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 June 30, 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: 333-93239-01 Enterprise Products Operating L.P. (Exact name of Registrant as specified in its charter) Delaware 76-0568220 (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 ___ --- No common equity securities of Enterprise Products Operating L.P. (the "Company") are held by non-affiliates of the Company. The Company is owned 98.9899% by its Parent and Limited Partner, Enterprise Products Partners L.P. (a publicly-traded master limited partnership under New York Stock Exchange ("NYSE") symbol "EPD" (SEC File No. 1-14323)), and 1.0101% by its General Partner, Enterprise Products GP, LLC.Enterprise Products Operating L.P. and Subsidiaries TABLE OF CONTENTS Page No. ---- Part I. Financial Information Item 1. Consolidated Financial Statements Enterprise Products Operating L.P. Unaudited Consolidated Financial Statements: Consolidated Balance Sheets, June 30, 2001 and December 31, 2000 1 Statements of Consolidated Operations for the three and six months ended June 30, 2001 and 2000 2 Statements of Consolidated Cash Flows for the three and six months ended June 30, 2001 and 2000 3 Statements of Consolidated Partners' Equity and Comprehensive Income for the three and six months ended June 30, 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 19 Item 3 Quantitative and Qualitative Disclosures about Market Risk 33 Part II. Other Information Item 2 Use of Proceeds 37 Item 6. Exhibits and Reports on Form 8-K 38 Signature Page Glossary The following abbreviations, acronyms or terms used in this Form 10-Q are defined below: Acadian Gas Acadian Gas, LLC BBtu/d Billion British thermal units per day, a measure of heating value Bcf Billion cubic feet Bcf/d Billion cubic feet per day BPD Barrels per day Btu British thermal unit, a measure of heating value Company Enterprise Products Partners L.P. and subsidiaries Enron Enron North America Corp. and subsidiaries EPCO Enterprise Products Company, an affiliate of the Company EPE El Paso Corporation, its subsidiaries and affiliates FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission General Partner Enterprise Products GP, LLC, the general partner of the Company and Operating Partnership Limited Partner Enterprise Products Partners L.P., the parent of the Company Manta Ray A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Manta Ray Offshore Gathering Company, LLC MBFC Mississippi Business Finance Corporation MBPD Thousand barrels per day MMBbls Millions of barrels MMBtus Million British thermal units, a measure of heating value MMcf Million cubic feet MMcf/d Million cubic feet per day MTBE Methyl tertiary butyl ether Nautilus A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Nautilus Pipeline Company, LLC NGL or NGLs Natural gas liquid(s) NYSE New York Stock Exchange PTR Plant thermal reduction SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards Shell Shell Oil Company, its subsidiaries and affiliates PART 1. FINANCIAL INFORMATION. Item 1. CONSOLIDATED FINANCIAL STATEMENTS. Enterprise Products Operating L.P. Consolidated Balance Sheets (Dollar amounts in thousands) June 30, December 31, ASSETS 2001 2000 ------------------------------------- Current Assets Cash and cash equivalents (includes restricted cash of $7,321 at June 30, 2001) $ 120,337 $ 58,446 Accounts receivable - trade, net of allowance for doubtful accounts of $17,032 at June 30, 2001 and $10,916 at December 31, 2000 383,680 409,085 Accounts receivable - affiliates 9,011 5,738 Inventories 99,783 93,222 Prepaid and other current assets 79,260 12,107 ------------------------------------- Total current assets 692,071 578,598 Property, Plant and Equipment, Net 1,232,792 975,322 Investments in and Advances to Unconsolidated Affiliates 414,808 298,954 Intangible assets, net of accumulated amortization of $7,874 at June 30, 2001 and $5,374 at December 31, 2000 90,369 92,869 Other Assets 9,012 2,867 ------------------------------------- Total $2,439,052 $1,948,610 ===================================== LIABILITIES AND PARTNERS' EQUITY Current Liabilities Accounts payable - trade $ 59,208 $ 96,560 Accounts payable - affiliate 51,339 56,447 Accrued gas payables 353,444 377,126 Accrued expenses 12,577 20,579 Other current liabilities 81,385 34,763 ------------------------------------- Total current liabilities 557,953 585,475 Long-Term Debt 855,608 403,847 Other Long-Term liabilities 17,260 15,613 Minority Interest 1,136 1,004 Commitments and Contingencies Partners' Equity Limited Partner 1,011,215 937,829 General Partner 10,318 9,569 Accumulated other comprehensive income (9,711) Parent's Units acquired by Trust (4,727) (4,727) ------------------------------------- Total Partners' Equity 1,007,095 942,671 ------------------------------------- Total $2,439,052 $1,948,610 ===================================== See Notes to Unaudited Consolidated Financial Statements Page 1 Enterprise Products Operating L.P. Statements of Consolidated Operations (Unaudited) (Dollar amounts in thousands) Three Months Six Months Ended June 30, Ended June 30, ---------------------------- ---------------------------- 2001 2000 2001 2000 ---------------------------- ---------------------------- REVENUES Revenues from consolidated operations $959,397 $592,913 $1,795,712 $1,339,194 Equity income in unconsolidated affiliates 9,050 11,097 11,061 18,540 ---------------------------- ---------------------------- Total 968,447 604,010 1,806,773 1,357,734 COST AND EXPENSES Operating costs and expenses 851,639 546,306 1,629,380 1,219,212 Selling, general and administrative 8,418 7,658 14,586 13,042 ---------------------------- ---------------------------- Total 860,057 553,964 1,643,966 1,232,254 ---------------------------- ---------------------------- OPERATING INCOME 108,390 50,046 162,807 125,480 OTHER INCOME (EXPENSE) Interest expense (16,331) (8,070) (23,318) (15,844) Interest income from unconsolidated affiliates 3 94 15 202 Dividend income from unconsolidated affiliates 2,761 1,632 3,995 Interest income - other 1,626 1,358 5,771 2,973 Other, net (251) (62) (531) (425) ---------------------------- ---------------------------- Other income (expense) (14,953) (3,919) (16,431) (9,099) ---------------------------- ---------------------------- INCOME BEFORE MINORITY INTEREST 93,437 46,127 146,376 116,381 MINORITY INTEREST (44) (33) (67) (70) ---------------------------- ---------------------------- NET INCOME $ 93,393 $ 46,094 $ 146,309 $ 116,311 ============================ ============================ See Notes to Unaudited Consolidated Financial Statements Page 2 Enterprise Products Operating L.P. Statements of Consolidated Cash Flows (Dollar amounts in Thousands) Six Months Ended June 30, ------------------------------------- 2001 2000 ------------------------------------- OPERATING ACTIVITIES Net income $146,309 $116,311 Adjustments to reconcile net income to cash flows provided by (used for) operating activities: Depreciation and amortization 23,234 18,347 Equity in income of unconsolidated affiliates (11,061) (18,540) Distributions received from unconsolidated affiliates 13,212 14,268 Leases paid by EPCO 5,320 5,324 Minority interest 67 70 Gain (loss) on sale of assets (387) 2,303 Changes in fair market value of financial instruments (See Note 7) (55,880) Net effect of changes in operating accounts (30,611) 56,136 ------------------------------------- Operating activities cash flows 90,203 194,219 ------------------------------------- INVESTING ACTIVITIES Capital expenditures (57,090) (154,246) Proceeds from sale of assets 563 52 Business acquisitions, net of cash acquired (225,665) Collection of notes receivable from unconsolidated affiliates 6,519 Investments in and advances to unconsolidated affiliates (115,282) (3,040) ------------------------------------- Investing activities cash flows (397,474) (150,715) ------------------------------------- FINANCING ACTIVITIES Long-term debt borrowings 449,716 463,818 Long-term debt repayments (355,000) Debt issuance costs (3,125) (2,759) Cash distributions to partners (77,494) (68,328) Cash distributions to minority interest (45) Cash contributions from minority interest 110 Increase in restricted cash (7,321) ------------------------------------- Financing activities cash flows 361,841 37,731 ------------------------------------- NET CHANGE IN CASH AND CASH EQUIVALENTS 54,570 81,235 CASH AND CASH EQUIVALENTS, JANUARY 1 58,446 5,159 ------------------------------------- CASH AND CASH EQUIVALENTS, JUNE 30 $113,016 $ 86,394 ===================================== See Notes to Unaudited Consolidated Financial Statements Page 3 Enterprise Products Operating L.P. Statements of Consolidated Partners' Equity and Comprehensive Income (Unaudited, amounts in thousands) Partners' Equity at June 30, --------------------------------------- 2001 2000 --------------------------------------- Limited Partners Balance, beginning of year $ 937,829 $791,279 Net income 144,831 115,137 Leases paid by EPCO 5,266 5,270 Cash distributions (76,711) (67,639) ------------------ ------------------- Balance, end of period 1,011,215 844,047 ------------------ ------------------- ------------------ ------------------- Treasury Units (4,727) (4,727) ------------------ ------------------- General Partner Balance, beginning of year 9,569 8,074 Net income 1,478 1,174 Leases paid by EPCO 54 54 Cash distributions (783) (690) ------------------ ------------------- Balance, end of period 10,318 8,612 ------------------ ------------------- Accumulated Other Comprehensive Loss Balance, beginning of year Cumulative transition adjustment recorded on January 1, 2001 upon adoption of SFAS 133 (see Note 7) (42,190) Reclassification of cumulative transition adjustment to earnings 32,479 ------------------ Balance, end of period (9,711) ------------------ ------------------ ------------------- Total Partners' Equity $1,007,095 $847,932 ================== =================== Other Comprehensive Income For the Six Months Ended June 30, --------------------------------------- 2001 2000 --------------------------------------- Net Income $146,309 $116,311 Less: Reclassification of cumulative transition adjustment from Accumulated Other Comprehensive Loss (9,711) ------------------ ------------------- Comprehensive Income $136,598 $116,311 ================== =================== See Notes to Unaudited Consolidated Financial Statements Page 4 Enterprise Products Operating L.P. Notes to Unaudited Consolidated Financial Statements 1. GENERAL In the opinion of Enterprise Products Operating 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 June 30, 2001 and consolidated results of operations, cash flows, partners' equity and comprehensive income for the three and six month periods ended June 30, 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 Company's Annual Report on Form 10-K (File No. 333-93239-01) for the year ended December 31, 2000. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The results of operations for the three and six month periods ended June 30, 2001 are not necessarily indicative of the results to be expected for the full year due to the effects of, among other things, (a) seasonal variations in NGL and natural gas prices, (b) timing of maintenance and other expenditures and (c) acquisitions of assets and other interests. Certain reclassifications have been made to prior years' financial statements to conform to the presentation of the current period financial statements. These reclassifications do not affect historical earnings of the Company. Dollar amounts presented in the tabulations within the notes to the consolidated financial statements are stated in thousands of dollars, unless otherwise indicated. 