information by the business segment to which the entities relate.
Our initial investment in Promix, La Porte, Dixie, Neptune and Nemo exceeded our share of the historical cost of the underlying net assets of such entities (the “excess cost”). The excess cost of these investments is reflected in our investments in and advances to unconsolidated affiliates for these entities. That portion of excess cost attributable to the tangible plant and/or pipeline assets of each entity is amortized against equity earnings from these entities in a manner similar to depreciation. That portion of excess cost attributable to goodwill is subject to periodic impairment testing and is not amortized.
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The following table summarizes our excess cost information at March 31, 2003 and December 31, 2002 by the business segment to which the unconsolidated affiliates relate:
For the three months ended March 31, 2003 and 2002, we recorded $0.4 million and $0.5 million, respectively, of excess cost amortization which is reflected in our equity in income from unconsolidated affiliates.
Purchase of remaining 50% interest in EPIK
As discussed in Note 3, we purchased the remaining 50% ownership interests in EPIK in March 2003. As a result of this acquisition, EPIK became a wholly-owned subsidiary of ours. We recorded $1.8 million of equity income from EPIK for the two months that it was an unconsolidated subsidiary during the first quarter of 2003.
The following table summarizes our intangible assets at March 31, 2003 and December 31, 2002:
The following table shows amortization expense associated with our intangible assets for the three months ended March 31, 2003 and 2002:
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Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired and is comprised of the following (at March 31, 2003 and December 31, 2002):
Our goodwill amounts are classified as part of the Fractionation segment since they are related to assets recorded within this operating segment.
Our debt obligations consisted of the following at the dates indicated:
Letters of credit. At March 31, 2003 and December 31, 2002, we had $75 million of standby letter of credit capacity under our Multi-Year Revolving Credit facility. We had $25.7 million of letters of credit outstanding under this facility at March 31, 2003 and $2.4 million outstanding at December 31, 2002.
Parent-Subsidiary guarantor relationships. We act as guarantor of certain debt obligations of our subsidiaries, including all of our Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests). If the Operating Partnership were to default on any guaranteed debt obligation, we would be responsible for full payment of that obligation.
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New debt obligations issued during first quarter of 2003
During the first quarter of 2003, we completed the issuance of $850 million of private placement debt (Senior Notes C and D). Senior Notes C and D are unsecured obligations of our Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. We guarantee both Senior Notes C and D for our subsidiary through an unsecured and unsubordinated guarantee that is non-recourse to the General Partner. These notes were issued under an indenture containing certain covenants and are subject to a make-whole redemption right. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.
Senior Notes C. In January 2003, we issued $350 million in principal amount of 6.375% fixed-rate Senior Notes C due February 1, 2013 (“Senior Notes C”), from which we received net proceeds before offering expenses of approximately $347.7 million. These notes were sold at face value with no discount or premium. We used the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan that we incurred to finance the Mid-America and Seminole acquisitions. In April 2003, we initiated an offer to exchange the private placement Senior Notes C for publicly-registered Senior Notes C.
Senior Notes D. In February 2003, we issued $500 million in principal amount of 6.875% fixed-rate Senior Notes due March 1, 2033 (“Senior Notes D”), from which we received net proceeds before offering expenses of approximately $489.8 million. These notes were sold at a discount of 98.842% of their face amount. We used $421.4 million from this offering to repay the remaining principal balance outstanding under the 364-Day Term Loan. In addition, we applied $60.0 million of the proceeds to reduce the balance outstanding under the 364-Day Revolving Credit facility. The remaining proceeds were used for working capital purposes.
Repayment of 364-Day Term Loan
Our Operating Partnership entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We used $252.8 million of the $258.2 million in proceeds from the January 2003 equity offering (see Note 9), $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan by February 2003.
Covenants
We were in compliance with the various covenants of our debt agreements at March 31, 2003 and December 31, 2002.
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, 2003:
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Our Common Units, Subordinated Units and convertible Special Units represent limited partner interests in the Company. We are managed by the General Partner. The rights available to our partners are described in our Third Amended and Restated Agreement of Limited Partnership (together with any amendments thereto). Our Common Units trade on the New York Stock Exchange under the symbol “EPD.”
We allocate earnings and related amounts to Common and Subordinated Unitholders and the General Partner in accordance with our partnership agreement. These classes of our partnership interests are also entitled to receive cash distributions. For financial accounting and tax purposes, the Special Units are not allocated any portion of net income; however, for tax purposes, the Special Units are allocated a certain amount of depreciation until their conversion into Common Units.
In January 2003, we completed a public offering of 14,662,500 Common Units (including 1,912,500 Common Units sold pursuant to the underwriters’ over-allotment option) from which we received net proceeds before offering expenses of approximately $258.2 million, including our General Partner’s $5.2 million in capital contributions. We used $252.8 million of the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan. The remaining balance of proceeds was used for working capital purposes and offering expenses.
Our partnership agreement stipulates that the Subordinated Units may undergo an early conversion to Common Units if certain criteria are satisfied. As a result of meeting the necessary criteria, 10,704,936 of EPCO’s Subordinated Units converted to Common Units on May 1, 2003. The remaining 21,409,868 Subordinated Units will convert to Common Units on August 1, 2003 if the remaining criteria are met.
The following table details the Unit activity within each class of our limited partner interests during the three months ended March 31, 2003 and the outstanding balance of each at March 31, 2003:
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The net effect of changes in operating accounts and liabilities is as follows:
During the three months ended March 31, 2003, we completed two small business acquisitions and made minor adjustments to the purchase price allocation of the Mid-America and Seminole acquisitions. These acquisitions and adjustments affected various balance sheet accounts (see Note 3). The 2002 period reflects our acquisition of Diamond-Koch’s Mont Belvieu NGL and petrochemical storage business in January 2002 and their adjacent propylene fractionation business (Splitter III) in February 2002.
We record certain financial instruments relating to commodity positions and interest rate hedging activities at their respective fair values using mark-to-market accounting. For the three months ended March 31, 2002, we recognized a net $30.1 million in non-cash mark-to-market decreases in the fair value of these instruments, primarily in our commodity financial instruments portfolio. We had a limited number of such positions outstanding during the first quarter of 2003 and the non-cash change in fair value of these instruments was an increase of $28 thousand.
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 our physical purchase transactions made on the NYMEX exchange. The restricted cash balance at March 31, 2003 and December 31, 2002 was $18.8 million and $8.8 million, respectively.
