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 September 30, 1999 OR |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______ to _______ Commission file number: 1-14323 Enterprise Products Partners L.P. (Exact name of Registrant as specified in its charter) Delaware 76-0568219 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 2727 North Loop West Houston, Texas 77008-1037 (Address of principal executive offices) (Zip code) (713) 880-6500 (Registrant's telephone number including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes _X_ No ___ The registrant had 45,552,915 Common Units outstanding as of November 15, 1999.
Enterprise Products Partners L.P. and Subsidiaries TABLE OF CONTENTS <TABLE> <CAPTION> Page No. <S> <C> Part I. Financial Information Item 1. Consolidated Financial Statements Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements: Consolidated Balance Sheets, September 30, 1999 and December 31, 1998 1 Statements of Consolidated Operations for the Three and Nine Months ended September 30, 1999 and 1998 2 Statements of Consolidated Cash Flows for the Nine Months ended September 30, 1999 and 1998 3 Notes to Unaudited Consolidated Financial Statements 4-12 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 13-27 Item 3. Quantitative and Qualitative Disclosures about Market Risk 27-28 Part II. Other Information Item 6. Exhibits and Reports on Form 8-K 29-32 Signature Page 33 </TABLE>
PART 1. FINANCIAL INFORMATION. Item 1. CONSOLIDATED FINANCIAL STATEMENTS. Enterprise Products Partners L.P. Consolidated Balance Sheets (Amounts in thousands) <TABLE> <CAPTION> September 30, December 31, 1999 ASSETS 1998 (Unaudited) ------------------------------------- <S> <C> <C> Current Assets Cash and cash equivalents $ 24,103 $ 21,647 Accounts receivable - trade 57,288 187,615 Accounts receivable - affiliates 15,546 50,562 Inventories 17,574 102,992 Current maturities of participation in notes receivable from unconsolidated affiliates 14,737 9,778 Prepaid and other current assets 8,445 11,283 ------------------------------------- Total current assets 137,693 383,877 Property, Plant and Equipment, Net 499,793 772,157 Investments in and Advances to Unconsolidated Affiliates 91,121 235,864 Participation in Notes Receivable from Unconsolidated Affiliates 11,760 Intangible assets, net of amortization of $702 79,187 Other Assets 670 1,515 ===================================== Total $ 741,037 $ 1,472,600 ===================================== LIABILITIES AND PARTNERS' EQUITY Current Liabilities Current maturities of long-term debt $ 175,000 Accounts payable - trade $ 36,586 139,851 Accrued gas payables 27,183 143,397 Accrued expenses 7,540 13,071 Other current liabilities 11,462 15,017 ------------------------------------- Total current liabilities 82,771 486,336 Long-Term Debt 90,000 215,000 Other Long-Term Liabilities 539 Minority Interest 5,730 7,801 Commitments and Contingencies Partners' Equity Common Units (45,552,915 Units outstanding at December 31, 1998 and September 30, 1999) 433,082 417,651 Subordinated Units (21,409,870 Units outstanding at December 31, 1998 and 123,829 126,496 September 30, 1999) Special Units (14,500,000 Units outstanding at September 30, 1999) 215,828 Units acquired by Trust, at cost (267,200 Units outstanding at September 30, 1999) (4,727) General Partner 5,625 7,676 ------------------------------------- Total Partners' Equity 562,536 762,924 ===================================== Total $ 741,037 $ 1,472,600 ===================================== </TABLE> See Notes to Unaudited Consolidated Financial Statements 1
Enterprise Products Partners L.P. Statements of Consolidated Operations (Unaudited, Amounts in thousands, except per Unit amounts) <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 1998 1999 1998 1999 -------------------------------------------------------------------- <S> <C> <C> <C> <C> REVENUES Revenues from consolidated operations $ 164,620 $ 441,880 $ 562,703 $ 763,793 Equity income in unconsolidated affiliates 4,171 3,148 10,824 7,591 -------------------------------------------------------------------- Total 168,791 445,028 573,527 771,384 -------------------------------------------------------------------- COST AND EXPENSES Operating costs and expenses 153,197 401,155 521,428 688,250 Selling, general and administrative 3,751 3,200 15,362 9,200 -------------------------------------------------------------------- Total 156,948 404,355 536,790 697,450 -------------------------------------------------------------------- OPERATING INCOME 11,843 40,673 36,737 73,934 -------------------------------------------------------------------- OTHER INCOME (EXPENSE) Interest expense (2,500) (4,036) (13,304) (7,995) Interest income from unconsolidated affiliates 340 407 340 1,096 Interest income - other 85 682 645 1,114 Other, net 34 (1,010) 464 (1,522) -------------------------------------------------------------------- Other income (expense) (2,041) (3,957) (11,855) (7,307) -------------------------------------------------------------------- INCOME BEFORE EXTRAORDINARY ITEM AND MINORITY INTEREST 9,802 36,716 24,882 66,627 Extraordinary charge on early extinguishment of debt (27,176) (27,176) -------------------------------------------------------------------- INCOME (LOSS) BEFORE MINORITY INTEREST (17,374) 36,716 (2,294) 66,627 MINORITY INTEREST 174 (370) 23 (672) ==================================================================== NET INCOME (LOSS) $ (17,200) $ 36,346 $ (2,271) $ 65,955 ==================================================================== ALLOCATION OF NET INCOME (LOSS) TO: Limited partners $ (17,028) $ 35,983 $ (2,248) $ 65,295 ==================================================================== General partner $ (172) $ 363 $ (23) $ 660 ==================================================================== Number of Units Used in Computing Basic Earnings per Common Unit 63,441 66,696 57,830 66,715 ==================================================================== BASIC EARNINGS PER COMMON UNIT Income before extraordinary item and minority interest per common unit $ 0.15 $ 0.54 $ 0.43 $ 0.99 ==================================================================== Net income (loss) per common unit $ (0.27) $ 0.54 $ (0.04) $ 0.98 ==================================================================== Number of Units Used in Computing Diluted Earnings per Common Unit 63,441 76,310 57,830 69,955 ==================================================================== DILUTED EARNINGS PER COMMON UNIT Income before extraordinary item and minority interest per common unit $ 0.15 $ 0.48 $ 0.43 $ 0.94 ==================================================================== Net income (loss) per common unit $ (0.27) $ 0.47 $ (0.04) $ 0.93 ==================================================================== </TABLE> See Notes to Unaudited Consolidated Financial Statements 2
Enterprise Products Partners L.P Statements of Consolidated Cash Flows (Unaudited, Dollars in Thousands) <TABLE> <CAPTION> Nine Months Ended September 30, 1998 1999 ----------------------------- <S> <C> <C> OPERATING ACTIVITIES Net income (loss) ($2,271) $65,955 Adjustments to reconcile net income (loss) to cash flows provided by (used for) operating activities: Extraordinary item - early extinguishment of debt 27,176 Depreciation and amortization 14,796 17,280 Equity in income of unconsolidated affiliates (10,824) (7,591) Leases paid by EPCO 3,327 7,918 Minority interest (23) 672 (Gain) loss on sale of assets (274) 122 Net effect of changes in operating accounts (75,824) (34,246) ----------------------------- Operating activities cash flows (43,917) 50,110 ----------------------------- INVESTING ACTIVITIES Capital expenditures (7,159) (10,603) Proceeds from sale of assets 1,890 8 Acquisitions (208,095) Participation in notes receivable from unconsolidated affiliates: Purchase of notes receivable (33,724) Collection of notes receivable 3,542 16,719 Unconsolidated affiliates: Investments in and advances to (19,988) (58,460) Distributions received 6,601 4,607 ----------------------------- Investing activities cash flows (48,838) (255,824) ----------------------------- FINANCING ACTIVITIES Net proceeds from sale of common units 243,309 Long-term debt borrowings 75,000 350,000 Long-term debt repayments (256,493) (59,923) Net decrease in restricted cash 4,522 Cash dividends paid to partners (81,321) Cash dividends paid to minority interest (830) Units acquired by consolidated trusts (4,727) Cash contributions from EPCO to minority interest 59 ----------------------------- Financing activities cash flows 66,338 203,258 ----------------------------- CASH CONTRIBUTIONS FROM EPCO 18,468 NET CHANGE IN CASH AND CASH EQUIVALENTS (7,949) (2,456) CASH AND CASH EQUIVALENTS, JANUARY 1 18,941 24,103 ============================= CASH AND CASH EQUIVALENTS, SEPTEMBER 30 $ 10,992 $ 21,647 ============================= </TABLE> See Notes to Unaudited Consolidated Financial Statements 3
Enterprise Products Partners L.P. Notes to Consolidated Financial Statements (Unaudited) 1. GENERAL In the opinion of Enterprise Products Partners L.P. (the "Company"), the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of the Company's consolidated financial position as of September 30, 1999, consolidated results of operations for the three and nine month periods ended September 30, 1999 and 1998, and its consolidated cash flows for the nine month periods ended September 30, 1999 and 1998. Although the Company believes the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. These unaudited financial statements should be read in conjunction with the financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 1998 ("Form 10-K"). The results of operations for the three and nine month periods ended September 30, 1999 are not necessarily indicative of the results to be expected for the full year. 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 At September 30, 1999, the Company's significant unconsolidated affiliates accounted for by the equity method included the following: Belvieu Environmental Fuels ("BEF") - a 33-1/3% economic interest in a Methyl Tertiary Butyl Ether ("MTBE") production facility located in southeast Texas. Baton Rouge Fractionators LLC ("BRF") - a 31.25% economic interest in a natural gas liquid ("NGL") fractionation facility located in southeastern Louisiana. Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% economic interest in a propylene concentration unit located in southeastern Louisiana which is under construction and scheduled to become operational in the third quarter of 2000. EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate economic interest in a refrigerated NGL marine terminal loading facility located in southeast Texas. Wilprise Pipeline Company, LLC ("Wilprise") - a 33-1/3% economic interest in a NGL pipeline system located in southeastern Louisiana. Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33-1/3% economic interest in a NGL pipeline system located in Louisiana, Mississippi, and Alabama. In connection with the Tejas Natural Gas Liquids, LLC ("TNGL") acquisition (discussed in Note 3) the Company acquired an additional 16-2/3% interest bringing the total investment in Tri-States to the current 33-1/3%. Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.7% economic interest in a NGL pipeline system located in south Louisiana. The Company's interest in Belle Rose was acquired in connection with the TNGL acquisition which is discussed in Note 3. 4
K/D/S Promix LLC ("Promix") - a 33-1/3% economic interest in a NGL fractionation facility and related storage facilities located in south Louisiana. The Company's interest in Promix was acquired in connection with the TNGL acquisition which is discussed in Note 3. The Company's investments in and advances to unconsolidated affiliates also includes Venice Energy Services Company, LLC ("VESCO") and Dixie Pipeline Company ("Dixie"). The VESCO investment consists of a 13.1% economic interest in a LLC owning a natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in Louisiana. The Dixie investment consists of an 11.5% interest in a corporation owning a 1,300-mile propane pipeline and the associated facilities extending from Mont Belvieu, Texas to North Carolina. These investments are accounted for using the cost method in accordance with generally accepted accounting principles. Effective July 1, 1999, a subsidiary of Enterprise Products Operating L.P. (the "Operating Partnership") acquired the remaining 51% economic interest of Mont Belvieu Associates ("MBA") from Kinder Morgan Energy Partners L.P. ("Kinder Morgan") and Enterprise Products Company ("EPCO") (see Note 3 for a general discussion regarding this acquisition). As a consequence, the results of operations since July 1, 1999 are included in consolidated operations. The 49% economic interest in income of MBA held by the Company prior to the acquisition was recorded as equity income. In conjunction with the acquisition of TNGL from Tejas Energy, LLC ("Tejas Energy") effective August 1, 1999, the Company currently owns 100% of the economic interest in Entell NGL Services, LLC ("Entell") (see Note 3 for a general discussion regarding the TNGL acquisition). As a result, Entell is now a wholly-owned subsidiary of the Operating Partnership. The Operating Partnership's 50% economic interest in the income of Entell prior to the acquisition has been recorded as equity income. Investments in and advances to unconsolidated affiliates at: December 31, September 30, 1998 1999 ----------------------------------- BEF $ 50,079 $ 56,493 MBA 12,551 BRF 17,896 34,656 BRPC 8,400 EPIK 5,667 12,974 Wilprise 4,873 8,063 Tri-States 55 28,324 Promix 29,590 Dixie 20,000 VESCO 25,000 Belle Rose 12,364 =================================== Total $ 91,121 $ 235,864 =================================== 5