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 8. At June 30, 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 $7.2 million at June 30, 2001. Page 5 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. o 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 41.67% 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 during the third quarter of 2001. o Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, "Evangeline") - an approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana. The Company acquired its interests in these entities as a result of the Acadian Gas, LLC acquisition (see Note 3 for a description of this acquisition). 2001 Gulf of Mexico natural gas pipeline equity investments The Company acquired its equity interests in Ocean Breeze, Neptune, Nemo and Starfish and their underlying investments on January 29, 2001 from EPE using proceeds from the issuance of the $450 Million Senior Notes (see Note 5 for discussion of long-term debt). The cash purchase price of the Ocean Breeze, Neptune and Nemo interests was $86.9 million with the purchase price of the Starfish interests being $25.1 million. As a result of its investment in Ocean Breeze and Neptune, the Company acquired a 25.67% interest in each of the Manta Ray and Nautilus systems and a 33.92% interest in the Nemo 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 MMcf/d and related equipment, the Nautilus system comprises approximately 101 miles of pipeline with a capacity of 600 MMcf/d, and the Nemo system, when completed in the third quarter of 2001, will comprise approximately 24 miles of pipeline with a capacity of 300 MMcf/d. Shell is responsible for the commercial and physical operations of these pipeline systems. The Company's investment in Ocean Breeze and Neptune includes excess cost over the underlying equity in the net assets of these entities of $22.7 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 $22.4 million at June 30, 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 during the third quarter of 2001. As a result of its investment in Starfish, the Company acquired a 50% interest in the Stingray system and a related onshore natural gas dehydration facility. The Company's sole partner in Starfish is an affiliate of Shell. The Stingray system comprises approximately 375 miles of pipeline with a capacity of 1.2 Bcf per Page 6 day and is located offshore Louisiana in the Gulf of Mexico. Shell is responsible for the commercial and physical operations of the Stingray system and related facilities. Historical information for periods prior to January 1, 2001 do reflect any impact associated with the Company's equity investments in Ocean Breeze, Neptune, Nemo and Starfish. See Note 3 for combined pro forma impact of these investments on selected financial information of the Company. Octane Enhancement segment: o Belvieu Environmental Fuels ("BEF") - a 33.33% interest in a 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 June 30, 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 under the Processing segment. Page 7 The following table summarizes investments in and advances to unconsolidated affiliates at: June 30, December 31, 2001 2000 ------------------------------------- Accounted for on equity basis: Fractionation: BRF $30,210 $30,599 BRPC 19,638 25,925 Promix 48,214 48,670 Pipeline: EPIK 15,467 15,998 Wilprise 8,617 9,156 Tri-States 27,238 27,138 Belle Rose 11,591 11,653 Dixie 38,179 38,138 Starfish 26,763 Ocean Breeze 960 Neptune 76,282 Nemo 10,814 Evangeline 5,574 Octane Enhancement: BEF 62,261 58,677 Accounted for on cost basis: Processing: VESCO 33,000 33,000 ------------------------------------- Total $414,808 $298,954 ===================================== The following table shows equity in income (loss) of unconsolidated affiliates for the periods indicated: For Three Months Ended For Six Months Ended June 30, June 30, ------------------------------------- ------------------------------------- 2001 2000 2001 2000 ------------------------------------- ------------------------------------- Fractionation: BRF $ 42 $ 208 $ 60 $ 737 BRPC 252 (29) 404 (19) Promix 1,396 1,546 1,789 3,208 Pipeline: EPIK (172) 178 (1,094) 1,970 Wilprise 85 74 (137) 162 Tri-States 135 843 100 1,521 Belle Rose 29 (30) (60) 149 Dixie 69 960 Starfish 1,022 1,973 Ocean Breeze 12 14 Neptune 1,095 1,789 Nemo 1 10 Evangeline (149) (149) Octane Enhancement: BEF 5,233 8,307 5,402 10,812 ------------------------------------- ------------------------------------- Total $9,050 $11,097 $11,061 $18,540 ===================================== ===================================== Page 8 The following table presents summarized income statement information for the unconsolidated affiliates accounted for by the equity method for the periods indicated (on a 100% basis): Summarized Income Statement data for the Six Months ended ----------------------------------------------------------------------------------------------- June 30, 2001 June 30, 2000 ---------------------------------------------- ----------------------------------------------- Operating Net Operating Net Revenues Income Income Revenues Income Income ---------------------------------------------- ----------------------------------------------- Fractionation: BRF $ 7,825 $ 300 $ 350 $ 9,215 $ 2,222 $ 2,284 BRPC 6,833 1,232 1,347 (187) (65) Promix 21,343 5,888 5,964 24,726 10,141 10,255 Pipeline: EPIK 1,967 (1,782) (1,725) 12,972 3,884 3,981 Wilprise 893 (378) (367) 1,423 470 485 Tri-States 3,953 262 299 7,247 4,470 4,562 Belle Rose 554 (205) (192) 1,266 366 366 Dixie (a) 24,036 8,301 4,829 Starfish (b) 13,467 4,390 3,916 Ocean Breeze (b) 87 87 65 Neptune (b) 16,747 8,648 8,581 Nemo (b) (42) 36 Evangeline (c) 47,609 1,010 (144) Octane Enhancement: BEF 113,918 15,922 16,207 137,430 32,373 32,437 ---------------------------------------------- ----------------------------------------------- Total $259,232 $ 43,633 $39,166 $194,279 $53,739 $54,305 ============================================== =============================================== Summarized Income Statement data for the Three Months ended ----------------------------------------------------------------------------------------------- June 30, 2001 June 30, 2000 ---------------------------------------------- ----------------------------------------------- Operating Net Operating Net Revenues Income Income Revenues Income Income ---------------------------------------------- ----------------------------------------------- Fractionation: BRF $ 3,802 $ 265 $ 294 $ 4,244 $ 569 $ 648 BRPC 3,400 793 842 (187) (99) Promix 12,340 4,447 4,487 12,517 4,752 4,809 Pipeline: EPIK 792 (375) (348) 3,816 324 387 Wilprise 494 224 227 691 212 222 Tri-States 2,321 388 403 3,513 2,490 2,527 Belle Rose 407 13 21 409 (64) (64) Dixie (a) 8,799 2,001 1,124 Starfish (b) 7,051 2,571 2,299 Ocean Breeze (b) 53 39 39 Neptune (b) 9,362 5,223 5,195 Nemo (b) (27) 2 Evangeline (c) 47,609 1,010 (144) Octane Enhancement: BEF 76,054 15,509 15,700 84,097 24,766 24,921 ---------------------------------------------- ----------------------------------------------- Total $172,484 $32,081 $30,141 $109,287 $32,862 $33,351 ============================================== =============================================== Page 9 Notes to Summarized Income Statement data tables: (a) Dixie became an equity method investment in October 2000. (b) These entities became equity method investments of the Company beginning in January 2001. (c) This entity became an equity method investment of the Company in April 2001 as a result of the Acadian Gas acquisition (see Note 3). 3. ACQUISITIONS Since January 1, 2001, the Company has invested approximately $338 million (net of cash acquired) in natural gas pipeline businesses. These include: o a combined $112 million in Ocean Breeze, Neptune, Nemo and Starfish (see Note 2 for a discussion of these equity investments); and, o an initial $226 million for the purchase of Acadian Gas, LLC ("Acadian Gas"). Acquisition of Acadian Gas On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an affiliate of Shell, for approximately $226 million in cash using proceeds from the issuance of the $450 Million Senior Notes. The cash purchase price is subject to certain post-closing adjustments expected to be completed during the third quarter of 2001 (see below). The effective date of the transaction was April 1, 2001. Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. Acadian Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are wholly-owned by Acadian Gas with the exception of the Evangeline system in which Acadian Gas owns an aggregate 49.5% interest. The assets acquired include a leased natural gas storage facility located in Napoleonville, Louisiana. The Acadian, Cypress and Evangeline 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 systems have interconnects with 12 interstate and four intrastate pipelines and a bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub. The Acadian Gas acquisition was accounted for under the purchase method of accounting and, accordingly, the initial purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated fair values at April 1, 2001, as follows: Current assets $ 83,123 Investments in unconsolidated affiliates 2,723 Property, plant and equipment 220,856 Current liabilities (79,577) Other long-term liabilities (1,460) --------------- Total purchase price $225,665 =============== The balances related to the Acadian Gas acquisition included in the consolidated balance sheet dated June 30, 2001 are based upon preliminary information and are subject to change as additional information is obtained. As noted earlier, the initial purchase price is subject to certain post-closing adjustments attributable to working capital items expected to be finalized during the third quarter of 2001. Historical information for periods prior to April 1, 2001 do not reflect any impact associated with the Acadian Gas acquisition. Page 10 Pro Forma effect of Acadian Gas acquisition and recently acquired equity investments The following table presents selected unaudited pro forma information for the three month period ended June 30, 2000 and six month periods ended June 30, 2001 and 2000 as if the acquisition of the Acadian Gas natural gas pipeline systems had been made as of the beginning of the years presented. This table also incorporates selected unaudited pro forma information for the three and six month periods ended June 30, 2000 relating to the Company's equity investments in Starfish, Ocean Breeze and Neptune. The pro forma information is based upon information currently available to and certain estimates and assumptions by management and, as a result, are not necessarily indicative of the financial results of the Company had the transactions actually occurred on these dates. Likewise, the unaudited pro forma information is not necessarily indicative of future financial results of the Company. Three Months Six Months Ended Ended June 30, ------------------------------------- June 30, 2000 2001 2000 -------------------------------------------------------- Revenues $756,769 $2,018,700 $1,608,252 ======================================================== Income before extraordinary item and minority interest $ 45,502 $ 150,660 $ 115,187 ======================================================== Net