FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 |X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2001 OR |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______ to _______ Commission file number: 1-14323 Enterprise Products Partners L.P. (Exact name of Registrant as specified in its charter) Delaware 76-0568219 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2727 North Loop West Houston, Texas 77008-1037 (Address of principal executive offices) (Zip code) (713) 880-6500 (Registrant's telephone number including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes _X_ No ___ The registrant had 46,524,515 Common Units outstanding as of May 14, 2001.Enterprise Products Partners L.P. and Subsidiaries TABLE OF CONTENTS Page No. --- Part I. Financial Information Item 1. Consolidated Financial Statements Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements: Consolidated Balance Sheets, March 31, 2001 and December 31, 2000 1 Statements of Consolidated Operations for the three months ended March 31, 2001 and 2000 2 Statements of Consolidated Cash Flows for the three months ended March 31, 2001 and 2000 3 Statements of Consolidated Partners' Equity and Comprehensive Income for the three months ended March 31, 2001 and 2000 4 Notes to Unaudited Consolidated Financial Statements 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operation 18 Item 3. Quantitative and Qualitative Disclosures about Market Risk 28 Part II. Other Information Item 2. Use of Proceeds 31 Item 6. Exhibits and Reports on Form 8-K 32 Signature PagePART 1. FINANCIAL INFORMATION. Item 1. CONSOLIDATED FINANCIAL STATEMENTS. Enterprise Products Partners L.P. Consolidated Balance Sheets (Dollar amounts in thousands) March 31, 2001 December 31, ASSETS (Unaudited) 2000 --------------------------------------- Current Assets Cash and cash equivalents $ 379,411 $ 60,409 Accounts receivable - trade, net of allowance for doubtful accounts of $10,227 at March 31, 2001 and $10,916 at December 31, 2000 323,897 409,085 Accounts receivable - affiliates 2,105 6,533 Inventories 24,770 93,222 Prepaid and other current assets 21,494 12,107 --------------------------------------- Total current assets 751,677 581,356 Property, Plant and Equipment, Net 991,216 975,322 Investments in and Advances to Unconsolidated Affiliates 405,182 298,954 Intangible assets, net of accumulated amortization of $6,624 at March 31, 2001 and $5,374 at December 31, 2000 91,619 92,869 Other Assets 9,931 2,867 --------------------------------------- Total $2,249,625 $1,951,368 ======================================= LIABILITIES AND PARTNERS' EQUITY Current Liabilities Accounts payable - trade $82,700 $96,559 Accounts payable - affiliate 38,498 56,447 Accrued gas payables 276,811 377,126 Accrued expenses 10,097 21,488 Other current liabilities 28,099 34,759 --------------------------------------- Total current liabilities 436,205 586,379 Long-Term Debt 855,773 403,847 Other Long-Term liabilities 15,555 15,613 Minority Interest 9,738 9,570 Commitments and Contingencies Partners' Equity Common Units (46,257,315 Units outstanding at March 31, 2001 and December 31, 2000) 526,364 514,896 Subordinated Units (21,409,870 Units outstanding at March 31, 2001 and December 31, 2000) 170,462 165,253 Special Units (16,500,000 Units outstanding at March 31, 2001 and December 31, 2000) 251,132 251,132 Treasury Units acquired by Trust, at cost (267,200 Common Units outstanding at March 31, 2001 and December 31, 2000) (4,727) (4,727) General Partner 9,575 9,405 Accumulated other comprehensive loss (see Note 8) (20,452) --------------------------------------- Total Partners' Equity 932,354 935,959 --------------------------------------- Total $2,249,625 $1,951,368 ======================================= See Notes to Unaudited Consolidated Financial Statements Page 1Enterprise Products Partners L.P. Statements of Consolidated Operations (Unaudited) (Amounts in thousands, except per Unit amounts) Three Months Ended March 31, ------------------------------- 2001 2000 ------------------------------- REVENUES Revenues from consolidated operations $836,315 $746,281 Equity income in unconsolidated affiliates 2,011 7,443 ------------------------------- Total 838,326 753,724 COST AND EXPENSES Operating costs and expenses 777,741 672,906 Selling, general and administrative 6,168 5,384 ------------------------------- Total 783,909 678,290 ------------------------------- OPERATING INCOME 54,417 75,434 OTHER INCOME (EXPENSE) Interest expense (6,987) (7,774) Interest income from unconsolidated affiliates 24 144 Dividend income from unconsolidated affiliates 1,632 1,234 Interest income - other 3,998 1,481 Other, net (280) (363) ------------------------------- Other income (expense) (1,613) (5,278) ------------------------------- INCOME BEFORE MINORITY INTEREST 52,804 70,156 MINORITY INTEREST (534) (709) ------------------------------- NET INCOME $ 52,270 $ 69,447 =============================== BASIC EARNINGS PER UNIT Income before minority interest $ 0.77 $ 1.04 =============================== Net income per Common and Subordinated unit $ 0.76 $ 1.03 =============================== DILUTED EARNINGS PER UNIT Income before minority interest $ 0.62 $ 0.86 =============================== Net income per Common, Subordinated and Special unit $ 0.61 $ 0.85 =============================== See Notes to Unaudited Consolidated Financial Statements Page 2Enterprise Products Partners L.P. Statements of Consolidated Cash Flows (Unaudited) (Dollar amounts in thousands) Three Months Ended March 31, ------------------------------------- 2001 2000 ------------------------------------- OPERATING ACTIVITIES Net income $ 52,270 $ 69,447 Adjustments to reconcile net income to cash flows provided by (used for) operating activities: Depreciation and amortization 10,781 9,048 Equity in income of unconsolidated affiliates (2,011) (7,443) Distributions received from unconsolidated affiliates 8,866 7,149 Leases paid by EPCO 2,633 2,637 Minority interest 534 709 Gain on sale of assets (381) Changes in fair market value of financial instruments (see Note 8) (16,361) Net effect of changes in operating accounts (7,634) 5,265 ------------------------------------- Operating activities cash flows 48,697 86,812 ------------------------------------- INVESTING ACTIVITIES Capital expenditures (25,338) (111,449) Proceeds from sale of assets 557 2 Collection of notes receivable from unconsolidated affiliates 3,287 Investments in and advances to unconsolidated affiliates (113,083) (5,972) ------------------------------------- Investing activities cash flows (137,864) (114,132) ------------------------------------- FINANCING ACTIVITIES Long-term debt borrowings 449,716 463,818 Long-term debt repayments - (355,000) Debt issuance costs (3,125) (2,451) Cash dividends paid to partners (38,056) (33,820) Cash dividends paid to minority interest by Operating Partnership (393) (345) Cash contributions from EPCO to minority interest 27 30 ------------------------------------- Financing activities cash flows 408,169 72,232 ------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS 319,002 44,912 CASH AND CASH EQUIVALENTS, JANUARY 1 60,409 5,230 ------------------------------------- CASH AND CASH EQUIVALENTS, MARCH 31 $379,411 $ 50,142 ===================================== See Notes to Unaudited Consolidated Financial Statements Page 3Enterprise Products Partners L.P. Statements of Consolidated Partners' Equity and Comprehensive Income (Unaudited, amounts in thousands) Partners' Equity ---------------------------------------------------------------------------- March 31, 2001 March 31, 2000 ------------------------------------- ------------------------------------- Units Amount Units Amount ------------------------------------- ------------------------------------- Limited Partners Balance, beginning of year 84,434 $931,281 81,463 $786,250 Net income 51,288 68,753 Leases paid by EPCO 2,606 2,611 Cash distributions (37,217) (33,483) ------------------------------------- ------------------------------------- Balance, end of period 84,434 947,958 81,463 824,131 ------------------------------------- ------------------------------------- ------------------------------------- ------------------------------------- Treasury Units (267) (4,727) (267) (4,727) ------------------------------------- ------------------------------------- General Partner Balance, beginning of year 9,405 7,942 Net income 982 694 Leases paid by EPCO 27 26 Cash distributions (839) (337) ------------------- ------------------ Balance, end of period 9,575 8,325 ------------------- ------------------ Accumulated Other Comprehensive Loss Cumulative transition adjustment recorded on January 1, 2001 upon adoption of SFAS 133 (42,190) (see Note 8) Reclassification of cumulative transition adjustment to earnings 21,738 ------------------- Balance, end of period (20,452) ------------------- ------------------------------------- ------------------------------------- Total Partners' Equity 84,167 $932,354 81,196 $827,729 ===================================== ===================================== Comprehensive Income For Three Months Ended ---------------------------------------------------------------------------- March 31, 2001 March 31, 2000 ------------------------------------- ------------------------------------- Net Income $ 52,270 $ 69,447 Less: Accumulated Other Comprehensive Loss (20,452) ------------------- ------------------ Comprehensive Income $ 31,818 $ 69,447 =================== ================== See Notes to Unaudited Consolidated Financial Statements Page 4Enterprise Products Partners L.P. Notes to Consolidated Financial Statements (Unaudited) 1. GENERAL In the opinion of Enterprise Products Partners L.P. (the "Company"), the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of the Company's consolidated financial position as of March 31, 2001 and consolidated results of operations, cash flows, partners' equity and comprehensive income for the three month periods ended March 31, 2001 and 2000. Although the Company believes 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 Securities and Exchange Commission. These unaudited financial statements should be read in conjunction with the financial statements and notes thereto included in the Company's annual report on Form 10-K (File No. 1-14323) for the year ended December 31, 2000. The results of operations for the three month period ended March 31, 2001 are not necessarily indicative of the results to be expected for the full year. Certain reclassifications have been made to prior years' financial statements to conform to the presentation of the current period financial statements. Dollar amounts presented in the tabulations within the notes to the consolidated financial statements are stated in thousands of dollars, unless otherwise indicated. All references to "Shell," unless the context indicates otherwise, shall refer collectively to Shell Oil Company, its subsidiaries and affiliates. Likewise, all references herein to "EPE," shall refer collectively to El Paso Corporation, its subsidiaries and affiliates. 2. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES The Company owns interests in a number of related businesses that are accounted for under the equity method or cost method. 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 the Company's business segments, see Note 9. At March 31, 2001, the Company's equity method investments (grouped by operating segment) included: Fractionation segment: o Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in a natural gas liquid ("NGL") fractionation facility located in southeastern Louisiana. o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest in a propylene concentration unit located in southeastern Louisiana that became operational in July 2000. o K/D/S Promix LLC ("Promix") - a 33.33% interest in a NGL fractionation facility and related storage facilities located in south Louisiana. The Company's investment includes excess cost over the underlying equity in the net assets of Promix of $8.0 million which is being amortized using the straight-line method over a period of 20 years. The unamortized balance of excess cost over the underlying equity in the net assets of Promix was $7.3 million at March 31, 2001. Pipeline segment: o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate interest in a refrigerated NGL marine terminal loading facility located in southeast Texas. Page 5o Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in a NGL pipeline system located in southeastern Louisiana. o Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% interest in a NGL pipeline system located in Louisiana, Mississippi, and Alabama. o Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.7% interest in a NGL pipeline system located in south Louisiana. o Dixie Pipeline Company ("Dixie") - a 19.9% interest in a 1,301-mile propane pipeline and associated facilities extending from Mont Belvieu, Texas to North Carolina. o Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural gas gathering system and related dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. o Ocean Breeze Pipeline Company LLC ("Ocean Breeze") - a 25.67% interest in a limited liability company ("LLC") owning a 1% interest in the natural gas gathering and transmission systems owned by Manta Ray Offshore Gathering Company, LLC ("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") located in the Gulf of