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, primarily within our Processing segment. In general, the types of risks we attempt to hedge are those relating 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.
Commodity hedging financial instruments
During the first three months of 2002, we recognized a loss of $45.1 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations and Comprehensive Income. In March 2002, the effectiveness of our primary commodity hedging strategy at the time deteriorated due to an
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unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.
During the first three months of 2003, we held a limited number of commodity financial instruments from which we recorded a loss of $0.9 million ($0.1 million was attributable to the Processing segment and the remainder to the Pipelines segment). The fair value of open positions at March 31, 2003 was a receivable of approximately $2 thousand.
Interest rate hedging financial instruments
During the fourth quarter of 2002, we entered into seven treasury lock transactions. Each treasury lock transaction carried a maturity date of either January 31, 2003 or April 15, 2003. The purpose of these transactions was to hedge the underlying U.S. treasury interest rate associated with our anticipated issuance of debt in early 2003 to refinance the Mid-America and Seminole acquisitions. The notional amounts of these transactions totaled $550 million, with a total treasury lock rate of approximately 4%.
Our treasury lock transactions are accounted for as cash flow hedges under SFAS No. 133. The fair value of these instruments at December 31, 2002 was a current liability of $3.8 million offset by a current asset of $0.2 million. The net $3.6 million non-cash mark-to-market liability was recorded as a component of comprehensive income on that date, with no impact to current earnings.
We settled all of the treasury locks by early February 2003 in connection with our issuance of Senior Notes C and D (see Note 8). The settlement of these instruments resulted in our receipt of $5.4 million of cash. This amount was recorded as a gain in other comprehensive income during the first quarter of 2003 and represents the effective portion of the treasury locks.
Of the $5.4 million recorded in other comprehensive income during the first quarter of 2003, $4.0 million is attributable to our issuance of Senior Notes C and is being amortized to earnings as a reduction in interest expense over the 10-year term of this debt. The remaining $1.4 million is attributable to our issuance of Senior Notes D and is being amortized to earnings as a reduction in interest expense over the 10-year term of the anticipated transaction as required by SFAS No. 133. The estimated amount to be reclassified from accumulated other comprehensive income to earnings during 2003 is $0.4 million. With the settlement of the treasury locks, the $3.6 million non-cash mark-to-market liability recorded at December 31, 2002 was reclassified out of accumulated other comprehensive income in Partners’ Equity to offset the current asset and liability we recorded at December 31, 2002 with no impact to earnings.
We have five reportable operating segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. The 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 Chief Executive Officer 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 polymer-grade and chemical-grade propylene fractionation services. Processing includes the natural gas processing business and its related NGL marketing activities. Octane Enhancement represents our equity interest in BEF, a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating 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. We define gross operating margin as operating income before: (1) depreciation and amortization amounts; (2) operating lease expenses for which the partnership does 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. Segment gross operating margin is derived by subtracting segment operating costs and expenses (before depreciation and amortization amounts, operating lease expenses for
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which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have provided a reconciliation of total gross operating margin (a non-GAAP performance measure) to operating income.
The following table shows our measurement of total segment gross operating margin for the periods indicated:
The following table reconciles GAAP operating income as shown in our Statements of Consolidated Operations and Comprehensive Income to total segment gross operating margin (a non-GAAP financial measure):
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Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table:
Our revenues are derived from a wide customer base. All consolidated revenues during the first quarter of 2003 and first quarter of 2002 were earned in the United States. Total consolidated revenues for the three months ended March 31, 2003 increased $819.5 million over those recorded during the same period in 2002. The majority of this increase is attributable to higher NGL prices, which (on a weighted-average basis for industry index prices) were 63 CPG during the first quarter of 2003 compared to 33 CPG during the first quarter of 2002. The higher NGL prices resulted in a significant increase in Processing segment revenues (particularly those of its NGL marketing activities component).
Also, higher natural gas prices during the first quarter of 2003 when compared to the first quarter of 2002 resulted in a substantial increase in Pipeline segment revenues from our Acadian Gas subsidiary. As part of its normal operations, Acadian Gas purchases natural gas from producers and suppliers and resells such natural gas to customers such as electric utility companies. The average index price for natural gas was $6.58 per MMBtu during the first quarter of 2003 versus $2.34 per MMBtu during the first quarter of 2002.
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In addition to the effect of higher NGL and natural gas prices, consolidated revenues also increased as a result of acquisitions. Our Mid-America and Seminole pipeline systems contributed $82.5 million in revenues during the first three months of 2003.
Total segment gross operating margin was $126.4 million for the first quarter of 2003 compared to $26.3 million for the first quarter of 2002. The primary reasons for the increase are (i) the 2003 period includes $47.5 million of gross operating margin from Mid-America and Seminole (we acquired these operations in July 2002) and (ii) the 2002 period included $45.1 million in commodity hedging losses. Mid-America and Seminole’s gross operating margin is classified under our Pipelines segment while commodity hedging results are primarily a function of our Processing segment activities.
Provision for income taxes is primarily applicable to the tax obligation of a consolidated subsidiary, Seminole Pipeline Company, which is a corporation and subject to income taxes. Seminole Pipeline Company became a consolidated subsidiary on August 1, 2002. The following is a summary of our provision for income taxes for the three months ended March 31, 2003:
The following is a reconciliation of our provision for income taxes at the federal statutory rate to our recorded provision for income taxes:
Significant components of deferred income tax assets and liabilities at March 31, 2003 are as follows:
Based upon the periods in which taxable temporary differences are anticipated to reverse, we believe it is more likely than not that the Company will realize the benefits of these deductible differences. Accordingly, we believe that no valuation allowance is required for the deferred tax assets. However, the amount of the deferred tax asset considered realizable could be adjusted in the future if estimates of reversing taxable temporary differences are revised.
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During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the “1998 Plan”). Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of our Common Units (the “Units”) may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. The exercise price per Unit, vesting and expiration terms, and rights to receive distributions on Units granted are determined by EPCO for each grant. EPCO funds the purchase of the Units under the 1998 Plan at fair value in the open market. In general, our responsibility for reimbursing EPCO for the expense it incurs when these options are exercised is as follows:
We account for our share of the cost of these awards using the intrinsic value-based method in accordance with APB No. 25, “Accounting for Stock Issued to Employees.” The exercise price of each option granted is equivalent to the market price of the Unit at the date of grant. Accordingly, no compensation expense related to Unit option grants is recognized in the Statements of Consolidated Operations and Comprehensive Income until the grants are exercised by the employee.