Equity in income of unconsolidated affiliates for the: Three Months ended Nine Months ended September 30, September 30, 1998 1999 1998 1999 ------------------------------------------------------------------ BEF $ 3,355 $ 2,519 $ 6,609 $ 4,756 MBA 862 72 4,305 1,256 BRF (258) (544) BRPC 4 4 EPIK (46) 59 (90) 236 Entell 258 1,389 Wilprise (130) (130) Tri-States 472 472 Belle Rose 245 245 Promix (93) (93) ================================================================== Total $ 4,171 $ 3,148 $ 10,824 $ 7,591 ================================================================== 3. ACQUISITIONS Acquisition of Tejas Natural Gas Liquids, LLC Effective August 1, 1999, the Company acquired TNGL from a subsidiary of Tejas Energy, an affiliate of Shell Oil Company ("Shell"). TNGL engages in natural gas processing and NGL fractionation, transportation, storage and marketing in Louisiana and Mississippi. TNGL's assets include a 20-year natural gas processing agreement with Shell for the rights to process its current and future natural gas production from the state and federal waters of the Gulf of Mexico and varying interests in eleven natural gas processing plants (including one under construction) with a combined gross capacity of 11.0 billion cubic feet per day (Bcfd) and a net capacity of 3.1 Bcfd; four NGL fractionation facilities with a combined gross capacity of 281,000 barrels per day (BPD) and net capacity of 131,500 BPD; four NGL storage facilities with approximately 29.5 million barrels of gross capacity and 8.8 million barrels of net capacity; and over 2,100 miles of NGL pipelines (including an 11.5% interest in Dixie Pipeline). As discussed in Note 5, the TNGL acquisition was purchased with a combination of $166 million in cash and 14.5 million issuance of non-distribution bearing convertible Special Units. The $166 million cash portion of the purchase price was funded with borrowings under the Company's new $350 million bank credit facility led by The Chase Manhattan Bank. The Special Units were valued within a range provided by an independent investment banker using both present value and Black Scholes Model methodologies. The consideration for the acquisition was determined by arms-length negotiation among the parties. The acquisition was accounted for under the purchase method of accounting and, accordingly, the purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated fair value at August 1, 1999 as follows: Current Assets $127.5 Investments 97.7 Property, net 225.8 Intangible asset 71.1 Liabilities (145.7) ========== Total purchase price $ 376.3 ========== 6
The $71.1 million intangible asset is associated with the 20-year natural gas processing agreement with Shell ("Shell Contract") and is being amortized over a period of 20 years, approximating the life of the agreement. For the quarter ending September 30, 1999, approximately $0.6 million of such amortization was charged to expense. The assets, liabilities and results of operations of TNGL are included with those of the Company as of August 1, 1999. Historical information for periods prior to August 1, 1999 do not reflect any impact associated with the TNGL acquisition. As described in Note 5, Tejas Energy has the opportunity to earn an additional 6.0 million non-distribution bearing, convertible special Contingency Units over the next two years upon the achievement of certain gas production thresholds under the Shell Contract. If such special Contingency Units are issued, the purchase price will be adjusted accordingly. Acquisition of Kinder Morgan and EPCO interest in Mont Belvieu Fractionation Facility Effective July 1, 1999, the Company acquired Kinder Morgan Energy Partners L.P.'s ("Kinder Morgan") 25% indirect ownership interest and EPCO's 0.5% indirect ownership interest in a 210,000 BPD NGL fractionation facility located in Mont Belvieu, Texas for approximately $41 million in cash and the assumption of approximately $ 4 million of debt. The $41 million in cash was funded with borrowings under the Company's new $350 million bank credit facility led by The Chase Manhattan Bank. The acquisition was accounted for under the purchase method of accounting and, accordingly, the purchase price has been allocated to the assets purchased and liabilities assumed based on their estimated fair value at July 1, 1999 as follows: Property, net $36.3 Intangible asset 8.7 Liabilities (3.8) ========== Total purchase price $ 41.2 ========== The intangible asset represents the excess cost of purchase price over the fair market value of the assets acquired and is being amortized over 20 years. For the quarter ending September 30, 1999, approximately $0.1 million of such amortization was charged to expense. Prior to this transaction, the Company held a 25% indirect and a 12.5% direct ownership interest in the fractionation facility. The indirect ownership interests of the Company, Kinder Morgan and EPCO were held through MBA. Prior to the acquisition, the 12.5% direct ownership interest and the 49% equity ownership of MBA were held by Enterprise Products Texas Operating L.P. ("EPTexas"). Upon completion of the transaction, EPTexas held 100% of MBA and, as a result, MBA was merged into EPTexas. The net assets and results of operations of MBA are included with those of EPTexas beginning with the July 1, 1999 acquisition date. Historical information for periods prior to July 1, 1999 does not reflect any impact associated with the acquisition of the Mont Belvieu Fractionation Facility. The Company's equity in the earnings of MBA prior to July 1, 1999 is included in equity in income of unconsolidated affiliates. Pro Forma Financial Information The balances included in the consolidated balance sheets related to the current year acquisitions are based upon preliminary information and are subject to change as additional information is obtained. Material changes in the preliminary allocations are not anticipated by management. The following pro forma information gives effect to the acquisition of TNGL and MBA as if the business combination had occurred at the beginning of each period presented. The pro forma adjustments which have been made are based on the preliminary allocation of the purchase price to assets acquired and liabilities 7
assumed. This pro forma information should be read in conjunction with the accompanying interim Consolidated Financial Statements, Management's Discussion and Analysis of Financial Condition and Results of Operations. This pro forma information is not necessarily indicative of the financial results which would have occurred had the acquisition taken place on the dates indicated, nor is it necessarily indicative of future financial results. <TABLE> <CAPTION> Three Months Ended Nine Months Ended (Amounts in millions) September 30, September 30, 1998 1999 1998 1999 ----------------------------------------------------------------------- <S> <C> <C> <C> <C> Unaudited Pro Forma Financial Information Revenues $ 282.6 $ 505.7 $ 1,043.9 $ 1,153.7 Income before extraordinary items 0.6 40.8 29.0 78.0 Net Income (26.6) 40.8 1.9 78.0 Earnings per Unit: Basic $ (0.40) $ 0.61 $ 0.03 $ 1.17 Diluted $ (0.33) $ 0.50 $ 0.02 $ 0.96 </TABLE> 4. LONG-TERM DEBT Existing Bank Credit facility. In July 1998, the Operating Partnership entered into a $200.0 million bank credit facility ("Bank Revolver A") that includes a $50.0 million working capital facility and a $150.0 million revolving term loan facility. The $150.0 million revolving term loan facility includes a sublimit of $30.0 million for letters of credit. As of September 30, 1999, the Company has borrowed $175.0 million under the bank credit facility which is due in July 2000. Management is currently exploring options to convert this short-term debt into long-term debt. The Company's obligations under the bank credit facility are unsecured general obligations and are non-recourse to the General Partner. Borrowings under the bank credit facility will bear interest at either the bank's prime rate or the Eurodollar rate plus the applicable margin as defined in the facility. The bank credit facility will expire in July 2000 and all amounts borrowed thereunder shall be due and payable at that time. There must be no amount outstanding under the working capital facility for at least 15 consecutive days during each fiscal year. As amended on July 28, 1999, the existing credit agreement relating to the facility contains a prohibition on distributions on, or purchases or redemptions of, Units if any event of default is continuing. In addition, the bank credit facility contains various affirmative and negative covenants applicable to the ability of the Company to, among other things, (i) incur certain additional indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) make investments, (v) engage in transactions with affiliates and (vi) enter into a merger, consolidation or sale of assets. The bank credit facility requires that the Operating Partnership satisfy the following financial covenants at the end of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined in the bank credit facility) of at least $250.0 million, (ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to Consolidated Interest Expense (as defined in the bank credit facility) for the previous 12-month period of at least 3.5 to 1.0 and (iii) maintain a ratio of Total Indebtedness (as defined in the bank credit facility) to EBITDA of no more than 3.0 to 1.0. A "Change of Control" constitutes an Event of Default under the bank credit facility. A Change of Control includes any of the following events: (i) Dan L. Duncan (and/or certain affiliates) cease to own (a) at least 51% (on a fully converted, fully diluted basis) of the economic interest in the capital stock of EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own, through a wholly owned subsidiary, at least 65% of the outstanding membership interest in the General Partner and at least a majority of the outstanding Common Units; (iii) any person or group beneficially owns more than 20% of the outstanding Common Units (excluding certain affiliates of EPCO or Shell Oil Company); (iv) the General Partner ceases to be the general partner of the Company or the Operating Partnership; or (v) the Company ceases to be the sole limited partner of the Operating Partnership. New Bank Credit facility. On July 28, 1999, the Operating Partnership entered into a $350.0 million bank credit facility ("Bank Revolver B") that includes a 8
$50.0 million working capital facility and a $300.0 million revolving term loan facility. The $300.0 million revolving term loan facility includes a sublimit of $10.0 million for letters of credit. The proceeds of this loan were used to finance the acquisition of TNGL and the MBA ownership interests. Future uses of the remaining credit line include the purchase of the Lou-Tex pipeline (see Note 10). Borrowings under the bank credit facility will bear interest at either the bank's prime rate or the Eurodollar rate plus the applicable margin as defined in the facility. The bank credit facility will expire in July 2001 and all amounts borrowed thereunder shall be due and payable at that time. There must be no amount outstanding under the working capital facility for at least 15 consecutive days during each fiscal year. The credit agreement relating to the new facility contains a prohibition on distributions on, or purchases or redemptions of Units if any event of default is continuing. In addition, the bank credit facility contains various affirmative and negative covenants applicable to the ability of the Company to, among other things, (i) incur certain additional indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) make investments, (v) engage in transactions with affiliates and (vi) enter into a merger, consolidation, or sale of assets. The bank credit facility requires that the Operating Partnership satisfy the following financial covenants at the end of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined in the bank credit facility) of at least $250.0 million, (ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to Consolidated Interest Expense (as defined in the bank credit facility) for the previous 12-month period of at least 3.5 to 1.0 and (iii) maintain a ratio of Total Indebtedness (as defined in the bank credit facility) to EBITDA of no more than 3.0 to 1.0. A "Change of Control" constitutes an Event of Default under the bank credit facility. A Change of Control includes any of the following events: (i) Dan L. Duncan (and/or certain affiliates) cease to own (a) at least 51% (on a fully converted, fully diluted basis) of the economic interest in the capital stock of EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own, through a wholly owned subsidiary, at least 65% of the outstanding membership interest in the General Partner and at least a majority of the outstanding Common Units; (iii) any person or group beneficially owns more than 20% of the outstanding Common Units (excluding certain affiliates of EPCO and Shell Oil Company); (iv) the General Partner ceases to be the general partner of the Company or the Operating Partnership; or (v) the Company ceases to be the sole limited partner of the Operating Partnership. Long-term debt consisted of the following: September 30, December 31, 1999 1998 (Unaudited) ------------------------------------- Bank Revolver A $90,000 $175,000 Bank Revolver B 215,000 ------------------------------------- Total 90,000 390,000 Less current maturities of long-term debt (175,000) ===================================== Long-term debt $90,000 $215,000 ===================================== 5. CAPITAL STRUCTURE At September 30, 1999, the Company had 33,552,915 Common Units and 21,409,870 Subordinated Units outstanding held by EPCO (the Company's ultimate parent), 12,000,000 Common Units outstanding held by third parties, and 14,500,000 non-distribution bearing, convertible Special Units held by Tejas Energy. During the first quarter of 1999, the Company established a revocable grantor trust (the "Trust") to fund future liabilities of a long-term incentive plan. At September 30, 1999, the Trust had purchased a total of 267,200 Common Units (the "Trust Units") which are accounted for in a manner similar to treasury stock under the cost method of accounting. The Trust Units are considered outstanding and will receive distributions; however, they are excluded from the calculation of net income per Unit in accordance with generally accepted accounting principles. 9