Mexico offshore Louisiana. o Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in a limited liability company owning a 99% interest in the Manta Ray and Nautilus natural gas gathering and transmission systems. o Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas gathering system being constructed in the Gulf of Mexico offshore Louisiana. The system is scheduled for completion in late 2001. The Company's investment in Ocean Breeze and Neptune includes excess cost over the underlying equity in the net assets of these entities of $24.0 million which is being amortized using the straight-line method over a period of 35 years (as a pipeline asset). The unamortized balance of excess cost over the underlying equity in the net assets of Ocean Breeze and Neptune was $23.8 million at March 31, 2001. Likewise, the Company's investment in Nemo includes excess cost over the underlying equity in the net assets of $0.8 million which will be amortized using the straight-line method over a period of 35 years (as a pipeline asset) when Nemo becomes operational in late 2001. See Note 3 for further information regarding the Company's investments in Starfish, Ocean Breeze, Neptune and Nemo. Octane Enhancement segment: o Belvieu Environmental Fuels ("BEF") - a 33.3% interest in a Methyl Tertiary Butyl Ether ("MTBE") production facility located in southeast Texas. The production of MTBE is driven by oxygenated fuels programs enacted under the federal Clean Air Act Amendments of 1990 and other legislation. Any changes to these programs that enable localities to elect not to participate in these programs, lessen the requirements for oxygenates or favor the use of non-isobutane based oxygenated fuels reduce the demand for MTBE and could have an adverse effect on the Company's results of operations. In recent years, MTBE has been detected in water supplies. The major source of the ground water contamination appears to be leaks from underground storage tanks. Although these detections have been limited and the great majority have been well below levels of public health concern, there have been calls for the phase-out of MTBE in motor gasoline in various federal and state governmental agencies and advisory bodies. In light of these developments, the owners of BEF have been formulating a contingency plan for use of the BEF facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion of the BEF facility from MTBE production to alkylate production. Depending upon the type of alkylate process chosen and the level of alkylate production desired, the cost to convert the facility from MTBE production to alkylate production can range from $20 million to $90 million, with the Company's share of these costs ranging from $6.7 million to $30 million. At March 31, 2001, the Company's investments in and advances to unconsolidated affiliates also includes Venice Energy Services Company, LLC ("VESCO"). The VESCO investment consists of a 13.1% interest in a LLC owning a natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in Louisiana. This investment is accounted for using the cost method. Page 6The following table summarizes investments in and advances to unconsolidated affiliates at: March 31, December 31, 2001 2000 ------------------------------------- Accounted for on equity basis: Fractionation: BRF $ 30,552 $ 30,599 BRPC 20,752 25,925 Promix 47,233 48,670 Pipeline: EPIK 15,195 15,998 Wilprise 8,747 9,156 Tri-States 27,103 27,138 Belle Rose 11,714 11,653 Dixie 38,110 38,138 Starfish 26,097 Ocean Breeze 970 Neptune 77,472 Nemo 9,151 Octane Enhancement: BEF 59,086 58,677 Accounted for on cost basis: Processing: VESCO 33,000 33,000 ------------------------------------- Total $405,182 $298,954 ===================================== The following table shows equity in income (loss) of unconsolidated affiliates for the periods indicated: For Three Months Ended March 31, ------------------------------------- 2001 2000 ------------------------------------- Fractionation: BRF $ 18 $ 529 BRPC 152 10 Promix 393 1,662 Pipeline: EPIK (922) 1,792 Wilprise (222) 88 Tri-States (35) 678 Belle Rose (89) 179 Dixie 891 Starfish 951 Ocean Breeze 2 Neptune 694 Nemo 9 Octane Enhancement: BEF 169 2,505 ------------------------------------- Total $2,011 $7,443 ===================================== Page 7The following table presents summarized income statement information for the unconsolidated subsidiaries accounted for by the equity method for the periods indicated (on a 100% basis): Summarized Income Statement data for the Three Months ended ----------------------------------------------------------------------------------------------- March 31, 2001 March 31, 2000 ---------------------------------------------- ----------------------------------------------- Operating Net Operating Net Revenues Income Income Revenues Income Income ---------------------------------------------- ----------------------------------------------- Fractionation: BRF $ 4,023 $ 35 $ 56 $ 4,971 $ 1,653 $ 1,636 BRPC 3,433 439 505 - - 34 Promix 9,002 1,440 1,477 12,484 5,236 5,285 Pipeline: EPIK 691 (1,891) (1,862) 9,156 3,560 3,594 Wilprise 398 (602) (594) 732 258 263 Tri-States 1,632 (126) (105) 3,734 1,980 2,035 Belle Rose 147 (219) (213) 857 430 430 Dixie (a) 19,327 9,649 5,834 Starfish (b) 6,616 2,098 1,902 Ocean Breeze (b) 20 12 12 Neptune (b) 7,409 3,148 3,369 Nemo (b) - (16) 28 Octane Enhancement: BEF 37,864 413 507 53,333 7,607 7,516 ---------------------------------------------- ----------------------------------------------- Total $ 90,562 $14,380 $10,916 $85,267 $20,724 $20,793 ============================================== =============================================== Notes to Summarized Income Statement data table: - ------------------------------------------------ (a) Dixie became an equity method investment in October 2000. (b) These entities became equity method investments of the Company in January 2001, see Note 3 for description of acquisitions. 3. ACQUISITIONS Manta Ray, Nautilus and Nemo Pipeline Systems On January 29, 2001, the Company acquired interests in three natural gas pipeline systems and related equipment located in the Gulf of Mexico offshore Louisiana from EPE for $88.1 million in cash. These systems total approximately 350 miles of pipeline. The Company acquired a 25.67% interest in each of the Manta Ray and Nautilus pipeline systems (as a result of its investment in Ocean Breeze and Neptune) and a 33.92% interest in the Nemo pipeline system. Affiliates of Shell own an interest in all three systems, and an affiliate of Marathon Oil Company owns an interest in the Manta Ray and Nautilus systems. The Manta Ray system comprises approximately 225 miles of pipeline with a capacity of 750 million cubic feet ("MMcf") per day and related equipment, the Nautilus system comprises approximately 101 miles of pipeline with a capacity of 600 MMcf per day, and the Nemo system, when completed in the fourth quarter of 2001, will comprise approximately 24 miles of pipeline with a capacity of 300 MMcf per day. Stingray Pipeline System and Related Facilities On January 29, 2001, the Company and an affiliate of Shell acquired, through their 50/50 ownership of Starfish, the Stingray natural gas pipeline system and related facilities from EPE for $50.2 million in cash. The Stingray system comprises approximately 375 miles of pipeline with a capacity of 1.2 billion cubic feet ("Bcf") per day Page 8offshore Louisiana in the Gulf of Mexico. Shell will be responsible for the commercial and physical operations of the Stingray system. The pro forma results of operations incorporating these investments for the three-month period ending March 31, 2000 is not materially different than the Company's historical results for the quarter ended March 31, 2000. In addition, the cash payments made to EPE for these acquisitions are subject to certain post-closing adjustments expected to be finalized in the second quarter of 2001. 4. LONG-TERM DEBT Long-term debt consisted of the following at: March 31, December 31, 2001 2000 --------------------------------------- Borrowings under: $350 Million Senior Notes, 8.25% fixed rate, due March 2005 $350,000 $350,000 $54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000 $450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000 --------------------------------------- Total principal amount 854,000 404,000 Increase in fair value related to hedging a portion of fixed-rate debt (see Note 8) 2,196 Less unamortized discount on: $350 Million Senior Notes (144) (153) $450 Million Senior Notes (279) Less current maturities of long-term debt - - --------------------------------------- Long-term debt $855,773 $403,847 ======================================= The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility and $150 Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit facilities at March 31, 2001 or December 31, 2000. At March 31, 2001, the Company had a total of $75 million of standby letters of credit available under its $250 Million Multi-Year Credit Facility of which $54.1 million was outstanding. $450 Million Senior Notes. On January 24, 2001, a subsidiary of the Company completed a public offering of $450 million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting discounts and commissions, of approximately $446.8 million. The proceeds from this offering were used to acquire the Acadian and EPE natural gas pipeline systems for $339.2 million (with $226 million of this amount paid on April 2, 2001 for Acadian - see Note 10) and to finance the cost to construct certain NGL pipelines and related projects and for working capital and other general partnership purposes. The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is also applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As with the $350 Million Senior Notes, the $450 Million Senior Notes: o are subject to a make-whole redemption right; o are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness; and, o are guaranteed by the Company through an unsecured and unsubordinated guarantee. The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 $800 million universal registration statement; therefore, the amount of securities available under this registration statement Page 9was reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement (the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt securities or a combination thereof. The Company expects to use the net proceeds from any sale of securities under the February 2001 Registration Statement for future business acquisitions and other general corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be applied to partnership purposes will depend on a number of factors, including the Company's funding requirements and the availability of alternative funding sources. The Company routinely reviews acquisition opportunities. The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and variable-rate debt instruments at March 31, 2001. Increase in fair value of fixed-rate debt. Upon adoption of Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3 million non-cash increase in the fair value of its fixed-rate debt. SFAS 133 required that the Company's interest rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption of the standard. After adoption of the standard, the interest rate swaps were dedesignated due to differences in the estimated maturity dates of the interest rate swaps versus the fixed-rate debt. As a result, the fair value of the hedged fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million increase in the fair value of the debt will be amortized to earnings over the remaining life of the fixed-rate debt to which it applies, which approximates 10 years. The fair value adjustment of $2.3 million is not a cash obligation of the Company and does not alter the amount of the Company's indebtedness. See Note 8 for additional information concerning the Company's financial instruments. Page 105. EARNINGS PER UNIT 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. Diluted earnings per Unit is computed by dividing net income available to limited partner interests by the weighted-average number of Common, Subordinated and Special Units outstanding during the period. The following table reconciles the number of shares used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three months ended March 31, 2001 and 2000: For the Three Months Ended March 31, 2001 2000 ------------------------------------- Income before minority interest $52,804 $70,156 General partner interest (982) (694) ------------------------------------- Income before minority interest available to Limited Partners 51,822 69,462 Minority interest (534) (709) ------------------------------------- Net income available to Limited Partners $51,288 $68,753 ===================================== BASIC EARNINGS PER UNIT Numerator Income before minority interest available to Limited Partners $51,822 $69,462 ===================================== Net income available to Limited Partners $51,288 $68,753 ===================================== Denominator Common Units outstanding 46,257 45,286 Subordinated Units outstanding 21,410 21,410 ------------------------------------- Total 67,667 66,696 ===================================== Basic Earnings per Unit Income before minority interest available to Limited Partners $ 0.77 $ 1.04 ===================================== Net income available to Limited Partners $ 0.76 $ 1.03 ===================================== DILUTED