Accounting principles require us to illustrate the pro forma effect on our net income (loss) and earnings per Unit as if the fair value-based method of accounting, based on SFAS No. 123, “Accounting for Stock Based Compensation,” had been applied to the 1998 Plan. The following table shows these pro forma effects for the periods indicated:
Basic earnings per Unit is computed by dividing net income available to limited partner interests by the weighted-average number of Common and Subordinated Units outstanding during the period. In general, diluted earnings per Unit is computed by dividing net income available to limited partner interests by the weighted-average number of Common,
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Subordinated and Special Units outstanding during the period. In a period of net operating losses, the Special Units are excluded from the calculation of diluted earnings per Unit due to their antidilutive effect (as occurred for the first quarter of 2002). 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 amount of Common Units outstanding in the following table does not include Treasury Units.
The following table reconciles the number of Units used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three months ended March 31, 2003 and 2002:
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In the opinion of Enterprise Products Operating L.P., the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of its consolidated financial position as of March 31, 2003 and consolidated results of operations and cash flows for the three months ended March 31, 2003 and 2002. Within these footnote disclosures of Enterprise Products Operating L.P., references to “we”, “us”, “our” or “the Company” shall mean the consolidated financial statements of Enterprise Products Operating L.P. References to “Limited Partner” shall mean the consolidated financial statements of our parent, Enterprise Products Partners L.P., which are included elsewhere in this combined report on Form 10-Q.
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 generally accepted accounting principles 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/A (File No. 333-93239-01) for the year ended December 31, 2002.
SFAS No. 143. We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement obligation (“ARO”) and the associated asset retirement cost. Under the provisions of this standard, we reviewed our long-lived assets for ARO liabilities and identified such liabilities in several operational areas. These include ARO liabilities related to (i) easements over property not currently owned by us and (ii) statutory regulatory requirements for abandonment or retirement of certain currently operated facilities.
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FIN 46. In January 2003, FIN 46, an interpretation of ARB No. 51, Consolidated Financial Statements, was issued to address perceived weaknesses in accounting for entities commonly known as special-purpose or off-balance-sheet entities, but the guidance applies to a larger population of entities. FIN 46 provides guidance for identifying the party with a controlling financial interest resulting from arrangements or financial interests rather than from voting interests. FIN 46 defines the term “variable interest entity” (or “VIE”) and is based on the premise that if a business enterprise has a controlling financial interest in a VIE, the assets, liabilities, and results of the activities of the VIE should be included in the consolidated financial statements of the business enterprise. FIN 46 applies immediately to VIEs created after January 31, 2003 and to VIEs in which an enterprise obtains an interest after that date. For variable interests in VIEs created before February 1, 2003, FIN 46 applies to public enterprises no later than the beginning of the first interim or annual period beginning after June 15, 2003. This FIN may be applied prospectively with the cumulative-effect adjustment as of the date on which it is first applied or by restating previously issued financial statements for one or more years with the cumulative-effect adjustment as of the beginning of the first year restated. We are currently studying the provisions of FIN 46. Based upon our initial interpretation of FIN 46, we do not believe that this guidance will have a material effect on our financial statements.
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Due to fluctuating market conditions in the midstream energy industry in which we operate, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the costs 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, 2003 and 2002, we recognized $10.4 million and $0.1 million, respectively, of such LCM adjustments. The majority of these write-downs were taken against NGL inventories.
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Parent-Subsidiary guarantor relationships. Our parent (which is our Limited Partner) is the guarantor of certain of our consolidated debt obligations. This parent-subsidiary guaranty provision exists under all of our consolidated debt obligations, with the exception of the Seminole Notes. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests). If we were to default on any guaranteed debt obligation, our Limited Partner would be responsible for full payment of that obligation.
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During the first quarter of 2003, we completed the issuance of $850 million of private placement debt (Senior Notes C and D). Senior Notes C and D are unsecured obligations and rank equally with its existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. Senior Notes C and D are guaranteed by the Limited Partner through an unsecured and unsubordinated guarantee that is non-recourse to the General Partner. These notes were issued under an indenture containing certain covenants and are subject to a make-whole redemption right. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.
We entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our Limited Partner’s October 2002 equity offering to partially repay this loan. We used $252.8 million of the $258.2 million in proceeds from our Limited Partner’s January 2003 equity offering (see Note 9), $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan by February 2003.
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We are owned 98.9899% by our Limited Partner and 1.0101% by our General Partner. The rights available to our partners are described in our Amended and Restated Agreement of Limited Partnership dated July 31, 1998. We are managed by our General Partner.
In January 2003, our Limited Partner completed an equity offering from which we received a cash contribution of $258.2 million, which includes our General Partner’s related capital contribution of $2.6 million. We used $252.8 million of the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan. The remaining balance of proceeds was used for working capital purposes and offering expenses.
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During the first three months of 2002, we recognized a loss of $45.1 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations and Comprehensive Income. In March 2002, the effectiveness of our primary commodity hedging strategy at the time deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.
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We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. We define gross operating margin as operating income before: (1) depreciation and amortization amounts; (2) operating lease expenses for which the partnership does 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. Segment gross operating margin is derived by subtracting segment operating costs and expenses (before depreciation and amortization amounts, operating lease expenses for which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have provided a reconciliation of total gross operating margin (a non-GAAP performance measure) to operating income.
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36
37
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Accounting principles require us to illustrate the pro forma effect on our net income (loss) as if the fair value-based method of accounting, based on SFAS No. 123, “Accounting for Stock Based Compensation,” had been applied to the 1998 Plan. The following table shows these pro forma effects for the periods indicated:
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Enterprise Products Partners L.P. is a publicly-traded limited partnership (NYSE, symbol “EPD”) that conducts substantially all of its business through its 98.9899% owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”), the Operating Partnership’s subsidiaries, and a number of investments with industry partners. Since the Operating Partnership owns substantially all of Enterprise Products Partners L.P.‘s consolidated assets and conducts substantially all of its business and operations, the information set forth herein constitutes combined information for the two registrants. Unless the context requires otherwise, references to “we”, “us”, “our” or the “Company” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P., which includes Enterprise Products Operating L.P. and its subsidiaries.
The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes thereto of the Company and Operating Partnership included in Part I of this quarterly report on Form 10-Q.