income $ 45,041 $ 150,593 $ 114,022 ======================================================== 4. RECENTLY ISSUED ACCOUNTING STANDARDS In June 2001, the FASB issued two new pronouncements: SFAS No. 141, " Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS 142 is effective for fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company is currently evaluating the provisions of SFAS 141 and SFAS 142 and has not adopted such provisions in its June 30, 2001 financial statements. Page 11 5. LONG-TERM DEBT Long-term debt consisted of the following at: June 30, 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 Unamortized balance of increase in fair value related to hedging a portion of fixed-rate debt 2,015 Less unamortized discount on: $350 Million Senior Notes (135) (153) $450 Million Senior Notes (272) Less current maturities of long-term debt --------------------------------------- Long-term debt $855,608 $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 June 30, 2001 or December 31, 2000. At June 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its $250 Million Multi-Year Credit Facility of which $19.9 million was outstanding. $450 Million Senior Notes. On January 24, 2001, 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 Gas, Ocean Breeze, Neptune, Nemo and Starfish natural gas pipeline systems for $336 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 subject to a make-whole redemption right; - are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness; and, - are guaranteed by the Limited Partner 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 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. The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and variable-rate debt instruments at June 30, 2001. Page 12 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 7 for additional information concerning the Company's financial instruments. 6. SUPPLEMENTAL CASH FLOW DISCLOSURE Six Months Ended June 30, ---------------------------------- 2001 2000 ---------------------------------- (Increase) decrease in: Accounts receivable $ 96,064 $65,821 Inventories 522 (104,477) Prepaid and other current assets (10,843) 3,154 Intangible assets (3,736) Other assets (118) (1,890) Increase (decrease) in: Accounts payable (55,682) (64,725) Accrued gas payable (78,008) 168,683 Accrued expenses (10,550) (11,965) Other current liabilities 27,817 5,907 Other liabilities 187 (636) ---------------------------------- Net effect of changes in operating accounts $(30,611) $56,136 ================================== Business acquisitions (net of cash received) for the 2001 period reflects a net $226 million paid to an affiliate of Shell for Acadian Gas. Investments in and advances to unconsolidated affiliates for the 2001 period reflects $112 million paid to EPE for equity interests in various Gulf of Mexico natural gas pipeline systems. 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 records various financial instruments relating to interest rate and commodity positions at their respective fair values. For the six months ended June 30, 2001, the Company recognized a net $55.9 million in non-cash mark-to-market gains related to increases in the fair value of these financial instruments ($52.5 million of this amount was attributable to commodity financial instruments with the remainder resulting from interest rate hedging activities). See Note 7 below for a further description of the Company's financial instruments. Cash and cash equivalents at June 30, 2001 per the Statements of Consolidated Cash Flows excludes $7.3 million of restricted cash associated with commodity hedging activities. Page 13 7. 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 enters 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. 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). The $42.2 million cumulative transition adjustment was or will be reclassified to earnings as follows: - $21.7 million during the first quarter of 2001; - $10.7 million during the second quarter of 2001; - $7.3 million during the third quarter of 2001; with the remaining - $2.5 million reclassified 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. The Company has entered into commodity financial instruments for time periods extending through June 2002. 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). Page 14 The following table shows the impact of commodity financial instruments on earnings for the three and six months ended June 30, 2001: For the Three For the Six Months Ended Months Ended June 30, June 30, 2001 2001 -------------------------------------- End of period non-cash mark-to-market accounting adjustments $39.0 $52.5 Net Gains (losses) on early closeouts and settlements 25.7 17.8 -------------------------------------- Net gain (loss) recorded in earnings $64.7 $70.3 ====================================== 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 impact 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 5 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 be 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 for 2001 includes a $5.5 million benefit related to a change in fair value of the Company's 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 market interest rates in effect on the specified settlement dates in the swap agreements. The $5.5 million benefit is primarily due to the decision of one counterparty not to exercise its early termination right under its swap agreement with the Company and, to a lesser extent, lower overall borrowing rates. Page 15 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. 8. 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 both liquids and natural gas pipeline systems, 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 based on 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. Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset's or investment's principal operations. The principal reconciling item between consolidated property, plant and equipment and segment property is construction-in-progress. Segment property represents those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not generally contribute to segment gross operating margin, these assets are not included in the operating segment totals until they are deemed operational. 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. Page 16 Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table: Operating Segments Adjs. ------------------------------------------------------------------ Octane and Consol. Fractionation Pipelines Processing Enhancement Other Elims. Totals --------------------------------------------------------------------------------------------- Revenues from external customers for three months ended: June 30, 2001 $86,566 $178,958 $693,242 $631 $959,397 June 30, 2000 97,004 16,914 478,244 751 592,913 for six months ended: June 30, 2001 176,245 186,145 1,432,011 1,311 1,795,712 June 30, 2000 188,901 23,926 1,125,101 1,266 1,339,194 Intersegment revenues for three months ended: June 30, 2001 44,133 24,631 131,657 96 $(200,517) June 30, 2000 47,264 14,826 139,654 94 (201,838) for six months ended: June 30, 2001 85,785 45,410 241,966 191 (373,352) June 30, 2000 82,729 28,025 281,885 188 (392,827) Equity income in unconsolidated affiliates: for three months ended: June 30, 2001 1,692 2,125 $5,233 9,050 June 30, 2000 1,725 1,065 8,307 11,097 for six months ended: June 30, 2001 2,253 3,406 5,402 11,061 June 30, 2000 3,926 3,802 10,812 18,540 Total revenues for three months ended: June 30, 2001 132,391 205,714 824,899 5,233 727 (200,517) 968,447 June 30, 2000 145,993 32,805 617,898 8,307 845 (201,838) 604,010 for six months ended: June 30, 2001 264,283 234,961 1,673,977 5,402 1,502 (373,352) 1,806,773 June 30, 2000 275,556 55,753 1,406,986 10,812 1,454 (392,827) 1,357,734 Gross operating margin by segment for three months ended: June 30, 2001 32,803 24,696 68,112 5,233 411 131,255 June 30, 2000 29,591 14,192 18,486 8,307 872 71,448 for six months ended: June 30, 2001 58,471 42,819 96,510 5,402 946 204,148 June 30, 2000 63,922 28,827 58,040 10,812 1,426 163,027 Segment property at: June 30, 2001 357,142 670,311 125,657 7,884 71,798 1,232,792 December 31, 2000 356,207 448,920 126,895 8,942 34,358 975,322 Investments in and advances to unconsolidated affiliates at: June 30, 2001 98,062 221,485 33,000 62,261 414,808 December 31, 2000 105,194 102,083 33,000 58,677 298,954 Page 17 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. A reconciliation of segment gross operating margin to consolidated income before minority interest follows: For Three Months Ended For Six Months Ended June 30, June 30, --------------------------------- --------------------------------- 2001 2000 2001 2000 --------------------------------- --------------------------------- Total segment gross operating margin $131,255 $71,448 $204,148 $163,027 Depreciation and amortization (11,793) (8,754) (21,822) (16,878) Retained lease expense, net (2,660) (2,687) (5,320) (5,324) Loss (gain) on sale of assets 6 (2,303) 387 (2,303) Selling, general and administrative (8,418) (7,658) (14,586) (13,042) --------------------------------- --------------------------------- Consolidated operating income 108,390 50,046 162,807 125,480 Interest expense (16,331) (8,070) (23,318) (15,844) Interest income from unconsolidated affiliates 3 94 15 202 Dividend income from unconsolidated affiliates 2,761 1,632 3,995 Interest income - other 1,626 1,358 5,771 2,973 Other, net (251) (62) (531) (425) --------------------------------- --------------------------------- Consolidated income before minority interest $ 93,437 $46,127 $146,376 $116,381 ================================= ================================= Page 18 Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. For the Interim Periods ended June 30, 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 Operating L.P. (the "Company") included elsewhere herein. Cautionary Statement regarding Forward-Looking 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. Risk Factors An investment in the Company's securities involves a degree of risk. 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 NGL 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, (g) the use of financial instruments to hedge commodity and interest rate risks and (h) failure to complete one or more new projects on time or within budget. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include the level of domestic oil, natural gas and NGL production, the availability of imported oil and natural gas, actions taken by foreign oil and natural gas producing nations, the availability of transportation systems with adequate capacity, the availability of competitive fuels and products, fluctuating and seasonal demand for oil, natural gas and NGLs and conservation and the extent of governmental regulation of production and the overall economic environment. The products that the Company processes, sells or transports are principally used as feedstocks in petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and commercial heating. A reduction in demand for the Company's products or processing or transportation services by the petrochemical, refining or heating industries, whether because of general economic conditions, reduced demand by consumers for the end products made with NGL products, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, governmental regulations affecting prices and production levels of natural gas or the content of motor gasoline or other reasons, could have a negative impact on the Company's results of operations. A material decrease in natural gas production or crude oil refining, as a result of depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in the volumes of NGLs processed or sold by the Company, thereby reducing revenue and operating income. 