EARNINGS PER UNIT Numerator Income before minority interest available to Limited Partners $51,822 $69,462 ===================================== Net income available to Limited Partners $51,288 $68,753 ===================================== Denominator Common Units outstanding 46,257 45,286 Subordinated Units outstanding 21,410 21,410 Special Units outstanding 16,500 14,500 ------------------------------------- Total 84,167 81,196 ===================================== Basic Earnings per Unit Income before minority interest available to Limited Partners $ 0.62 $ 0.86 ===================================== Net income available to Limited Partners $ 0.61 $ 0.85 ===================================== Page 116. DISTRIBUTIONS The Company intends, to the extent there is sufficient available cash from Operating Surplus, as defined by the Partnership Agreement, to distribute to each holder of Common Units at least a minimum quarterly distribution of $0.45 per Common Unit. The minimum quarterly distribution is not guaranteed and is subject to adjustment as set forth in the Partnership Agreement. With respect to each quarter during the Subordination Period, the Common Unitholders will generally have the right to receive the minimum quarterly distribution, plus any arrearages thereon, and the General Partner will have the right to receive the related distribution on its interest before any distributions of available cash from Operating Surplus are made to the Subordinated Unitholders. As an incentive, the General Partner's interest in quarterly distributions is increased after certain specified target levels are met. The Company made incentive cash distributions to the General Partner of $0.5 million during the three months ended March 31, 2001 and none during the same period in 2000. On January 17, 2000, the Company declared an increase in its quarterly cash distribution to $0.50 per Unit. This amount was subsequently raised to $0.525 per Unit on July 17, 2000 and $0.55 per Unit on December 7, 2000. On May 3, 2001, the Board of Directors of the General Partner approved an increase in the quarterly distribution rate to $.5875 per Unit beginning with the distribution pertaining to the second quarter of 2001. The following is a summary of cash distributions to partnership interests since the first quarter of 1999: Cash Distributions -------------------------------------------------------------------- Per Per Common Subordinated Record Payment Unit Unit Date Date -------------------------------------------------------------------- 1999 First Quarter $ 0.450 $ 0.450 Jan. 29, 1999 Feb. 11, 1999 Second Quarter $ 0.450 $ 0.070 Apr. 30, 1999 May 12, 1999 Third Quarter $ 0.450 $ 0.370 Jul. 30, 1999 Aug. 11, 1999 Fourth Quarter $ 0.450 $ 0.450 Oct. 29, 1999 Nov. 10, 1999 2000 First Quarter $ 0.500 $ 0.500 Jan. 31, 2000 Feb. 10, 2000 Second Quarter $ 0.500 $ 0.500 Apr. 28, 2000 May 10, 2000 Third Quarter $ 0.525 $ 0.525 Jul. 31, 2000 Aug. 10, 2000 Fourth Quarter $ 0.525 $ 0.525 Oct. 31, 2000 Nov. 10, 2000 2001 First Quarter $ 0.550 $ 0.550 Jan. 31, 2001 Feb. 9, 2001 Second Quarter $ 0.550 $ 0.550 Apr. 30, 2001 May 10, 2001 (through May 14, 2001) Page 127. SUPPLEMENTAL CASH FLOW DISCLOSURE The net effect of changes in operating assets and liabilities is as follows for the periods indicated: Three Months Ended March 31, ------------------------------------------ 2001 2000 ------------------------------------------ (Increase) decrease in: Accounts receivable $89,620 $(25,840) Inventories 68,452 30,085 Prepaid and other current assets (1,824) 3,291 Intangible assets (4,351) Other assets (1,128) (600) Increase (decrease) in: - Accounts payable (31,808) (32,848) Accrued gas payable (100,315) 49,473 Accrued expenses (11,391) (10,941) Other current liabilities (19,182) (2,964) Other liabilities (58) (40) ------------------------------------------ Net effect of changes in operating accounts $(7,634) $ 5,265 ========================================== During the first quarter of 2001, the Company purchased various equity interests in natural gas pipeline companies from EPE for approximately $113.2 million in cash. This amount is reflected in "Investments in and advances to unconsolidated affiliates" for the 2001 period. Capital expenditures for 2000 included $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related assets. As a result of the Company's adoption of SFAS 133 on January 1, 2001, the Company recorded various financial instruments relating to interest rate risk and commodity positions at their respective fair values. For the three months ended March 31, 2001, the Company recognized a net $16.4 million in non-cash mark-to-market gains related to increases in the fair value of these financial instruments ($13.5 million of this amount was attributable to commodity financial instruments with the remainder resulting from interest rate hedging activities). See Note 8 below for a further description of the Company's financial instruments. 8. FINANCIAL INSTRUMENTS The Company holds and issues financial instruments for the purpose of hedging the risks of certain identifiable and anticipated transactions. In general, the types of risks hedged are those relating to the variability of future earnings and cash flows caused by changes in commodity prices and interest rates. Commodity Financial Instruments - Gas Processing and related NGL and natural gas businesses The Company is exposed to commodity price risk through its natural gas processing and related NGL and natural gas businesses. In order to effectively manage this risk, the Company may enter into swaps, forwards, commodity futures, options and other commodity financial instruments with similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial instrument. The purpose of these risk management activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated transactions. The Company has adopted a commercial policy to manage its exposure to the risks generated by its gas processing and related NGL and natural gas businesses. The objective of this policy is to assist the Company in achieving its profitability goals while maintaining a portfolio of conservative risk, defined as remaining within the position limits established by the General Partner. The Company will enter into risk management transactions to manage price risk, basis risk, physical risk, or other risks related to the energy commodities on both a Page 13short-term (less than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the strategies of the Company associated with physical and financial risks, approves specific activities of the Company subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy. On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of the commodity financial instruments on the balance sheet based upon then current market conditions. The fair market value of the then outstanding commodity financial instruments was a net liability of $42.2 million (the "cumulative transition adjustment") with an offsetting equal amount recorded in Other Comprehensive Income. The amounts in Other Comprehensive Income are reclassified to earnings in the accounting period associated with the hedged transaction (e.g. production month). Of the $42.2 million cumulative transition adjustment, $21.7 million was reclassified to earnings during the first quarter of 2001 with the remaining balance scheduled to be reclassified as follows: $10.7 million during the second quarter of 2001, $7.3 million during the third quarter of 2001 and $2.5 million during the fourth quarter of 2001. The amounts recorded in Other Comprehensive Income at adoption of SFAS 133 will not be adjusted for changes in fair value; rather, any change in the fair value of these commodity financial instruments will be recorded in earnings (i.e., mark-to-market accounting treatment). The decision to record changes in the fair value of these commodity financial instruments directly to earnings rather than Other Comprehensive Income is based upon the determination by management that on an ongoing basis these commodity financial instruments would be ineffective under the guidelines of SFAS 133. In addition to the commodity financial instruments outstanding at January 1, 2001, the Company has continued to enter into commodity financial instruments to manage its risks in the gas processing and related NGL and natural gas businesses. Collectively, these financial instruments pertain to time periods extending to October 2001. These commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS 133. The Company continues to refer to these financial instruments as hedges in as much as this was the intent when such contracts were executed. This characterization is consistent with the actual economic performance of the contracts and the Company expects these financial instruments to continue to mitigate commodity price risk in the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS 133. As such, if these contracts do not qualify for hedge accounting under the specific guidelines of SFAS 133, the change in fair value of these commodity financial instruments will be reflected on the balance sheet and in earnings (i.e., mark-to-market accounting treatment). The Company recorded a net $5.6 million benefit in its operating costs and expenses during the first quarter of 2001 relating to the change in fair value of the commodity financial instruments in place as of January 1, 2001 and the change in fair value of commodity financial instruments executed after January 1, 2001. Of this amount, $13.5 million represents net non-cash benefits related to mark-to-market accounting adjustments recorded in earnings at March 31, 2001. The offsetting $7.9 million relates primarily to losses on settlements realized during the quarter. Other Financial Instruments - Interest rate swaps The objective of holding interest rate swaps is to manage debt service costs by converting a portion of the fixed-rate debt into variable-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount. Management believes that it is prudent to maintain a balance between variable-rate and fixed-rate debt. The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate exposure that impact future cash flows and evaluating hedging opportunities. The Company uses analytical techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the expected impact of changes in interest rates on the Company's future cash flows. The General Partner oversees the strategies of the Company associated with financial risks and approves instruments that are appropriate for the Company's requirements. On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of the interest rate swaps on the balance sheet since the swaps were considered fair value hedges. SFAS 133 required that management determine (at the standard's adoption date) (a) the fair value of the swaps based upon then current market conditions and (b) the estimated maturity date of the swaps (including an estimate of the Page 14impact of any early termination clauses). The recording of the fair market value of the swaps was offset by an equal increase in the fair value of the associated hedged debt instruments and, therefore, had no impact on earnings upon transition. See Note 4 for further information regarding the impact of SFAS 133 on the Company's fixed-rate long-term debt. After adoption, the interest rate swaps were dedesignated as hedging instruments due to differences between the maturity dates of the swaps and the associated hedged debt instruments. Dedesignation means that the financial instrument (in this case, the interest rate swaps) will not be accounted for using hedge accounting under SFAS 133. Upon dedesignation, any future changes in the fair value of the interest rate swap agreements will be recorded on the balance sheet through earnings. Dedesignation also entails that the previously associated hedged item (in this case, the debt instrument) will not be adjusted for future changes in its fair value. As a result, the $2.3 million change in fair value of the debt instrument recorded at the adoption date of SFAS 133 will amortized to earnings over the life of the previously associated debt instrument of approximately 10 years. Despite the dedesignation of the interest rate swaps, these financial instruments continue to be effective in achieving the risk management objectives for which they were intended. Interest expense during the first quarter of 2001 decreased $5.2 million due to the change in fair value of the interest rate swaps. The change in fair value of the interest rate swaps does not represent a cash gain or loss for the Company. The actual cash gain or loss on the interest rate swap agreements will be based upon the market interest rates in effect on the specified settlement dates in the swap agreements. The $5.2 million benefit recorded in the first quarter of 2001 was primarily due to the decision of one counterparty not to exercise its early termination right under its swap agreement with the Company (which accounted for $4.3 million of the benefit) and, to a lesser extent, the decision by the U.S. Federal Reserve to lower interest rates. Due to the complexity of SFAS 133, the Financial Accounting Standards Board ("FASB") organized a formal committee, the Derivatives Implementation Group ("DIG"), to provide ongoing recommendations to the FASB about implementation issues. Implementation guidance issued through the DIG process is still continuing; therefore, the