We have five reportable 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 interest in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating segment consists of fee-based marketing services and various operational support activities.
We evaluate segment performance based on our measurement of gross operating margin (in the aggregate and by segment). This non-generally accepted accounting principle financial measure is used in this quarterly report. Amounts included in the calculation of this measure are computed in accordance with generally accepted accounting principles (“GAAP”). As part of our quarterly report, we have provided a reconciliation of this non-GAAP financial measure to its most comparable financial measure calculated and presented in accordance with GAAP.
We believe that investors benefit from having access to the same financial measures being utilized by management. Gross operating margin is an important performance measure of the economic success of our core operations and individual asset locations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among segments. The nearest GAAP counterpart to gross operating margin is operating income. Operating income, however, includes expense items that management does not consider when evaluating the core profitability of an operation such as depreciation and selling, general and administrative costs.
We define gross operating margin as operating income before: (1) depreciation and amortization amounts; (2) operating lease expenses for which the partnership does 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. Segment gross operating margin is derived by subtracting segment operating costs and expenses (before depreciation and amortization amounts, operating lease expenses for which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have reconciled total gross operating margin (a non-GAAP performance measure) to operating income.
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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 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, see footnote 12 of our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
The following table shows our consolidated revenues, costs and expenses, equity in income of unconsolidated affiliates and operating income (loss) for the periods indicated (dollars in thousands):
The following table reconciles consolidated operating income (loss) to our measurement of total gross operating margin for the periods indicated (dollars in thousands):
EPCO subleases certain equipment to us located at our Mont Belvieu facility and 100 railroad tankcars for $1 dollar per year. These subleases (the “retained leases”) are part of the EPCO Agreement we executed with EPCO at 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. In addition, EPCO has assigned to us the purchase options associated with these leases. For additional information regarding the EPCO Agreement and the retained leases, see “Related party transactions” on page 50 and “Capital spending” on page 49 of this quarterly report.
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Our gross operating margin amounts by segment were as follows for the periods indicated (dollars in thousands):
Our significant plant production and other volumetric data were as follows for the periods indicated:
The following table illustrates selected average quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products since the beginning of 2002:
(a) Natural , NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including OPIS and CMAI(b) Crude Oil price is representative of the index price for West Texas Intermediate
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Three months ended March 31, 2003 compared to three months ended March 31, 2002
Revenues, operating costs and expenses, operating income and total gross operating margin.
Revenues for the three months ended March 31, 2003 increased $819.5 million over those recorded during the same period in 2002. The increase is primarily due to higher NGL, propylene and natural gas prices (see comparative product prices chart on page 42). The higher NGL prices resulted in a significant increase in Processing segment revenues (particularly those of its NGL marketing activities component). The higher propylene prices contributed to an increase in the revenues we derive from our petrochemical marketing activities. Also, the higher natural gas prices quarter-to-quarter resulted in an increase in Pipeline segment revenues from our Acadian Gas subsidiary. As part of its normal operations, Acadian Gas purchases natural gas from producers and suppliers and resells such natural gas to customers such as electric utility companies. Lastly, revenues increased as a result of acquisitions we completed since March 31, 2002 (particularly our acquisition of indirect interests in Mid-America and Seminole in July 2002).
Operating costs and expenses for the three months ended March 31, 2003 were $722.2 million higher than those recorded for the same period in 2002. The increase is primarily due to the same reasons that caused our revenues to be higher. As a result of the higher NGL, propylene and natural gas prices, the prices we paid for feedstocks and inventories increased. This affected our NGL and petrochemical marketing activities as well as our Acadian Gas natural gas purchases. In addition to the increase in product purchase prices, operating costs and expenses also increased as a result of acquisitions.
Our operating costs and expenses for the first three months of 2002 include a $45.1 million loss we recognized from our commodity hedging activities. In March 2002, the effectiveness of our primary commodity hedging strategy at the time deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002. During the first three months of 2003, we recorded a loss of $0.9 million from our commodity hedging activities.
Operating income was $85.0 million for the first three months of 2003 compared to a loss of $1.2 million for the first three months of 2002. Total gross operating margin was $126.4 million for the 2003 period versus $26.3 million for the 2002 period. The primary reasons for the increase in operating income and total gross operating margin are (i) the 2003 period includes results from our recently acquired Mid-America and Seminole pipeline systems and (ii) the 2002 period includes $45.1 million in commodity hedging losses. From a gross operating margin standpoint, Mid-America and Seminole contributed $47.5 million for the first quarter of 2003.
The following information highlights the significant quarter-to-quarter variances in gross operating margin by operating segment:
Pipelines. Gross operating margin from our Pipelines segment was $71.9 million for the first quarter of 2003 compared to $32.7 million for the first quarter of 2002. On an energy-equivalent basis, net pipeline throughput volume was 1,626 MBPD for the 2003 period versus 859 MBPD for the 2002 period. The increase in gross operating margin and throughput volume is primarily due to the acquisition of Mid-America and Seminole. These systems earned gross operating margin of $47.5 million on volumes of 816 MBPD for the first quarter of 2003. This acquisitions-related increase was offset by a decrease in gross operating margin from our Louisiana Pipeline System and our storage operations. Gross operating margin from our Louisiana Pipeline System declined $2.4 million quarter-to-quarter primarily due to lower throughput volumes attributable to a decrease in NGL extraction rates at regional gas processing facilities. Gross operating margin from our NGL and petrochemical storage operations was $4.7 million lower quarter-to-quarter as a result of higher storage well charges.
Fractionation. Gross operating margin from our Fractionation segment was $29.0 million for the first quarter of 2003 compared to $24.4 million for the first quarter of 2002. Gross operating margin from NGL fractionation improved $2.2 million quarter-to-quarter primarily due to an increase in in-kind fees at our Norco facility due to higher NGL prices. NGL fractionation volumes were 240 MBPD during the first three months of 2003 compared to 204 MBPD during the first three months of 2002. Gross operating margin from propylene fractionation declined $2.8 million quarter-to-quarter primarily due to higher energy-related costs, unscheduled
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maintenance at one of our propylene fractionators and lower petrochemical marketing margins. Propylene fractionation volumes were 61 MBPD during the 2003 period versus 52 MBPD during the 2002 period. Gross operating margin from isomerization increased $3.6 million quarter-to-quarter primarily due to higher volumes and NGL by-product revenues. Isomerization volumes increased to 80 MBPD during the 2003 period from 74 MBPD during the 2002 period. Gross operating margin for our Fractionation segment also includes a one-time benefit of $1.1 million resulting from the settlement of a business interruption and related insurance claims involving Fractionation segment assets used to support our BEF investment.