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 various uncertainties including the following key factors: (a) the accuracy of the Company's estimates regarding its spending requirements, (b) the occurrence of any Page 19 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. For a further description of the risks of owning the Company's securities, see the Limited Partner's registration documents filed with the SEC on Form S-1/A dated July 21,1998 and the Company's Form S-3 dated December 21, 1999 and Form S-3 dated February 23, 2001 (altogether with any amendments thereto). Company Overview The Company was formed on April 9, 1998 as a Delaware limited partnership to acquire, own and operate the NGL processing and distribution assets of Enterprise Products Company ("EPCO"). The Company conducts substantially all of the business of its publicly-traded (NYSE, symbol "EPD") limited partner, Enterprise Products Partners L.P. (the "Limited Partner"), which owns 98.9899% of the Company's equity interests. Enterprise Products GP, LLC (the "General Partner") is the Company's general partner and owns 1.0101% of the Company's equity interests. Both the Limited Partner and the General Partner are subsidiaries of EPCO. 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. The Company is a leading North American provider of a wide range of midstream energy services to its customers along the central and western Gulf Coast. The Company's services include 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 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. Page 20 The Company's operations in Louisiana and Mississippi include varying interests in twelve natural gas processing plants with a combined capacity of 11.6 Bcf/d and net capacity of 3.2 Bcf/d, 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 NGL and petrochemical 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. Beginning in January 2001, the Company owns varying equity interests in four Gulf of Mexico offshore Louisiana natural gas pipeline systems totaling 725 miles of pipeline (with an aggregate gross capacity of 2.85 Bcf/d) and related assets. These equity interests were purchased from EPE at a cost of approximately $112 million. With the completion of the Acadian Gas, LLC ("Acadian Gas") acquisition in April 2001, the Company now owns varying interests in an additional 1,042 miles of natural gas pipeline systems (with an aggregate gross capacity of over 1.1 Bcf/d) and related facilities located in south Louisiana. For additional information regarding these recent investments and business acquisitions, see "Recent acquisitions and other investments" below. 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 generally 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 addition, the Company's newly acquired natural gas pipeline businesses are viewed as fee-based operations. See "Recent acquisitions and other investments" below for a further discussion of the impact of commodity price risk on these operations. 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 of 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. As part of its natural gas processing and related merchant activities, the Company uses commodity financial instruments to reduce its exposure to the market risks associated with changes in natural gas and NGL prices. Recent acquisitions and other investments Natural gas pipelines General. Since January 1, 2001, the Company has invested approximately $338 million (net of cash acquired) in natural gas pipeline businesses. These include an initial $226 million paid to Shell for the purchase of Acadian Gas (an onshore Louisiana system) and a combined $112 million paid to EPE for equity interests in four Gulf of Mexico natural gas pipelines (primarily offshore Louisiana systems). The acquisition of these natural gas pipeline 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 Page 21 refineries) and provide opportunities for enhanced services to customers as well as generating additional fee-based cash flows. These businesses will be accounted for as part of the Company's Pipeline segment. Natural gas pipeline systems receive natural gas from producers, other pipelines or shippers through system interconnects and redeliver the natural gas at other points. Generally, natural gas transportation agreements provide these systems with a fee per unit of volume (generally in MMBtus) transported. Natural gas pipeline businesses (such as those of Acadian Gas) may also involve gathering and purchasing natural gas from producers and suppliers and transporting and reselling such natural gas to electric utility companies, local distribution companies, industrial customers, affiliates of other pipeline and gas marketing companies as well as transporting and gathering natural gas for shippers on a fee basis. Overall, the Company's Gulf of Mexico systems do not take title to the natural gas that they transport; the shipper retains title and the associated commodity price risk. In the Company's Acadian Gas operations, it does take title to natural gas streams and is exposed to commodity price risk through its natural gas inventories and certain of its contracts. The results of operation for the six months ended June 30, 2001 include three month's impact of the Acadian Gas acquisition and six month's impact of the Gulf of Mexico natural gas pipelines. See Note 3 of the Notes to Unaudited Consolidated Financial Statements for selected pro forma financial data regarding these transactions as if they had both occurred on January 1, 2001 and 2000. Acadian Gas. On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an affiliate of Shell, for approximately $226 million in cash using proceeds from the issuance of the $450 Million Senior Notes. The cash purchase price is subject to certain post-closing adjustments expected to be completed during the third quarter of 2001. The effective date of the transaction was April 1, 2001. Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. Acadian Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are wholly-owned by Acadian Gas with the exception of the Evangeline system in which Acadian Gas holds an approximate 49.5% interest. The assets acquired include a leased natural gas storage facility located in Napoleonville, Louisiana. The Acadian, Cypress and Evangeline 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 systems have interconnects with 12 interstate and four intrastate pipelines and a bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub. Interests in four Gulf of Mexico natural gas pipeline systems. On January 29, 2001, the Company purchased equity interests in four Gulf of Mexico natural gas pipeline systems and related assets from EPE for $112 million, after taking into account certain post-closing adjustments completed in the second quarter of 2001. The Company acquired a 50% equity interest in Starfish Pipeline Company LLC ("Starfish") which owns the Stingray natural gas pipeline system and a related natural gas dehydration facility. The Stingray system is a 375-mile FERC-regulated natural gas pipeline system that transports natural gas and injected condensate from certain production areas offshore Louisiana in the Gulf of Mexico to onshore transmission systems located in south Louisiana. The natural gas dehydration facility is connected to the onshore terminal of the Stingray system in south Louisiana. In addition to Starfish, the Company acquired a 25.67% equity interest in Ocean Breeze Pipeline Company LLC ("Ocean Breeze") and Neptune Pipeline Company LLC ("Neptune") as well as a 33.92% equity interest in Nemo Gathering Company, LLC ("Nemo"). Ocean Breeze and Neptune collectively own the Manta Ray and Nautilus natural gas gathering and transmission systems located in the Gulf of Mexico offshore Louisiana. The Manta Ray system comprises approximately 225 miles of unregulated pipelines with a capacity of 750 MMcf/d and related equipment, the Nautilus system comprises approximately 101 miles of FERC-regulated pipelines with a capacity of 600 MMcf/d, 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/d. Page 22 Affiliates of Shell own the remaining equity interests in Starfish and varying interests in Ocean Breeze, Neptune and Nemo. An affiliate of Marathon Oil Company owns an interest in Ocean Breeze and Neptune. In addition, Shell is the operator of the assets held by Starfish, Ocean Breeze, Neptune and Nemo. These natural gas pipeline systems and related assets are strategically located to serve continental shelf and deepwater developments in the central Gulf of Mexico. Management believes that the equity interests acquired from EPE complement and integrate well with those of the Acadian Gas acquisition. These investments are expected to benefit the Company's midstream focus by: o broadening its midstream business by providing additional services to customers; and by o contributing to the Company's ability to obtain anticipated increases in natural gas production from deepwater Gulf of Mexico development. Management believes that these assets have a significant upside potential, since Shell and Marathon have dedicated production from over 1,000 square miles of Gulf of Mexico offshore Louisiana natural gas leases to these systems and only a small portion of this total has been developed to date. Regulatory environment of natural gas systems. The Stingray and Nautilus natural gas pipeline systems are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each system operates under separate FERC approved tariffs that establish rates, terms and conditions under which each system provides services to its customers. Generally, the FERC's authority extends to: o transportation of natural gas, rates and charges; o certification and construction of new facilities; o extension or abandonment of services and facilities; o maintenance of accounts and records; o depreciation and amortization policies; o acquisition and disposition of facilities; o initiation and discontinuation of services; and o various other matters. As noted above, the Stingray and Nautilus systems have tariffs established through filings with the FERC that have a variety of terms and conditions, each of which affect the operations of each system and their ability to recover fees for the services they provide. Generally, changes to these fees or terms can only be implemented upon approval by the FERC. Collectively, the Acadian Gas and Gulf of Mexico pipeline systems acquired by the Company are subject to various governmental and environmental legislation. Each of these systems has a continuing program of inspection designed to ensure compliance with such legislation including pollution control and pipeline safety requirements. The Company believes that these systems are in substantial compliance with the applicable requirements. 