initial conclusions reached by the Company concerning the application of SFAS 133 upon adoption may be altered. As a result, additional SFAS 133 transition adjustments may be recorded in future periods as the Company adopts new DIG interpretations approved by the FASB. 9. SEGMENT INFORMATION Operating segments are components of a business about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. The Company has five reportable operating segments: Fractionation, Pipeline, 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. Fractionation includes NGL fractionation, butane isomerization (converting normal butane into high purity isobutane) and polymer grade propylene fractionation services. Pipeline consists of pipeline, storage and import/export terminal services. Processing includes the natural gas processing business and its related NGL merchant activities. Octane Enhancement represents the Company's 33.33% ownership 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 other plant support functions. The Company evaluates segment performance on the basis of gross operating margin. Gross operating margin reported for each segment represents operating income before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of assets and general and administrative expenses. In addition, segment gross operating margin is exclusive of interest expense, interest income (from unconsolidated affiliates or others), dividend income from unconsolidated affiliates, minority interest, extraordinary charges and other income and expense transactions. The Company's equity earnings from unconsolidated affiliates are included in segment gross operating margin. Page 15Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset's or investment's principal operations. The principal reconciling item between consolidated property, plant and equipment and segment property is construction-in-progress. Segment property represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not generally contribute to segment gross operating margin, these assets are not included in the operating segment totals until they are deemed operational. Segment gross operating margin is inclusive of intersegment revenues, which are generally based on transactions made at market-related rates. These revenues have been eliminated from the consolidated totals. Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table: Operating Segments Adjustments ------------------------------------------------------------------- Octane and Consolidated Fractionation Pipelines Processing Enhancement Other Eliminations Totals ---------------------------------------------------------------------------------------------- Revenues from external customers for the three months ended: March 31, 2001 $89,679 $7,187 $738,769 $680 $836,315 March 31, 2000 91,897 7,012 646,857 515 746,281 Intersegment revenues for the three months ended: March 31, 2001 41,652 20,779 110,309 95 (172,835) March 31, 2000 35,465 13,199 142,231 94 (190,989) Equity income in unconsolidated affiliates for the three months ended: March 31, 2001 562 1,280 169 2,011 March 31, 2000 2,201 2,737 2,505 7,443 Total revenues for the three months ended: March 31, 2001 131,893 29,246 849,078 169 775 (172,835) 838,326 March 31, 2000 129,563 22,948 789,088 2,505 609 (190,989) 753,724 Gross operating margin by segment for the three months ended: March 31, 2001 25,668 18,123 28,398 169 535 72,893 March 31, 2000 34,331 14,635 39,554 2,505 554 91,579 Segment property, net at: March 31, 2001 352,682 446,772 125,685 8,413 57,664 991,216 December 31, 2000 356,207 448,920 126,895 8,942 34,358 975,322 Investments in and advances to unconsolidated affiliates at: March 31, 2001 98,537 214,560 33,000 59,085 405,182 December 31, 2000 105,194 102,083 33,000 58,677 298,954 All consolidated revenues were earned in the United States. The operations of the Company are centered along the Texas, Louisiana and Mississippi Gulf Coast areas. Page 16A reconciliation of segment gross operating margin to consolidated income before minority interest follows: For Three Months Ended March 31, 2001 2000 --------------------------------- Total segment gross operating margin $72,893 $91,579 Depreciation and amortization (10,029) (8,124) Retained lease expense, net (2,660) (2,637) Gain on sale of assets 381 - Selling, general and administrative (6,168) (5,384) --------------------------------- Consolidated operating income 54,417 75,434 Interest expense (6,987) (7,774) Interest income from unconsolidated affiliates 24 144 Dividend income from unconsolidated affiliates 1,632 1,234 Interest income - other 3,998 1,481 Other, net (280) (363) --------------------------------- Consolidated income before minority interest $52,804 $70,156 ================================= 10. SUBSEQUENT EVENTS Acadian Acquisition On April 2, 2001, the Company announced that it had completed its acquisition of Acadian Gas, LLC ("Acadian") from Shell US Gas and Power LLC (formerly Coral Energy LLC), an affiliate of Shell for approximately $226 million in cash (utilizing cash on hand at March 31, 2001). The effective date of the transaction was April 1, 2001. Acadian's assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline systems, which together have over one billion cubic feet per day of capacity. These natural gas pipeline systems are wholly-owned by Acadian with the exception of the Evangeline system in which Acadian holds an approximate 49.5% interest. The system includes a leased natural gas storage facility at Napoleonville, Louisiana. These systems link supplies of natural gas from onshore developments and, through connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies, electric generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. In addition, these pipelines have interconnects with 12 interstate pipelines and four intrastate pipelines and a bi-directional interconnect with the U.S. natural gas marketplace at the Henry Hub. Page 17Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION. For the Interim Periods ended March 31, 2001 and 2000 The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Enterprise Products Partners L.P. (the "Company") included elsewhere herein. All references herein to "Shell", unless the context indicates otherwise, shall refer collectively to Shell Oil Company, its subsidiaries and affiliates. Likewise, all references herein to "EPE," shall refer collectively to El Paso Corporation, its subsidiaries and affiliates. Uncertainty of Forward-Looking Statements and Information This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on the belief of the Company and the General Partner, as well as assumptions made by and information currently available to the Company and the General Partner. When used in this document, words such as "anticipate," "estimate," "project," "expect," "plan," "forecast," "intend," "could," "believe," "may" and similar expressions and statements regarding the plans and objectives of the Company for future operations, are intended to identify forward-looking statements. Although the Company and the General Partner believe that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, projected, or expected. Among the key risk factors that may have a direct bearing on the Company's results of operations and financial condition are: (a) competitive practices in the industries in which the Company competes, (b) fluctuations in oil, natural gas, and natural gas liquid ("NGL") product prices and production due to weather and other natural and market forces, (c) operational and systems risks, (d) environmental liabilities that are not covered by indemnity or insurance, (e) the impact of current and future laws and governmental regulations (including environmental regulations) affecting the NGL industry in general, and the Company's operations in particular, (f) loss of a significant customer, and (g) failure to complete one or more new projects on time or within budget. In addition, the Company's expectations regarding its future capital expenditures as described in "Liquidity and Capital Resources" are only its forecasts regarding these matters. These forecasts may be substantially different from actual results due to the factors described in the previous paragraph as well as uncertainties related to the following: (a) the accuracy of the Company's estimates regarding its spending requirements, (b) the occurrence of any unanticipated acquisition opportunities, (c) the need to replace any unanticipated losses in capital assets, (d) changes in the strategic direction of the Company and (e) unanticipated legal, regulatory and contractual impediments with regards to its construction projects. Company Overview The Company is a leading integrated North American provider of natural gas processing and natural gas liquids fractionation, transportation and storage services to producers of NGLs and consumers of NGL products. Beginning in the first quarter of 2001, the Company is also engaged in the transportation of natural gas production from various fields located in Gulf of Mexico offshore Louisiana developments. The Company's natural gas business expanded to encompass the purchase, sale, transportation and storage of natural gas in Louisiana beginning in the second quarter of 2001 as a result of completion of the Acadian Gas, LLC ("Acadian") acquisition from Shell effective April 1, 2001. The Company is a publicly traded master limited partnership (NYSE, symbol "EPD") that conducts substantially all of its business through Enterprise Products Operating L.P. (the "Operating Partnership"), the Operating Partnership's subsidiaries, and a number of joint ventures with industry partners. The Company was formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise Products Company ("EPCO"). The general partner of the Company, Enterprise Products GP, LLC, a majority-owned Page 18subsidiary of EPCO, holds a 1.0% general partner interest in the Company and a 1.0101% general partner interest in the Operating Partnership. The principal executive office of the Company is located at 2727 North Loop West, Houston, Texas, 77008-1038, and the telephone number of that office is 713-880-6500. References to, or descriptions of, assets and operations of the Company in this document include the assets and operations of the Operating Partnership and its subsidiaries. The Company currently provides a wide range of midstream energy services to its customers along the central and western Gulf Coast including the: o gathering, transmission and storage of natural gas from both onshore and offshore Louisiana developments; o purchase and sale of natural gas in south Louisiana; o processing of natural gas into a merchantable and transportable form of energy that meets industry quality specifications by removing NGLs and impurities; o fractionating for a processing fee mixed NGLs produced as by-products of oil and natural gas production into their component products: ethane, propane, isobutane, normal butane and natural gasoline; o converting normal butane to isobutane through the process of isomerization; o producing MTBE from isobutane and methanol; o transporting NGL products to end users by pipeline and railcar; o separating high purity propylene from refinery-sourced propane/propylene mix; and o transporting high purity propylene to plastics manufacturers by pipeline. Natural gas transported, processed and/or sold by the Company generally is consumed as fuel by residential, electric and industrial centers. NGL and petrochemical products processed by the Company generally are used as feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential and commercial heating. Company Operations and Assets The Company's operations are concentrated in the Texas, Louisiana, and Mississippi Gulf Coast area. A large portion of these operations take place in Mont Belvieu, Texas, which is the hub of the domestic NGL industry and is adjacent to the largest concentration of refineries and petrochemical plants in the United States. The facilities the Company operates at Mont Belvieu include: (a) one of the largest NGL fractionation facilities in the United States with a net processing capacity of 131 thousand barrels per day ("MBPD"); (b) the largest commercial butane isomerization complex in the United States with a potential isobutane production capacity of 116 MBPD; (c) a MTBE production facility with a net production capacity of 5 MBPD; and (d) two propylene fractionation units with a combined production capacity of 31 MBPD. The Company owns all of the assets at its Mont Belvieu facility except for the NGL fractionation facility, in which it owns an effective 62.5% interest; one of the propylene fractionation units, in which it owns a 54.6% interest and controls the remaining interest through a long-term lease; the MTBE production facility, in which it owns a 33.3% interest; and one of its three isomerization units and one deisobutanizer which are held under long-term leases with purchase options. The Company's operations in Louisiana and Mississippi include varying interests in twelve natural gas processing plants with a combined capacity of 11.6 billion cubic feet per day ("Bcfd") and net capacity of 3.2 Bcfd, six NGL fractionation facilities with a combined net processing capacity of 159 MBPD and a propylene fractionation facility with a net capacity of 7 MBPD. The Company owns, operates or has an interest in approximately 65.0 million barrels of gross storage capacity (44.3 million barrels of net capacity) in Texas, Louisiana and Mississippi that are an integral part of its processing operations. The Company also leases and operates one of only two commercial NGL import/export terminals on the Gulf Coast. In addition, the Company has operating and non-operating ownership interests in over 2,900 miles of NGL and petrochemical pipelines. Page 19Beginning in January 2001, the Company owns varying interests in four offshore natural gas gathering and transmission systems totaling 725 miles of pipeline (with an aggregate gross capacity of 2.85 Bcfd) and an onshore natural gas dehydration facility. Equity interests in these assets were purchased from EPE at a cost of approximately $113.2 million (subject to certain post-closing adjustments). These pipelines and their associated assets are strategically located to serve expanding continental shelf and deepwater developments in the Gulf of Mexico. With the completion of the Acadian acquisition in April 2001 (a second quarter 2001 event), the Company now owns varying interests in an additional 1,042 miles of natural gas gathering and transmission pipelines (with an aggregate gross capacity of over 1.0 Bcfd) and related facilities. The cost of the acquisition was approximately $226 million. The Acadian acquisition: o gives the Company an extensive intrastate natural gas pipeline system with access to both supply and markets; o positions the Company to compete for incremental natural gas supplies from new discoveries onshore, the offshore Louisiana continental shelf and Gulf of Mexico deepwater developments; o enables the Company to compete for growing industrial and petrochemical demand (including new gas-fired power generation projects); and o allows for additional natural gas processing opportunities. The acquisition of these natural gas businesses from EPE and Shell represents a strategic investment for the Company. Management believes that these assets have attractive growth attributes given the expected long-term increase in natural gas demand for industrial and power generation uses. In addition, these assets extend the Company's midstream energy service relationship with long-term NGL customers (producers, petrochemical suppliers and refineries) and provide opportunities for enhanced services to customers as well as generating additional fee-based cash flows. The Company's operating margins are primarily derived from services provided to its tolling customers and from merchant activities. In its tolling operations, the Company is paid a fee based on volumes processed, transported, stored or handled. The Company generally does not take title to products as part of its tolling operations; however, in those instances where title to products does transfer to the Company, the Company matches the timing and purchase price of the products with those of the sale of the products so as to reduce or eliminate exposure to fluctuations in commodity prices. Examples of the Company's tolling operations include the Gulf of Mexico natural gas pipelines, NGL fractionation services, isomerization tolling arrangements, propylene fractionation, liquids pipeline transportation services and fee-based marketing services. In its merchant activities, the Company is exposed to fluctuations in commodity prices. In the Company's isobutane merchant business (and to a certain extent its propylene fractionation activities), the Company takes title to feedstock products and sells processed end products. The Company's profitability from this type merchant activity is dependent upon the prices of feedstocks and end products, which may vary on a seasonal basis. In order to limit the exposure to commodity price fluctuations in these business areas, the company attempts to match the timing and price of its feedstock purchases with those of the sales of end products. Operating margins from the company's natural gas processing (and related merchant businesses) are generally derived from the price spread earned on the sale of purity NGL products extracted from natural gas stream. To the extent the Company takes title to the NGLs removed from the natural gas stream and reimburses the producer for the reduction in the Btu content and/or the natural gas used as fuel (the "PTR" or "shrinkage"), the Company's operating margins are affected by the prices of NGLs and natural gas. The Company uses commodity financial instruments to reduce its exposure to the change in the prices of NGLs and natural gas. Current Business Environment The first quarter of 2001 was a challenging quarter for the natural gas processing and NGL industry. In the gas processing business, with natural gas prices approaching record high levels of $10 per MMBtu early in the quarter, natural gas processing plants industry-wide operated at significantly reduced extraction rates or temporarily shutdown. In the case of a natural gas processing plant, high natural gas prices may result in the cost of fuel and shrinkage exceeding the value of the NGLs extracted. As a result of the high natural gas prices encountered in January 2001, the Company, along with other participants in the natural gas processing industry, elected to minimize their recovery of NGLs or, in some instances, to bypass the natural gas streams around gas processing plants altogether. As a result of minimal or no NGL extraction, natural gas volumes Page 20downstream of the processing plants became higher in NGL content than allowed by pipeline specifications. The natural gas pipeline operators responded by issuing operational flow orders that threatened to shut-in some of the rich natural gas from the deepwater developments unless the NGL content of these natural gas streams was reduced to lower levels. In order to meet the specifications of the natural gas pipeline operators, the Company and producers negotiated interim reductions in fuel and shrinkage costs to levels that were significantly below the prevailing cost of natural gas. With these interim provisions in place, the Company's gas processing plants increased NGL extraction rates with the objective to lower the NGL content of the natural gas stream to a level satisfactory to the pipeline operators. Overall, equity NGL production rates at the Company's natural gas processing facilities declined to 46 MBPD in the first quarter of 2001 compared with 72 MBPD during the fourth quarter of 2000. The decrease in the Company's equity NGL production combined with reduced extraction rates at (or the temporary shutdown of) third-party natural gas processing facilities led to a decline in NGL volumes available for fractionation and/or transportation at the Company's other facilities and pipelines. This situation, however, also created regional shortages of NGLs, especially propane, which resulted in large regional pricing differences. This provided the Company with opportunities to serve these supply-short markets through the sale of inventory by its merchant businesses. As natural gas prices have begun to normalize, equity NGL production rates at the Company's facilities have returned to the 60 MBPD to 65 MBPD range. The Company expects NGL fractionation and transportation volumes to rebound as NGL production throughout the industry improves in response to moderating fuel costs. Management anticipates that the demand for its commercial isomerization services will strengthen in the coming quarter as refiners increase production of both alkylates and MTBE for gasoline blending. In addition, the Company is utilizing its spare capacity to take advantage of interim favorable pricing spreads between normal butane and isobutane. The market for MTBE is expected to be strong in the second quarter of 2001 as gasoline refiners increase the production of cleaner-burning fuels for the upcoming summer driving season. To illustrate, MTBE prices have increased from approximately $1.13 per gallon in January 2001 to over $1.50 per gallon in April 2001. The following table illustrates selected average quarterly prices for natural gas, crude oil, selected NGL products and polymer grade propylene since the first quarter of 1999: Polymer Natural Normal Grade Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene, $/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound ----------------------------------------------------------------------------------------- (a) (b) (c) (c) (c) (c) (c) Fiscal 1999: First quarter $1.70 $13.05 $0.20 $0.24 $0.29 $0.31 $0.12 Second quarter $2.12 $17.66 $0.27 $0.31 $0.37 $0.38 $0.13 Third quarter $2.56 $21.74 $0.34 $0.42 $0.49 $0.49 $0.16 Fourth quarter $2.52 $24.54 $0.30 $0.41 $0.52 $0.52 $0.19 Fiscal 2000: First quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21 Second quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26 Third quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26 Fourth quarter $5.22 $31.98 $0.49 $0.67 $0.75 $0.73 $0.24 Fiscal 2001: First quarter $7.00 $28.81 $0.43 $0.55 $0.63 $0.69 $0.23 (c) - ------------------------------------------------------------------------------------------------------------- (a) Natural gas, NGL and polymer grade propylene prices represent an average of index prices (b) Crude Oil price is representative of West Texas Intermediate (c) Natural gas prices averaged $9.87 per MMBtu for January, $6.17 per MMBtu for February and $4.96 per MMBtu for March. Page 21Results of Operation of the Company The Company has five reportable operating segments: Fractionation, Pipeline, Processing, Octane Enhancement and Other. Fractionation includes NGL fractionation, butane isomerization (converting normal butane into high purity isobutane) and polymer grade propylene fractionation services. Pipeline consists of pipeline, storage and import/export terminal services. Processing includes the natural gas processing business and its related NGL merchant activities. Octane Enhancement represents the Company's 33.3% ownership 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 other plant support functions. The management of the Company evaluates segment performance on the basis of gross operating margin ("gross operating margin" or "margin"). Gross operating margin reported for each segment represents operating income before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of assets and selling, general and administrative expenses. In addition, segment gross operating margin is exclusive of interest expense, interest income (from unconsolidated affiliates or others), dividend income from unconsolidated affiliates, minority interest, extraordinary charges and other income and expense transactions. The Company's equity earnings from unconsolidated affiliates are included in segment gross operating margin. The Company's gross operating margin by segment (in thousands of dollars) along with a reconciliation to consolidated operating income for the quarters ended March 31, 2001 and 2000 were as follows: For the Quarter Ended March 31, ----------------------------------- 2001 2000 ----------------------------------- Gross Operating Margin by segment: Fractionation $25,668 $34,331 Pipeline 18,123 14,635 Processing 28,398 39,554 Octane enhancement 169 2,505 Other 535 554 ----------------------------------- Gross Operating margin total 72,893 91,579 Depreciation and amortization 10,029 8,124 Retained lease expense, net 2,660 2,637 Gain on sale of assets (381) - Selling, general and administrative expenses 6,168 5,384 ----------------------------------- Consolidated operating income $54,417 $75,434 =================================== Page 22The Company's significant production and other volumetric data (on a net basis) for the quarters ended March 31, 2001 and 2000 were as follows: For the Quarter Ended March 31, 2001 2000 ------------------------------------ MBPD, Net - --------- Equity NGL Production 46 71 NGL Fractionation 165 218 Isomerization 70 67 Propylene Fractionation 30 30 Octane Enhancement 3 4 Major NGL and Petrochemical Pipelines 356 374 Mdth/D, Net (a) - --------------- Natural Gas Pipelines 506 n/a (a) Throughput on the Company's natural gas pipeline systems is measured in thousands of decatherms per day (Mdth/D), a commercial unit of measure used in the natural gas industry. Recent Acquisitions The Company has recently completed the acquisition of the following Louisiana-based natural gas pipeline systems: o Acadian Gas, LLC ("Acadian"); o Stingray Pipeline Company, LLC ("Stingray") and West Cameron Dehydration, LLC ("West Cameron"); and o Sailfish Pipeline Company, LLC ("Sailfish") and Moray Pipeline Company, LLC ("Moray"). Acadian. On April 2, 2001, the Company announced that it had completed the purchase of Acadian from Shell US Gas and Power LLC, an affiliate of Shell, for $226 million in cash, inclusive of working capital. The acquisition of Acadian integrates its natural gas pipeline systems in South Louisiana with the Company's Gulf Coast natural gas processing and NGL fractionation, pipeline and storage system. The Acadian acquisition gives the Company an extensive intrastate natural gas pipeline system with access to both supply and markets; positions the Company to compete for incremental natural gas supplies from new discoveries onshore, the offshore Louisiana continental shelf and Gulf of Mexico deepwater developments; enables the Company to take advantage of growing industrial and petrochemical demand (including new gas-fired power generation projects) along with additional natural gas processing opportunities. Acadian's assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline systems, which together have over one billion cubic feet ("Bcf") per day of capacity. These natural gas pipeline systems are wholly-owned by Acadian with the exception of the Evangeline system in which Acadian holds an approximate 49.5% economic interest. The system includes a leased natural gas storage facility at Napoleonville, Louisiana. Stingray, West Cameron, Sailfish and Moray (collectively, the "El Paso acquisition"). On January 29, 2001, Starfish Pipeline Company LLC, a 50/50 joint venture between the Company and Shell, completed the purchase of the Stingray natural gas pipeline system, West Cameron dehydration facility and certain offshore Louisiana lateral pipelines from EPE. The Company's share of the cash purchase price of these assets was $25.1 million. In addition, the Company purchased 100% of the membership interests of Sailfish and Moray from EPE for approximately $88.1 million in cash. Sailfish owns 25.67% of the Manta Ray Offshore Gathering Company, LLC ("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") through its ownership interests in Ocean Breeze Pipeline Company LLC and Neptune Pipeline Company LLC. Moray holds a 33.92% interest in the Nemo Gathering Page 23Company, LLC ("Nemo"). The cash payments made to EPE for these acquisitions are subject to certain post-closing adjustments expected to be finalized in the second quarter of 2001. Collectively, the Company acquired interests in four natural gas gathering and transmission pipeline systems in the Gulf of Mexico totaling approximately 725 miles of pipeline with an aggregate gross capacity of 2.85 Bcfd. These pipelines and their associated assets are strategically located to serve continental shelf and deepwater developments in the central Gulf of Mexico. As with the Acadian acquisition, the El Paso acquisition broadens the Company's midstream business by providing additional services to customers, and it benefits from increased natural gas production from deepwater Gulf of Mexico development. Management believes that the assets acquired from EPE complement and integrate well with those of the Acadian acquisition. Stingray owns a 375-mile FERC-regulated two phase natural gas pipeline system that transports natural gas and injected condensate from the High Island, West Cameron, East Cameron, Vermillion and Garden Banks areas in the Gulf of Mexico to onshore transmission systems at Holly Beach and Cameron Parish, Louisiana. West Cameron is an unregulated dehydration facility located at and connected to the onshore terminal of Stingray in south Louisiana. Shell is the operator of the Stingray and West Cameron facilities. Manta Ray (which is jointly owned by Sailfish, Shell and Marathon Gas Transmission Company Inc.) owns 225 miles of unregulated natural gas transmission lines primarily located on the outer continental shelf offshore Louisiana. Nautilus (which is owned by Sailfish, Shell and Marathon Gas Transmission Company Inc.) owns 101 miles of FERC-regulated natural gas pipelines and related facilities extending from points offshore Louisiana to interconnecting pipelines near the Garden City and Neptune gas processing facilities. Nemo (which is jointly owned by Moray and Shell) is a development stage enterprise that is constructing and will operate an offshore Louisiana natural gas gathering pipeline and related facilities that will connect certain Shell offshore platform assets to Manta Ray. Management believes that these assets have a significant upside potential, since Shell and Marathon have dedicated production from over 1,000 square miles of offshore natural gas leases to these systems and only a small portion of this total has been developed to date. Shell is the operator of the Manta Ray, Nautilus and Nemo systems. Equistar storage facility. In addition to the natural gas pipeline acquisitions, the Company announced on February 1, 2001 that it had acquired a NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million. The salt dome storage cavern, which is located near the Company's Mont Belvieu, Texas complex, has a capacity of one million barrels. The purchase also includes adjacent acreage which would support the development of additional storage capacity. Three Months Ended March 31, 2001 compared with Three Months Ended March 31, 2000 Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 11% to $838.3 million in 2001 compared to $753.7 million in 2000. The Company's operating costs and expenses increased by 16% to $777.7 million in 2001 versus $672.9 million in 2000. Operating income decreased 28% to $54.4 million in 2001 from $75.4 million in 2000. The principal factors behind the decrease in operating income were lower volumes and higher energy costs both of which were related to the increase in natural gas prices. Fractionation. The Company's gross operating margin for the Fractionation segment decreased to $25.7 million in 2001 from $34.3 million in 2000. NGL fractionation margin for the first quarter of 2001 decreased $10.4 million compared to 2000 due to lower volumes and higher energy costs. NGL fractionation net volumes decreased to 165 MBPD in 2001 from 218 MBPD in 2000 as a result of lower extraction rates at gas processing facilities in 2001 versus 2000 when the industry was maximizing NGL production. For the first quarter of 2001, gross operating margin from isomerization services increased $4.5 million compared to 2000 primarily due to an increase in volumes and toll processing fees. Isomerization volumes increased to 70 MBPD during the first quarter of 2001 versus 67 MBPD during the same period in 2000 due to solid demand for the Company's services. Gross operating margin for the first quarter of 2001 from propylene fractionation decreased $2.3 million compared to the first quarter of 2000 primarily due to higher energy costs and moderating prices. Net propylene fractionation volumes were 30 MBPD for both periods. Page 24Pipeline. The Company's gross operating margin for the Pipeline segment was $18.1 million in the first quarter of 2001 compared to $14.6 million in 2000. The improvement in gross margin was due to strong demand for transportation services on the Lou-Tex NGL Pipeline, which was operational for the entire first quarter of 2001; increased demand and a larger ownership interest in the Dixie propane pipeline and the January 29, 2001 acquisition of interests in four Gulf of Mexico offshore Louisiana natural gas pipeline systems from EPE. Net liquids throughput on the Company's major NGL and petrochemical pipeline systems averaged 356 MBPD for the first quarter of 2001 compared to 374 MBPD for the first quarter of 2000. Net natural gas throughput for the recently acquired natural gas pipelines was 506 thousand decatherms per day ("Mdth/D"). Processing. For the first quarter of 2001, the Processing segment generated gross operating margin of $28.4 million compared to $39.6 million in 2000. The Processing segment includes the Company's natural gas processing business and related merchant activities. The Company's equity NGL production was 46 MBPD for the current quarter versus 71 MBPD for the same period in 2000. As mentioned previously under Current Business Environment, higher natural gas prices caused the Company and other participants in the processing industry to minimize recoveries of NGLs for most of the first quarter of 2001 versus the first quarter of 2000 when NGL recoveries were maximized. This situation, however, also created regional shortages of NGLs, especially propane, which resulted in large regional pricing differences. This provided the Company with opportunities to serve these supply-short markets through the sale of inventory by its merchant business. Lastly, gross operating margin for this segment includes approximately $13.5 million of non-cash mark-to-market gains related to the Company's natural gas and NGL hedging activities. See Note 8 of the Notes to Consolidated Financial Statements for further information regarding the Company's use of commodity financial instruments. Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $2.3 million in the first quarter of 2001 compared with 2000 levels. The decline is attributable to a maintenance outage which began in early December 2000 and lasted until February 2001. MTBE production, on a net basis, was 3 MBPD in 2001 compared to 4 MBPD during the first quarter of 2000. Selling, general and administrative expenses ("SG and A"). SG and A expenses increased $0.8 million in the first quarter of 2001 compared to the first quarter of 2000. The increase is attributable to a slight rise in the administrative services fee charged by EPCO versus year-ago levels and the costs associated with the additional staff and resources deemed necessary to support the Company's ongoing expansion activities resulting from acquisitions and other business development. Liquidity and Capital Resources General. The Company's primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures (both maintenance and expansion-related), business acquisitions and distributions to the partners. The Company expects to fund its short-term needs for such items as maintenance capital expenditures and quarterly distributions to the partners from operating cash flows. Capital expenditures for long-term needs resulting from future expansion 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 bank credit facilities and the issuance of additional Common Units and public debt. The Company's debt service requirements are expected to be funded by operating cash flows or refinancing arrangements. As noted above, certain of the Company's liquidity and capital resource requirements are met using borrowings under bank credit facilities and/or the issuance of additional Common Units or public debt (separately or in combination). As of March 31, 2001, availability under the Company's revolving bank credit facilities was $400 million (which may be increased to $500 million under certain conditions). In addition to the existing revolving bank credit facilities, a subsidiary of the Company issued $450 million of public debt in January 2001 (the "$450 Million Senior Notes") using the remaining shelf availability under its $800 million December 1999 universal shelf registration (the "December 1999 Registration Statement"). The proceeds from this offering were used to acquire the Acadian and EPE natural gas pipeline systems for $339.2 million (with $226 million of this amount paid in April 2001 for Acadian) and to finance the cost to construct certain NGL pipelines and related projects and for working capital and other general partnership purposes. On February 23, 2001, the Company filed a $500 million universal shelf registration (the "February 2001 Registration Statement") covering the issuance of Page 25an unspecified amount of equity or debt securities or a combination thereof. For a broader discussion of the Company's outstanding debt and changes therein, see the section below labeled "Long-term Debt". In June 2000, the Company received approval from its Unitholders to increase by 25,000,000 the number of Common Units available (and unreserved) to the Company for general partnership purposes during the Subordination Period. This increase has improved the future financial flexibility of the Company in any potential business acquisition. If deemed necessary, management believes that additional financing arrangements can be obtained at reasonable terms. Management believes that maintenance of the Company's investment grade credit ratings (currently, Baa3 by Moody's Investor Service and BBB by Standard and Poors) combined with a continued ready access to debt and equity capital at reasonable rates and sufficient trade credit to operate its businesses efficiently are a solid foundation to providing the Company with ample resources to meet its long and short-term liquidity and capital resource requirements. Operating, Investing and Financing Cash Flows for the three months ended March 31, 2001 and 2000. Cash flows from operating activities were a $48.7 million inflow for 2001 compared to a $86.8 million inflow in 2000. Cash flows from operating activities primarily reflect the effects of net income, depreciation and amortization, extraordinary items, equity income and distributions from unconsolidated affiliates, fluctuations in fair values of financial instruments and changes in working capital. Net income decreased in 2001 from 2000 levels due to reasons mentioned previously under "Results of Operation of the Company." Depreciation and amortization increased a combined $1.7 million in 2001 over 2000 primarily the result of additional capital expenditures and acquisitions. The Company received $8.9 million in distributions from its equity method investments in 2001 compared to $7.1 million in 2000. Of the $1.8 million increase in distributions, $1.5 million is attributable to the natural gas pipeline assets purchased from EPE in January 2001. Operating cash flow for 2001 also includes an adjustment for the $16.4 million in non-cash mark-to-market gains related to natural gas, NGL and interest rate hedging activities. The net effect of changes in operating accounts from year to year is generally the result of timing of NGL sales and purchases near the end of the period. Cash used for investing activities was $137.9 million in 2001 compared to $114.1 million in 2000. Cash outflows included capital expenditures of $25.3 million in 2001 