On August 1, 1999, in exchange for its NGL business (see Note 3), Tejas Energy received 14.5 million non-distribution bearing, convertible Special Units in the Company and $166 million in cash. The 14.5 million non-distribution bearing, convertible Special Units received by Tejas Energy represent an approximate 17.6% equity ownership in the Company. These convertible Special Units do not accrue distributions and are not entitled to cash distributions until their conversion into Common Units, which occurs automatically with respect to 1.0 million Units on August 1, 2000 (or the day following the record date for determining units entitled to receive distributions in the second quarter of 2000), 5.0 million Units on August 1, 2001 and 8.5 million Units on August 1, 2002. Tejas Energy has the opportunity to earn an additional 6 million non-distribution bearing, convertible Contingency Units over the next two years based on certain performance criteria. Shell will earn 3 million convertible Contingency Units if at any point during calendar year 2000 (or extensions thereto due to force majeure events), gas production by Shell from its offshore Gulf of Mexico producing properties and leases is 950 million cubic feet per day for 180 not-necessarily-consecutive days or 375 billion cubic feet on a cumulative basis. Shell will earn another 3 million convertible Contingency Units if at any point during calendar year 2001 (or extensions thereto due to force majuere events) such gas production is 900 million cubic feet per day for 180 not-necessarily-consecutive days or 350 billion cubic feet on a cumulative basis. If either or both of the preceding performance tests is not met but Shell's Offshore Gulf of Mexico gas production reaches 725 billion cubic feet on a cumulative basis in calendar years 2000 and 2001 (or extensions thereto due to force majuere events), Shell would still earn 6 million non-distribution bearing, convertible Contingency Units. If all of the Contingency Units are earned, 1 million Contingency Units would convert into Common Units on August 1, 2002 and 5 million Contingency Units would convert into Common Units on August 1, 2003. The Contingency Units do not accrue distributions and are not entitled to cash distributions until conversion into Common Units. Tejas Energy's ownership interest in the Company would then increase to approximately 23.2%. Under the rules of the New York Stock Exchange, conversion of the Special Units into Common Units requires approval of the Company's Unitholders. The General Partner has agreed to call a special meeting of the Unitholders for the purpose of soliciting such approval. EPC Partners II, Inc. ("EPC II"), which owns in excess of 81% of the outstanding Common Units, has agreed to vote its Units in favor of such approval, which will satisfy the approval requirement. 6. DISTRIBUTIONS On January 12, 1999, the Company declared a quarterly distribution of $.45 per Unit for the fourth quarter of 1998, which was paid on February 11, 1999 to all Unitholders of record on January 29, 1999. The Company declared its distribution for the first quarter of 1999 on April 16, 1999 in the amount of $.45 per Common Unit. The first quarter 1999 distribution was paid on May 12, 1999 to Common Unitholders of record on April 30, 1999. The Company declared a $.45 per Common Unit distribution for the second quarter of 1999 on July 16, 1999. The second quarter 1999 distribution was paid on August 11, 1999 to Common Unitholders of record on July 30, 1999. The third quarter 1999 distribution of $.45 per Unit was declared on October 15, 1999 and was paid on November 10, 1999 to all Unitholders of record at the close of business on October 29, 1999. 10
7. SUPPLEMENTAL CASH FLOW DISCLOSURE The net effect of changes in operating assets and liabilities is as follows: Nine Months Ended September 30, 1998 1999 -------------------------------- (Increase) decrease in: Accounts receivable $ 19,879 $ (48,448) Inventories (41,985) (64,992) Prepaid and other current assets (550) (4,647) Other assets (494) (1,757) Increase (decrease) in: Accounts payable - trade (27,255) 43,944 Accrued gas payable (8,437) 61,474 Accrued expenses (4,503) 1,236 Other current liabilities (12,479) (21,595) Other liabilities 539 ================================ Net effect of changes in operating accounts $ (75,824) $ (34,246) ================================ 8. RECENTLY ISSUED ACCOUNTING STANDARDS On June 6, 1999, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133-an amendment of FASB Statement No. 133" which effectively delays and amends the application of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" for one year, to fiscal years beginning after June 15, 2000. Management is currently studying both SFAS No. 137 and SFAS No. 133 for possible impact on the consolidated financial statements. On April 3, 1998, the American Institute of Certified Public Accountants issued Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up Activities." For years beginning after December 15, 1998, SOP 98-5 generally requires that all start-up costs of a business activity be charged to expense as incurred and any start-up costs previously deferred should be written off as a cumulative effect of a change in accounting principle. Adoption of SOP 98-5 during 1999 did not have a material impact on the consolidated financial statements except for a $4.5 million noncash write-off that occurred on January 1, 1999 of the unamortized balance of deferred start-up costs of BEF, in which the Company owns a 33-1/3% interest. This write-off caused a $1.5 million reduction in the equity in income of unconsolidated affiliates for 1999 and a corresponding reduction in the Company's investment in unconsolidated affiliates. 9. CONCENTRATION OF CREDIT RISK A substantial portion of the Company's revenues are derived from natural gas processing and the fractionation, isomerization, propylene production, marketing, storage and transportation of NGLs to various companies in the NGL industry, primarily located in the United States. Although this concentration could affect the Company's overall exposure to credit risk since these customers might be affected by similar economic or other conditions, management believes the Company is exposed to minimal credit risk, since the majority of its business is conducted with major companies within the industry and much of the business is conducted with companies with whom the Company has joint operations. The Company generally does not require collateral for its accounts receivable. 11
The Company is subject to a number of risks inherent in the industry in which it operates, primarily fluctuating gas and liquids prices and gas supply. The Company's financial condition and results of operations will depend significantly on the prices received for NGLs and the price paid for gas consumed in the NGL extraction process. These prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the control of the Company. In addition, the Company must continually connect new wells through third-party gathering systems which serve the gas plants in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of wells drilled by third parties will depend on, among other factors, the price of gas and oil, the energy policy of the federal government, and the availability of foreign oil and gas, none of which is in the Company's control. 10. SUBSEQUENT EVENT Purchase of Lou-Tex Pipeline On July 27, 1999, the Company announced the execution of a letter of intent to acquire a Louisiana and Texas pipeline asset from Concha Chemical Pipeline Company ("Concha"), an affiliate of Shell, for an undisclosed amount of cash. The pipeline being acquired, referred to as the Lou-Tex pipeline, is 263 miles of 10" pipeline from Sorrento, Louisiana to Mont Belvieu, Texas. The Lou-Tex pipeline is currently dedicated to the transportation of chemical grade propylene from Sorrento to the Mont Belvieu area. The acquisition of the Lou-Tex pipeline is the first step in the Company's development of a $210 million, 160,000 barrel per day gas liquids pipeline system. This larger system will link growing supplies of NGLs produced in Louisiana and Mississippi with the principal NGL markets on the United States Gulf Coast. The completion of the Lou-Tex transaction is subject to the successful negotiation of definitive agreements, approval of those agreements by the respective managements and regulatory approvals. This purchase of the pipeline asset from Concha is expected to be completed in the fourth quarter of 1999. The development of the expanded Lou-Tex gas liquids pipeline system is expected to be completed in the second half of 2000. 12
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. For the Interim Periods ended September 30, 1999 and 1998 The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Enterprise Products Partners L.P. ("Enterprise" or the "Company") included elsewhere herein. The Company The Company is a leading integrated North American provider of processing and transportation services to domestic and foreign producers of natural gas liquids ("NGLs") and other liquid hydrocarbons and domestic and foreign consumers of NGLs and liquid hydrocarbon products. The Company manages a fully integrated and diversified portfolio of midstream energy assets and is engaged in NGL processing and transportation through direct and indirect ownership and operation of NGL fractionators. It also manages NGL processing facilities, storage facilities, pipelines, and rail transportation facilities, and methyl tertiary butyl ether ("MTBE") and propylene production and transportation facilities in which it has a direct and indirect ownership. As a result of the recent Tejas Natural Gas Liquids, LLC ("TNGL") acquisition described below, the Company is also engaged in natural gas processing in Louisiana and Mississippi. The Company is a publicly traded master limited partnership (NYSE, symbol "EPD") that conducts substantially all of its business through Enterprise Products Operating L.P. (the "Operating Partnership"), the Operating Partnership's subsidiaries, and a number of joint ventures with industry partners. The Company was formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise Products Company ("EPCO"). The principal executive office of the Company is located at 2727 North Loop West, Houston, Texas, 77008-1038, and the telephone number of that office is 713-880-6500. References to, or descriptions of, assets and operations of the Company in this quarterly report include the assets and operations of the Operating Partnership and its subsidiaries as well as the predecessors of the Company. General The Company (i) processes natural gas; (ii) fractionates 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; (iii) converts normal butane to isobutane through the process of isomerization; (iv) produces MTBE from isobutane and methanol; and (v) transports NGL products to end users by pipeline and railcar. The Company also separates high purity propylene from refinery-sourced propane/propylene mix and transports high purity propylene to plastics manufacturers by pipeline. 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. The Company's NGL processing operations are concentrated in the Texas, Louisiana, and Mississippi Gulf Coast area. A large portion is concentrated 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 we operate at Mont Belvieu include: (i) one of the largest NGL fractionation facilities in the United States with an average production capacity of 210,000 barrels per day; (ii) the largest butane isomerization complex in the United States with an average isobutane production capacity of 80,000 barrels per day; (iii) one of the largest MTBE production facilities in the United States with an average production capacity of 14,800 barrels per day; and (iv) two propylene fractionation units with an average combined production capacity of 31,000 barrels per day. 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% economic interest (see Recent Acquisitions below); 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 33-1/3% interest; and one of its three isomerization units and one deisobutanizer which are held under long-term leases with purchase options. The Company also owns and operates 13