Processing. Gross operating margin from our Processing segment was $30.0 million for the first quarter of 2003 compared to a loss of $33.4 million for the first quarter of 2002. As noted under our discussion of operating costs and expenses on page 43, the 2002 period includes commodity hedging losses of $45.1 million. Our commodity hedging results for the first quarter of 2003 were negligible. During the first quarter of 2003, our NGL marketing activities benefited from higher NGL prices and strong demand for propane and normal butane. This more than offset the decrease in gross operating margin caused by a decrease in equity NGL production from 81 MBPD during the 2002 period to 54 MBPD in the 2003 period.
The decrease in equity NGL production was largely attributable to higher natural gas prices relative to NGL prices, which caused us to minimize the amount of NGLs that were extracted by our natural gas processing facilities. In order to meet the natural gas processing needs of Shell (our largest processing customer) in this difficult pricing environment, we renegotiated certain aspects of the 20-year Shell natural gas processing agreement during the first quarter of 2003. For a general discussion of this amendment, see our discussion entitled “Related party transactions” on page 50.
Octane enhancement. Our equity earnings from BEF were a loss of $3.4 million for the first quarter of 2003 compared to income of $3.0 million for the first quarter of 2002. The quarter-to-quarter decline in equity earnings is attributable to increased downtime related to maintenance activities (which contributed to higher maintenance expenses); lower MTBE sales margins (primarily due to high methanol feedstock prices); and MTBE inventory valuation adjustments. BEF’s gross MTBE production rate declined to 10.1 MBPD during the first quarter of 2003 from 13.5 MBPD during the first quarter of 2002. We held a 33.3% ownership interest in BEF during both periods.
Selling, general and administrative expenses. These expenses were $11.5 million for the first quarter of 2003 versus $8.0 million for the first quarter of 2002. The increase is primarily due to the additional staff and resources needed to support our expansion activities resulting from acquisitions and other business development. The 2003 period includes a $2.0 million payment we made to Williams for general and administrative transition services related to our acquisition of the Mid-America and Seminole pipelines. These payments ceased in February 2003 when we took over the operation of these two systems.
Interest expense. Interest expense increased to $41.9 million for the first quarter of 2003 from $18.5 for the first quarter of 2002. The increase is primarily due to debt obligations we incurred as a result of business acquisitions, particularly the $1.2 billion in overall financing used to purchase Mid-America and Seminole in July 2002.
Interest expense for the 2003 period includes a non-cash charge of $11.3 million related to unamortized costs associated with the 364-Day Term Loan that we used to initially fund the Mid-America and Seminole acquisitions. In February 2003, we completely repaid this loan. As a result, all unamortized costs associated with this debt was charged to expense. For more information regarding our debt obligations and changes since December 31, 2002, please see “Our liquidity and capital resources – Our debt obligations”.
The following represents a combined discussion of our liquidity and capital resources and those of our Operating Partnership. Within this section, references to partnership equity pertains to limited partner interests issued by us, whereas references to debt pertains to those obligations entered into by our Operating Partnership or its subsidiaries.
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General
Our primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures (both sustaining and expansion-related), 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.
Operating cash flows primarily reflect the effects of net income adjusted for depreciation and amortization, equity income and cash distributions from unconsolidated affiliates, fluctuations in fair values of financial instruments 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, increased competition from petroleum-based products due to pricing differences or other reasons, could have a negative impact on 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 a more complete discussion of these and other risk factors pertinent to our businesses, see “Cautionary Statement regarding Forward-Looking Information and Risk Factors” on page 56 of this quarterly report.
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, 2003, we had approximately $2.0 billion outstanding under various debt agreements. On that date, total borrowing capacity under our revolving commercial bank credit facilities was $500 million of which $217.3 million of capacity was available. For additional information regarding our debt, see “Our debt obligations” on page 48.
In February 2001, we filed a universal shelf registration with the SEC covering the issuance of up to $500 million of partnership equity or public debt obligations. In October 2002, we sold 9.8 million Common Units under this shelf registration statement which generated $182.5 million of cash to us (including related capital contributions from our General Partner). In January 2003, we sold an additional 14.7 million Common Units under this shelf registration which generated $258.2 million of cash to us (including related capital contributions from our General Partner). We used the cash generated by these equity offerings to reduce debt outstanding under our 364-Day Term Loan and for working capital purposes. Also, in January and February 2003, we issued $850 million of private placement debt (Senior Notes C and D). For information regarding our application of cash generated by these debt offerings, please read the section titled “Our debt obligations” within this “Our liquidity and capital resources” discussion.
In January 2003, we filed a new $1.5 billion universal shelf registration statement with the SEC covering the issuance of an unallocated amount of partnership equity or public debt obligations (separately or in combination). In accordance with Rule 457(p) promulgated under the Securities Act of 1933, as amended, the registration fee associated with the unsold portion of the securities under the shelf registration statement filed in February 2001 was used to offset the registration fee due in connection with our $1.5 billion universal shelf registration statement. When our new shelf registration was declared effective by the SEC in April 2003, the securities remaining under the shelf registration statement filed in February 2001 were deemed deregistered.
We have the ability to issue an unlimited number of Common Units to finance acquisitions and capital improvements if Adjusted Operating Surplus (as defined within our partnership agreement) for each of the four fiscal quarters immediately preceding the expenditure, on a pro forma basis, would have increased as a result of such expenditure (i.e., would have been accretive on a pro forma basis for each of the quarters in the test). For those
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acquisitions and other transactions that do not qualify under the aforementioned pro forma “accretive” test, we have 54,550,000 Units available for general partnership purposes during the Subordination Period. The Subordination Period generally extends until the first day of any quarter beginning after June 30, 2003 when certain financial tests have been satisfied. We expect the Subordination Period to end on August 1, 2003. After the Subordination Period expires, we may prudently issue an unlimited number of Units for general partnership purposes that do not meet the pro forma “accretive” test.
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.