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. Current Business Environment The second quarter of 2001 was a period of recovery for the NGL industry. The decline in natural gas prices from the record levels of the first quarter of 2001 resulted in increased NGL extraction rates throughout the industry. Consequently, the Company saw a rebound in NGL volumes available for fractionation and/or transportation. Page 23 At the Company's gas processing facilities, equity NGL production volumes increased from the 46 MBPD of the first quarter of 2001 to 63 MBPD in the second quarter of 2001. Natural gas prices, which approached $10 per MMBtu in January 2001, fell to nearly $3 per MMBtu during July 2001. The price of natural gas relative to the price of NGLs plays a major role in gas processing costs since high natural gas prices result in increased fuel and shrinkage costs which may, at times, exceed the value of the NGLs extracted from the gas. The low equity NGL production rate seen in the first quarter was the result of minimal NGL extraction caused by the abnormally high cost of natural gas. As natural gas prices moderated in the second quarter, NGL extraction rates at the Company's processing facilities and those of other industry participants increased resulting in additional volumes throughout its NGL value chain. In the second quarter of 2001, NGL prices declined along with those of other forms of energy. The resultant loss of value has been mitigated (or in some cases, reversed) by the Company's hedging activities. During the third quarter of 2001, the Company expects that natural gas prices will generally weaken and that NGL prices will stabilize. In light of these expectations, management continues to monitor its commodity financial instruments portfolio due to the volatility of the energy markets. Third quarter equity NGL production is expected to approximate 75 MBPD. The Company's recently acquired natural gas pipeline businesses (i.e. Acadian Gas and the Gulf of Mexico joint ventures) have experienced strong demand for their services. In response to the long-term expected increase in natural gas demand, many producers have stepped up their drilling activities resulting in an increase in natural gas volumes available for transportation. Producers believe that natural gas demand will increase near-term due to new gas-fired electric generation facilities commencing operations and a rebound in industrial and commercial demand with the moderation of natural gas prices and an improving economy. Conversely, any material downturn in either the domestic or global economy or long-term decrease in natural gas pricing below $2.75 to $3.00 per MMBTU could result in decreased drilling activities. Barring the latter scenario, the Company's natural gas pipelines expect to maintain or grow their current throughput levels for the near term associated with third-party activities, the most significant of which is the start-up of operations at the Shell Brutus field. This field is expected to generate approximately 130 BBtu/d of natural gas throughput volume and 10 MBPD of equity NGL production by the end of 2001. During the second quarter of 2001, the Company's isomerization services and isobutane merchant business benefited from strong demand for isobutane used in the manufacture of gasoline. The increase in demand stemmed from refiners increasing gasoline production in anticipation of short-term gasoline supply imbalances heading into the summer driving season. In response, the Company's Mont Belvieu isomerization units ran at near full rates during the early part of the second quarter with the isobutane merchant business profiting on strong spot and contract sales. Also, the Company's Houston Ship Channel import facility and related pipeline system experienced significant volume and margin increases as commercial butane imports (used as feedstock for isobutane) were transported to Mont Belvieu to satisfy the demands of increased isobutane production. By the end of the second quarter, isobutane demand returned to more normalized levels as refiners perceived that gasoline supplies had stabilized. As a result, the Company anticipates that its isomerization and related merchant business (along with its import dock and related pipelines) will experience normalized margins and volumes during the third quarter of 2001. Propylene fractionation margins are slightly less than last year due to continuing weakness in the propylene markets. Management expects prices to stabilize during the third quarter of 2001 with a slight rise expected in the fourth quarter of 2001 due to a strengthening domestic economy and increased propylene demand. The Company's MTBE operations (reported under the Octane Enhancement business segment) experienced healthy margins early in the second quarter of 2001 due to the seasonal surge in gasoline blending requirements from refiners; however, as gasoline supplies and demand have stabilized, MTBE prices and margins have fallen. The Company expects results from MTBE operations to be near breakeven for the third and fourth quarters of 2001 as a result of this seasonal decrease in prices. With regards to its major liquids pipelines, the Company expects the Louisiana Pipeline System to benefit from the seasonal rise in propane shipments that are carried on the Dixie Pipeline with the strongest movements anticipated during the fourth quarter of 2001. EPIK's financial performance is expected to improve significantly over the last half of 2001. Exports of butane and propane are expected to increase as a result Page 24 of moderating domestic prices for both products relative to foreign markets. This situation should make these products more attractive on the world market and EPIK should benefit from a heavy slate of vessel loadings for export. 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) (a) (a) (a) (a) (a) 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 (c) $7.00 $28.81 $0.43 $0.55 $0.63 $0.69 $0.23 Second quarter (c) $4.61 $27.88 $0.33 $0.46 $0.53 $0.63 $0.19 - ---------------------------------------------------------------------------------------------------------------- (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) After reaching a high of $9.87 per MMBtu in January 2001, natural gas prices have declined to an average of $3.68 per MMBtu in June 2001. Results 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 liquids and natural gas pipeline systems, 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 based on 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. Page 25 The Company's gross operating margin by segment (in thousands of dollars) along with a reconciliation to consolidated operating income for the three and six month periods ended June 30, 2001 and 2000 were as follows: For Three Months Ended For Six Months Ended June 30, June 30, ------------------------------------ ----------------------------------- 2001 2000 2001 2000 ------------------------------------ ----------------------------------- Gross Operating margin by segment: Fractionation $ 32,803 $29,591 $ 58,471 $ 63,922 Pipeline 24,696 14,192 42,819 28,827 Processing 68,112 18,486 96,510 58,040 Octane enhancement 5,233 8,307 5,402 10,812 Other 411 872 946 1,426 ------------------------------------ ----------------------------------- Gross Operating margin total 131,255 71,448 204,148 163,027 Depreciation and amortization 11,793 8,754 21,822 16,878 Retained lease expense, net 2,660 2,687 5,320 5,324 Loss (gain) on sale of assets (6) 2,303 (387) 2,303 Selling, general and administrative expenses 8,418 7,658 14,586 13,042 ------------------------------------ ----------------------------------- Consolidated operating income $108,390 $50,046 $162,807 $125,480 ==================================== =================================== The Company's significant production and other volumetric data (on a net basis) for the three and six month periods ended June 30, 2001 and 2000 were as follows: For the three months ended For the six months ended June 30, June 30, --------------------------------- ---------------------------------- 2001 2000 2001 2000 --------------------------------- ---------------------------------- MBPD, Net --------- Equity NGL Production 63 72 54 72 NGL Fractionation 202 215 184 217 Isomerization 94 81 82 74 Propylene Fractionation 29 30 30 30 Octane Enhancement 5 5 4 5 Major NGL and Petrochemical Pipelines 519 340 438 350 MMBtu/D, Net ------------ Natural Gas Pipelines 1,295,370 1,263,039 Three Months Ended June 30, 2001 compared with Three Months Ended June 30, 2000 Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 60% to $968.4 million in 2001 compared to $604.0 million in 2000. The Company's operating costs and expenses increased by 56% to $851.6 million in 2001 versus $546.3 million in 2000. Operating income increased 117% to $108.3 million in 2001 from $50.0 million in 2000. Second quarter 2001 revenues and expenses have primarily been impacted by the acquisition of Acadian Gas and increased merchant business activities. The majority of the increase in operating income for 2001 relates to $39.0 million in non-cash mark-to-market gains relating to the Company's commodity hedging activities. Fractionation. The Company's gross operating margin for the Fractionation segment increased to $32.8 million in 2001 from $29.6 million in 2000. NGL fractionation margin declined $4.3 million quarter-to-quarter primarily the result of higher energy costs and lower fractionation volumes. NGL fractionation net volumes were 202 MBPD for 2001 compared to 215 MBPD during 2000. With the decline in natural gas prices since February 2001, NGL fractionation volumes have improved since the first quarter 2001's 165 MBPD rate due to higher liquids extraction rates at gas processing facilities. The 2000 volume is representative of a period when the industry was maximizing NGL production. Page 26 The Company's isomerization business posted a $6.7 million increase in margin in 2001 over 2000 levels with isomerization volumes increasing from 81 MBPD in 2000 to 94 MBPD in 2001. The increase in both margin and volume is attributable to a strong isobutane market early in the second quarter of 2001 which led to an increase in demand for the Company's isomerization services. Gross operating margin from propylene fractionation declined by $0.5 million primarily due to moderating prices and a slight decrease in volumes. Propylene fractionation volumes were 29 MBPD in 2001 versus 30 MBPD during the 2000 period. Pipeline. The Company's gross operating margin for the Pipeline segment was $24.7 million in 2001 compared to $14.2 million in 2000. Of the $10.5 million increase, $5.2 million is attributable to natural gas pipelines (i.e., the newly acquired Acadian Gas and the Gulf of Mexico systems) which benefited from a strong natural gas marketplace. Natural gas pipeline volumes averaged 1,295 BBtu/d on a net basis. Of the Company's liquids-oriented assets, the recently completed Lou-Tex NGL Pipeline added $2.4 million in margin on volumes of 21 MBPD and the Houston Ship Channel import facility and related pipeline system added $3.1 million primarily due to strong imports of commercial butane. Net liquids throughput volumes increased to 519 MBPD in 2001 compared with 340 MBPD in 2000. Of the 179 MBPD increase in net throughput volumes, 143 MBPD is attributable to the higher import activity. Processing. For the second quarter of 2001, the Processing segment generated gross operating margin of $68.1 million compared to $18.5 million during the same period in 2000. The Processing segment includes the Company's natural gas processing business and related merchant activities. Gross operating margin from natural gas processing plants posted a $44.1 million increase over 2000 levels primarily due to a $59.1 million increase in net hedging gains from $5.6 million in 