approximately 35 million barrels of storage capacity at Mont Belvieu and elsewhere that are an integral part of its processing operations, a network of approximately 500 miles of pipelines along the Gulf Coast and a NGL fractionation facility in Petal, Mississippi with an average production capacity of 7,000 barrels per day. The Company also leases and operates one of only two commercial NGL import/export terminals on the Gulf Coast. As a result of the Tejas Natural Gas Liquids, LLC ("TNGL") acquisition, the Company acquired, effective August 1, 1999, a 20-year natural gas processing agreement with Shell Oil Company ("Shell") for the rights to process its current and future natural gas production from the state and federal waters of the Gulf of Mexico and varying interests in 11 natural gas processing plants (including one under construction) with a combined gross capacity of 11.0 billion cubic feet per day ("Bcfd") and net capacity of 3.1 Bcfd; four NGL fractionation facilities with a combined gross capacity of 281,000 BPD and net capacity of 131,500 BPD; four NGL storage facilities with approximately 29.5 million barrels of gross capacity and 8.8 million barrels of net capacity; and over 2,100 miles of NGL pipelines (including a 11.5% interest in Dixie Pipeline). Recent Acquisitions Tejas Natural Gas Liquids, LLC. As noted above, effective August 1, 1999, the Company acquired TNGL from Tejas Energy, LLC ("Tejas Energy"), an affiliate of Shell, in exchange for 14.5 million non-distribution bearing, convertible special partner units of the Company and a cash payment of $166 million. The Company has also agreed to issue up to 6.0 million non-distribution bearing, convertible special units to Tejas Energy in the future if the volumes of natural gas that the Company processes for Shell and its affiliates reach certain agreed upon levels in 2000 and 2001. The businesses acquired from Tejas Energy include natural gas processing and NGL fractionation, transportation and storage in Louisiana and Mississippi and its NGL supply and marketing business. As described in General above, the assets acquired include varying interests in 11 natural gas processing plants, four NGL fractionation facilities, four NGL storage facilities and over 2,100 miles of NGL pipelines. The Company's major customer related to the TNGL assets is Shell. Under the terms of a 20-year processing agreement with Shell, the Company has the right to process substantially all of Shell's current and future natural gas production from the Gulf of Mexico. This includes natural gas production from the developments currently referred to as deepwater. Natural gas processing plants are generally located near the production area. When produced at the wellhead, natural gas generally must be processed to separate the merchantable, pipeline quality natural gas (principally methane), from NGLs and other impurities. Wet or rich natural gas normally must be processed to render the natural gas acceptable for transport in the nation's pipeline system and to meet specifications required by local natural gas distribution companies. After being extracted in the field, mixed NGLs, sometimes referred to as "y-grade" or "raw make" are typically transported to a central facility for fractionation and subsequent sale. Mont Belvieu NGL Fractionation facility. Effective July 1, 1999, a subsidiary of the Operating Partnership acquired an additional 25% interest in the Mont Belvieu NGL fractionation facility from Kinder Morgan for a purchase price of approximately $41 million in cash and the assumption of $4 million in debt. An additional 0.5% interest in the same facility was purchased from EPCO for a cash purchase price of $0.9 million. These acquisitions increased our effective economic interest in the Mont Belvieu NGL fractionation facility from 37.0% to 62.5%. Industry Environment Because certain NGL products compete with other refined petroleum products in the fuel and petrochemical feedstock markets, NGL product prices are set by or in competition with refined petroleum products. Increased production and importation of NGLs and NGL products in the United States may decrease NGL product prices in relation to refined petroleum alternatives and thereby increase consumption of NGL products as NGL products are substituted for other more expensive refined petroleum products. Conversely, a decrease in the production and importation of NGLs and NGL products could increase NGL product prices in relation to refined petroleum product prices and thereby decrease consumption of NGLs. However, because of the relationship of crude oil and natural gas production to NGL production, the Company believes any imbalance in the prices of NGLs and NGL products and alternative products would be temporary. 14
Historically, when the price of crude oil is a multiple of ten or more to the price of natural gas (i.e., crude oil $20 per barrel and natural gas $2 per thousand cubic feet ("MCF")), NGL pricing has been strong due to increased use in manufacturing petrochemicals. In 1998, the industry experienced an annualized multiple of approximately six (i.e., crude oil $12 per barrel and natural gas $2 per MCF), which caused petrochemical manufacturing demand to change from reliance on NGLs to a preference for crude oil derivatives. This change resulted in the lowering of both the production and pricing of NGLs. In the NGL industry, revenues and cost of goods sold can fluctuate significantly up or down based on current NGL prices. However, operating margins will generally remain constant except for the effect of inventory price adjustments or increased operating expenses. NGL Fractionation The profitability of this business unit depends on the volume of mixed NGLs that the Company processes for its toll customers and the level of toll processing fees charged to its customers. The most significant variable cost of fractionation is the cost of energy required to operate the units and to heat the mixed NGLs to effect separation of the NGL products. The Company is able to reduce its energy costs by capturing excess heat and re-using it in its operations. Additionally, the Company's NGL fractionation processing contracts typically contain escalation provisions for cost increases resulting from increased variable costs, including energy costs. Effective July 1, 1999, the Company's ownership interest in the Mont Belvieu NGL fractionation facility increased to an effective 62.5% from 37.0%. Since the acquisition, the Company's 62.5% interest in the results of operations of the fractionation facility have been included in consolidated operations. Prior to the acquisition, the Company's 12.5% direct economic interest was included in consolidated operations, and its effective 24.5% economic interest was recorded as equity income. Isomerization The profitability of this business unit depends on the volume of normal butane that the Company isomerizes (i.e., converts) into isobutane for its toll processing customers, the level of toll processing fees charged to its customers, and the margins generated from selling isobutane to merchant customers. The Company's toll processing customers pay the Company a fee for isomerizing their normal butane into isobutane. In addition, the Company sells isobutane that it obtains by isomerizing normal butane into isobutane, fractionating mixed butane into isobutane and normal butane, or purchasing isobutane in the spot market. The Company determines the optimal sources for isobutane to meet sales obligations based on current and expected market prices for isobutane and normal butane, volumes of mixed butane held in inventory, and estimated costs of isomerization and mixed butane fractionation. The Company purchases most of its imported mixed butanes between the months of February and October. During these months, the Company is able to purchase imported mixed butanes at prices that are often at a discount to posted market prices. Because of its storage capacity, the Company is able to store these imports until the summer months when the spread between isobutane and normal butane typically widens or until winter months when the prices of isobutane and normal butane typically rise. As a result, inventory investment is generally at its highest level at the end of the third quarter of the year. Should this spread not materialize, or in the event absolute prices decline, margins generated from selling isobutane to merchant customers may be negatively affected. Propylene Fractionation The profitability of this business unit depends on the volumes of refinery-sourced propane/propylene mix that the Company processes for its toll customers, the level of toll processing fees charged to its customers and the margins associated with buying refinery-sourced propane/propylene mix and selling high purity propylene to meet sales contracts with non-tolling customers. Pipelines The Company operates both interstate and intrastate NGL product and propylene pipelines. The Company's interstate pipelines are common carriers and 15
must provide service to any shipper who requests transportation services at rates regulated by the Federal Energy Regulatory Commission ("FERC"). The Company's intrastate common carrier pipelines are regulated by the State of Louisiana. The profitability of this business unit is primarily dependent on pipeline throughput volumes. Gas Processing As a result of the TNGL acquisition, the Company is now engaged in natural gas processing in Louisiana and Mississippi via ownership interests in eleven plants. The profitability of the natural gas processing plants is primarily dependent on the volume of NGLs extracted from the natural gas streams and the pricing of NGLs and natural gas in the marketplace. Unconsolidated Affiliates At September 30, 1999, the Company's significant unconsolidated affiliates accounted for using the equity method were BEF, BRF, BRPC, EPIK, Wilprise, Tri-States, Belle Rose, and Promix. BEF owns the MTBE production facility operated by the Company at its Mont Belvieu complex. BRF owns a NGL fractionation facility in southeastern Louisiana that began operations in the third quarter of 1999. BRPC is a newly-formed joint venture (August 1999) between the Operating Partnership and Exxon Chemical Company ("Exxon") which owns a propylene concentration unit under construction in southeastern Louisiana. The Company holds a 30% economic interest in BRPC. Management anticipates that operations will commence at this plant in the third quarter of 2000. EPIK owns a refrigerated NGL marine terminal loading facility located on the Houston ship channel. An expansion of EPIK's NGL marine terminal loading facility is under way and is scheduled for completion in the fourth quarter of 1999. Wilprise owns a NGL pipeline in Louisiana which started operations in the third quarter of 1999 in conjunction with the start-up of the BRF fractionator. Tri-States owns a NGL pipeline in Louisiana, Mississippi, and Alabama which became operational in March 1999. Effective with the TNGL acquisition, the Company acquired an equity interest in Belle Rose and Promix. Belle Rose owns a NGL pipeline system in south Louisiana. The Company owns 41.7% of Belle Rose. Promix owns a NGL fractionation and related storage facilities in south Louisiana. The Company holds a 33-1/3% interest in Promix. In connection with the TNGL acquisition, the Company acquired an additional 16-2/3% of Tri-States bringing the total ownership interest to the current 33-1/3%. As of September 30, 1999, the Company had two investments accounted for using the cost method. These were VESCO and Dixie. VESCO owns a natural gas processing plant, fractionation and storage facilities, and a gas gathering pipeline system in Louisiana. The Company holds a 13.1% economic interest in VESCO. The Dixie investment consists of an 11.5% interest in a corporation owning a 1,300 mile propane pipeline and the associated facilities extending from Mont Belvieu, Texas to North Carolina. Results of Operations Historically, the Company has had only one reportable segment: NGL Operations. The operating margin of this segment has been reported on under five distinct business units: NGL Fractionation, Isomerization, Propylene Fractionation, Pipeline, and Storage and Other Plants. With the acquisition of TNGL, management has opted to add a sixth business unit: TNGL Operations. In addition, with the growth of the Company's equity method investments, Equity in income of unconsolidated affiliates has been included in operating margin in order to provide a more comprehensive view of the Company's results of operations. For the future, due to the growing complexity of the Company's operations with the acquisition of TNGL late in the third quarter of 1999, management is currently studying alternative reporting methods such as reporting results of operations using multiple segments. 16