The following discussion highlights significant quarter-to-quarter comparisons regarding our consolidated operating, investing and financing cash flows:
Operating cash flows. Cash flow from operating activities was an inflow of $151.6 million during the first quarter of 2003 compared to an outflow of $10.0 million during the first quarter of 2002. The following table summarizes the major components of operating cash flows for first three months of 2003 and 2002 (dollars in thousands):
As shown in the table above, cash flow before changes in operating accounts was an inflow of $101.1 million during the first quarter of 2003 versus $38.2 million during the same period in 2002. We believe that cash flow from operating activities before changes in operating accounts is an important measure of our liquidity. We believe it provides an indication of our ability to generate core cash flows from the assets and investments we own or in which we have an interest. The $62.9 million increase in this element of our operating cash flows is primarily due to:
The $21.3 million increase in depreciation and amortization is primarily due to businesses we acquired since the first quarter of 2002. Changes in operating accounts are 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. For
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additional information regarding changes in operating accounts, please see footnote 10 in our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.
Investing cash flows. During the first three months of 2003, we used $73.1 million in cash for investing activities compared to $396.5 million during the same period for 2002. We used $28.8 million and $368.6 million for business acquisitions during the first quarter of 2003 and 2002, respectively. The 2003 period includes our acquisition of the Port Neches Pipeline and the remaining 50% ownership interests in EPIK. The 2002 period includes our acquisition of Diamond-Koch’s Mont Belvieu NGL and petrochemical storage business and propylene fractionation business.
Our capital expenditures were $23.8 million during the first quarter of 2003 and $17.1 million during the first quarter of 2002. The majority of the expenditures for the 2003 period related to Processing segment projects whereas the expenditures for the 2002 period centered on Pipeline segment projects. In addition, we made investments in and advances to our unconsolidated affiliates of $20.5 million during the first quarter of 2003 compared to $10.8 million during the first quarter of 2002. The increase is primarily due to funding our share of the expansion projects of our Gulf of Mexico natural gas pipeline investments.
Financing cash flows. Our financing activities were a cash outflow of $69.7 million during the first quarter of 2003 versus a cash inflow of $304.4 million during the first quarter of 2002. During the 2003 period, we made net payments on our debt obligations of $244.8 million with the aid of $258.2 million from our January 2003 equity offering. The 2003 period reflects our issuance of Senior Notes C ($350 million in principal amount) and Senior Notes D ($500 million in principal amount) and the final repayment of $1.0 billion that was outstanding under our 364-Day Term Loan. The 2002 period reflects the borrowings under our revolving bank credit facilities primarily to fund the acquisition of Diamond-Koch’s propylene fractionation business. Cash distributions to our partners increased to $69.2 million during the first quarter of 2003 from $47.4 million during the first quarter of 2002 primarily due to increases in both the declared quarterly distribution rates and the number of Units eligible for distributions.
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Our debt obligations
Parent-Subsidiary guarantor relationships. We act as guarantor of certain debt obligations of our subsidiaries including, all of our Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests). If the Operating Partnership were to default on any guaranteed debt obligation, we would be responsible for full payment of that obligation.
Senior Notes C. In January 2003, we issued $350 million in principal amount of 6.375% fixed-rate Senior Notes C due February 1, 2013 (“Senior Notes C”), from which we received net proceeds before offering expenses of approximately $347.7 million. These notes were sold at face value with no discount or premium. We used the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan that we
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incurred to finance the Mid-America and Seminole acquisitions. In April 2003, we initiated an offer to exchange the private placement Senior Notes C for publicly-registered Senior Notes C.
Our Operating Partnership entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We used $252.8 million of the $258.2 million in proceeds from the January 2003 equity offering, $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan by February 2003.
Credit ratings
Our current investment grade credit ratings are Baa2 by Moody’s Investor Service and BBB by Standard and Poors. Upon our acquisitions of the Mid-America and Seminole pipelines, both agencies maintained our ratings; however, each placed us on negative outlook pending the issuance of an appropriate amount of equity to repay the debt we incurred to fund these acquisitions. The agencies have responded positively to our recent equity and debt offerings. 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 which independently judge our creditworthiness based on a variety of quantitative and qualitative factors.
Capital spending
At March 31, 2003, we had $11.1 million in estimated outstanding purchase commitments attributable to capital projects. Of this amount, $7.8 million is related to the construction of assets that will be recorded as property, plant and equipment and $3.3 million is associated with our share of capital projects of our unconsolidated affiliates which will be recorded as additional investments in unconsolidated affiliates.
During the remainder of 2003, we expect capital spending on internal growth projects to approximate $105.9 million, of which $44.5 million is forecasted for various projects within our Pipelines segment; $35.7 million for the expansion of our Norco NGL fractionator and $13.3 million for the expansion of our Neptune gas processing facility. Our unconsolidated affiliates forecast a combined $35.1 million in capital expenditures during the remainder of 2003, the majority of which relate to expansion projects on our Gulf of Mexico natural gas pipeline systems. Our share of these forecasted capital expenditures is estimated at $15.1 million.
EPCO subleases to us all of the equipment it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, two cogeneration units and approximately 100 railcars for one dollar per year and has assigned to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the lease payments associated with these items. We have notified the original lessor of the isomerization unit of our intent to exercise the purchase option assigned to us. The purchase price of this equipment is expected to be up to $23.1 million and be payable in 2004.
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With regards to our material contractual obligations, there have been no significant changes outside of the ordinary course of our business since December 31, 2002 except for the following:
The following table summarizes our updated material contractual obligations related to our debt obligations:
Relationship with EPCO and Its Affiliates
We have an extensive and ongoing relationship with EPCO and its affiliates. EPCO is controlled by Dan L. Duncan, Chairman and a director (and Chairman of the Board of Directors) of the General Partner. In addition, three other members of the Board of Directors (O.S. Andras, Randa D. Williams and Richard H. Bachmann) and the remaining executive and other officers of the General Partner are employees of EPCO. The principal business activity of our General Partner is to act as our managing partner. Collectively, EPCO and its affiliates owned 57.4% of our limited partnership interests and 70.0% of our General Partner at March 31, 2003.
We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO. We reimburse EPCO for the costs of its employees who perform operating functions for us. In addition, we reimburse EPCO for the costs of certain of employees who manage our business and affairs.
EPCO is also the operator of certain facilities we own or have an equity interest in. We have also entered into an agreement with EPCO to provide trucking services to us for the loading and transportation of products. Lastly, in the normal course of business, we buy from and sell NGL products to EPCO’s Canadian affiliate.