2000 to $64.7 million in 2001 (see discussion below). The net hedging gains more than offset the effects of lower equity NGL volumes and prices and a rise in energy-related operating costs. The Company's equity NGL production was 63 MBPD for the 2001 quarter versus 72 MBPD for the same period in 2000. Although lower on a quarter-to-quarter basis, equity NGL production for the second quarter of 2001 improved from the 46 MBPD rate of the first quarter of 2001. The improvement is related to the overall decline in natural gas prices that have led processors industrywide to increase NGL recoveries. Gross operating margin from merchant activities in 2001 increased $5.5 million over 2000 primarily due to strong demand for isobutane. Gross operating margin for the 2001 period includes $64.7 million of net hedging profits resulting from the Company's commodity hedging activities. Of this amount, $39.0 million is attributable to net non-cash mark-to-market gains on the commodity financial instruments that were outstanding at June 30, 2001. The Company employs various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL prices) on its natural gas processing business and related merchant activities. A large number of the Company's commodity financial instruments are based on the historical relationship between natural gas prices and NGL prices. This type of hedging strategy utilizes the forward sale of natural gas at a fixed-price with the expected margin on the settlement of the position offsetting or mitigating changes in the anticipated margins on NGL merchant activities and the value of its NGL equity production. During the second quarter of 2001, the Company benefited from a decline in natural gas prices relative to its fixed positions. The decline in natural gas prices created gains on the settlement and early closeout of certain positions of approximately $25.7 million. If natural gas prices had not declined to the degree seen during the quarter, a smaller gain or a loss on hedging activities may have resulted offset somewhat by anticipated higher NGL prices. A variety of factors influence whether or not the Company's hedging strategy is successful. For additional information regarding the Company's commodity financial instruments, see Item 3 "Quantitative and Qualitative Disclosures about Market Risk" on page 33. Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $3.1 million in the second quarter of 2001 compared with 2000 levels. MTBE production, on a net basis, was 5 MBPD in both 2001 and 2000. The decline in margin is primarily due to lower MTBE prices in 2001 relative to the 2000 period and higher energy costs. Interest expense. Interest expense for the second quarter of 2001 increased $8.3 million over the same period in 2000. The increase is primarily due to interest associated with the $450 Million Senior Notes issued in January 2001. Page 27 Six Months Ended June 30, 2001 compared with Six Months Ended June 30, 2000 Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 29% to $1.8 billion in 2001 compared to $1.4 billion in 2000. The Company's operating costs and expenses increased by 33% to $1.6 billion in 2001 versus $1.2 billion in 2000. Operating income increased 30% to $162.8 million in 2001 from $125.5 million in 2000. Year-to-date 2001 revenues and expenses have increased due to the acquisition of Acadian Gas and increased merchant business activities. In addition year-to-date 2001 expenses have increased due to higher than normal natural gas prices which affects energy-related operating costs at the Company's facilities. The majority of the increase in operating income for 2001 relates to $52.5 million in non-cash mark-to-market gains relating to the Company's commodity hedging activities. Fractionation. The Company's gross operating margin for the Fractionation segment decreased to $58.5 million from $63.9 million. NGL fractionation margin decreased $14.7 million primarily due to lower processing volumes and higher energy-related operating costs. NGL fractionation net volumes decreased to 184 MBPD for the first six months of 2001 compared to 217 MBPD during the same period in 2000. The decrease is the result of lower extraction rates at gas processing facilities in early 2001 (due to the high cost of natural gas) versus 2000 when the industry was maximizing NGL production. NGL fractionation volumes improved to 202 MBPD during the second quarter of 2001 as extraction rates increased and the price of natural gas declined. For the first six months of 2001, gross operating margin from isomerization services increased $11.2 million compared to 2000 primarily due to an increase in volumes and toll processing fees. Isomerization volumes increased to 82 MBPD during the first six months of 2001 versus 74 MBPD during the same period in 2000 due to increased demand for the Company's services. Gross operating margin from propylene fractionation decreased $2.8 million compared to the first six months of 2001 primarily due to higher energy costs and moderating prices. Net propylene fractionation volumes were 30 MBPD for both periods. Pipeline. The Company's gross operating margin for the Pipeline segment was $42.8 million compared to $28.8 million in 2000. Of the $14.0 million increase, $6.9 million is attributable to natural gas transportation activities (i.e. Acadian Gas and the Gulf of Mexico systems) which benefited from a strong natural gas marketplace in 2001. The Company's recently completed Lou-Tex NGL Pipeline added $5.1 million on volumes of 22 MBPD. In addition, margin on the Company's Lou-Tex Propylene Pipeline for 2001 was $2.9 million higher than 2000 (primarily due to this asset being purchased in March 2000). Strong imports of mixed NGLs (particularly commercial butanes) resulted in a $3.1 million increase in margins for the Houston Ship Channel import facility and related pipeline system. The increase in commercial butane imports was related to the strong demand for isobutane which occurred between February and May 2001. Overall, net throughput on the Company's major liquids pipelines improved to 438 MBPD in 2001 versus 350 MBPD in 2000, with 76 MBPD of the increase stemming from increased imports and related pipeline activity along the Houston Ship Channel. Net throughput for the natural gas pipelines averaged 1,263 BBtu/d with Acadian Gas accounting for 725 BBtu/d and the Gulf of Mexico systems for the balance. Processing. For the 2001 period, the Processing segment generated gross operating margin of $96.5 million compared to $58.0 million in 2000. Gross operating margin from the natural gas processing plants posted a $4.1 million increase over 2000 levels primarily due to a $67.3 million increase in net hedging gains from $3.0 million in 2000 to $70.3 million in 2001 (see discussion below). The net hedging gains more than offset the effects of lower equity NGL volumes and prices and a rise in energy-related operating costs. Equity NGL production averaged 54 MBPD during the 2001 period compared to 72 MBPD during the 2000 period. The 2001 rate of 54 MBPD reflects the very low NGL extraction rates of the first quarter of 2001 (46 MBPD) when natural gas prices were at their peak. As natural gas costs have declined since January 2001, equity NGL production has begun returning to higher levels (63 MBPD during the second quarter of 2001). The 2000 rate reflects a period in which processors were operating facilities at near full extraction rates. Gross operating margin from merchant activities increased $34.4 million over 2000 primarily due to strong demand for propane in the first quarter of 2001 for heating and isobutane in the second quarter of 2001 for refining. Gross operating margin for the 2001 period includes $70.3 million of net hedging profits resulting from the Company's commodity hedging activities. Of this amount, $52.5 million is attributable to non-cash mark-to-market gains on the commodity financial instruments that were outstanding at June 30, 2001. As Page 28 discussed earlier under the Processing segment's quarter-to-quarter variance explanation (see Page 27), the Company employs various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL prices) on its natural gas processing business and related merchant activities. Of the $70.3 million in net hedging profits, $17.8 million is attributable to realized gains on the settlement and early closeout of certain positions. Currently, the predominant strategy employed by the Company utilizes natural gas-based commodity financial instruments to hedge future NGL production and sales. This type of hedge is based upon the historical relationship between natural gas and NGL prices. The key factor behind the net hedging gains recognized by the Company is the decline in natural gas prices relative to the fixed natural gas prices found in its commodity financial instrument portfolio. If natural gas prices had not declined to the degree seen during the quarter, a smaller gain or a loss on hedging activities may have resulted which should have been offset somewhat by correlative higher NGL prices which have increased the value of the Company's equity NGL production. A variety of factors influence whether or not the Company's hedging strategy is successful. For additional information regarding the Company's commodity financial instruments, see Item 3 "Quantitative and Qualitative Disclosures about Market Risk" on page 33 and the quarter-to-quarter variance explanation for Processing found on page 27. Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $5.4 million in the first six months of 2001 compared with the same period in 2000. MTBE production, on a net basis, was 4 MBPD in 2001 and 5 MBPD in 2000. The decline in margin is primarily due to lower MTBE prices in 2001 relative to the 2000 period, higher energy-related operating costs and a prolonged maintenance outage which lasted from December 2000 until February 2001. Interest expense. Interest expense for 2001 increased $7.5 million over 2000. The increase is attributable to the interest associated with the $450 Million Senior Notes issued in January 2001. Interest expense for 2001 includes a $5.5 million benefit related to a change in fair value of the Company's 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 market interest rates in effect on the specified settlement dates in the swap agreements. The $5.5 million benefit is primarily due to the decision of one counterparty not to exercise its early termination right under its swap agreement with the Company and, to a lesser extent, lower overall borrowing rates. 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 its partners. The Company expects to fund its short-term needs for such items as maintenance capital expenditures and quarterly distributions to its 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, the issuance of additional public debt and contributions from its partners. 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 public debt (separately or in combination). As of June 30, 2001, availability under the Company's 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, 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 Gas and Gulf of Mexico natural gas pipeline 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 and Limited Partner filed a $500 million universal shelf registration (the "February 2001 Registration Statement") covering the issuance of an 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". Page 29 In June 2000, the Limited Partner received approval from its Unitholders to increase by 25,000,000 the number of Common Units available (and unreserved) for general partnership purposes during its subordination period. This increase has improved the future financial flexibility of the Limited Partner to contribute cash and/or other assets to the Company for business expansions and acquisitions. 