The Company's operating margins by business unit for the three and nine month periods ended September 30, 1998 and 1999 were as follows: <TABLE> <CAPTION> Three Months Ended Nine Months Ended September 30, September 30, 1998 1999 1998 1999 --------------------------------------------------------- <S> <C> <C> <C> <C> <C> Operating Margin: NGL Fractionation $ 1,274 $ 1,369 $ 2,812 $ 2,901 Isomerization 2,267 17,731 15,729 35,727 Propylene Fractionation 3,538 5,374 8,004 16,813 Pipeline 3,221 2,553 10,268 6,268 TNGL Operations 13,648 13,648 Storage and Other Plants 1,123 51 4,462 185 Equity in Income of Unconsolidated Affiliates 4,171 3,148 7,591 10,824 ========================================================= Total $ 15,594 $ 43,874 $ 52,099 $ 83,133 ========================================================= </TABLE> The Company's plant production data (in thousands of barrels per day or "MBPD") for the three and nine month periods ended September 30, 1998 and 1999 were as follows: Three Months Ended Nine Months Ended September 30, September 30, 1998 1999 1998 1999 ---------------------------------------------- Plant Production Data : TNGL Equity NGL Production 63 63 NGL Fractionation 180 149 197 155 Isomerization 65 77 65 73 MTBE 14 12 13 13 Propylene Fractionation 26 26 26 27 The Company's equity in income of unconsolidated affiliates (in thousands) for the three and nine month periods ended September 30, 1998 and 1999 were as follows: Three Months ended Nine Months ended September 30, September 30, 1998 1999 1998 1999 --------------------------------------------------------------- BEF $ 3,355 $ 2,519 $ 6,609 $ 4,756 MBA 862 72 4,305 1,256 BRF (258) (544) BRPC 4 4 EPIK (46) 59 (90) 236 Entell 258 1,389 Wilprise (130) (130) Tri-States 472 472 Belle Rose 245 245 Promix (93) (93) =============================================================== Total $ 4,171 $ 3,148 $ 10,824 $ 7,591 =============================================================== Three Months Ended September 30, 1999 Compared with Three Months Ended September 30, 1998 17
Revenues; Costs and Expenses The Company's revenues increased to $445.0 million in 1999 compared to $168.8 million in 1998. The Company's costs and expenses increased to $404.4 million in 1999 compared to $156.9 million in 1998. Operating margin increased to $43.9 million in 1999 compared to $15.6 million in 1998. The primary reasons for the increase in operating margins are an improvement in the isomerization business and the addition of the operating results of the TNGL assets. NGL Fractionation. Operating margin from NGL fractionation, which reflects earnings from the Company's Mont Belvieu NGL fractionation assets, was $1.4 million for the third quarter of 1999 compared to $1.3 million for the third quarter of 1998. For the quarter, NGL fractionation volumes at Mont Belvieu averaged 149 MBPD compared to 180 MBPD for the same period in 1998. The slight increase in operating margin for the quarter was principally due to the Company's acquisition of an additional ownership interest in the fractionation from Kinder Morgan and EPCO, offset by lower volumes fractionated. The lower fractionation rates are attributable to the short-term diversion of customer volumes to competitors. The Company fully expects that the diverted volumes will be recovered. Isomerization. The Company's margin in isomerization was $17.7 million for the third quarter of 1999 versus $2.3 million for the third quarter of 1998. Plant production volumes for the third quarter of 1999 averaged 77 MBPD as compared to 65 MBPD for the same period in 1998. The margin improvement was attributable to the increase in plant production volumes, a stronger price environment for normal butane and isobutane during the third quarter of 1999 which benefited the merchant portion of this business and non-recurring inventory write-downs which impaired margins in the third quarter of 1998. The operating margin for 1999 included a $0.7 million benefit from the amortization of the deferred gain associated with the sale and leaseback of one of the Company's isomerization units. Excluding this benefit, the operating margin for 1999 would have been $17.0 million as compared to $2.3 million in 1998. Isobutane volumes from tolling and merchant activities for the third quarter of 1999 averaged 98 MBPD as compared to 107 MBPD for the same period in 1998. Average daily toll processing volumes were 58 MBPD in 1999 and 1998. Isobutane volumes related to merchant activities were 40 MBPD in 1999 and 49 MBPD in 1998. Isobutane merchant volumes decreased in the third quarter of 1999 compared to third quarter of 1998 due to lower margins on isobutane sales relative to normal butane sales. The average spread between isobutane and normal butane decreased from a positive 2.3 cents per gallon ("CPG") in the third quarter of 1998 to a negative 1.2 CPG in the third quarter of 1999. Propylene Fractionation. The Company's operating margin from propylene fractionation for the third quarter of 1999 increased to $5.4 million from $3.5 million for the third quarter of 1998. Propylene fractionation for both periods averaged 26 MBPD. The earnings improvement was primarily attributable to the Company's actions in the merchant portion of the business to match the volume, timing and price of feedstock purchases with sales of the product. Polymer grade propylene prices for the third quarter of 1999 were significantly stronger at 15.7 cents per pound ("CPP") versus 13.7 CPP in the third quarter of 1998. The increase in propylene prices in general for 1999 is attributable to higher crude oil prices and increased global propylene demand. Pipeline. Operating margin from pipeline operations for the third quarter of 1999 was $2.6 million as compared to $3.2 million for the third quarter of 1998. The decrease in operating margin is primarily attributable to lower butane import volume in the third quarter of 1999 as compared to 1998. The lower volumes led to a $0.3 million decrease in the operating margin in 1999 versus 1998. A strengthening of normal butane prices worldwide has led to a decrease in the availability of import volumes coming to the U.S. Gulf Coast. Throughput for the third quarter of 1999 averaged 192 MBPD as compared to 193 MBPD for the same period in 1998. TNGL Operations. The operating margin from the assets acquired from TNGL in the third quarter 1999 was $13.6 million. Since the effective date of the TNGL acquisition was August 1, 1999, the operating margin included in the Company's results of operations was for the months of August and September. Gas Processing produced an operating margin of approximately $9.2 million. NGL fractionation generated an operating margin of $4.1 million. The Pipelines and Other assets produced an operating margin of $0.3 million. 18
Gas Processing is comprised of interests in eleven natural gas processing plants (one of which is under construction) with 11 billion cubic feet per day ("Bcfd") of gross capacity and 3.1 Bcfd of net capacity to the Company's interest anchored by a 20-year natural gas processing agreement with Shell (the "Shell Agreement"). The Company is operator of four of these facilities. Its major customer is Shell. Under the terms of a 20-year processing agreement with Shell, the Company has the right to process substantially all of Shell's current and future natural gas production from the Gulf of Mexico. This includes natural gas production from the developments currently referred to as deepwater. Also included in Gas Processing is the Tebone NGL fractionation facility. This fractionation facility is an integral part of the Tebone and North Terrebone Gas Processing facility. The Tebone NGL fractionation facility was built to receive raw make from the North Terrebone Gas Processing facility and has a rated capacity of 30 MBPD. During the months of August and September, the Gas Processing facilities produced NGLs at a rate of 63 MBPD with the Tebone fractionator operating at 29 MBPD. NGL fractionation business is comprised of the Norco NGL fractionation facility located in Louisiana. This facility is wholly owned by the Company and has a capacity of 60 MBPD. During the months of August and September, the Norco NGL fractionation plants operated a rate of 47 MBPD. Pipeline and Other TNGL assets is primarily composed of varying ownership interests in NGL and NGL product pipelines and storage assets located in southern Louisiana. Selling, General and Administrative Expenses Selling, general and administrative expenses decreased $0.6 million to $3.2 million in 1999 from $3.8 million in 1998. The 1998 charges included $0.8 million in one-time expenses related to the initial public offering in July 1998. This amount was offset by a $0.2 million increase in the monthly charge from EPCO. On July 7, 1999, the Audit and Conflicts Committee of Enterprise Products GP, LLC (the "general partner") authorized an increase in the administrative services fee to $1.1 million per month in accordance with the EPCO Agreement from the initial rate of $1.0 million per month. The increased fees were effective August 1, 1999. Interest Expense Interest expense for the second quarter was $4.0 million in 1999 and $2.5 million in 1998. This increase is principally due to the increased level of average debt outstanding during the third quarter of 1999 attributable to the borrowings associated with the TNGL and Mont Belvieu fractionation facility acquisitions. Of the total debt outstanding at September 30, 1999 of $390 million, approximately $208 million is directly related to these two acquisition transactions. Equity Income in Unconsolidated Affiliates Equity income in unconsolidated affiliates was $3.1 million in 1999 compared to $4.2 million in 1998. Equity income from BEF decreased from $3.4 million in the third quarter of 1998 to $2.5 million in the comparable period for 1999. The decrease of $0.9 million is primarily attributable to downtime associated with maintenance activities in July 1999. As a result of the acquisition of the remaining MBA ownership interests in the Mont Belvieu fractionator on July 1, 1999 and subsequent consolidation of operating results, equity income from MBA ceased effective on that date. The third quarter 1998 equity income amount includes $0.9 million from MBA. EPIK showed a slight increase over the third quarter of 1998 with $0.1 million in equity income versus a loss of $0.1 million in the prior period. Wilprise showed a slight loss during the quarter of $0.1 million with the BRF fractionation facility evidencing a loss as well of $0.3 million. Both the Wilprise pipeline and the BRF fractionation facility started operations in the third quarter of 1999. The Company acquired equity interests in other entities as a result of the TNGL acquisition. Among these entities were Belle Rose (equity income of $0.2 million) and Promix (equity loss of $0.1 million). With the acquisition of an additional 16-2/3% in Tri-States, the Company obtained an equity interest of 33-1/3%. This investment contributed $0.5 million in equity income. 19
Nine Months Ended September 30, 1999 Compared with Nine Months Ended September 30, 1998 Revenues; Costs and Expenses The Company's revenues increased by 35% to $771.4 million in 1999 compared to $573.5 million in 1998. The Company's costs and expenses decreased by 32% to $688.3 million in 1999 compared to $521.4 million in 1998. Operating margin increased by 60% to $83.1 million in 1999 compared to $52.1 million in 1998. The primary reasons for the increase in operating margins are an improvement in the isomerization and propylene fractionation business areas and the addition of the operating results of the TNGL assets. NGL Fractionation. The Company's operating margin for NGL fractionation was $2.9 million for 1999 versus $2.8 million for 1998. Average daily fractionation volumes decreased from 197 MBPD in 1998 to 155 MBPD in 1999. Fractionation volumes are lower in 1999 as compared to 1998 due primarily to ethane rejection, downtime associated with preventative maintenance activities, lower natural gas production caused by depressed oil and gas prices in early 1999, and the short-term diversion of customer volumes to a competitor. During the first quarter of 1999, natural gas prices remained higher than the energy unit equivalent of ethane; therefore, upstream natural gas processing plants rejected ethane which reduced the volumes delivered to Company facilities for fractionation services. The Company took advantage of the reduced demand for its fractionation services during the first quarter of 1999 to perform certain preventative maintenance procedures on one of its fractionation facilities that are generally required every two to three years. During the second quarter of 1999, volumes were reduced due to the short-term diversion of customer volumes to a competitor. Management expects that these volumes will be fully recovered. Isomerization. The Company's operating margin for isomerization increased to $35.8 million in 1999 compared to $15.7 million in 1998. The operating margin for 1999 included a $2.0 million benefit from the amortization of the deferred gain associated with the sale and leaseback of one of the Company's isomerization units. The margin improvement is primarily attributable to a stronger price environment for normal butane and isobutane during 1999 which benefited the merchant portion of this business and non-recurring inventory write-downs which impaired margins in 1998. Excluding this benefit, the operating margin for 1999 would have been $33.8 million as compared to $15.7 million in 1998. Isobutane volumes from tolling and merchant activities for 1999 averaged 100 MBPD as compared to 102 MBPD for the same period in 1998. Average daily toll processing volumes were 57 MBPD in 1999, or 73% of total volumes produced, compared to 56 MBPD in 1998, or 86% of total volumes produced. Isobutane volumes related to merchant activities were 43 MBPD in 1999 and 45 MBPD in 1998. Propylene Fractionation. The Company's operating margin increased to $16.8 million in 1999 from $8.0 million in 1998. Propylene production averaged 27 MBPD in 1999 as compared to 26 MBPD in 1998. The earnings improvement was primarily attributable to the Company's actions to minimize risk in the merchant portion of this business by matching the volume, timing and price of feedstock purchases with sales of end products. The operating margin also benefited from an increase in production volumes associated with spot business caused by increased demand for polymer grade propylene. Pipeline. The Company's operating margin from pipeline operations was $6.3 million in 1999 compared to $10.3 million in 1998. Throughput for 1999 averaged 184 MBPD as compared to 198 MBPD for the same period in 1998. The decrease in throughput was primarily attributable to a decrease in import volumes. The decrease in Pipeline margin is principally related to the Company's contribution of certain wholly-owned pipeline assets, in the first quarter of 1999, and its export loading facility, in June 1998 to joint ventures in which the Company owns a 50% interest. As a result, the earnings from these assets since the time of their contribution are included in equity income from unconsolidated affiliates as prescribed by the equity method of accounting rather than in earnings from consolidated pipeline operations. This change in accounting treatment accounts for approximately $2.8 million of the decrease. TNGL Operations. The operating margin from the assets acquired from TNGL in the third quarter 1999 was $13.6 million. Since the effective date of the TNGL acquisition was August 1, 1999, the operating margin included in the Company's results of operations was for the months of August and September. Gas Processing produced an operating margin of approximately $9.2 million. NGL fractionation generated an operating margin of $4.1 million. The Pipelines and Other assets produced an operating margin of $0.3 million. 20
Gas Processing is comprised of interests in eleven natural gas processing plants (one of which is under construction) with 11 billion cubic feet per day ("Bcfd") of gross capacity and 3.1 Bcfd of net capacity to the Company's interest anchored by a 20-year natural gas processing agreement with Shell (the "Shell Agreement"). The Company is operator of four of these facilities. Its major customer is Shell. Under the terms of a 20-year processing agreement with Shell, the Company has the right to process substantially all of Shell's current and future natural gas production from the Gulf of Mexico. This includes natural gas production from the developments currently referred to as deepwater. Also included in Gas Processing is the Tebone NGL fractionation facility. This fractionation facility is an integral part of the Tebone and North Terrebone Gas Processing facility. The Tebone NGL fractionation facility was built to receive raw make from the North Terrebone Gas Processing facility and has a rated capacity of 30 MBPD. During the months of August and September, the Gas Processing facilities produced NGLs at a rate of 63 MBPD with the Tebone fractionator operating at 29 MBPD. NGL fractionation business is comprised of the Norco NGL fractionation facility located in Louisiana. This facility is wholly owned by the Company and has a capacity of 60 MBPD. During the months of August and September, the Norco NGL fractionation plants operated a rate of 47 MBPD. Pipeline and Other TNGL assets is primarily composed of varying ownership interests in NGL and NGL product pipelines and storage assets located in southern Louisiana. Selling, General and Administrative Expenses Selling, general and administrative expenses decreased $6.2 million to $9.2 million in 1999 from $15.4 million in 1998. This decrease was primarily due to the adoption of the EPCO Agreement in July 1998 in conjunction with the Company's initial public offering ("IPO") which fixed reimbursable selling, general, and administrative expenses at an initial $1.0 million per month. On July 7, 1999, the Audit and Conflicts Committee of the general partner authorized an increase in the administrative services fee to $1.1 million per month in accordance with the EPCO Agreement. The increased fees are effective August 1, 1999. Interest Expense Interest expense was $8.0 million in 1999 and $13.3 million in 1998. This decrease was principally due to the reduced level of average debt outstanding during the first quarter of 1999 attributable to the retirement of debt in July 1998 using proceeds from the Company's IPO. The decrease was muted, however, due to a substantial increase in the average debt outstanding in the third quarter of 1999 due to the borrowings associated with the TNGL and Mont Belvieu fractionation facility acquisitions. Equity Income in Unconsolidated Affiliates Equity income in unconsolidated affiliates was $7.6 million in 1999 compared to $10.8 million in 1998. Equity income from BEF decreased from $6.6 million in 1998 to $4.8 million in 1999. Equity income from BEF for both periods was affected by required annual maintenance on the Company's MTBE facility that generally takes the unit out of production for approximately three weeks. Equity income from BEF during 1999 also includes a $1.5 million non-cash charge for the cumulative effect of a change in accounting principal related to the write-off of deferred start-up costs as prescribed by generally accepted accounting principles. Equity income from MBA decreased to $1.3 million in 1999 from $4.3 million in 1998 due to decreased throughput caused by ethane rejection and downtime associated with preventative maintenance activities. In addition, as a result of the acquisition of the remaining MBA ownership interests in the Mont Belvieu fractionator on July 1, 1999 and subsequent consolidation of operating results, equity income from MBA ceased effective on that date. The 1998 results for MBA are for a nine-month period whereas the 1999 results reflect a six-month period. The third quarter results of operations are now consolidated and included in NGL Fractionation. EPIK showed a slight increase over the 1998 with $0.2 million in equity income versus a loss of $0.1 million in the prior period. The 1998 results for EPIK reflected its first quarter in existence whereas the 1999 results are for nine months. Wilprise showed a slight loss of $0.1 million 21
with the BRF fractionation facility generating a loss of $0.5 million. Both the Wilprise pipeline and the BRF fractionation facility started operations in the third quarter of 1999. Equity income from Entell was $1.4 million through July 31, 1999. Effective August 1, 1999, as a result of the TNGL acquisition, the results of operations for Entell are now included in consolidated pipeline revenues. Consolidation of operating results is necessary under generally accepted accounting principles since the combined interests of the Company now equal 100% (prior to August 1, 1999, the Company held a 50% interest with TNGL holding the remaining 50%). The Company acquired equity interests in other entities as a result of the TNGL acquisition. Among these entities were Belle Rose (equity income of $0.2 million) and Promix (equity loss of $0.1 million). With the acquisition of an additional 16-2/3% in Tri-States, the Company obtained an equity interest of 33-1/3%. This investment contributed $0.5 million in equity income. Financial Condition and Liquidity General The Company's primary cash requirements, in addition to normal operating expenses, are debt service, maintenance capital expenditures, expansion capital expenditures, and quarterly distributions to the partners. The Company expects to fund future cash distributions and maintenance capital expenditures with cash flows from operating activities. Capital expenditures for future expansion activities and asset acquisitions are expected to be funded with cash flows from operating activities and borrowings under the revolving bank credit facilities. Cash flows from operating activities were a $50.1 million inflow for the first nine months of 1999 compared to a $43.9 million outflow for the comparable period of 1998. Cash flows from operating activities primarily reflect the effects of net income, depreciation and amortization, extraordinary items, equity income of unconsolidated affiliates and changes in working capital. Net income increased significantly as a result of improved overall margins and the TNGL acquisition. Depreciation and amortization increased by $2.5 million in 1999 primarily as a result of additional capital expenditures and the TNGL and Mont Belvieu fractionator acquisitions (the "acquisitions") in the third quarter of 1999. Amortization expense increased by $0.7 million due to the amortization of the excess cost recorded in connection with acquisitions. The excess cost associated with the acquisitions will be amortized over a 20-year period at approximately $0.4 million per month. The net effect of changes in operating accounts from year to year is generally the result of timing of NGL sales and purchases near the end of the period. Cash outflows for investing activities were $255.8 million in 1999 and $48.8 million for the comparable period of 1998. Cash outflows included capital expenditures of $10.6 million for 1999 and $7.2 million for 1998. Included in the capital expenditures amounts are maintenance capital expenditures of $1.7 million for 1999 and $5.6 million for 1998. Investing cash outflows in 1999 also included $58.4 million in advances to and investments in unconsolidated affiliates versus $20.0 million for the comparable period of 1998. The $38.4 million increase stems primarily from contributions made to the Wilprise, Tri-States, BRF, and BRPC joint ventures located in Louisiana. Also, the Company received $16.7 million in payments on notes receivable from the BEF and MBA notes purchased during 1998 with the proceeds of the Company's IPO. In conjunction with the acquisition of the MBA interest in the Mont Belvieu fractionation facility, $5.8 million was received during the third quarter 1999 from MBA for the balance of the Company's note receivable. The $9.8 million outstanding balance of notes receivable from unconsolidated affiliates relates to the participation in the BEF note. This balance will be collected in equal installments of approximately $3.3 million each at the end of November 1999, February 2000 and May 2000. Cash outflows for investing activities also include the cash payments related to the acquisitions. Per the terms of the TNGL acquisition, $166.0 million was paid to Tejas Energy in September 1999. Likewise, $42.1 million was paid to Kinder Morgan and EPCO to purchase their collective 51% interest in MBA. As described in Note 10 of the notes to the consolidated financial statements, the Company expects to complete a third significant acquisition in the fourth quarter of 1999 - the purchase of a pipeline from Concha Chemical Pipeline Company ("Concha"), an affiliate of Shell, for approximately $100 million in cash. The purchase of the Lou-Tex pipeline is the first step in the Company's development of a $210 million, 160,000 barrel per day gas liquids pipeline system. The completion of the Lou-Tex transaction is subject to the successful 22
negotiation of definitive agreements, approval of those agreements by the respective managements and regulatory approvals. The development of the expanded Lou-Tex gas liquids pipeline system is expected to be completed in the second half of 2000. Cash flows from financing activities were a $203.3 million inflow in 1999 versus a $66.3 million inflow for the comparable period of 1998. Cash flows from financing activities are affected primarily by repayments of long-term debt, borrowings under the long-term debt agreements and distributions to the partners. The 1998 period reflects the transactions that occurred in the IPO in July 1998. The 1999 period includes $215 million in long-term debt borrowings associated with the TNGL and Mont Belvieu fractionation facility acquisition. Cash flows from financing activities for 1999 also reflected the net purchase of $4.7 million of Common Units by a consolidated trust. Future Capital Expenditures The Company currently estimates that its share of remaining expenditures for significant capital projects in fiscal 1999 will be approximately $8.6 million (including $6.2 million for the BRPC propylene concentrator). These expenditures relate to the construction of joint venture projects which will be recorded as additional investments in unconsolidated affiliates. The Company forecasts that an additional $24.3 million will be spent in 1999 on capital projects that will be recorded as property, plant, and equipment (including $10.9 million for the Lou-Tex pipeline and $5.6 million for the construction of gas plants acquired from TNGL). The Company expects to finance these expenditures out of operating cash flows and borrowings under its bank credit facilities. As of September 30, 1999, the Company had $13.2 million in outstanding purchase commitments attributable to its capital projects. Of this amount, $4.7 million is associated with significant capital projects which will be recorded as additional investments in unconsolidated affiliates for accounting purposes. Distributions from Unconsolidated Affiliates Distributions to the Company from MBA were $1.9 million in 1999 and $4.7 million in 1998. The level of distributions is lower in 1999 versus 1998 due to lower fractionation margins and the acquisition of the MBA interest in the Mont Belvieu fractionation facility on July 1, 1999. Distributions from BEF in 1999 were $0.3 million versus $1.9 million in 1998. Distributions from BEF are down from 1998 levels due to downtime associated with maintenance activities. Distributions from EPIK in 1999 were $1.6 million. EPIK was formed in the second quarter of 1998 and had no distributions until the third quarter of 1998. Bank Credit Facility Existing Bank Credit facility. In July 1998, the Operating Partnership entered into a $200.0 million bank credit facility ("Bank Revolver A") that includes a $50.0 million working capital facility and a $150.0 million revolving term loan facility. The $150.0 million revolving term loan facility includes a sublimit of $30.0 million for letters of credit. As of September 30, 1999, the Company has borrowed $175.0 million under the bank credit facility which is due in July 2000. Management is currently exploring options to convert this short-term debt into long-term debt. The Company's obligations under the bank credit facility are unsecured general obligations and are non-recourse to the General Partner. Borrowings under the bank credit facility will bear interest at either the bank's prime rate or the Eurodollar rate plus the applicable margin as defined in the facility. The bank credit facility will expire in July 2000 and all amounts borrowed thereunder shall be due and payable at that time. There must be no amount outstanding under the working capital facility for at least 15 consecutive days during each fiscal year. As amended on July 28, 1999, the existing credit agreement relating to the facility contains a prohibition on distributions on, or purchases or redemptions of, Units if any event of default is continuing. In addition, the bank credit facility contains various affirmative and negative covenants applicable to the ability of the Company to, among other things, (i) incur certain additional indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) make investments, (v) engage in transactions with affiliates and (vi) enter into a merger, consolidation or sale of assets. The bank credit facility requires that the Operating Partnership satisfy the following financial covenants at the end of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined in the bank credit facility) of at least $250.0 million, (ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to 23