versus $111.4 million in 2000. Capital expenditures for the first quarter of 2000 included $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related assets. In addition, capital expenditures include maintenance capital project costs of $1.0 million in 2001 and $0.3 million in 2000. The 2000 period includes $3.3 million in cash receipts related to the Company's participation in the BEF note, which was extinguished in May 2000 with BEF's final principal payment. Investing cash outflows in 2001 includes $113.1 million in advances to and investments in unconsolidated affiliates compared to $6.0 million in 2000. The increase is due to purchase of the natural gas pipeline systems from EPE in January 2001. Cash receipts from financing activities were $408.2 million during the first quarter of 2001 compared to $72.2 million during the same period in 2000. Cash flows from financing activities are primarily affected by repayments of debt, borrowings under debt agreements and distributions to partners. The 2001 period includes proceeds from the $450 Million Senior Notes issued in January 2001 whereas the 2000 period includes proceeds from the $350 Million Senior Notes and the $54 Million MBFC Loan and the associated repayments on various bank credit facilities. Distributions to partners and the minority interest increased to $38.4 million in 2001 from $34.2 million in 2000 primarily due to an increase in the quarterly distribution rate. The Company is exposed to various market risks including commodity price risk (through its gas processing and related NGL businesses) and interest rate risk. These risks may entail significant cash outlays in the future that are not offset by their underlying hedged positions. For a complete description of the Company's risk management policies and potential exposures, see "Item 3. Quantitative and Qualitative Disclosures about Market Risk" on page 28 of this Form 10-Q report and Note 8 of the Notes to Consolidated Financial Statements. Future Capital Expenditures. The Company estimates that its share of currently approved capital expenditures in the projects of its unconsolidated affiliates will be approximately $7.0 million for the remainder of 2001. In addition, the Company forecasts that $118.7 million will be spent during the remainder Page 26of 2001 on currently approved capital projects that will be recorded as property, plant and equipment (the majority of which relate to various pipeline projects). As of March 31, 2001, the Company had $9.6 million in outstanding purchase commitments attributable to its capital projects. Of this amount, $7.1 million is related to the construction of assets that will be recorded as property, plant and equipment and $2.5 million is associated with capital projects which will be recorded as additional investments in unconsolidated affiliates. New Texas environmental regulations may necessitate extensive redesign and modification of the Company's Mont Belvieu facilities to achieve the air emissions reductions needed for federal Clean Air Act compliance in the Houston-Galveston area. Until litigation challenging these regulations is resolved, the technology to be employed and the cost for modifying the facilities to achieve enough reductions cannot be determined, and capital funds have not been budgeted for such work. Regardless of the outcome of this litigation, expenditures for emissions reduction projects will be spread over several years, and management believes the Company will have adequate liquidity and capital resources to undertake them. For additional information about this litigation, see the discussion under the topic Clean Air Act--General on page 22 of the Company's Form 10-K for fiscal 2000. Long-term Debt. Long-term debt consisted of the following at: March 31, December 31, 2001 2000 --------------------------------------- Borrowings under: $350 Million Senior Notes, 8.25% fixed rate, due March 2005 $350,000 $350,000 $54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000 $450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000 --------------------------------------- Total principal amount 854,000 404,000 Increase in fair value related to hedging a portion of fixed-rate debt 2,196 Less unamortized discount on: $350 Million Senior Notes (144) (153) $450 Million Senior Notes (279) Less current maturities of long-term debt - - --------------------------------------- Long-term debt $855,773 $403,847 ======================================= The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility and $150 Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit facilities at March 31, 2001 or December 31, 2000. At March 31, 2001, the Company had a total of $75 million of standby letters of credit available under its $250 Million Multi-Year Credit Facility of which $54.1 million was outstanding. On January 24, 2001, a subsidiary of the Company completed a public offering of $450 million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting discounts and commissions, of approximately $446.8 million. The proceeds from this offering were used to acquire the Acadian and EPE natural gas pipeline systems for $339.2 million and to finance the cost to construct certain NGL pipelines and related projects and for working capital and other general partnership purposes. The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is also applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As with the $350 Million Senior Notes, the $450 Million Senior Notes are: o subject to a make-whole redemption right; o an unsecured obligation and rank equally with existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness; and, o guaranteed by the Company through an unsecured and unsubordinated guarantee. Page 27The Company was in compliance with the restrictive covenants associated with the $350 Million and $450 Million Senior Notes at March 31, 2001. The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 Registration Statement; therefore, the amount of securities available under this universal shelf registration statement was reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement (the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt securities or a combination thereof. The Company expects to use the net proceeds from any sale of securities under the February 2001 Registration Statement for future business acquisitions and other general corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be applied to partnership purposes will depend on a number of factors, including the Company's funding requirements and the availability of alternative funding sources. The Company routinely reviews acquisition opportunities. Upon adoption of Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3 million non-cash increase in the fair value of its fixed-rate debt. SFAS 133 required that the Company's interest rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption of the standard. After adoption of the standard, the interest rate swaps were dedesignated due to differences in the estimated maturity dates of the interest rate swaps versus the fixed-rate debt. As a result, the fair value of the hedged fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million increase in the fair value of the debt will be amortized to earnings over the remaining life of the fixed-rate debt to which it applies, which approximates 10 years. See Note 4 and Note 8 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding interest rate swaps and the associated change in the fair value of the fixed-rate debt. Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The Company is exposed to financial market risks, including changes in commodity prices in its natural gas and NGL businesses and in interest rates with respect to a portion of its debt obligations . The Company may use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) to mitigate these risks. The Company generally does not use financial instruments for speculative (or trading) purposes. Commodity Price Risk The Company is exposed to commodity price risk through its natural gas and related NGL businesses. In order to effectively manage this risk, the Company may enter into swaps, forwards, commodity futures, options and other commodity financial instruments with similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial instrument. The purpose of these risk management activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated transactions. The Company has adopted a commercial policy to manage its exposure to the risks generated by its gas processing and related NGL and natural gas businesses. The objective of this policy is to assist the Company in achieving its profitability goals while maintaining a portfolio of conservative risk, defined as remaining within the position limits established by the General Partner. The Company will enter into risk management transactions to manage price risk, basis risk, physical risk, or other risks related to the energy commodities on both a short-term (less than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the strategies of the Company associated with physical and financial risks, approves specific activities of the Company subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy. The following table presents the hypothetical changes in fair values arising from immediate selected potential changes in the quoted market prices of the Company's commodity financial instruments outstanding at the Page 28dates noted within the table. The sensitivity analysis model used to estimate the fair values of the commodity financial instruments takes into account the following primary factors/assumptions: o the current quoted market cost of natural gas; o the current quoted market cost of related NGL production; o changes in the composition of commodities hedged (i.e., the mix between natural gas and related NGL hedges outstanding); o fluctuations in the overall volume of commodities hedged (for both natural gas and related NGL hedges outstanding); o market interest rates, which are used in determining the present value; and, o a liquid market for such financial instruments. An increase in fair value of the commodity financial instruments (based upon the assumptions noted above) approximates the gain that would be recognized in earnings if all of the commodity financial instruments were settled at the respective balance sheet dates. Conversely, a decrease in fair value of the commodity financial instruments would result in the recording of a loss at the respective balance sheet date. To the extent the commodity financial instruments are effective in hedging their associated commodity positions, the gain or loss recognized on these commodity financial instruments would be offset by a corresponding gain or loss on the hedged commodity positions, which are not included in the table below. The gains or losses resulting from these hedging activities are a component of the Company's operating costs and expenses as reflected in its Statements of Consolidated Operations. Asset (liability) Impact of a 10% increase Impact of a 10% decrease Estimated in quoted market prices in quoted market prices Fair Value at date Increase (Decrease) Increase(Decrease) indicated assuming Asset(liability) in Fair Value Asset(liability) in Fair Value no change in Adjusted estimate due to increase in Adjusted estimate due to decrease in quoted market prices of Fair Value quoted market prices of Fair Value quoted market prices Estimated impact of changes in quoted market prices on commodity financial instruments at: (in millions of dollars) December 31,2000 (38.6) (56.3) (17.7) (20.9) 17.7 March 31,2001 (4.6) (26.1) (21.5) 16.5 21.1 May 9,2001 24.0 8.3 (15.7) 39.7 15.7 The fair value of the commodity financial instruments at December 31, 2000 was estimated at $38.6 million payable. On March 31, 2001, the fair value of the commodity financial instruments outstanding was estimated at $4.6 million payable. The change in fair value between December 31, and March 31, 2001 was primarily due to the settlement of certain open positions, lower natural gas prices and a change in the composition of commodities hedged. By May 9, 2001, the fair value of the commodity financial instruments was a receivable position primarily due to a further decline in natural gas prices. The Company's commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS 133, as amended and interpreted. The Company continues to refer to these commodity financial instruments as hedges in as much as this was the intent when such contracts were executed. This characterization is consistent with the actual economic performance of these financial instruments and the Company expects such commodity financial instruments to continue to mitigate commodity price risk in the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS 133. As such, if these commodity financial instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS 133, the change in fair value of these instruments will be reflected on the balance sheet and in earnings using mark-to-market accounting. For additional information regarding the commodity financial instruments, see Note 8 of the Notes to Consolidated Financial Statements that are part of this Form 10-Q quarterly report. Page 29Interest rate risk Variable-rate Debt. At March 31, 2001 and 2000, the Company had no financial instruments in place to cover any potential interest rate risk on its variable-rate debt obligations. Variable-rate