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, Baa2 by Moody's Investor Service and BBB by Standard and Poors) combined with a continued ready access to debt (and equity-sourced capital from its Limited Partner) 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 six months ended June 30, 2001 and 2000. Cash flows from operating activities were a $90.2 million inflow compared to a $194.2 million inflow in 2000. Cash flows from operating activities primarily reflect the effects of net income, depreciation and amortization, equity income and distributions from unconsolidated affiliates, fluctuations in fair values of financial instruments and changes in working capital. Net income increased $30.0 million in 2001 compared to 2000 due to reasons mentioned previously under "Results of Operation of the Company". Depreciation and amortization increased a combined $4.9 million in 2001 over 2000 primarily due to additional capital expenditures and business acquisitions. The Company received $13.2 million in distributions from its equity method investments in 2001 compared to $14.3 million in 2000. The $1.1 million decrease in distributions is primarily related to a decrease in BEF's earnings due to lower MTBE prices and volumes, lower throughput volumes on the Tri-States pipeline system and processing volumes at Promix attributable to lower NGL extraction rates during the early part of 2001 offset by receipts from the newly acquired Gulf of Mexico natural gas pipelines. Operating cash flow also includes an adjustment for the $55.9 million in non-cash mark-to-market gains related to commodity and interest rate risk hedging activities. The net effect of changes in operating accounts from period to period is generally the result of timing of NGL sales and purchases near the end of the period and changes in inventory values related to pricing or volumes or a combination thereof. The Company is exposed to various market risks including commodity price risk (primarily through its gas processing and related NGL businesses) and interest rate risk. The Company attempts to manage its price risk by utilizing certain hedging strategies defined elsewhere herein. These risks, however, may entail significant cash outlays in the future that may not be entirely offset by their underlying hedged positions. During 2001, the Company has recognized $70.3 million in net hedging profits related to its commodity hedging portfolio. Of this amount, a net $17.8 million has been realized through settlements and the early closeout of certain positions through June 30, 2001. The remaining $52.5 million represents non-cash mark-to-market gains on commodity financial instruments that remained open at June 30, 2001. When appropriate, the Company may elect to close certain of its commodity financial instruments prior to their contractual settlement dates in order to realize gains or limit losses. As of August 1, 2001, the Company has realized $26.3 million of the $52.5 million in non-cash mark-to-market gains recorded at the end of the second quarter. The realization of the remaining amount depends upon a number of factors including, most notably, the current market price of natural gas on the settlement or closing date relative to the price in the underlying financial instruments. If the price of natural gas rises beyond the hedging positions taken by the Company, it will result in losses rather than gains on its hedging activities. The Company continues to aggressively monitor its commodity hedging portfolio in light of the energy markets. For a more complete description of the Company's risk management policies and potential exposures, see "Item 3. Quantitative and Qualitative Disclosures about Market Risk" on page 33 and Note 7 of the Notes to Unaudited Consolidated Financial Statements. Cash used for investing activities was $397.5 million in 2001 compared to $150.7 million in 2000. Cash outflows included capital expenditures of $57.1 million in 2001 versus $154.2 million in 2000. Capital expenditures for 2000 include $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 $2.7 million in 2001 and $0.5 million in 2000. The Company's completion of the Acadian Gas business acquisition resulted in an initial payment to Shell of $225.7 million in April 2001, subject to certain post-closing purchase price adjustments. The 2000 period also includes $6.5 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. Lastly, investing cash outflows in 2001 includes $115.3 million in investments in and advances to unconsolidated affiliates compared to $3.0 million in 2000. Page 30 Cash receipts from financing activities were $361.8 million during the first six months of 2001 compared to $37.7 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 increased to $77.5 million in 2001 from $68.3 million in 2000 primarily due to an increase in the quarterly distribution requirements of the Limited Partner. During the first six months of 2001, the Company has invested $338 million in business acquisitions and the purchase of interests in other companies. These investments include the acquisition of Acadian Gas, LLC and interests in four natural gas pipelines in the Gulf of Mexico. The Company will continue to analyze potential acquisitions, joint ventures or similar transactions with businesses that operate in complementary markets and geographic regions. In recent years, major oil and gas companies have sold non-strategic assets including assets in the midstream natural gas industry in which the Company operates. Management believes that this trend will continue, and the Company expects independent oil and natural gas companies to consider similar options. In addition, management believes that the Company is well positioned to continue to grow through acquisitions that will expand its platform of assets and through internal growth. The Company anticipates that it will achieve its annual growth objective for 2001: investing $400 million in energy infrastructure projects and acquisitions while allowing for the Limited Partner to increase its cash distribution rate by at least 10% for the full year. The Company and its Limited Partner have adopted a cash distribution policy (at the direction and discretion of the General Partner) that retains a significant amount of cash flow for reinvestment in the growth of the business. Over the last two years, the Company has reinvested approximately $238 million to fund expansions and acquisitions. The Company's cash distribution policy provides management with a great deal of financial flexibility in executing its growth strategy. 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 33 of this Form 10-Q report and Note 7 of the Notes to Consolidated Financial Statements. Future Capital Expenditures. The Company forecasts that $100.7 million will be spent during the remainder of 2001 on currently approved capital projects that will be recorded as property, plant and equipment (the majority of which relate to various pipeline projects such as the Sorrento to Napoleonville pipeline and Port Arthur to Lake Charles system). In addition, the Company estimates that its share of currently approved capital expenditures in the projects of its unconsolidated affiliates will be approximately $1.1 million for the remainder of 2001. As of June 30, 2001, the Company had $11.3 million in outstanding purchase commitments attributable to its capital projects. Of this amount, $10.9 million is related to the construction of assets that will be recorded as property, plant and equipment and $0.4 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. Page 31 Long-term Debt. Long-term debt consisted of the following at: June 30, 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 Unamortized balance of increase in fair value related to hedging a portion of fixed-rate debt 2,015 Less unamortized discount on: $350 Million Senior Notes (135) (153) $450 Million Senior Notes (272) Less current maturities of long-term debt --------------------------------------- Long-term debt $855,608 $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 June 30, 2001 or December 31, 2000. At June 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its $250 Million Multi-Year Credit Facility of which $19.9 million was outstanding. On January 24, 2001, 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 Gas and Gulf of Mexico natural gas pipeline systems 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 Limited Partner through an unsecured and unsubordinated guarantee. The Company was in compliance with the restrictive covenants associated with the $350 Million and $450 Million Senior Notes at June 30, 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. Page 32 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 5 and Note 7 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. Recently Issued Accounting Standards In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001. There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS 142 is effective for fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets recognized in an entity's statement of financial position at that date, regardless of when those assets were initially recognized. The Company is currently evaluating the provisions of SFAS 141 and SFAS 142 and has not adopted such provisions in its June 30, 2001 financial statements. Issuance of last installment of Limited Partner Special Units to Shell On or about June 30, 2001, Shell met certain year 2001 performance criteria for the issuance of the remaining 3.0 million non-distribution bearing, convertible contingency Units of the Limited Partner (referred to as Special Units once they are issued). Per a contingent unit agreement with Shell, the Limited Partner issued these Special Units on August 2, 2001. The value of these new Limited Partner Units was determined to be $117.1 million using present value techniques. This amount will be contributed by the Limited Partner to the Company (with a corresponding contribution by the General Partner to maintain current ownership percentages). This amount will increase the purchase price of the TNGL acquisition and the value of the Shell Processing Agreement when the issuance is recorded during the third quarter of 2001. The $117.1 million increase in value of the Shell Processing Agreement will be amortized over the remaining life of the contract. As a result, the Company's amortization expense is expected to increase by approximately $1.6 million per quarter ($6.5 million annually). 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. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include the level of domestic oil, natural gas and NGL production, the availability of imported oil and natural gas, actions taken by foreign oil and natural gas producing nations, the availability of transportation systems with adequate capacity, Page 33 the availability of alternative fuels and products, seasonal demand for oil, natural gas and NGLs, conservation, the extent of governmental regulation of production and the overall economic environment. In order to 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. As an ancillary service, Acadian Gas utilizes commodity financial instruments to manage the sales price of natural gas for certain of its customers. 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 enters 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 Company assesses the risk of its commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis performed on this portfolio measures the potential gain or loss in earnings (i.e., the change in fair value of the portfolio) based on a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the dates noted within the table. The sensitivity analysis model takes into account the following primary factors and assumptions: o the current quoted market price of natural gas; o the current quoted market price 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 factors and 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. The sensitivity analysis model does not include the impact that the same hypothetical price movement would have on the hedged commodity positions to which they relate. Therefore, the impact on the fair value of the commodity financial instruments of a change in commodity prices would be offset by a corresponding gain or loss on the hedged commodity positions, assuming: o the commodity financial instruments are not closed out in advance of their expected term, o the commodity financial instruments function effectively as hedges of the underlying risk, and o as applicable, anticipated underlying transactions settle as expected. The Company routinely reviews its open commodity financial instruments in light of current market conditions. If market conditions warrant, some instruments may be closed out in advance of their contractual settlement dates thus realizing a gain or loss depending on the specific exposure. When this occurs, the Company may enter into new commodity financial instruments to reestablish the hedge of the commodity position to which the closed instrument relates. Page 34 Under the guidelines of SFAS 133, as amended and interpreted, a hedge is normally regarded as effective if, among other things, at inception and throughout the life of the hedge, the Company could expect changes in the fair value of the hedged item to be almost fully offset by the changes in the fair value of the hedging instrument. Currently, the Company's commodity financial instruments do not qualify as effective hedges under the guidelines of SFAS 133, with the result being that changes in the fair value of these financial instruments are recorded on the balance sheet and in earnings through mark-to-market accounting. The use of mark-to-market accounting for the commodity financial instruments portfolio results in a degree of non-cash earnings volatility that is dependant upon changes in the underlying commodity prices. Even though the commodity financial instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS 133, the Company views these financial instruments as hedges in as much as this was the intent when such contracts are 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. For additional information regarding commodity financial instruments, see Note 7 of the Notes to Unaudited Consolidated Financial Statements. Sensitivity Analysis for Commodity Financial Instruments Portfolio Estimates of Fair Value ("FV") and Earnings Impact ("EI") due to selected changes in quoted market prices at dates selected December June August 31, 2000 30, 2001 7, 2001 ------------------------------------------ (in millions of dollars) ------------------------------------------ FV assuming no change in quoted market prices, Asset (Liability) $(38.6) $ 49.2 $32.7 FV assuming 10% increase in quoted market prices, Asset (Liability) $(56.3) $ 37.4 $24.9 EI assuming 10% increase in quoted market prices, Gain (Loss) $(17.7) $(11.8) $(7.8) FV assuming 10% decrease in quoted market prices, Asset (Liability) $(20.9) $ 61.5 $41.2 EI assuming 10% decrease in quoted market prices, Gain (Loss) $ 17.7 $ 12.3 $ 8.5 The fair value of the commodity financial instruments at December 31, 2000 was estimated at $38.6 million payable. On June 30, 2001, the fair value of the commodity financial instruments outstanding was estimated at $49.2 million receivable. The change in fair value between December 31, 2000 and June 30, 2001 was primarily due to the lower natural gas prices, settlement of certain open positions and a change in the composition of commodities hedged. By August 7, 2001, the fair value of the commodity financial instruments was $32.7 million reflecting the early closeout of certain positions and a further reduction in natural gas prices. Historical 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. Interest rate risk Variable-rate Debt. At March 31, 2001 and 2000, the Company had no variable rate debt outstanding and as such 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. 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. Page 35 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. Sensitivity Analysis for Interest Rate Swap Portfolio Estimates of Fair Value ("FV") and Earnings Impact ("EI") due to selected changes in quoted market prices at dates selected December June August 31, 2000 30, 2001 7, 2001 ------------------------------------------ (Estimates in millions of dollars) ------------------------------------------ FV assuming no change in quoted market prices, Asset (Liability) $ 2.5 $ 7.1 $ 8.8 FV assuming 10% increase in quoted market prices, Asset (Liability) $ 1.9 $ 5.9 $ 7.6 EI assuming 10% increase in quoted market prices, Gain (Loss) $(0.6) $(1.2) $(1.2) FV assuming 10% decrease in quoted market prices, Asset (Liability) $ 3.1 $ 8.4 $ 9.9 EI assuming 10% decrease in quoted market prices, Gain (Loss) $ 0.6 $ 1.3 $ 1.1 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. By June 30, 2001, the notional amount had been 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 June 30, 2001 is primarily related to lower interest rates and the decision by one counterparty not to exercise its early termination right. At August 7, 2001, the fair value of the interest rate swaps was estimated at $8.8 million due to lower interest rates. The Company's interest rate swap agreements were dedesignated as hedging instruments after the 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 (interest expense) using mark-to-market accounting. For additional information regarding the interest rate swaps, see Note 7 of the Notes to Unaudited Consolidated Financial Statements that are part of this Form 10-Q quarterly report. Page 36 Other. At June 30, 2001 and December 31, 2000, the Company had $120.4 million and $58.4 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. Counterparty risk The Company has credit risk from its extension of credit for sales of products and services, and has credit risk with its counterparties in terms of settlement risk and performance risk associated with its commodity financial instruments and interest rate swap agreements. On all transactions where the Company is exposed to credit risk, the Company analyzes the counterparty's financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The counterparty to a majority of the Company's commodity financial instruments is a major Houston, Texas-based energy company. The credit risk to this party is somewhat mitigated by cash or letters of credit held by the Company in an amount dependent upon the exposure to the counterpary. Related Accounting Developments Due to the complexity of SFAS 133, the 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. For additional information regarding SFAS 133, see Note 7 of the Notes to Unaudited Consolidated Financial Statements. 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 and the Limited Partner'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 and 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: Initial payment to finance Acadian Gas acquisition $(226) To finance investment in various Gulf of Mexico natural gas pipelines (112) To finance remainder of the costs to construct certain NGL pipelines and related projects, and for working capital and other general Company purposes (109) -------------- Total uses of funds $(447) ============== Page 37 The initial $226 million payment to Shell for Acadian Gas was made in April 2001, subject to certain post-closing purchase price adjustments. Also, the Company paid EPE $112 million in January 2001 for the purchase of equity interests in four Gulf of Mexico natural gas pipeline systems (Starfish, Ocean Breeze, Neptune and Nemo). Item 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 as 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 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.) +4.2 Contribution Agreement by and 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 "B" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.) ^4.3 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). ^4.4 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). *4.5 $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). *4.6 $150 Million 364-Day Revolving Credit Agreement among 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 38 *4.7 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). *4.8 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). *4.9 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). *4.10 First Amendment to $250 million Multi-Year Revolving Credit Agreement dated April 19, 2001. (Exhibit 4.10 to Form 10-Q filed May 14, 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 among 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 among Sun Company, Inc. (RandM), 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 among 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. (RandM) 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 among 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 among 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 39 ^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 among Tejas Natural Gas Liquids, LLC and Shell Oil Company, Shell Exploration and Production Company, Shell Offshore Inc., Shell Deepwater Development Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas Inc. dated August 1, 1999. (Exhibit 10.14 to Form 10-Q filed on November 15, 1999). ++10.13 Fifth Amendment to Conveyance of Gas Processing Rights dated as of April 1, 2001 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration and Production Company, Shell Offshore, Inc., Shell Consolidated Energy Resources, Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas, Inc. * Incorporated by reference to the filings of the Registrant as indicated ^ Incorporated by reference to the filings of Enterprise Products Partners L.P. as indicated + Incorporated by reference to the filings of Tejas Energy LLC as indicated ++ Filed herewith (b) Reports on Form 8-K The following Form 8-K reports were filed during the quarter ending June 30, 2001: 8-K filed on April 4, 2001. On April 2, 2001, the Company announced that it had completed the purchase of Acadian Gas from an affiliate of Shell. The effective date of the transaction was April 1, 2001. Page 40 Signatures 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 Operating L.P.. (A Delaware Limited Partnership) By: Enterprise Products GP, LLC as General Partner /s/ Michael J. Knesek ______________________________ Vice President, Controller and Date: August 13, 2001 Principal Accounting Officer
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10-Q Filing
Enterprise Products Operating L P Inactive 10-Q2001 Q2 Quarterly report
Filed: 13 Aug 01, 12:00am