The following table shows our related party revenues and operating expenses attributable to EPCO for the periods indicated:
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Relationship with Shell
We have a commercial relationship with Shell as a partner, customer and vendor. At March 31, 2003, Shell owned approximately 20.1% of our limited partnership interests and 30.0% of our General Partner. Currently, three members of the Board of Directors of the General Partner (J.A. Berget, J.R. Eagan and A.Y. Noojin, III) are employees of Shell.
Shell and its affiliates are the Company’s single largest customer. During the three months ended March 31, 2003 and 2002, they accounted for 5.5% and 8.7%, respectively, of our consolidated revenues. Our revenues from Shell reflect the sale of NGL and petrochemical products to them and the fees we charge them for 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 them.
The most significant contract affecting our natural gas processing business is the 20-year, keepwhole Shell processing agreement, which grants us the right to process Shell’s current and future production from state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond 20 years. This contract was amended effective March 1, 2003. Generally, the amended contract has the following rights and obligations:
In our natural gas processing activities under this contract, we reimburse Shell for the energy value of (i) the NGLs we extract and (ii) the natural gas we consume as fuel. This energy value is referred to as plant thermal reduction (“PTR”) and is based on the Btu content of the natural gas taken out of the stream. The amended contract contains a mechanism (termed “Consideration Adjustment Outside of Normal Operations” or “CAONO”) to adjust the value of the PTR we reimburse to Shell. The CAONO, in effect, protects us from processing at an economic loss when the value of the NGLs we extract is less than the sum of the cost of the PTR reimbursement, operating costs of the gas processing facility and other costs such as NGL fractionation and pipeline fees.
In general, the CAONO adjustment requires the comparison of our average net gas processing margin to an upper and lower limit (all as defined within the agreement). If our average net processing margin is below the lower limit, the PTR reimbursement payable to Shell is decreased by the product of the absolute value of the difference between our average net processing margin and the specified lower limit multiplied by the volume of NGLs extracted. To the extent our average net processing margin is higher than the upper limit (the probability of which we believe is low), the PTR reimbursement payable to Shell is increased by the product of the difference between the average net gas processing margin and the specified upper limit multiplied by the volume of NGLs extracted.
The underlying purpose of the CAONO mechanism is to provide Shell with relative assurance that its gas will continue to be processed during periods when natural gas prices are high relative to NGL prices (times when we would choose not to process) while continuing to protect us from processing Shell’s gas at an economic loss.
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The following table shows our related party revenues and operating expenses attributable to Shell for the periods indicated:
Shell is also a partner with us in the Gulf of Mexico natural gas pipelines we acquired from El Paso in 2001. We also lease from Shell its 45.4% interest in our Splitter I propylene fractionation facility.
As a result of our analysis of the identified AROs, we were not required to recognize such potential liabilities. Our rights to the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently plan to renew all such easement agreements and use these properties indefinitely. Therefore, the ARO liability is not estimable for such easements. If we decide not to renew these agreements, an ARO liability would be recorded at that time. ARO liabilities related to statutory regulatory requirements for abandonment or retirement of certain currently operated facilities were also identified. We currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement occurred. Certain Gulf of Mexico natural gas pipelines, in which we have an equity interest, have identified ARO’s relating to regulatory requirements. There is no current intention to abandon or retire these pipelines. If these pipelines were abandoned or retired, an ARO liability would then be disclosed.
SFAS No. 148. We adopted this standard as of December 31, 2002. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. We have provided the information required by this statement under footnote 14 of the Notes to Unaudited Consolidated Financial Statements included elsewhere in this quarterly report.
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FIN 45. We implemented this FASB interpretation as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We have provided the information required by this interpretation under footnote 8 of the Notes to Unaudited Consolidated Financial Statements included elsewhere in this quarterly report.
In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the 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.
There have been no significant changes in our critical accounting policies since December 31, 2002. For a detailed discussion of these policies, please see the section titled “Our critical accounting policies” under Item 7 of our annual report on Form 10-K for 2002. The following is a condensed discussion of our critical accounting policies and the estimates and assumptions underlying them.
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. Additionally, if we determine that an asset’s undepreciated cost may not be recoverable due to impairment, this would result in a charge against earnings.
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At March 31, 2003 and December 31, 2002, the net book value of our property, plant and equipment was $2.8 billion. See footnote 5 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our property, plant and equipment.
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 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, 2003 and December 31, 2002, the net book value of our intangible assets was $274.1 million and $277.7 million. See footnote 7 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our intangible assets.
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 impact the fair value of the reporting unit and result in a charge to earnings to reduce the carrying value of goodwill.
At March 31, 2003 and December 31, 2002, the carrying value of our goodwill was $81.5 million. See footnote 7 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our goodwill.
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. The revenues that we record are not materially based on estimates. We believe the assumptions underlying any revenue estimates that we use will not prove to be significantly different from actual amounts due to the routine nature of these estimates and the stability of our operations.
Mark-to-market accounting for certain financial instruments
Our earnings are also affected by use of the mark-to-market method of accounting required under GAAP for certain financial instruments. We use short-term, highly liquid financial instruments such as swaps, forwards and other contracts to manage price risks associated with inventories, firm commitments and certain anticipated transactions, primarily within our Processing segment. The use of mark-to-market accounting for financial instruments may cause our non-cash earnings to fluctuate based upon changes in underlying indexes, primarily commodity prices. Fair value for the financial instruments we employ is determined using price data from highly liquid markets such as the NYMEX commodity exchange.
During the first three months of 2002, we recognized a loss of $45.1 million from our commodity hedging activities. Of this loss, $28.7 million was attributable to the change in fair value of the portfolio between December
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31, 2001 and March 31, 2002. The fair value of open positions at March 31, 2002 was a payable of $23.1 million. In March 2002, the effectiveness of our primary commodity hedging strategy deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss.
During the first three months of 2003, we entered into a limited number of commodity financial instruments from which we recorded a loss of $0.9 million. The fair value of open positions at March 31, 2003 was a receivable of approximately $2 thousand. See footnote 11 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our financial instruments.
Uncertainties regarding our investment in BEF
In recent years, MTBE has been detected in municipal and private water supplies resulting in various legal actions. BEF has not been named in any MTBE legal action to date. In light of these developments, we and the other two partners of BEF are formulating a plan for the BEF facility if MTBE is banned. We are evaluating a possible conversion of the facility from MTBE production to alkylate production. The carrying value of our investment in BEF was $50.9 million at March 31, 2003.