debt obligations do expose the Company to possible increases in interest expense and decreases in earnings if interest rates were to rise. At March 31, 2001 and 2000, the Company had no variable-rate debt outstanding. Fixed-rate Debt. In March 2000, the Company entered into interest rate swaps whereby the fixed-rate of interest on a portion of the $350 Million Senior Notes and the $54 Million MBFC Loan was effectively swapped for floating-rates tied to the six month London Interbank Offering Rate ("LIBOR"). The objective of holding interest rate swaps is to manage debt service costs by effectively converting a portion of the fixed-rate debt into variable-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount. Management believes that it is prudent to maintain a balance between variable-rate and fixed-rate debt. The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate exposure that impact future cash flows any by evaluating hedging opportunities. The Company uses analytical techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the expected impact of changes in interest rates on the Company's future cash flows. The General Partner oversees the strategies of the Company associated with financial risks and approves instruments that are appropriate for the Company's requirements. The following table presents the hypothetical changes in fair values arising from immediate selected potential changes in quoted market prices of the Company's interest rate swaps outstanding at the dates noted within the table. The sensitivity analysis model used to estimate the fair values of the interest rate swaps takes into account the following primary factors/assumptions: (a) current market interest rates (including forward LIBOR rates and current federal funds rate), (b) early termination options exercisable by the counterparty (if the fair value of the swap indicates a receivable) and (c) a liquid market for interest rate swaps. An increase in fair value of the interest rate swaps approximates the gain that would be recognized in earnings if all of the interest rate swaps were settled at the respective balance sheet dates. Conversely, a decrease in fair value of the interest rate swaps would result in the recording of a loss at the respective balance sheet date. The gains or losses resulting from the interest rate hedging activities are a component of the Company's interest expense as reflected in its Statements of Consolidated Operations. Asset (liability) Impact of a 10% increase Impact of a 10% decrease Estimated in quoted market prices in quoted market prices Fair Value at date Increase (Decrease) Increase(Decrease) indicated assuming Asset(liability) in Fair Value Asset(liability) in Fair Value no change in Adjusted estimate due to increase in Adjusted estimate due to decrease in quoted market prices of Fair Value quoted market prices of Fair Value quoted market prices Estimated impact of changes in quoted market prices on interest rate swaps at: (in millions of dollars) December 31,2000 2.5 1.9 (0.6) 3.1 0.6 March 31,2001 7.1 5.8 (1.3) 8.4 1.3 May 9,2001 7.6 6.4 (1.2) 8.9 1.3 The interest rate swaps outstanding at December 31, 2000 reflected a notional amount of $154 million of fixed-rate debt with the fair value of swaps estimated at $2.5 million. At March 31, 2001, the notional amount was reduced to $104 million due to the early termination of one of the swaps by a counterparty with the aggregate fair value of the remaining swaps estimated at $7.1 million. The change in fair value between December 31, 2000 and March 31, 2001 is primarily related to the decision by one counterparty not to exercise its early termination right and lower interest rates. At May 9, 2001, the fair value of the interest rate swaps was estimated at $7.6 million. The change in fair value between March 31, 2001 and May 9, 2001 is attributable to slightly lower interest rates. Page 30The Company's interest rate swap agreements were dedesignated for being accounted for as hedging instruments after adoption of SFAS 133; therefore, the interest rate swap agreements are accounted for on a mark-to-market basis. However, these financial instruments continue to be effective in achieving the risk management activities for which they were intended. As a result, the change in fair value of these instruments will be reflected on the balance sheet and in earnings (as an offset to interest expense) using mark-to-market accounting. For additional information regarding the interest rate swaps, see Note 8 of the Notes to Consolidated Financial Statements that are part of this Form 10-Q quarterly report. Other. At March 31, 2001 and December 31, 2000, the Company had $379.4 million and $60.4 million invested in cash and cash equivalents, respectively. All cash equivalent investments other than cash are highly liquid, have original maturities of less than three months, and are considered to have insignificant interest rate risk. Due to the complexity of SFAS 133, the Financial Accounting Standards Board ("FASB") organized a formal committee, the Derivatives Implementation Group ("DIG"), to provide ongoing recommendations to the FASB about implementation issues. Implementation guidance issued through the DIG process is still continuing; therefore, the initial conclusions reached by the Company concerning the application of SFAS 133 upon adoption may be altered. As a result, additional SFAS 133 transition adjustments may be recorded in future periods as the Company adopts new DIG interpretations approved by the FASB. PART II. OTHER INFORMATION Item 2. Use of Proceeds The following table shows the Use of Proceeds from the $450 Million Senior Notes offering completed on January 29, 2001. The $450 Million Senior Notes represented a takedown of the remaining shelf availability under the Company's December 1999 Registration Statement filed with the Securities and Exchange Commission (File Nos. 333-93239 and 333-93239-01, effective January 14, 2000). The title of the registered debt securities was "7.50% Senior Notes Due 2011." The underwriters of the offering were Goldman, Sachs & Co., Salomon Smith Barney Inc., Banc One Capital Markets, Inc., First Union Securities, Inc., Scotia Capital (USA) Inc. and Tokyo-Mitsubishi International plc. The 10-year Senior Notes have a maturity date of February 1, 2011 and bear a fixed-rate interest coupon of 7.50%. Amounts (in millions) -------------- Proceeds: Sale of $450 Million Senior Notes to public at 99.937% per Note $450 Less underwriting discount of 0.650% per Note (3) -------------- Total proceeds $447 ============== Use of Proceeds: To finance Acadian acquisition $(226) To finance investment in various natural gas pipeline entities purchased from EPE (113) To finance remainder of the costs to construct certain NGL pipelines and related projects, and for working capital and other general Company purposes (108) -------------- Total uses of funds $(447) ============== The $226 million payment to Shell for Acadian was made in early April 2001. The $113 million in payments made to EPE for the four natural gas pipeline systems were made in late January 2001. Page 31Item 6. Exhibits and Reports on Form 8-K (a) Exhibits *2.1 Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated ad of September 22, 2000. (Exhibit 10.1 to Form 8-K filed on September 26, 2000). *3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. (Exhibit 3.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *3.2 Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "D" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC. *3.3 First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated September 17, 1999. (Exhibit 99.8 on Form 8-K/A-1 filed October 27, 1999). *3.4 Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated June 9, 2000. (Exhibit 3.6 to Form 10-Q filed August 11, 2000). *4.1 Form of Common Unit certificate. (Exhibit 4.1 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *4.2 Unitholder Rights Agreement among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "C" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC. *4.3 Contribution Agreement between Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "B" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC. *4.4 Registration Rights Agreement between Tejas Energy LLC and Enterprise Products Partners L.P. dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "E" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC. *4.5 Form of Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee. (Exhibit 4.1 on Form 8-K filed March 10, 2000). *4.6 Form of Global Note representing $350 million principal amount of 8.25% Senior Notes Due 2005. (Exhibit 4.2 on Form 8-K filed March 10, 2000). *4.7 $250 Million Multi-Year Revolving Credit Agreement among Enterprise Products Operating L.P., First Union National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17, 2000. (Exhibit 4.2 on Form 8-K filed January 25, 2001). *4.8 $150 Million 364-Day Revolving Credit Agreement between Enterprise Products Operating L.P. and First Union National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17, 2000. (Exhibit 4.3 on Form 8-K filed January 25, 2001). Page 32*4.9 Guaranty Agreement (relating to the $250 Million Multi-Year Revolving Credit Agreement) by Enterprise Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17, 2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001). *4.10 Guaranty Agreement (relating to the $150 Million 364-Day Revolving Credit Agreement) by Enterprise Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17, 2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001). 4.12 First Amendment to $250 million Multi-Year Revolving Credit Agreement dated April 19, 2001. *4.11 Form of Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011. (Exhibit 4.1 to Form 8-K filed January 25, 2001). *10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline Partnership, L.P., Chunchula Pipeline Company, LLC, Propylene Pipeline Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise Products Texas Operating L.P. dated June 1, 1998.(Exhibit 10.1 to Registration Statement on Form S-1/A, File No: 333-52537, filed on July 8, 1998). *10.2 Form of EPCO Agreement between Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC and Enterprise Products Company. (Exhibit 10.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *10.3 Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998. (Exhibit 10.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.4 Venture Participation Agreement between Sun Company, Inc. (R&M), Liquid Energy Corporation and Enterprise Products Company dated May 1, 1992. (Exhibit 10.4 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.5 Partnership Agreement between Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992. (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc. (R&M) dated August 16, 1995. (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.7 Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules Incorporated dated December 13, 1978. (Exhibit 10.9 to Registration Statement on Form S-1, File No. 333-52537, dated May 13, 1998). *10.8 Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas between Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985. (Exhibit 10.10 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.9 Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities between Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum Company and Mont Belvieu Associates dated July 17, 1985. (Exhibit 10.11 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.10 Amendment to Propylene Facility and Pipeline Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1993. (Exhibit 10.12 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). Page 33*10.11 Amendment to Propylene Facility and Pipeline Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1995. (Exhibit 10.13 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.12 Fourth Amendment to Conveyance of Gas Processing Rights between Tejas Natural Gas Liquids, LLC and Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Deepwater Development Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas Inc. dated August 1, 1999. (Exhibit 10.14 to Form 10-Q filed on November 15, 1999). * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith (b) Reports on Form 8-K The following Form 8-K reports were filed during the quarter ending March 31, 2001: 8-K filed on January 25, 2001. On January 24, 2001, a subsidiary of the entered into an underwriting agreement for the public offering by the of $450 million of 7.50% Senior Notes (the "$450 Million Senior Notes") due in February 2011. The Senior Notes are unconditionally guaranteed by the Company. The closing and issuance of the $450 Million Senior Notes occurred on January 29, 2001. In addition, this current report was used to file as exhibits the documents relating to the $250 Million Multi-Year Credit Facility and $150 Million 364-Day Credit Facility. 8-K filed on February 2, 2001. The Company published a press release relating to fourth quarter 2000 and fiscal 2000 earnings on January 30, 2001. The text of the release was filed as an exhibit to this current report. Page 34Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. Enterprise Products Partners L.P. (A Delaware Limited Partnership) By: Enterprise Products GP, LLC as General Partner /s/ Michael J. Knesek --------------------- Vice President, Controller and Date: May 14, 2001 Principal Accounting Officer