Consolidated Interest Expense (as defined in the bank credit facility) for the previous 12-month period of at least 3.5 to 1.0 and (iii) maintain a ratio of Total Indebtedness (as defined in the bank credit facility) to EBITDA of no more than 3.0 to 1.0. A "Change of Control" constitutes an Event of Default under the bank credit facility. A Change of Control includes any of the following events: (i) Dan L. Duncan (and/or certain affiliates) cease to own (a) at least 51% (on a fully converted, fully diluted basis) of the economic interest in the capital stock of EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own, through a wholly owned subsidiary, at least 65% of the outstanding membership interest in the General Partner and at least a majority of the outstanding Common Units; (iii) any person or group beneficially owns more than 20% of the outstanding Common Units (excluding certain affiliates of EPCO or Shell Oil Company); (iv) the General Partner ceases to be the general partner of the Company or the Operating Partnership; or (v) the Company ceases to be the sole limited partner of the Operating Partnership. New Bank Credit facility. On July 28, 1999, the Operating Partnership entered into a $350.0 million bank credit facility ("Bank Revolver B") that includes a $50.0 million working capital facility and a $300.0 million revolving term loan facility. The $300.0 million revolving term loan facility includes a sublimit of $10.0 million for letters of credit. The proceeds of this loan were used to finance the acquisition of TNGL and the MBA ownership interests. Future uses of the remaining credit line include the purchase of the Lou-Tex pipeline (see Note 10). Borrowings under the bank credit facility will bear interest at either the bank's prime rate or the Eurodollar rate plus the applicable margin as defined in the facility. The bank credit facility will expire in July 2001 and all amounts borrowed thereunder shall be due and payable at that time. There must be no amount outstanding under the working capital facility for at least 15 consecutive days during each fiscal year. The credit agreement relating to the new facility contains a prohibition on distributions on, or purchases or redemptions of Units if any event of default is continuing. In addition, the bank credit facility contains various affirmative and negative covenants applicable to the ability of the Company to, among other things, (i) incur certain additional indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) make investments, (v) engage in transactions with affiliates and (vi) enter into a merger, consolidation, or sale of assets. The bank credit facility requires that the Operating Partnership satisfy the following financial covenants at the end of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined in the bank credit facility) of at least $250.0 million, (ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to Consolidated Interest Expense (as defined in the bank credit facility) for the previous 12-month period of at least 3.5 to 1.0 and (iii) maintain a ratio of Total Indebtedness (as defined in the bank credit facility) to EBITDA of no more than 3.0 to 1.0. A "Change of Control" constitutes an Event of Default under the bank credit facility. A Change of Control includes any of the following events: (i) Dan L. Duncan (and/or certain affiliates) cease to own (a) at least 51% (on a fully converted, fully diluted basis) of the economic interest in the capital stock of EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own, through a wholly owned subsidiary, at least 65% of the outstanding membership interest in the General Partner and at least a majority of the outstanding Common Units; (iii) any person or group beneficially owns more than 20% of the outstanding Common Units (excluding certain affiliates of EPCO and Shell Oil Company); (iv) the General Partner ceases to be the general partner of the Company or the Operating Partnership; or (v) the Company ceases to be the sole limited partner of the Operating Partnership. MTBE Production The Company owns a 33-1/3% economic interest in the BEF partnership that owns the MTBE production facility located within the Compan's Mont Belvieu complex. 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 opt out of 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. 24
On March 25, 1999, the Governor of California ordered the phase-out of MTBE in that state by the end of 2002 due to allegations by several public advocacy and protest groups that MTBE contaminates water supplies, causes health problems and has not been as beneficial in reducing air pollution as originally contemplated. The order also seeks to obtain a waiver of the oxygenate requirement from the federal Environmental Protection Agency ("EPA") in order to facilitate the phase-out; however, due to increasing concerns about the viability of alternative fuels, the California legislature on October 10, 1999 passed the Sher Bill (SB 989) stating that MTBE should be banned as soon as feasible rather than by the end of 2002. In addition, legislation to amend the federal Clean Air Act of 1990 has been introduced in the U.S. House of Representatives to ban the use of MTBE as a fuel additive within three years. Legislation introduced in the U.S. Senate would eliminate the Clean Air Act's oxygenate requirement in order to assist the elimination of MTBE in fuel. No assurance can be given as to whether this or similar federal legislation ultimately will be adopted or whether Congress or the EPA might takes steps to override the MTBE ban in California. In November 1998, U.S. EPA Administrator Carol M. Browner appointed a Blue Ribbon Panel (the "Panel") to investigate the air quality benefits and water quality concerns associated with oxygenates in gasoline, and to provide independent advice and recommendations on ways to maintain air quality while protecting water quality. The Panel issued a report on their findings and recommendations in July 1999. The Panel urged the widespread reduction in the use of MTBE due to the growing threat to drinking water sources despite that fact that use of reformulated gasolines have contributed to significant air quality improvements. The Panel credited reformulated gasoline with "substantial reductions" in toxic emissions from vehicles and recommended that those reductions be maintained by the use of cleaner-burning fuels that rely on additives other than MTBE and improvements in refining processes. The Panel stated that the problems associated with MTBE can be characterized as a low-level, widespread problem that had not reached the state of being a public health threat. The Panel's recommendations are geared towards confronting the problems associated with MTBE now rather than letting the issue grow into a larger and worse problem. The Panel did not call for an outright ban on MTBE but stated that its use should be curtailed significantly. The Panel also encouraged a public educational campaign on the potential harm posed by gasoline when it leaks into ground water from storage tanks or while in use. Based on the Panel's recommendations, the EPA will ask Congress for a revision of the Clean Air Act of 1990 that maintains air quality gains and allows for the removal of the oxygenate demand in gasoline. In light of these developments, the Company is formulating a contingency plan for use of the BEF MTBE facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion of the BEF facility from MTBE production to alkylate production. At present, the forecasted cost to the Company of this conversion would be in the $20 million to $25 million range with the Company's share being $6.7 million to $8.3 million. Management anticipates that if MTBE is banned alkylate demand will rise as producers use it to replace MTBE as an octane enhancer. Alkylate production would be expected to generate margins comparable to those of MTBE. Greater alkylate production would be expected to increase isobutane consumption nationwide and result in improved isomerization margins for the Company. Year 2000 Readiness Disclosure Pursuant to the EPCO Agreement, any selling, general and administrative expenses related to Year 2000 compliance issues are covered by the annual administrative services fee paid by the Company to EPCO. Consequently, only those costs incurred in connection with Year 2000 compliance which relate to operational information systems and hardware will be paid directly by the Company. Since 1997, EPCO has been assessing the impact of Year 2000 compliance issues on the software and hardware used by the Company. A team was assembled to review and document the status of EPCO's and the Company's systems for Year 2000 compliance. The key information systems reviewed include the Company's pipeline Supervisory Control and Data Acquisition ("SCADA") system, plant, storage, and other pipeline operating systems. In connection with each of these areas, consideration was given to hardware, operating systems, applications, data base management, system interfaces, electronic transmission, and outside vendors. As of October 31, 1999 work is approximately 99% complete in all areas. 25
As of September 30, 1999, EPCO had spent approximately $326,500 in connection with Year 2000 compliance and has estimated the future costs to approximate $12,000. This cost estimate does not include internal costs of EPCO's previously existing resources and personnel that might be partially used for Year 2000 compliance or cost of normal system upgrades which also included various Year 2000 compliance features or fixes. Such internal costs have been determined to be materially insignificant to the total estimated cost of Year 2000 compliance. These amounts are current cost estimates and actual future costs could potentially be higher or lower than the estimates. At this time, the Company believes its total cost for known or anticipated remediation of its information systems to make them Year 2000 compliant will not be material to its financial position or its ability to sustain operations. As of September 30, 1999, the Company had incurred expenditures of approximately $1,026,000 in connection with finalizing its Year 2000 compliance project (principally the SCADA system). The Company does not expect any additional material expenditures. This approximate cost does not include the Company's internal costs related to previously existing resources and personnel that might be partially used for remediation of Year 2000 compliance issues. Such internal costs have been determined to be materially insignificant to the total estimated cost of Year 2000 compliance. The Company relies on third-party suppliers for certain systems, products and services, including telecommunications. There can be no assurance that the systems of other companies on which the Company's systems rely also will timely be compliant or that any such failure to be compliant by another company would not have an adverse effect on the Company's systems. The Company has received certain information concerning Year 2000 compliance status from a group of critical suppliers and vendors. This information has assisted the Company in determining the extent to which it may be vulnerable to the failure of third parties to address their Year 2000 compliance issues. Based on the responses received to date, the Company believes that its critical suppliers and vendors will be Year 2000 compliant. Management believes it has a program to address the Year 2000 compliance issue in a timely manner. Final completion of the plan and testing of replacement or modified systems is anticipated by November 30, 1999. Nevertheless, since it is not possible to anticipate all possible future outcomes, especially when third parties are involved, there could be circumstances in which the Company would be unable to invoice customers or collect payments. The failure to correct a material Year 2000 compliance problem could result in an interruption in or failure of certain normal business activities or operations of the Company. Such failures could have a material adverse effect on the Company. The amount of potential liability and lost revenue has not been estimated. The Company and EPCO have developed a contingency plan to address unavoidable risks associated with Year 2000 compliance issues. Management has examined the Year 2000 compliance issue and determined that a worst-case scenario would be a total, unexpected facility shutdown caused by a disruption of third-party utilities (principally a total electrical power outage). Enterprise personnel are trained to respond timely and effectively to such emergencies; however, because of the uncertainty surrounding the Year 2000 problem, the Company will have additional resources available to assist the operations, maintenance, and various other groups on December 31, 1999 and January 1, 2000. The Company will have extra operating, maintenance, process control, computer support, environmental and safety personnel on site and/or on standby in the event that a Year 2000 problem arises. The Company and EPCO will have a defined team of trained personnel available for the rollover into January 1, 2000, so that any disruption to Company or EPCO facilities can be handled safely and so that a return to normal operations can be commenced as soon as is practicable. Accounting Standards On June 6, 1999, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133-an amendment of FASB Statement No. 133" which effectively delays and amends the application of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" for one year, to fiscal years beginning after June 15, 2000. Management is currently studying both SFAS No. 137 and SFAS No. 133 for possible impact on the consolidated financial statements. 26
On April 3, 1998, the American Institute of Certified Public Accountants issued Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up Activities." For years beginning after December 15, 1998, SOP 98-5 generally requires that all start-up costs of a business activity be charged to expense as incurred and any start-up costs previously deferred should be written off as a cumulative effect of a change in accounting principle. Adoption of SOP 98-5 during 1999 did not have a material impact on the consolidated financial statements except for a $4.5 million noncash write-off that occurred on January 1, 1999 of the unamortized balance of deferred start-up costs of BEF, in which the Company owns a 33-1/3% interest. This write-off caused a $1.5 million reduction in the equity in income of unconsolidated affiliates for 1999 and a corresponding reduction in the Company's investment in unconsolidated affiliates. Uncertainty of Forward-Looking Statements and Information. This quarterly report 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," and "may," and similar expressions and statements regarding the plans and objectives of the Company for future operations, are intended to identify forward-looking statements. Although the Company and the General Partner believe that the expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, projected, or expected. Among the key risk factors that may have a direct bearing on the Company's results of operations and financial condition are: (a) competitive practices in the industries in which the Company competes, (b) fluctuations in oil, natural gas, and NGL product prices and production, (c) operational and systems risks, (d) environmental liabilities that are not covered by indemnity or insurance, (e) the impact of current and future laws and governmental regulations (including environmental regulations) affecting the NGL industry in general, and the Company's operations in particular, (f) loss of a significant customer, and (g) failure to complete one or more new projects on time or within budget. Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Historically, the Company has been exposed to financial market risks, including changes in interest rates with respect to its investments in financial instruments and changes in commodity prices. The Company could, but generally did not, use derivative financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) or derivative commodity instruments (i.e., commodity futures, forwards, swaps, or options, and other commodity instruments with similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial instrument) to mitigate either of these risks. The return on the Company's financial investments was generally not affected by foreign currency fluctuations. Through the third quarter of 1999, the Company did not use any material derivative financial instruments for speculative purposes. At September 30, 1999, the Company had no material derivative instruments in place to cover any potential interest rate, foreign currency or other financial instrument risk. At September 30, 1999, the Company had $21.6 million invested in cash and cash equivalents. 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. The Company's inventory of NGLs and NGL products at September 30, 1999, was $103.0 million. Inventories are carried at the lower of cost or market. A 10% adverse change in commodity prices would result in an approximate $10.3 million decrease in the fair value of the Company's inventory, based on a sensitivity analysis at September 30, 1999. Actual results may differ materially. All the Company's long-term debt is at variable interest rates; a 10% change in the base rate selected would have an approximate $2.1 million effect on the amount of interest expense for the year based upon amounts outstanding at September 30, 1999. Beginning with the fourth quarter of 1999, the Company adopted a commercial policy to manage exposures to the risks generated by the NGL business. The objective of the policy is to assist the Company in achieving its profitability goals while maintaining a portfolio of conservative risk, defined as remaining 27
within the position limits established by the Board of Directors of the general partner. The Company will enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to energy commodities on both a short-term (less than 30 days) and long-term basis, not to exceed 18 months. The general partner has established a Risk Committee (the "committee") that will oversee overall strategies associated with physical and financial risks. The committee will approve specific commercial policies of the Company subject to this policy, including authorized products, instruments and markets. The committee is also charged with establishing specific guidelines and procedures for implementing the policy and ensuring compliance with the policy. This policy will affect transactions beginning with the fourth quarter of 1999. 28
PART II. OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K (a) Exhibits *3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. (Exhibit 3.1 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *3.2 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). *3.3 LLC Agreement of Enterprise Products GP (Exhibit 3.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *3.4 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 in the Schedule 13D filed September 27, 1999 by Tejas Energy LLC ; filed as Exhibit 99.7 on Form 8-K dated October 4, 1999). *3.5 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). *4.1 Form of Common Unit certificate (Exhibit 4.1 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *4.2 $200 million Credit Agreement among Enterprise Products Operating L.P., the Several Banks from Time to Time Parties Hereto, Den Norske Bank ASA, and Bank of Tokyo-Mitsubishi, Ltd., Houston Agency as Co-Arrangers, The Bank of Nova Scotia, as Co-Arranger and as Documentation Agent and The Chase Manhattan Bank as Co-Arranger and as Agent dated as of July 27, 1998 as Amended and Restated as of September 30, 1998. (Exhibit 4.2 on Form 10-K for year ended December 31, 1998, filed March 17, 1999). *4.3 First Amendment to $200 million Credit Agreement dated July 28, 1999 among Enterprise Products Operating L.P. and the several banks thereto. (Exhibit 99.9 on Form 8-K/A-1 filed October 27, 1999). *4.4 $350 million Credit Agreement among Enterprise Products Operating L.P., BankBoston, N.A., Societe Generale, Southwest Agency and First Union National Bank, as Co-Arrangers, The Chase Manhattan Bank, as Co-Arranger and as Administrative Agent, The First National Bank of Chicago, as Co-Arranger and as Documentation Agent, The Bank of Nova Scotia, as Co-Arranger and Syndication Agent, and the Several Banks from Time to Time parties hereto with First Union Capital Markets acting as Managing Agent and Chase Securities Inc. acting as Lead Arranger and Book Manager dated July 28, 1999 (Exhibit 99.10 on Form 8-K/A-1 filed October 27, 1999). *4.5 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 in the Schedule 13D filed September 27, 1999 by Tejas Energy LLC ; filed as Exhibit 99.5 on Form 8-K dated October 4, 1999). 29
*10.1Articles 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). *10.2Form of EPCO Agreement between Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC and Enterprise Products Company (Exhibit 10.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998). *10.3Transportation 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). *10.4Venture Participation Agreement between Sun Company, Inc. (R&M), Liquid Energy Corporation and Enterprise Products Company dated May 1, 1992 (Exhibit 10.4 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.5Partnership Agreement between Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992 (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.6Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc. (R&M) dated August 16, 1995 (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.7Articles of Partnership of Mont Belvieu Associates dated July 17, 1985 (Exhibit 10.7 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.8First Amendment to Articles of Partnership of Mont Belvieu Associates dated July 15, 1996 (Exhibit 10.8 to Registration Statement on Form S-1, File No. 333-52537, filed on May 13, 1998). *10.9Propylene 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). *10.10 Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas between Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985 (Exhibit 10.10 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). *10.11 Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities between Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum Company and Mont Belvieu Associates dated July 17, 1985 (Exhibit 10.11 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998). 30
*10.12 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). *10.13 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). 10.14Fourth Amendment to Conveyance of Gas Processing Rights between Tejas Natural Gas Liquids, LLC and Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Deepwater Development Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas Inc. dated August 1, 1999. *99.1Contribution Agreement between Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by reference the above document included in the Schedule 13D filed September 27, 1999 by Tejas Energy LLC ; filed as Exhibit 99.4 on Form 8-K dated October 4, 1999). *99.2Registration Rights Agreement between Tejas Energy LLC and Enterprise Products Partners L.P. dated September 17, 1999. (The Company incorporates by reference the above document included in the Schedule 13D filed September 27, 1999 by Tejas Energy LLC ; filed as Exhibit 99.6 on Form 8-K dated October 4, 1999). 27.1 Financial Data Schedule * Asterisk indicates exhibits incorporated by reference as indicated (b) Reports on Form 8-K Three reports on Form 8-K were filed during the third quarter of 1999 associated with the Tejas acquisition. On September 20, 1999 a Form 8-K was filed whereby the Company announced it had completed its acquisition of TNGL, from Tejas Energy, an affiliate of Shell. In exchange for its NGL business, Tejas Energy received 14.5 million convertible special partnership units in the Company and $166 million in cash. Tejas Energy has the opportunity to earn an additional 6.0 million convertible contingency units over the next two years. As part of the transaction, the Company has entered into a long-term gas processing agreement with Shell for its Gulf of Mexico production. TNGL's NGL businesses include natural gas processing and NGL fractionation, transportation, storage and marketing. All of TNGL's assets in Louisiana and Mississippi are included under the terms of the transaction. This acquisition by the Company forms a fully integrated Gulf Coast NGL processing, fractionation, storage, transportation and marketing business. On October 4, 1999, a Form 8-K was filed whereby the Company summarized the Unitholder Rights Agreement and other material agreements associated with the TNGL acquisition. This filing incorporated by reference certain material documents associated with the acquisition. 31
On October 27, 1999, a Form 8-K/A-1 was filed whereby the Company disclosed certain historical financial information of TNGL for the years ended 1996, 1997, and 1998. In addition, this filing contained other documentation relating to the TNGL acquisition. 32
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 Partners L.P. (A Delaware Limited Partnership) By: Enterprise Products GP, LLC as General Partner Date: November 15, 1999 By: /s/ Gary L. Miller Executive Vice President Chief Financial Officer and Treasurer 33