Conversion of EPCO Subordinated Units to Common Units
On May 1, 2003, 10,704,936 of EPCO’s Subordinated Units converted to Common Units as a result of the Company satisfying certain financial tests. The remaining 21,409,872 Subordinated Units are anticipated to convert to Common Units on August 1, 2003. These conversions will have no impact upon our earnings per unit or distributions since Subordinated Units are already included in both the basic and fully-diluted earnings per unit calculations and are distribution-bearing.
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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 review our “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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There has been no material change in our commodity financial instruments portfolio since December 31, 2002. During the first quarter of 2003, we settled all interest rate-related financial instruments that were outstanding at December 31, 2002 (see the following discussion titled “Interest rate-related financial instruments portfolio”). For additional information regarding our financial instruments, see footnote 11 of our Notes to Unaudited Consolidated Financial Statements.
Commodity financial instruments portfolio
At December 31, 2002, the net fair value of this portfolio was a payable of $26 thousand, based entirely upon quoted market prices. At March 31, 2003, the net fair value of this portfolio was a receivable $2 thousand. We continue to have only a limited number of commodity financial instruments outstanding.
During the first three months of 2002, we recognized a loss of $45.1 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations. In March 2002, the effectiveness of our primary commodity hedging strategy at the time deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.
During the first three months of 2003, we recorded a loss of $0.9 million from our commodity hedging activities, of which $0.1 million is attributable to the Processing segment and the remainder to Pipelines.
Interest rate-related financial instruments portfolio
Interest rate swap agreements. At December 31, 2002, we had one interest rate swap outstanding having a notional amount of $54 million and a fair value at that date of $1.6 million. The counterparty elected to exercise its option to terminate this swap as of March 1, 2003 and we received $1.6 million associated with the final settlement of this swap on that date. The early termination of the swap had no impact on our earnings. At March 31, 2003, we have no interest rate swap agreements outstanding.
Treasury Locks. During the fourth quarter of 2002, we entered into seven treasury lock transactions, each with an original maturity of either January 31, 2003 or April 15, 2003. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific U.S. treasury security for an established period of time. The purpose of these transactions was to hedge the underlying treasury interest rate associated with our anticipated issuance of debt in early 2003 to partially refinance the Mid-America and Seminole acquisitions. Our treasury lock transactions are accounted for as cash flow hedges under SFAS No. 133. The notional amounts of these transactions totaled $550 million, with a total treasury lock rate of approximately 4%.
We elected to settle all of the treasury locks during the first quarter of 2003 in connection with our issuance of Senior Notes C and D (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our liquidity and capital resources—Our debt obligations” under Item 2 of this quarterly report). The settlement of the treasury locks resulted in our receipt of $5.4 million of cash.
The fair value of these instruments at December 31, 2002 was a current liability of $3.8 million offset by a current asset of $0.2 million. The net $3.6 million net liability was recorded as a component of comprehensive income on that date, with no impact to current earnings. With the settlement of the treasury locks, the $3.6 million net liability was reclassified out of accumulated other comprehensive income in Partners’ Equity to offset the
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current asset and liabilities we recorded at December 31, 2002, with no impact to earnings. For additional information regarding our treasury lock transactions, see our footnote 11 of our Notes to Unaudited Consolidated Financial Statements.
In the 90-day period before the filing of this quarterly report, the CEO and CFO of the General Partner of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively the “registrants”) have evaluated the effectiveness of the registrants’ disclosure controls and procedures. These disclosure controls and procedures are those controls and other procedures we maintain, which are designed to insure that all of the information required to be disclosed by the registrants in all of their combined and separate periodic reports filed with the SEC is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the registrants in their reports filed or submitted under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including the CEO and CFO of the General Partner, as appropriate to allow those persons to make timely decisions regarding required disclosure.
Subsequent to the date when the disclosure controls and procedures were evaluated, there have not been any significant changes in the registrants’ controls or procedures or in other factors that could significantly affect such controls or procedures. No significant deficiencies or material weaknesses were detected, so no corrective actions needed to be taken.
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(a)(1) and (2) Financial Statements and Financial Statement Schedules.
See “Index to Financial Statements” set forth on page F-1.
(a)(3) Exhibits.
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(b) Reports on Form 8-K.
January 10, 2003 filing, Item 5. On January 9, 2003, we entered into an underwriting agreement for the public offering of 12,750,000 Common Units, including 1,000,000 Common Units to be offered to four trusts established for the benefit of the children of Dan L. Duncan, the Chairman of the Board of our General Partner. Closing of the issuance and sale of the Common Units occurred on January 15, 2003.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this combined quarterly report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on May 13, 2003.
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CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OFENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OFENTERPRISE PRODUCTS PARTNERS L.P.
I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Partners L.P., certify that:
Date: May 13, 2003
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CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OFENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OFENTERPRISE PRODUCTS PARTNERS L.P.
I, Michael A. Creel, the Principal Financial Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Partners L.P., certify that:
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CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OFENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF ENTERPRISE PRODUCTS OPERATING L.P.
I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Operating L.P., certify that:
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CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OFENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OFENTERPRISE PRODUCTS OPERATING L.P.
I, Michael A. Creel, the Principal Financial Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Operating L.P., certify that:
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EXHIBIT 99.1
CERTIFICATION OF O.S. ANDRAS, CHIEF EXECUTIVE OFFICEROF ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF ENTERPRISE PRODUCTS OPERATING L.P. AND ENTERPRISE PRODUCTS PARTNERS L.P.
In connection with this combined quarterly report of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively, the “Registrants”) on Form 10-Q for the three months ending March 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, O.S. Andras, Chief Executive Officer of Enterprise Products GP, LLC, the General Partner of the Registrants, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrants.
A signed original of this written statement required by Section 906 has been provided to the Registrants and will be retained by the Registrants and furnished to Securities and Exchange Commission or its staff upon request.
CERTIFICATION OF MICHAEL A. CREEL, CHIEF FINANCIAL OFFICER OF ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OFENTERPRISE PRODUCTS OPERATING L.P. AND ENTERPRISE PRODUCTS PARTNERS L.P.
In connection with the combined quarterly report of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively, the “Registrants”) on Form 10-Q for the three months ending March 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael A. Creel, Chief Financial Officer of Enterprise Products GP, LLC, the General Partner of the Registrants, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that: