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, 2000
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number: 1-14323
Enterprise Products Partners L.P.
(Exact name of Registrant as specified in its charter)
Delaware 76-0568219
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2727 North Loop West
Houston, Texas
77008-1037
(Address of principal executive offices) (Zip code)
(713) 880-6500
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes _X_ No ___
The registrant had 46,535,715 Common Units outstanding as of November 13, 2000.
<PAGE>
Enterprise Products Partners L.P. and Subsidiaries
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
No.
Part I. Financial Information
Item 1. Consolidated Financial Statements
Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements:
<S> <C>
Consolidated Balance Sheets, September 30, 2000 and December 31, 1999 1
Statements of Consolidated Operations
for the Three and Nine Months ended September 30, 2000 and 1999 2
Statements of Consolidated Cash Flows
for the Nine Months ended September 30, 2000 and 1999 3
Notes to Unaudited Consolidated Financial Statements 4
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk 33
Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders. 35
Item 6. Exhibits and Reports on Form 8-K 35
Signature Page
</TABLE>
<PAGE>
PART 1. FINANCIAL INFORMATION.
Item 1. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Dollar amounts in thousands)
<TABLE>
<CAPTION>
September 30,
2000 December 31,
ASSETS (Unaudited) 1999
---------------------------------------
Current Assets
<S> <C> <C>
Cash and cash equivalents $ 41,443 $ 5,230
Accounts receivable - trade, net of allowance for doubtful accounts of
$12,053 at September 30, 2000 and $15,871 at December 31, 1999 302,766 262,348
Accounts receivable - affiliates 37,050 56,075
Inventories 138,039 39,907
Current maturities of participation in notes receivable from
unconsolidated affiliates - 6,519
Prepaid and other current assets 13,162 14,459
---------------------------------------
Total current assets 532,460 384,538
Property, Plant and Equipment, Net 941,836 767,069
Investments in and Advances to Unconsolidated Affiliates 280,206 280,606
Intangible assets, net of accumulated amortization of $4,186 at
September 30, 2000 and $1,345 at December 31, 1999 88,577 61,619
Other Assets 4,457 1,120
---------------------------------------
Total $ 1,847,536 $ 1,494,952
=======================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of long-term debt $ 50,000 $ 129,000
Accounts payable - trade 107,356 69,294
Accounts payable - affiliate 34,035 64,780
Accrued gas payables 278,651 233,360
Accrued expenses 11,496 16,510
Other current liabilities 30,925 18,176
---------------------------------------
Total current liabilities 512,463 531,120
Long-Term Debt 404,000 166,000
Other Long-Term liabilities 7,094 296
Minority Interest 9,353 8,071
Commitments and Contingencies
Partners' Equity
Common Units (45,552,915 Units outstanding at December 31, 1999 and
46,535,715 Units outstanding at September 30, 2000) 463,239 428,707
Subordinated Units (21,409,870 Units outstanding at December 31, 1999
and September 30, 2000) 154,205 131,688
Special Units (14,500,000 Units outstanding at December 31, 1999 and
16,500,000 Units outstanding at September 30, 2000) 292,715 225,855
Treasury Units acquired by Trust, at cost (267,200 Units outstanding at
December 31, 1999 and September 30, 2000) (4,727) (4,727)
General Partner
9,194 7,942
---------------------------------------
Total Partners' Equity 914,626 789,465
---------------------------------------
Total $ 1,847,536 $ 1,494,952
=======================================
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
1
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Enterprise Products Partners L.P.
Statements of Consolidated Operations
(Unaudited)
(Amounts in thousands, except per Unit amounts)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
2000 1999 2000 1999
------------------------------- --------------------------------
REVENUES
<S> <C> <C> <C> <C>
Revenues from consolidated operations $ 717,113 $ 441,880 $ 2,056,307 $ 763,793
Equity income in unconsolidated affiliates 4,750 3,148 23,290 7,591
------------------------------- --------------------------------
Total 721,863 445,028 2,079,597 771,384
------------------------------- --------------------------------
COST AND EXPENSES
Operating costs and expenses 659,021 401,758 1,878,233 688,977
Selling, general and administrative 6,978 3,200 20,020 9,200
------------------------------- --------------------------------
Total 665,999 404,958 1,898,253 698,177
------------------------------- --------------------------------
OPERATING INCOME 55,864 40,070 181,344 73,207
OTHER INCOME (EXPENSE)
Interest expense (7,486) (4,515) (23,330) (8,907)
Interest income (expense) from unconsolidated affiliates (88) 407 182 1,096
Dividend income from unconsolidated affiliates 2,241 - 6,236 -
Interest income - other 317 682 3,023 1,114
Other, net (71) 72 (496) 117
------------------------------- --------------------------------
Other income (expense) (5,087) (3,354) (14,385) (6,580)
------------------------------- --------------------------------
INCOME BEFORE MINORITY INTEREST 50,777 36,716 166,959 66,627
MINORITY INTEREST (514) (370) (1,689) (672)
------------------------------- --------------------------------
NET INCOME $ 50,263 $ 36,346 $ 165,270 $ 65,955
=============================== ================================
ALLOCATION OF NET INCOME TO:
Limited partners $ 49,566 $ 35,983 $ 163,423 $ 65,295
=============================== ================================
General partner $ 697 $ 363 $ 1,847 $ 660
=============================== ================================
BASIC EARNINGS PER UNIT
Income before minority interest $ 0.75 $ 0.54 $ 2.47 $ 0.99
=============================== ================================
Net income per Common and Subordinated unit $ 0.74 $ 0.54 $ 2.44 $ 0.98
=============================== ================================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 0.60 $ 0.48 $ 2.02 $ 0.94
=============================== ================================
Net income per Common, Subordinated
and Special unit $ 0.60 $ 0.47 $ 2.00 $ 0.93
=============================== ================================
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
2
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Enterprise Products Partners L.P.
Statements of Consolidated Cash Flows
(Dollars in Thousands)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
2000 1999
-------------------------------------
OPERATING ACTIVITIES
<S> <C> <C>
Net income $ 165,270 $ 65,955
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 27,952 17,280
Equity in income of unconsolidated affiliates (23,290) (7,591)
Distributions received from unconsolidated affiliates 25,997 4,607
Leases paid by EPCO 7,904 7,918
Minority interest 1,689 672
Loss on sale of assets 2,276 122
Net effect of changes in operating accounts (29,942) (34,246)
-------------------------------------
Operating activities cash flows 177,856 54,717
-------------------------------------
INVESTING ACTIVITIES
Capital expenditures (200,157) (10,603)
Proceeds from sale of assets 85 8
Business acquisitions, net of cash acquired (208,095)
Collection of notes receivable from unconsolidated affiliates 6,519 16,719
Investments in and advances to unconsolidated affiliates (2,307) (58,460)
-------------------------------------
Investing activities cash flows (195,860) (260,431)
-------------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 514,000 350,000
Long-term debt repayments (355,000) (59,923)
Cash dividends paid to partners (103,347) (81,321)
Cash dividends paid to minority interest by Operating Partnership (1,055) (830)
Units acquired by consolidated trust - (4,727)
Unit repurchases (465) -
Cash contributions from EPCO to minority interest 84 59
-------------------------------------
Financing activities cash flows 54,217 203,258
-------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 36,213 (2,456)
CASH AND CASH EQUIVALENTS, JANUARY 1 5,230 24,103
-------------------------------------
CASH AND CASH EQUIVALENTS, SEPTEMBER 30 $ 41,443 $ 21,647
=====================================
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
3
<PAGE>
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, 2000, consolidated
results of operations for the three and nine month periods ended September 30,
2000 and 1999 and consolidated cash flows for the nine month periods ended
September 30, 2000 and 1999. Although the Company believes the disclosures in
these financial statements are adequate to make the information presented not
misleading, certain information and footnote disclosures normally included in
annual financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to the rules and
regulations of the Securities and Exchange Commission. These unaudited financial
statements should be read in conjunction with the financial statements and notes
thereto included in the Company's Annual Report on Form 10-K (File No. 1-14323)
for the year ended December 31, 1999.
The results of operations for the three and nine month periods ended September
30, 2000 are not necessarily indicative of the results to be expected for the
full year.
Certain reclassifications have been made to prior years' financial statements to
conform to the presentation of the current period financial statements.
Dollar amounts presented in the tabulations within the notes to the consolidated
financial statements are stated in thousands of dollars, unless otherwise
indicated.
2. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
At September 30, 2000, the Company's unconsolidated affiliates accounted for by
the equity method included the following:
Belvieu Environmental Fuels ("BEF") - a 33.33% economic interest in a Methyl
Tertiary Butyl Ether ("MTBE") production facility located in southeast Texas.
Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% 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 that became
operational in July 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 37.35% economic interest in a
NGL pipeline system located in southeastern Louisiana.
Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% economic
interest in a NGL pipeline system located in Louisiana, Mississippi, and
Alabama.
Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.7% economic interest in a NGL
pipeline system located in south Louisiana.
4
<PAGE>
K/D/S Promix LLC ("Promix") - a 33.33% economic interest in a NGL fractionation
facility and related storage facilities located in south Louisiana. The
Company's investment includes excess cost over the underlying equity in the net
assets of Promix of $7.5 million at September 30, 2000 which is being amortized
using the straight-line method over a period of 20 years. For the three and nine
months ended September 30, 2000, the Company recorded amortization expense
associated with this excess cost of $0.1 million and $0.3 million, respectively,
which is reflected in the equity earnings from Promix. For the third quarter of
1999, such amortization was $0.2 million.
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. At September 30, 2000, the Dixie
investment consisted of an 11.5% interest in a corporation owning a 1,301-mile
propane pipeline and associated facilities extending from Mont Belvieu, Texas to
North Carolina. On October 6, 2000, the Company purchased an additional 8.4%
economic interest in Dixie from Conoco Pipe Line Company for $19.4 million (see
Note 11). The Company's ownership interest in Dixie now stands at 19.9%. Through
September 30, 2000, these investments were accounted for using the cost method.
During the third quarter of 1999, the Company acquired the remaining interest in
Mont Belvieu Associates, 51%, ("MBA") and Entell NGL Services, LLC, 50%,
("Entell"). Accordingly, after the acquisition of the remaining interests, MBA
terminated and Entell became a wholly owned subsidiary of the Company and is
included as a consolidated entity from that point forward.
The following table shows investments in and advances to unconsolidated
affiliates at:
September 30, December 31,
2000 1999
---------------------------------------
Accounted for on equity basis:
BEF $ 61,989 $ 63,004
Promix 49,981 50,496
BRF 29,673 36,789
Tri-States 27,697 28,887
EPIK 17,662 15,258
Belle Rose 11,655 12,064
BRPC 19,344 11,825
Wilprise 9,160 9,283
Accounted for on cost basis:
VESCO 33,000 33,000
Dixie 20,045 20,000
---------------------------------------
Total $ 280,206 $ 280,606
=======================================
5
<PAGE>
The following table shows equity in income (loss) of unconsolidated affiliates
for the three and nine month periods ended September 30, 2000 and 1999:
<TABLE>
<CAPTION>
For Three Months Ended For Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
------------------------------------- -------------------------------------
<S> <C> <C> <C> <C>
BEF $ 2,190 $ 2,519 $ 13,002 $ 4,756
MBA - 72 - 1,256
BRF 434 (258) 1,171 (544)
BRPC 134 4 115 4
EPIK (124) 59 1,846 236
Wilprise 135 (130) 297 (130)
Tri-States 694 472 2,215 472
Promix 1,170 (93) 4,378 (93)
Belle Rose 117 245 266 245
Other - 258 - 1,389
------------------------------------- -------------------------------------
Total $ 4,750 $ 3,148 $ 23,290 $ 7,591
===================================== =====================================
</TABLE>
The following table presents summarized income statement information for the
unconsolidated subsidiaries accounted for by the equity method:
<TABLE>
<CAPTION>
For the Three Months ended For the Nine Months ended
September 30, 2000 September 30, 2000
--------------------------------------------------- ---------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
--------------------------------------------------- ---------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
BEF $ 77,330 $ 6,201 $ 6,570 $ 214,761 $ 38,575 $ 39,007
EPIK 1,856 (290) (249) 14,789 3,561 3,699
BRF 4,775 1,282 1,347 13,989 3,504 3,631
BRPC 2,333 398 477 2,333 211 383
Wilprise 727 398 406 2,149 867 891
Tri-States 3,430 2,059 2,088 10,677 6,530 6,650
Promix 12,242 3,959 4,019 36,968 14,057 14,274
Belle Rose 536 279 279 1,802 645 645
--------------------------------------------------- ---------------------------------------------------
Total $ 103,229 $ 14,286 $ 14,937 $ 297,468 $ 67,950 $ 69,180
=================================================== ===================================================
For the Three Months ended For the Nine Months ended
September 30, 1999 September 30, 1999
--------------------------------------------------- ---------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
--------------------------------------------------- ---------------------------------------------------
BEF $ 47,885 $ 7,067 $ 7,556 $ 128,516 $ 19,476 $ 14,269
EPIK 2,520 253 264 5,954 733 751
BRF 2,317 (512) (827) 2,317 (579) (1,741)
BRPC - - 13 - - 13
Wilprise 291 (399) (390) 291 (399) (390)
Tri-States 4,611 1,377 1,417 4,611 1,377 1,417
Promix 7,990 1,715 354 7,990 1,715 354
Belle Rose 639 566 566 1,138 551 590
MBA - - 147 12,329 2,731 2,563
Other 910 516 516 4,842 2,778 2,778
--------------------------------------------------- ---------------------------------------------------
Total $ 67,163 $ 10,583 $ 9,616 $ 167,988 $ 28,383 $ 20,604
=================================================== ===================================================
</TABLE>
6
<PAGE>
BEF
BEF is a partnership that owns the MTBE production facility located within the
Company'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 elect
not to participate in these programs, lessen the requirements for oxygenates or
favor the use of non-isobutane based oxygenated fuels reduce the demand for MTBE
and could have an adverse effect on the Company's results of operations.
In recent years, MTBE has been detected in water supplies. The major source of
the ground water contamination appears to be leaks from underground storage
tanks. Although these detections have been limited and the great majority of
these detections have been well below levels of public health concern, there
have been actions calling for the phase-out of MTBE in motor gasoline in various
federal and state governmental agencies.
In light of these developments, the Company is formulating a contingency plan
for use of the BEF facility if MTBE were banned or significantly curtailed.
Management is exploring a possible conversion of the BEF facility from MTBE
production to alkylate production. At present the forecasted cost 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.
3. ACQUISITIONS
Effective August 1, 1999, the Company acquired Tejas Natural Gas Liquids, LLC
("TNGL") from a subsidiary of Tejas Energy, LLC, now Coral Energy, LLC, an
affiliate of Shell Oil Company ("Shell") for $166 million in cash and the
issuance of 14.5 million non-distribution bearing, convertible Special Units.
All references hereafter to "Shell", unless the context indicates otherwise,
shall refer collectively to Shell Oil Company, its subsidiaries and affiliates.
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 ("Shell Processing
Agreement") and varying interests in eleven natural gas processing plants, four
NGL fractionation facilities; four NGL storage facilities and approximately
1,500 miles in pipelines.
In addition to the Special Units, Shell may be granted 6.0 million
non-distribution bearing, convertible Contingency Units provided that certain
performance criteria are met in calendar years 2000 and 2001 (see Note 5). Under
terms of the agreement with Shell, the Company will issue 3.0 million
Contingency Units in 2000 and an additional 3.0 million Contingency Units in
2001 provided the performance tests are successfully completed. On June 28,
2000, Shell met the performance criteria outlined for calendar year 2000 and in
accordance with its contingent Unit agreement with Shell, the Company issued the
3.0 million Contingency Units (deemed "Special Units" once they are issued) on
August 1, 2000.
The value of these new Special Units is $55.2 million using present value
techniques. In August 2000, the TNGL acquisition purchase price and the value of
the Shell Processing Agreement were increased by the $55.2 million value of the
Units. If the remainder of the Contingency Units are issued in 2001 (or at such
later date as agreed to by the parties), the purchase price and value of the
Shell Processing Agreement will be adjusted accordingly. The value of the Shell
Processing Agreement (classified as an Intangible Asset on the balance sheet)
was $80.2 million at September 30, 2000 and $54.0 million at December 31, 1999.
The value has been adjusted for the new Special Units issued to Shell (as noted
previously), finalization of purchase accounting adjustments and related
amortization.
Effective July 1, 1999, the Company acquired Kinder Morgan Operating LP "A"'s
25% indirect ownership interest and Enterprise Products Company's ("EPCO") 0.5%
indirect ownership interest in a 210,000 barrel per day NGL fractionation
facility located in Mont Belvieu, Texas for approximately $42 million in cash
and the assumption of approximately $4 million in debt.
Both acquisitions were accounted for using the purchase method of accounting,
and accordingly, the purchase price of each has been allocated to the assets
purchased and liabilities assumed based on their estimated fair value at the
effective date of each transaction.
7
<PAGE>
Pro Forma effect of Acquisitions
The following table presents unaudited pro forma information for the three and
nine month periods ended September 30, 1999 as if the acquisition of TNGL from
Shell and the Mont Belvieu NGL fractionation facility from Kinder Morgan and
EPCO had been made as of January 1, 1999:
Three Nine
Months Months
Ended Ended
-----------------------------------
September 30, 1999
-----------------------------------
Revenues $ 506,944 $ 1,151,444
===================================
Net income $ 40,586 $ 80,698
===================================
Allocation of net income to
Limited partners $ 40,180 $ 79,891
===================================
General Partner $ 406 $ 807
===================================
Units used in earning per Unit calculations
Basic 66,696 66,715
===================================
Diluted 81,196 81,215
===================================
Income per Unit before minority interest
Basic $ 0.61 $ 1.21
===================================
Diluted $ 0.50 $ 0.99
===================================
Net income per Unit
Basic $ 0.60 $ 1.20
===================================
Diluted $ 0.49 $ 0.98
===================================
Diluted earnings per Unit do not include the pro rata effect of the 3.0 million
Contingency Units issued on August 1, 2000.
4. LONG-TERM DEBT
General. Long-term debt at September 30, 2000 was comprised of $350 million in
5-year public Senior Notes (the "$350 Million Senior Notes") issued by
Enterprise Products Operating L.P. (the "Operating Partnership"), a 10-year $54
million loan agreement with the Mississippi Business Finance Corporation ("MBFC"
and the "$54 Million MBFC Loan") and $50 million outstanding under the $350
Million Bank Credit Facility. The issuance of the $350 Million Senior Notes
represented a partial takedown of the $800 million universal shelf registration
(the "Registration Statement") that was filed with the Securities and Exchange
Commission in December 1999. The proceeds from the $350 Million Senior Notes and
the $54 Million MBFC Loan were used to extinguish all outstanding balances owed
under the $200 Million Bank Credit Facility and the $350 Million Bank Credit
Facility at the time of the offerings.
8
<PAGE>
The following table summarizes long-term debt at:
September 30, December 31,
2000 1999
--------------------------------------
Borrowings under:
$200 Million Bank Credit Facility $ 129,000
$350 Million Bank Credit Facility $ 50,000 166,000
$350 Million Senior Notes 350,000
$54 Million MBFC Loan 54,000
--------------------------------------
Total 454,000 295,000
Less current maturities of long-term debt 50,000 129,000
--------------------------------------
Long-term debt $ 404,000 $ 166,000
======================================
At September 30, 2000, the Operating Partnership had a total of $40 million of
standby letters of credit available of which approximately $13.3 million were
outstanding under letter of credit agreements with the banks.
$200 Million Bank Credit Facility. In July 1998, the Operating Partnership
entered into a $200 million bank credit facility that included a $50 million
working capital facility and a $150 million revolving credit facility. On March
15, 2000, the Operating Partnership used $169 million of the proceeds from the
issuance of the $350 Million Senior Notes to retire this credit facility in
accordance with its agreement with the banks.
$350 Million Bank Credit Facility. In July 1999, the Operating Partnership
entered into a $350 Million Bank Credit Facility that includes a $50 million
working capital facility and a $300 million revolving credit facility. The $300
million revolving credit facility includes a sublimit of $40 million for letters
of credit. Borrowings under the $350 Million 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 Operating Partnership elects
the basis for the interest rate at the time of each borrowing.
This facility is scheduled to 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. In March 2000, the Operating Partnership used $179
million of the proceeds from the issuance of the $350 Million Senior Notes and
$47 million from the $54 Million MBFC Loan to payoff the outstanding balance on
this credit facility. Due to borrowings in the third quarter for investment and
working capital purposes, $50 million was outstanding under this facility at
September 30, 2000.
The credit agreement relating to this facility contains a prohibition on
distributions to or purchases 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 Operating Partnership 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 credit agreement generally prohibits
redemptions of Units except for those transactions related to the 1,000,000 Unit
Buy-back Program announced in July 2000. In August 2000, the lenders and Company
executed a waiver allowing for this program. 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. The Operating Partnership was in compliance with the restrictive
covenants at September 30, 2000.
$350 Million Senior Notes. On March 13, 2000, the Operating Partnership
completed a public offering of $350 million in principal amount of 8.25%
fixed-rate Senior Notes due March 15, 2005 at a price to the public of 99.948%
per Senior Note. The Operating Partnership received proceeds, net of
underwriting discounts and commissions, of approximately $347.7 million. The
proceeds were used to pay the entire $169 million outstanding principal balance
9
<PAGE>
on the $200 Million Bank Credit Facility and $179 million of the $226 million
outstanding principal balance on the $350 Million Bank Credit Facility.
The $350 Million Senior Notes are subject to a make-whole redemption right by
the Operating Partnership. The notes are an unsecured obligation of the
Operating Partnership and rank equally with its existing and future unsecured
and unsubordinated indebtedness and senior to any future subordinated
indebtedness. The notes are guaranteed by the Company through an unsecured and
unsubordinated guarantee and were issued under an indenture containing certain
restrictive covenants. These covenants restrict the ability of the Company and
the Operating Partnership, with certain exceptions, to incur debt secured by
liens and engage in sale and leaseback transactions. The Company and Operating
Partnership were in compliance with the restrictive covenants at September 30,
2000.
Settlement was completed on March 15, 2000. The issuance of the $350 Million
Senior Notes was a takedown under the Company's $800 million Registration
Statement; therefore, the amount of securities available under the Registration
Statement have been reduced to $450 million.
$54 Million MBFC Loan. On March 27, 2000, the Operating Partnership executed a
$54 million loan agreement with the MBFC which was funded with proceeds from the
sale of Taxable Industrial Revenue Bonds ("Bonds") by the MBFC. The Bonds issued
by the MBFC are 10-year bonds with a maturity date of March 1, 2010 and bear a
fixed-rate interest coupon of 8.70%. The Operating Partnership received proceeds
from the sale of the Bonds, net of underwriting discounts and commissions, of
approximately $53.6 million. The proceeds were used to pay the remaining $47
million outstanding principal balance on the $350 Million Bank Credit Facility
and for working capital and other general partnership purposes. In general, the
proceeds of the Bonds were used to reimburse the Operating Partnership for costs
incurred in acquiring and constructing the Pascagoula, Mississippi natural gas
processing plant.
The Bonds were issued at par and are subject to a make-whole redemption right by
the Operating Partnership. The Bonds are guaranteed by the Company through an
unsecured and unsubordinated guarantee. The loan agreement contains certain
covenants including maintaining appropriate levels of insurance on the
Pascagoula natural gas processing facility and restrictions regarding mergers.
The Company was in compliance with the restrictive covenants at September 30,
2000.
5. CAPITAL STRUCTURE AND EARNINGS PER UNIT
Second Amended and Restated Agreement of Limited Partnership of the Company. The
Second Amended and Restated Agreement of Limited Partnership of the Company (the
"Partnership Agreement") sets forth the calculation to be used to determine the
amount and priority of cash distributions that the Common Unitholders,
Subordinated Unitholders and the General Partner will receive. The Partnership
Agreement also contains provisions for the allocation of net earnings and losses
to the Unitholders and the General Partner. For purposes of maintaining partner
capital accounts, the Partnership Agreement specifies that items of income and
loss shall be allocated among the partners in accordance with their respective
percentage interests. Normal allocations according to percentage interests are
done only, however, after giving effect to priority earnings allocations in an
amount equal to incentive cash distributions allocated 100% to the General
Partner. As an incentive, the General Partner's percentage interest in quarterly
distributions is increased after certain specified target levels are met. When
quarterly distributions exceed $0.506 per Unit, the General Partner receives a
percentage of the excess between the actual distribution rate and the target
level ranging from approximately 15% to 50% depending on the target level
achieved.
The Partnership Agreement generally authorizes the Company to issue an unlimited
number of additional limited partner interests and other equity securities of
the Company for such consideration and on such terms and conditions as shall be
established by the General Partner in its sole discretion without the approval
of the Unitholders. During the Subordination Period, however, the Company is
limited with regards to the number of equity securities that it may issue that
rank senior to Common Units (except for Common Units upon conversion of
Subordinated Units, pursuant to employee benefit plans, upon conversion of the
general partner interest as a result of the withdrawal of the General Partner or
in connection with acquisitions or capital improvements that are accretive on a
per Unit basis) or an equivalent number of securities ranking on a parity with
the Common Units, without the approval of the holders of at least a Unit
Majority. A Unit Majority is defined as at least a majority of the outstanding
10
<PAGE>
Common Units (during the Subordination Period), excluding Common Units held by
the General Partner and its affiliates, and at least a majority of the
outstanding Common Units (after the Subordination Period).
In April 2000, the Company mailed a Proxy Statement to its public Unitholders
asking them to consider and vote for a proposal to amend the Partnership
Agreement to increase the number of additional Common Units that may be issued
during the Subordination Period without the approval of a Unit Majority from
22,775,000 Common Units to 47,775,000 Common Units. The primary purpose of the
requested increase was to improve the future financial flexibility of the
Company since 20,500,000 Common Units of the 22,775,000 Common Units available
to the partnership during the Subordination Period were reserved for issuance in
connection with the TNGL acquisition. At a special meeting of the Unitholders
and General Partner held on June 9, 2000, this proposal was approved by 90.7% of
the public Unitholders. The amendment increases the number of Common Units
available (and unreserved) to the Company for general partnership purposes
during the Subordination Period from 2,275,000 to 27,275,000.
Subordinated Units. The 21,409,872 Subordinated Units have no voting rights
until converted into Common Units at the end of the Subordination Period. The
Subordination Period will generally extend until the first day of any quarter
beginning after June 30, 2003 when the Conversion Tests have been satisfied.
Generally, the Conversion Test will have been satisfied when the Company has
paid from Operating Surplus and generated from Adjusted Operating Surplus the
minimum quarterly distribution on all Units for each of the three preceding
four-quarter periods. Upon expiration of the Subordination Period, all remaining
Subordinated Units will convert into Common Units on a one-for-one basis and
will thereafter participate pro rata with the other Common Units in
distributions of Available Cash.
The Partnership Agreement stipulates that 50% of the Subordinated Units (or
10,704,936 Subordinated Units) may undergo an early conversion into Common Units
should certain criteria be satisfied. Based upon these criteria, the earliest
that the first 25% of the Subordinated Units (or 5,352,468 Subordinated Units)
would convert into Common Units is April 1, 2002. Should the criteria continue
to be satisfied through the first quarter of 2003, an additional 25% of the
Subordinated Units would undergo an early conversion into Common Units on April
1, 2003. The remaining 10,704,936 Subordinated Units would convert into Common
Units on July 1, 2003 should the balance of the conversion requirements be met.
Special Units. The Special Units issued to Shell do not accrue distributions and
are not entitled to cash distributions until their conversion into Common Units.
For financial accounting purposes, the Special Units are allocated a portion of
net income based on the ownership interest that such Units represent. For tax
purposes, the Special Units generally are not allocated a portion of net income
but are allocated a certain amount of depreciation until their conversion into
Common Units. On August 1, 2000, 1.0 million of the original tranche of 14.5
million Special Units converted into Common Units. The remaining 13.5 million
Special Units of the original tranche will automatically convert into Common
Units as follows: 5.0 million Units on August 1, 2001 and 8.5 million Units on
August 1, 2002.
On June 28, 2000, Shell met certain year 2000 performance criteria for the
issuance of 3.0 million non-distribution bearing, convertible Contingency Units
(referred to as the "second tranche" of Special Units). Per an agreement with
Shell, the Company issued the second tranche of Special Units on August 1, 2000.
Shell has the opportunity to earn an additional 3.0 million non-distribution
bearing, convertible Contingency Units (i.e., a "third tranche" of Special
Units) based on certain performance criteria for calendar year 2001.
Specifically, Shell will earn the third tranche of Special Units if at any point
during calendar year 2001 (or extensions thereto due to force majeure events)
gas production by Shell from its offshore Gulf of Mexico producing properties
and leases is 900 million cubic feet per day for 180 not-necessarily-consecutive
days or 350 billion cubic feet on a cumulative basis. If the year 2001
performance test 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 majeure events), Shell would still earn
the third tranche of Special Units. If both the second and third tranches of
Special Units are earned, 1.0 million of these Special Units would convert into
Common Units on August 1, 2002 and 5.0 million of these Special Units would
convert into Common Units on August 1, 2003. Special Units issued to Shell as
part of these contingent agreements do not accrue distributions and are not
entitled to cash distributions until conversion into Common Units. With regards
to income and depreciation allocation from either a financial accounting or tax
basis, these Special Units will be treated identically to the 14.5 million
Special Units originally issued.
11
<PAGE>
Under the rules of the New York Stock Exchange, the conversion feature of the
Special Units into Common Units requires approval of the Company's Unitholders.
With respect to the August 2000 conversion, EPC Partners II, Inc. ("EPC II"),
which owns in excess of 81% of the outstanding Common Units, voted its Units in
favor of conversion, which provided the necessary votes for approval.
Units Acquired by Trust. 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, 2000, 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.
On May 12, 2000, the Company filed a Registration Statement with the Securities
and Exchange Commission for the transfer of up to (i) 1,000,000 Common Units to
fund a long-term incentive plan established by the General Partner and (ii)
1,000,000 Common Units to fund a long-term incentive plan established by
Enterprise Products Company.
Earnings per Unit. The Company has no dilutive securities that would require
adjustment to net income for the computation of diluted earnings per Unit. The
following is a reconciliation of the number of units used in the computation of
basic and diluted earnings per Unit for all periods presented.
<TABLE>
<CAPTION>
For Three Months Ended For Nine Months Ended
At September 30, At September 30,
2000 1999 2000 1999
----------------------------- -----------------------------
<S> <C> <C> <C> <C>
Weighted average number of Common
and Subordinated Units outstanding 67,356 66,696 66,917 66,715
Weighted average number of Special
Units to be converted to Common Units 15,826 9,614 14,945 3,240
----------------------------- -----------------------------
Units used to compute diluted
earnings per Unit 83,182 76,310 81,862 69,955
============================= =============================
</TABLE>
The second tranche of Special Units (formerly Contingency Units, as described
above) are included in diluted earnings per Unit calculation beginning August 1,
2000 (the effective date of the contingent agreement between Shell and the
Company). The Contingency Units relating to the third tranche of Special Units
to be issued upon achieving certain performance criteria in future periods have
been excluded from diluted earnings per Unit because such tests have not been
met at September 30, 2000.
6. DISTRIBUTIONS
The Company intends, to the extent there is sufficient available cash from
Operating Surplus, as defined by the Partnership Agreement, to distribute to
each holder of Common Units at least a minimum quarterly distribution of $0.45
per Common Unit. The minimum quarterly distribution is not guaranteed and is
subject to adjustment as set forth in the Partnership Agreement. With respect to
each quarter during the Subordination Period, which will generally not end
before June 30, 2003, the Common Unitholders will generally have the right to
receive the minimum quarterly distribution, plus any arrearages thereon, and the
General Partner will have the right to receive the related distribution on its
interest before any distributions of available cash from Operating Surplus are
made to the Subordinated Unitholders. As an incentive, the General Partner's
interest in quarterly distributions is increased after certain specified target
levels are met (see Note 5 discussion regarding incentive distributions under
the section titled Second Amended and Restated Agreement of Limited Partnership
of the Company.) The Company made incentive cash distributions to the General
Partner of $0.2 million on August 10, 2000 and $0.2 million on November 10,
2000 for the second and third quarter of 2000, respectively.
12
<PAGE>
On January 17, 2000, the Company declared an increase in its quarterly cash
distribution to $0.50 per Unit. This amount was subsequently raised to $0.525
per Unit on July 17, 2000.
The following is a summary of cash distributions to partnership interests since
the first quarter of 1999:
<TABLE>
<CAPTION>
Cash Distributions
--------------------------------------------------------------------------
Per Common Per Subordinated Record Payment
Unit Unit Date Date
--------------------------------------------------------------------------
1999
<S> <C> <C> <C> <C>
First Quarter $ 0.450 $ 0.450 January 29, 1999 February 11, 1999
Second Quarter $ 0.450 $ 0.070 April 30, 1999 May 12, 1999
Third Quarter $ 0.450 $ 0.370 July 30, 1999 August 11, 1999
Fourth Quarter $ 0.450 $ 0.450 October 29, 1999 November 10, 1999
2000
First Quarter $ 0.500 $ 0.500 January 31, 2000 February 10, 2000
Second Quarter $ 0.500 $ 0.500 April 28, 2000 May 10, 2000
Third Quarter $ 0.525 $ 0.525 July 31, 2000 August 10, 2000
Fourth Quarter $ 0.525 $ 0.525 October 31, 2000 November 10, 2000
(through November 13, 2000)
</TABLE>
7. SUPPLEMENTAL CASH FLOW DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Nine Months Ended
September 30,
2000 1999
------------------------------------
(Increase) decrease in:
Accounts receivable $ (15,409) $ (48,448)
Inventories (66,270) (64,992)
Prepaid and other current assets 1,297 (4,647)
Intangible assets (4,805) -
Other assets (5,419) (1,757)
Increase (decrease) in:
Accounts payable 7,109 43,944
Accrued gas payable 47,517 61,474
Accrued expenses (6,314) 1,236
Other current liabilities 12,749 (21,595)
Other liabilities (397) 539
------------------------------------
Net effect of changes in operating accounts $ (29,942) $ (34,246)
====================================
Capital expenditures for the first nine months of 2000 were $200.2 million
compared to $10.6 million for the same period in 1999. Capital expenditures in
2000 included $99.6 million for the purchase of the Lou-Tex Propylene Pipeline
and related assets, $71.5 million in construction costs for the Lou-Tex NGL
Pipeline and $4.1 million in construction costs for the Neptune gas processing
facility.
The purchase of the Lou-Tex Propylene Pipeline and related assets from Concha
Chemical Pipeline Company, an affiliate of Shell, was completed on February 25,
2000. The effective date of the transaction was March 1, 2000. The Lou-Tex
Propylene Pipeline is a 263-mile, 10" pipeline that transports chemical grade
propylene from Sorrento, Louisiana to Mont Belvieu, Texas. Also acquired in this
transaction was 27.5 miles of 6" ethane pipeline between Sorrento and Norco,
Louisiana, and a 0.5 million barrel storage cavern at Sorrento, Louisiana.
13
<PAGE>
8. RECENTLY ISSUED ACCOUNTING STANDARDS
In December 1999, the Securities and Exchange Commission ("SEC") issued Staff
Accounting Bulletin ("SAB") No. 101 " Revenue Recognition in Financial
Statements." SAB 101 summarizes certain of the staff's views in applying
generally accepted accounting principles to revenue recognition in financial
statements. On June 26, 2000, the SEC issued an amendment to SAB 101 effectively
delaying its implementation until the fourth quarter of fiscal years beginning
after December 15, 1999. The Company believes that the adoption of SAB 101 will
not have a material effect on its results of operations.
In June 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 the application of SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities" for one year, to fiscal years beginning after June 15,
2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - an amendment of FASB
Statement No. 133" which amends and supercedes various sections of SFAS No. 133.
Management is currently studying SFAS No. 133 and its amendments for their
possible impact on the consolidated financial statements when they are adopted
in January 2001.
9. FINANCIAL INSTRUMENTS
The Company enters into swaps and other contracts to hedge the price risks
associated with inventories, commitments and certain anticipated transactions.
The Company does not currently hold or issue financial instruments for trading
purposes. The swaps and other contracts are with established energy companies
and major financial institutions. The Company believes its credit risk is
minimal on these transactions, as the counterparties are required to meet
stringent credit standards. There is continuous day-to-day involvement by senior
management in the hedging decisions, operating under resolutions adopted by the
board of directors of the General Partner.
Interest Rate Swaps. The Company's interest rate exposure results from
variable-rate borrowings from commercial banks and fixed-rate borrowings
pursuant to the $350 Million Senior Notes and the $54 Million MBFC Loan. The
company manages its exposure to changes in interest rates in its consolidated
debt portfolio by utilizing interest rate swaps. An interest rate swap, in
general, requires one party to pay a fixed-rate on the notional amount while the
other party pays a floating-rate based on the notional amount.
In March 2000, after the issuance of the $350 Million Senior Notes and the
execution of the $54 Million MBFC Loan, 100% of the Operating Partnership's
consolidated debt were fixed-rate obligations. To maintain a balance between
variable-rate and fixed-rate exposure, the Operating Partnership entered into
interest rate swap agreements with a notional amount of $154 million by which
the Operating Partnership receives payments based on a fixed-rate and pays an
amount based on a floating-rate. At September 30, 2000, the Operating
Partnership's consolidated debt portfolio interest rate exposure was 55 percent
fixed and 45 percent floating, after considering the effect of the interest rate
swap agreements. The notional amount does not represent exposure to credit loss.
The Operating Partnership monitors its positions and the credit ratings of its
counterparties. Management believes the risk of incurring a credit related loss
is remote, and that if incurred, such losses would be immaterial.
14
<PAGE>
The effect of these swaps (none of which are leveraged) was to decrease the
Company's interest expense by $0.4 million and $0.9 million for the three and
nine months ended September 30, 2000, respectively. Following is selected
information on the Company's portfolio of interest rate swaps at September 30,
2000:
Interest Rate Swap Portfolio at September 30, 2000 (1) :
(Dollars in millions)
Early Fixed /
Notional Termination Floating
Amount Period Covered Date (2) Rate (3)
--------------------------------------------------------------------------------
$ 50.0 March 2000 - March 2005 March 2001 8.25% / 7.3100%
$ 50.0 March 2000 - March 2005 March 2001 8.25% / 7.3150%
$ 54.0 March 2000 - March 2010 March 2003 8.70% / 7.6575%
Notes:
(1) All swaps outstanding at September 30, 2000 were entered into for the
purpose of managing the Operating Partnership's exposure to fluctuations in
market interest rates.
(2) In each case, the counterparty has the option to terminate the interest
rate swap on the Early Termination Date
(3) In each case, the Operating Partnership is the floating-rate payor. The
floating rate was the rate in effect as of September 30, 2000.
10. SEGMENT INFORMATION
The Company has five reportable operating segments: Fractionation, Pipeline,
Processing, Octane Enhancement and Other. Fractionation includes NGL
fractionation, butane isomerization (converting normal butane into high purity
isobutane) and polymer grade propylene fractionation services. Pipeline consists
of pipeline, storage and import/export terminal services. Processing includes
the natural gas processing business and its related NGL merchant activities.
Octane Enhancement represents the Company's 33.33% ownership interest in a
facility that produces motor gasoline additives to enhance octane (currently
producing MTBE). The Other operating segment consists of fee-based marketing
services and other plant support functions.
Operating segments are components of a business about which separate financial
information is available that is evaluated regularly by the chief operating
decision maker in deciding how to allocate resources and in assessing
performance. Generally, financial information is required to be reported on the
basis that it is used internally for evaluating segment performance and deciding
how to allocate resources to segments.
The management of the Company evaluates segment performance on the basis of
gross operating margin. Gross operating margin reported for each segment
represents operating income before depreciation and amortization, lease expense
obligations retained by EPCO, gains and losses on the sale of assets and general
and administrative expenses. In addition, segment gross operating margin is
exclusive of interest expense, interest income (from unconsolidated affiliates
or others), dividend income from unconsolidated affiliates, minority interest,
extraordinary charges and other income and expense transactions. The Company's
equity earnings from unconsolidated affiliates are included in segment gross
operating margin.
Consolidated property, plant and equipment and investments in and advances to
unconsolidated affiliates are allocated to each segment on the basis of each
asset's or investment's principal operations. The principal reconciling item
between consolidated property, plant and equipment and segment property, plant
and equipment is construction-in-progress. Segment property, plant and equipment
represents those facilities and projects that contribute to gross operating
margin. Since assets under construction do not generally contribute to segment
gross operating margin, these assets are not included in the operating segment
totals until they are deemed operational.
Segment gross operating margin is inclusive of intersegment revenues. These
revenues have been eliminated from the consolidated totals.
15
<PAGE>
Information by operating segment, together with reconciliations to the
consolidated totals, is presented in the following table:
<TABLE>
<CAPTION>
Operating Segments Adjustments
-----------------------------------------------------------------
Octane and Consolidated
Fractionation Pipelines Processing Enhancement Other Eliminations Totals
-------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external customers
Three months ended September 30, 2000 $ 120,227 $ (1,864) $ 605,875 $ 2,191 $ 793 $ (5,359) $ 721,863
Three months ended September 30, 1999 56,278 6,059 387,218 2,519 - (7,046) 445,028
Nine months ended September 30, 2000 322,793 25,998 1,730,976 13,003 2,059 (15,232) 2,079,597
Nine months ended September 30, 1999 174,427 14,160 610,729 4,756 - (32,688) 771,384
Intersegment revenues
Three months ended September 30, 2000 46,538 12,083 165,761 - 93 (224,475) -
Three months ended September 30, 1999 49,353 9,815 62,299 - 123 (121,590) -
Nine months ended September 30, 2000 129,266 40,108 447,646 - 282 (617,302) -
Nine months ended September 30, 1999 86,713 27,126 62,336 - 327 (176,502) -
Total revenues
Three months ended September 30, 2000 166,765 10,219 771,636 2,191 886 (229,834) 721,863
Three months ended September 30, 1999 105,631 15,874 449,517 2,519 123 (128,636) 445,028
Nine months ended September 30, 2000 452,059 66,106 2,178,622 13,003 2,341 (632,534) 2,079,597
Nine months ended September 30, 1999 261,140 41,286 673,065 4,756 327 (209,190) 771,384
Gross operating margin by segment
Three months ended September 30, 2000 32,510 10,292 29,083 2,190 429 - 74,504
Three months ended September 30, 1999 36,142 6,985 7,110 2,519 170 - 52,926
Nine months ended September 30, 2000 96,432 39,120 87,123 13,002 1,854 - 237,531
Nine months ended September 30, 1999 78,955 15,836 6,677 4,756 651 - 106,875
Property, plant and equipment
At September 30, 2000 358,802 356,307 127,001 - 1,062 98,664 941,836
At December 31, 1999 362,198 249,453 122,495 - 113 32,810 767,069
Investments in and advances
to unconsolidated affiliates
At September 30, 2000 98,998 86,219 33,000 61,989 - - 280,206
At December 31, 1999 99,110 85,492 33,000 63,004 - - 280,606
</TABLE>
Pipeline revenues for the three months ended September 30, 2000 include the
impact of a $9.8 million intercompany elimination between revenues and operating
costs and expenses (attributable to the second quarter of 2000). Since the
decrease in revenues is offset by an equal decrease in operating costs and
expenses, there was no impact on gross operating margin as a result of the
reclassification.
16
<PAGE>
A reconciliation of segment gross operating margin to consolidated income before
minority interest follows:
<TABLE>
<CAPTION>
For Three Months Ended For Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
--------------------------------- ----------------------------------
<S> <C> <C> <C> <C>
Total segment gross operating margin $ 74,504 $ 52,926 $ 237,531 $ 106,875
Depreciation and amortization (9,029) (7,012) (25,907) (16,368)
Retained lease expense, net (2,660) (2,645) (7,984) (7,978)
Loss on sale of assets 27 1 (2,276) (122)
Selling, general and administrative (6,978) (3,200) (20,020) (9,200)
--------------------------------- ----------------------------------
Consolidated operating income 55,864 40,070 181,344 73,207
Interest expense (7,486) (4,515) (23,330) (8,907)
Interest income (expense) from unconsolidated affiliates (88) 407 182 1,096
Dividend income from unconsolidated affiliates 2,241 - 6,236 -
Interest income - other 317 682 3,023 1,114
Other, net (71) 72 (496) 117
--------------------------------- ----------------------------------
Consolidated income before minority interest $ 50,777 $ 36,716 $ 166,959 $ 66,627
================================= ==================================
</TABLE>
11. SUBSEQUENT EVENTS
On September 25, 2000, the Company announced that its Operating Partnership has
executed a definitive agreement to purchase Acadian Gas, LLC ("Acadian") from
Coral Energy, LLC, an affiliate of Shell Oil Company, for $226 million in cash,
inclusive of working capital. The acquisition of Acadian integrates natural gas
pipeline systems in South Louisiana with the Company's Gulf Coast natural gas
processing and NGL fractionation, pipeline and storage system. Acadian's assets
are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline
natural gas pipeline systems, which together have over one billion cubic feet
("Bcf") per day of capacity. These natural gas pipeline systems are wholly-owned
by Acadian, with the exception of the Evangeline system in which Acadian holds
an approximate 49.5% economic interest. The system includes a leased natural gas
storage facility at Napoleonville, Louisiana with 3.4 Bcf of capacity.
Completion of this transaction is subject to certain conditions, including
regulatory approvals. The purchase is expected to be completed in the fourth
quarter of 2000.
On October 6, 2000, the Company announced that a subsidiary had purchased an
additional 3,521 shares of common stock of Dixie from Conoco Pipe Line Company
for approximately $19.4 million. The purchase brings the Company's economic
interest in Dixie to 19.9%.
17
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
For the Interim Periods ended September 30, 2000 and 1999
The following discussion and analysis should be read in conjunction
with the unaudited consolidated financial statements and notes thereto of
Enterprise Products Partners L.P. (the "Company") included elsewhere herein. All
references herein to "Shell", unless the context indicates otherwise, shall
refer collectively to Shell Oil Company, its subsidiaries and affiliates.
Uncertainty of Forward-Looking Statements and Information
MD&A contains various forward-looking statements and information that
are based on the belief of the Company and the General Partner, as well as
assumptions made by and information currently available to the Company and the
General Partner. When used in this document, words such as "anticipate,"
"estimate," "project," "expect," "plan," "forecast," "intend," "could,"
"believe," 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 due to weather and other
concerns, (c) operational and systems risks, (d) environmental liabilities that
are not covered by indemnity or insurance, (e) the impact of current and future
laws and governmental regulations (including environmental regulations)
affecting the NGL industry in general, and the Company's operations in
particular, (f) loss of a significant customer, and (g) failure to complete one
or more new projects on time or within budget.
In addition, the Company's expectations regarding its future capital
expenditures as described in "Liquidity and Capital Resources" are only its
forecasts regarding these matters. In addition to the factors described in the
previous paragraph, these forecasts may be substantially different from actual
results, which are affected by the following major factors: (a) the accuracy of
the Company's estimates regarding its spending requirements, (b) the occurrence
of any unanticipated acquisition opportunities, (c) the need to replace any
unanticipated losses in capital assets, (d) changes in the strategic direction
of the Company and (e) unanticipated legal, regulatory and contractual
impediments with regards to its construction projects.
Company Overview
The Company is a leading integrated North American provider of natural
gas processing and natural gas liquids ("NGL" or "NGLs") fractionation,
transportation and storage services to producers of NGLs and consumers of NGL
products. The Company is a publicly traded master limited partnership (NYSE,
symbol "EPD") that conducts substantially all of its business through Enterprise
Products Operating L.P. (the "Operating Partnership"), the Operating
Partnership's subsidiaries, and a number of joint ventures with industry
partners. The Company was formed in April 1998 to acquire, own, and operate all
of the NGL processing and distribution assets of Enterprise Products Company
("EPCO"). The general partner of the Company, Enterprise Products GP, LLC (the
"General Partner"), a majority-owned subsidiary of EPCO, holds a 1.0% general
partner interest in the Company and a 1.0101% general partner interest in the
Operating Partnership.
The principal executive office of the Company is located at 2727 North
Loop West, Houston, Texas, 77008-1038, and the telephone number of that office
is 713-880-6500. References to, or descriptions of, assets and operations of the
Company in this document include the assets and operations of the Operating
Partnership and its subsidiaries.
18
<PAGE>
The Company (i) processes natural gas into a merchantable and
transportable form of energy that meets industry quality specifications by
removing NGLs and impurities; (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 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 the Company operates at Mont Belvieu include: (a) one of
the largest NGL fractionation facilities in the United States with an average
gross production capacity of 210 thousand barrels per day ("MBPD"); (b) the
largest butane isomerization complex in the United States with an average
isobutane production capacity of 116 MBPD; (c) a MTBE production facility with
an average gross production capacity of 15 MBPD; and (d) two propylene
fractionation units with an average combined production capacity of 31 MBPD. The
Company owns all of the assets at its Mont Belvieu facility except for the NGL
fractionation facility, in which it owns an effective 62.5% economic interest;
one of the propylene fractionation units, in which it owns a 54.6% interest and
controls the remaining interest through a long-term lease; the MTBE production
facility, in which it owns a 33.33% interest; and one of its three isomerization
units and one deisobutanizer which are held under long-term leases with purchase
options.
The Company's operations in Louisiana and Mississippi include varying
interests in eleven natural gas processing plants with a combined capacity of
11.0 billion cubic feet per day ("Bcfd") and net capacity of 3.1 Bcfd, five NGL
fractionation facilities with a combined gross capacity of 341 MBPD and net
capacity of 151 MBPD and a propylene fractionation facility with a gross
capacity of 22.5 MBPD and net capacity of 6.8 MBPD. In addition, the Company
owns and operates a NGL fractionation facility in Petal, Mississippi with an
average production capacity of 7 MBPD.
The Company owns, operates or has an interest in approximately 65.0
million barrels of gross storage capacity (44.3 million barrels of net capacity)
in Texas, Louisiana and Mississippi that are an integral part of its processing
operations. The Company also leases and operates one of only two commercial NGL
import/export terminals on the Gulf Coast. In addition, the Company has
operating and non-operating ownership interests in over 2,900 miles of NGL
pipelines along the Gulf Coast (including the 206-mile Lou-Tex NGL Pipeline
currently under construction and expected in service during the fourth quarter
of 2000).
The Company's operating margins are derived from services provided to
its tolling customers and from merchant activities. In the Company's toll
processing operations, it does not take title to the product and is simply paid
a fee based on volumes processed, transported, stored or handled. The Company's
profitability from toll processing operations depends primarily on the volumes
of natural gas, NGLs and refinery-sourced propane/propylene mix processed and
transported and the level of associated fees charged to its customers. In the
Company's isomerization merchant activities and to a certain extent its
propylene fractionation business, it takes title to feedstock products and sells
processed end products. The Company's profitability from these merchant
activities is dependent on the prices of feedstocks and end products, which may
vary on a seasonal basis. In the Company's propylene fractionation business and
isomerization business, the Company generally attempts to match the timing and
price of its feedstock purchases with those of the sales of end products so as
to reduce exposure to fluctuations in commodity prices. The Company's operating
margins from its natural gas processing business are generally derived from the
margins earned on the sale of purity NGL products extracted from natural gas
streams. To the extent it takes title to the NGLs removed from the natural gas
stream and reimburses the producer for the reduction in the British thermal unit
("Btu") content and/or the natural gas used as fuel (the "PTR" or "shrinkage"),
the Company's margins are affected by the prices of NGLs and natural gas.
Management uses financial instruments to reduce its exposure to the change in
the prices of NGLs and natural gas.
19
<PAGE>
The Company will continue to analyze potential acquisitions, joint
ventures or similar transactions with businesses that operate in complementary
markets and geographic regions. In recent years, major oil and gas companies
have sold non-strategic assets including assets in the midstream natural gas
industry in which the Company operates. Management believes that this trend will
continue, and the Company expects independent oil and natural gas companies to
consider similar options. In the last two years, the Company has announced
several acquisitions, the largest of which are Tejas Natural Gas Liquids, LLC
("TNGL") (completed in the third quarter of 1999) and Acadian Gas, LLC
("Acadian") (announced in September 2000 and pending completion). See "Recent
Acquisitions" under the "Results of Operations of the Company" section below for
further details on these and other acquisition transactions.
Business Environment
The domestic and international economies continue to be strong,
creating firm demand for the products and services of the U. S. NGL industry.
Each of the Company's business segments have benefited from steady domestic and
international demand for NGLs, petroleum liquids and MTBE.
During the first nine months of 2000, the Company's natural gas
processing business was running at optimal levels due to a strong NGL price
environment and robust demand for natural gas processing services by producers
such as Shell, the Company's largest natural gas processing customer. The strong
NGL price environment has supported full NGL recovery at the Company's gas
processing plants. Recent increases in natural gas prices may moderate maximum
recovery levels for some NGL products (primarily ethane) during the fourth
quarter of 2000. An increase in natural gas production that is high in NGL
content, which will be available for processing as producers respond to the high
natural gas price environment, is expected to offset to some degree the
potential decline in product recovery levels.
The Company's NGL production in 2000 has significantly increased over
1999 levels as a result of steady to growing levels of natural gas production
available for processing, higher NGL content natural gas and new processing
facilities, such as the Company's Neptune plant. Neptune was brought on-line in
February 2000 and is now producing in excess of 16 MBPD. For the three and nine
months ended September 30, 2000, equity NGL production at the Company's gas
processing facilities averaged 73 MBPD and 72 MBPD, respectively, as compared to
65 MBPD during the third quarter of 1999. Management believes that the Company's
equity NGL production volumes will continue to increase during 2001. This
increase will result from gas production coming on-line from several new Gulf of
Mexico gas fields to which the Company holds gas processing rights, the most
significant of which is Shell's deepwater Brutus development (with expected
equity NGL production of 10 MBPD by the end of 2001).
The highly competitive environment in which the Company's Mont Belvieu
NGL fractionators operate has continued to suppress NGL fractionation fees at
these facilities. The Company has and is continuing to aggressively acquire new
and reacquire previous NGL fractionation customers, along with offering
competitively-priced bundled service packages involving transportation,
fractionation and other services. These service packages allow the Company to
take full advantage of its presence throughout the entire Gulf Coast NGL value
chain. As a result of these efforts, throughput at the Mont Belvieu NGL
fractionation facility has increased significantly in 2000. For the three and
nine months ended September 30, 2000, throughput averaged 174 MBPD and 169 MBPD,
respectively, as compared to 149 MBPD and 155 MBPD during the same periods in
1999. Throughput levels at the Company's Louisiana NGL fractionation facilities
have also increased due to additional production from gas processing facilities.
With the completion of the Lou-Tex NGL Pipeline in the fourth quarter of 2000,
the Company will be positioned to fully utilize its Mont Belvieu NGL
fractionation facilities to process NGL's from Louisiana starting in the first
quarter of 2001.
The demand for the Company's commercial isomerization services depends
on requirements for isobutane in excess of naturally occurring isobutane that is
produced from NGL fractionation and refinery operations. The market for these
services has been firm in 2000 due to the continued need for isobutane for
alkylation, propylene oxide, and as a feedstock for MTBE. Management expects
that this market will remain steady throughout the remainder of 2000.
20
<PAGE>
During the third quarter of 2000, the rapid price increase for
propylene experienced during the first half of 2000 began to reverse. During the
first half, propylene prices were driven by the dramatic increases in crude oil
and NGL prices. These factors contributed to similar increases in the cost for
ethylene and propylene from steam crackers and for refinery grade propylene
produced by refineries. In addition, the price spike in motor gasoline created a
very competitive market for refinery grade propylene used in the production of
alkylate which is blended to motor gasoline. With the perceived stabilization
and potential softening in crude oil prices, propylene buyers have been
successful in achieving price reductions by reducing purchases and consuming
inventory. Contract prices for polymer grade propylene increased from
approximately 19.5 cents per pound at the beginning of 2000 to 27.5 cents per
pound by the end of June. By the end of September, the contract price had
slipped to 24 cents per pound. Management anticipates that prices will continue
to soften throughout the remainder of this year with the price leveling out to
that seen in the beginning of 2000. The Company is exposed to these price
decreases only to the extent that it sells product pursuant to long-term
agreements with market-based pricing or spot market transactions.
Favorable domestic economic conditions have led to an increase in
demand for the Company's pipeline transportation services as NGL feedstocks and
products are being consumed at record levels throughout the Gulf Coast region.
Pipeline throughput has also increased as a result of strategic acquisitions
made by the Company, such as the purchase of the Lou-Tex Propylene Pipeline in
the first quarter of 2000. The Company expects pipeline throughput to continue
to increase as new projects such as the Lou-Tex NGL Pipeline become operational.
The Company anticipates using the Lou-Tex NGL Pipeline to transport NGL products
and mixed propane/propylene streams between the Louisiana and Texas markets to
take advantage of product value differentials between the two regions in
addition to transporting production from Louisiana gas processing facilities to
Mont Belvieu for fractionation.
During the second quarter of 2000, Belvieu Environmental Fuels' ("BEF")
MTBE operations benefited from tight international supplies as Middle East MTBE
volumes were diverted to European countries instead of the United States. The
spot price increased to near record levels in the second quarter of 2000 when
the lower imports were met with the increased seasonal demands from domestic
gasoline producers. During the second quarter of 2000, MTBE prices reached near
record levels averaging $1.32 per gallon ($1.58 during the month of June). As
refiners decreased demand and imports returned to the domestic market, MTBE
market prices began to decline in the third quarter to approximately $1.11 per
gallon by the end of September. The Company's operating results from its Octane
Enhancement segment are impacted by changes in market prices since BEF's
contract with Sunoco, Inc. R&M ("Sun"), which is contracted to purchase 100% of
BEF's MTBE production, is based on a market-related negotiated price. As a
result, management believes that gross operating margin in this segment will be
affected by seasonal variations in the demand for motor gasoline which is
normally greater in the April to September period (i.e., the summer driving
season) than the October to March period. Management expects fourth quarter of
2000 gross operating margin from Octane Enhancement will be less than the
results posted for the third quarter of 2000.
21
<PAGE>
The following table illustrates selected average quarterly prices for
natural gas, crude oil, selected NGL products and polymer grade propylene
since the first quarter of 1999:
<TABLE>
<CAPTION>
Polymer
Natural Normal Grade
Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene,
$/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound
(a) (b) (c) (c) (c) (c) (c)
-----------------------------------------------------------------------------------------
Fiscal 1999:
<S> <C> <C> <C> <C> <C> <C> <C>
First quarter $1.70 $13.05 $0.20 $0.24 $0.29 $0.31 $0.12
Second quarter $2.12 $17.66 $0.27 $0.31 $0.37 $0.38 $0.13
Third quarter $2.56 $21.74 $0.34 $0.42 $0.49 $0.49 $0.16
Fourth quarter $2.52 $24.54 $0.30 $0.41 $0.52 $0.52 $0.19
Fiscal 2000:
First quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21
Second quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26
Third quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26
</TABLE>
Notes:
(a) Natural gas, NGL and polymer grade propylene prices represent an average of
index prices
(b) Crude Oil price is representative of West Texas Intermediate
Results of Operation of the Company
The Company has five reportable operating segments: Fractionation,
Pipeline, Processing, Octane Enhancement and Other. Fractionation includes NGL
fractionation, butane isomerization (converting normal butane into high purity
isobutane) and polymer grade propylene fractionation services. Pipeline consists
of pipeline, storage and import/export terminal services. Processing includes
the natural gas processing business and its related NGL merchant activities.
Octane Enhancement represents the Company's 33.33% ownership interest in a
facility that produces motor gasoline additives to enhance octane (currently
producing MTBE). The Other operating segment consists of fee-based marketing
services and other plant support functions.
The management of the Company evaluates segment performance on the
basis of gross operating margin ("gross operating margin" or "margin"). Gross
operating margin reported for each segment represents operating income before
depreciation and amortization, lease expense obligations retained by EPCO, gains
and losses on the sale of assets and general and administrative expenses. In
addition, segment gross operating margin is exclusive of interest expense,
interest income (from unconsolidated affiliates or others), dividend income from
unconsolidated affiliates, minority interest, extraordinary charges and other
income and expense transactions. The Company's equity earnings from
unconsolidated affiliates are included in segment gross operating margin.
22
<PAGE>
The Company's gross operating margin by segment (in thousands of
dollars) along with a reconciliation to consolidated operating income for the
three and nine month periods ended September 30, 2000 and 1999 were as follows:
<TABLE>
<CAPTION>
For Three Months Ended For Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
----------------------------------- -----------------------------------
Gross Operating Margin by segment:
<S> <C> <C> <C> <C>
Fractionation $ 32,510 $ 36,142 $ 96,432 $ 78,955
Pipeline 10,292 6,985 39,120 15,836
Processing 29,083 7,110 87,123 6,677
Octane enhancement 2,190 2,519 13,002 4,756
Other 429 170 1,854 651
----------------------------------- -----------------------------------
Gross Operating margin total 74,504 52,926 237,531 106,875
Depreciation and amortization 9,029 7,012 25,907 16,368
Retained lease expense, net 2,660 2,645 7,984 7,978
Loss (gain) on sale of assets (27) (1) 2,276 122
Selling, general and administrative expenses 6,978 3,200 20,020 9,200
----------------------------------- -----------------------------------
Consolidated operating income $ 55,864 $ 40,070 $ 181,344 $ 73,207
=================================== ===================================
</TABLE>
The Company's significant plant production and other volumetric data
(in thousands of barrels per day on an equity basis) for the three and nine
month periods ended September 30, 2000 and 1999 were as follows:
<TABLE>
<CAPTION>
For Three Months Ended For Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
----------------------------------- -----------------------------------
Plant production and operating data:
<S> <C> <C> <C> <C>
NGL Production 73 65 72 65
NGL Fractionation 214 201 215 178
Isomerization 84 77 77 73
Propylene Fractionation 34 26 31 27
MTBE 6 4 5 4
Major Pipelines 278 264 323 230
</TABLE>
In order to more accurately compare operating rates between the 2000
and 1999 periods, the 1999 volumes associated with the assets acquired from TNGL
have been adjusted to reflect the period in which the Company owned them.
Recent Acquisitions
1999 Acquisitions. The Company completed two acquisitions during the
third quarter of 1999. Effective August 1, 1999, the Company acquired TNGL from
Shell, in exchange for 14.5 million non-distribution bearing, convertible
special partnership Units of the Company and $166 million in cash. The Company
also agreed to issue up to 6.0 million additional non-distribution bearing
special partnership Units to Shell in the future if the volumes of natural gas
that the Company processes for Shell reach agreed upon levels in 2000 and 2001.
The first 3.0 million of these additional special partnership Units were issued
on August 1, 2000.
The businesses acquired from Shell include natural gas processing and
NGL fractionation, transportation and storage in Louisiana and Mississippi and
its NGL supply and merchant business. The assets acquired include varying
interests in eleven natural gas processing plants, four NGL fractionation
facilities, four NGL storage facilities, operator and non-operator ownership
interests in approximately 1,500 miles of NGL pipelines, and a 20-year natural
gas processing agreement with Shell. The Company accounted for this acquisition
23
<PAGE>
using the purchase method. The value of the 20-year natural gas processing
agreement (classified as an Intangible Asset on the balance sheet) was $80.2
million at September 30, 2000 and $54.0 million at December 31, 1999. The value
has been adjusted for the 3.0 million additional special partnership Units
issued to Shell on August 1, 2000, finalization of purchase accounting
adjustments and related amortization.
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 Operating LP "A" ("Kinder Morgan") for a purchase
price of approximately $41.2 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. This acquisition (referred to as the
"MBA acquisition") increased the Company's effective economic interest in the
Mont Belvieu NGL fractionation facility from 37.0% to 62.5%. As a result of this
acquisition, the results of operations after July 1, 1999 were consolidated
rather than included in equity income from unconsolidated affiliates.
The results of operations for the three and nine month periods ended
September 30, 1999 include two month's impact of the businesses acquired from
TNGL and three month's impact of the additional ownership interest acquired as a
result of the MBA transaction. See the section below labeled "Pro Forma impact
of Acquisitions" for selected financial data reflecting these transactions as if
they had occurred on January 1, 1999.
2000 Acquisitions. On September 25, 2000, the Company announced that
its Operating Partnership has executed a definitive agreement to purchase
Acadian Gas, LLC ("Acadian") from Coral Energy, LLC, an affiliate of Shell Oil
Company, for $226 million in cash, inclusive of working capital. The acquisition
of Acadian integrates natural gas pipeline systems in South Louisiana with the
Company's Gulf Coast natural gas processing and NGL fractionation, pipeline and
storage system. Acadian's assets are comprised of the 438-mile Acadian, 577-mile
Cypress and 27-mile Evangeline natural gas pipeline systems, which together have
over one billion cubic feet ("Bcf") per day of capacity. These natural gas
pipeline systems are wholly-owned by Acadian with the exception of the
Evangeline system in which Acadian holds an approximate 49.5% economic interest.
The system includes a leased natural gas storage facility at Napoleonville,
Louisiana with 3.4 Bcf of capacity. Completion of this transaction is subject to
certain conditions, including regulatory approvals. The purchase is expected to
be completed in the fourth quarter of 2000.
Three Months Ended September 30, 2000 compared with Three Months Ended September
30, 1999
Revenues, Costs and Expenses and Operating Income. The Company's
revenues increased 62% to $721.9 million in 2000 compared to $445.0 million in
1999. The Company's operating costs and expenses increased by 64% to $659.0
million in 2000 versus $401.8 million in 1999. Operating income increased 39% to
$55.9 million in 2000 from $40.1 million in 1999. The principal factors behind
the increase in operating income were (a) the improvement in NGL product prices
in 2000 versus 1999 and (b) the additional margins associated with the
businesses acquired in the TNGL acquisition. The 1999 period includes two months
of margins associated with the TNGL operations whereas the 2000 period includes
three months.
Fractionation. For the third quarter of 2000, gross operating margin
for the Fractionation segment was $32.5 million compared to $36.1 million in
1999. NGL fractionation margin increased $3.3 million in 2000 compared to 1999
primarily due to additional margins from the fractionators acquired from TNGL
(i.e., Norco, Promix, Venice and Tebone). As noted earlier, the third quarter of
1999 includes only two months of margin from these fractionators whereas the
third quarter of 2000 includes three months. On a net basis, NGL fractionation
volumes increased from 201 MBPD in 1999 to 214 MBPD in 2000 reflecting the
Company's successful campaign to increase its customer base at its Mont Belvieu
facilities. Gross operating margin from the isomerization business decreased a
net $6.3 million during the third quarter of 2000 primarily due to the
reclassification of margins from NGL merchant activities that, beginning with
the implementation of the current segment reporting structure which was adopted
effective with the beginning of the fourth quarter of 1999, are now reported in
the Processing segment. Isomerization volumes increased from 77 MBPD in 1999 to
84 MBPD in 2000 due to increased demand for the Company's services. Gross
operating margin from the Company's propylene fractionation business decreased
slightly primarily due to higher energy and maintenance costs. Propylene
fractionation volumes increased from 26 MBPD in 1999 to 34 MBPD in 2000 due to
the startup of the BRPC facilities in July 2000.
24
<PAGE>
Pipeline. The Company's gross operating margin from the Pipeline
segment was $10.3 million in the third quarter of 2000 compared to $7.0 million
during the same period in 1999. Overall volumes increased to 278 MBPD in 2000
versus 264 MBPD in 1999. The $3.3 million increase from quarter to quarter is
generally attributable to the addition of margins from the pipeline and storage
assets acquired from TNGL. As noted earlier, the 1999 period includes only two
months of margin from these assets whereas the 2000 period reflects three months
of operations.
Processing. The Company's gross operating margin for Processing was
$29.1 million in 2000 compared to $7.1 million in 1999. Due to the TNGL
acquisition, the 1999 margin includes only two months of gas processing
operations whereas the third quarter of 2000 includes three months. This segment
benefited from the strong NGL pricing environment in 2000 versus 1999 and a
rise in equity NGL production from 65 MBPD in 1999 to 73 MBPD in 2000.
Octane Enhancement. The Company's gross operating margin for Octane
Enhancement decreased to $2.2 million in 2000 from $2.5 million in 1999. The
decrease is the result of lower margins on spot MTBE sales in the third quarter
of 2000 versus the margins on contract-based MTBE sales in the third quarter of
1999. Equity MTBE production increased to 6 MBPD in 2000 from 4 MBPD in 1999.
Other. The Company's gross operating margin for the Other segment was
$0.4 million in 2000 compared to $0.2 million in 1999. The increase is primarily
due to fee-based marketing services added in the fourth quarter of 1999.
Selling, general and administrative expenses ("SG&A"). SG&A expenses
increased to $7.0 million in the third quarter of 2000 from $3.2 million during
the same period in 1999. The higher costs result from an increase in the
administrative services fee charged by EPCO to $1.6 million per month beginning
in January 2000 versus the approximately $1.1 million per month charged in the
third quarter of 1999. The remainder of the increase is attributable to the
additional staff and resources deemed necessary to support the Company's ongoing
expansion activities resulting from acquisitions and other business development.
Interest expense. The Company's interest expense increased to $7.5
million in the third quarter of 2000 from $4.5 million in the third quarter of
1999. The increase is primarily attributable to a rise in average debt levels to
$437 million in the third quarter of 2000 from $255 million in the third quarter
of 1999. Debt levels have increased over the last year due to acquisitions and
various capital expenditures.
Nine Months Ended September 30, 2000 compared with Nine Months Ended September
30, 1999
Revenues, Costs and Expenses and Operating Income. The Company's
revenues increased 170% to $2,079.6 million in 2000 compared to $771.4 million
in 1999. The Company's operating costs and expenses increased by 173% to
$1,878.2 million in 2000 versus $689.0 million in 1999. Operating income
increased 148% to $181.3 million in 2000 from $73.2 million in 1999. The
principal factors behind the increase in operating income were (a) the
improvement in NGL product prices in 2000 versus 1999 and (b) the additional
margins associated with the businesses acquired in the TNGL acquisition. The
1999 period includes two months of margins associated with the TNGL operations
whereas the 2000 period includes nine months.
Fractionation. The Company's gross operating margin for the
Fractionation segment increased to $96.4 million in 2000 from $79.0 million in
1999. For the first nine months of 2000, NGL fractionation margin increased
$29.4 million over 1999 as a result of the additional margins from the four NGL
fractionators acquired from TNGL. As noted previously, the 1999 period includes
only two months of margin from these fractionators whereas the 2000 period
includes nine months. In addition, equity income from BRF reflects three
quarters of operations in 2000 versus one quarter in 1999. BRF commenced
operations in the third quarter of 1999. Net NGL fractionation volumes increased
from 178 MBPD in 1999 to 215 MBPD in 2000 primarily due to the Company's
acquisition of new and previous customers at its Mont Belvieu NGL fractionator
in 2000 and the increased ownership of the Mont Belvieu NGL fractionator as a
result of the MBA acquisition. For the first nine months of 2000, gross
operating margin from the isomerization business decreased $10.0 million
compared to 1999 primarily due to a reclassification of margins from NGL
merchant activities that, beginning with the implementation of the current
25
<PAGE>
segment reporting structure which was adopted effective with the fourth quarter
of 1999, are now reported in the Processing segment. Isomerization volumes
increased from 73 MBPD in 1999 to 77 MBPD in 2000 due to strong demand for the
Company's services. Gross operating margin from propylene fractionation for the
first nine months of 2000 decreased slightly compared to 1999 primarily due to
higher energy and maintenance costs. Net equity volumes at these facilities
improved to 31 MBPD in 2000 versus 27 MBPD in 1999 due to the startup of the
BRPC propylene concentrator in July 2000.
Pipeline. The Company's gross operating margin for the Pipeline segment
was $39.2 million in 2000 compared to $15.8 million in 1999. Overall volumes
increased to 323 MBPD in 2000 from 230 MBPD in 1999. Generally, the $23.4
million increase in margin is attributable to the additional volumes and margins
contributed by the pipeline and storage assets acquired from TNGL, higher
margins from the Houston Ship Channel Distribution System and EPIK due to an
increase in export volumes plus the margins from the Lou-Tex Propylene Pipeline
that was purchased in March 2000.
The growth in export volumes is attributable to EPIK's new chiller unit
that began operations in the fourth quarter of 1999. On February 25, 2000, the
purchase of the Lou-Tex Propylene Pipeline and related assets from Concha
Chemical Pipeline Company, an affiliate of Shell, was completed at a cost of
approximately $100 million. The effective date of the transaction was March 1,
2000. The Lou-Tex Propylene Pipeline is a 263-mile, 10" pipeline that transports
up to 50 MBPD of chemical grade propylene from Sorrento, Louisiana to Mont
Belvieu, Texas. Also acquired in this transaction was a 27.5-mile 6" ethane
pipeline between Sorrento and Norco, Louisiana and a 0.5 million barrel storage
cavern at Sorrento, Louisiana.
Processing. The Company's gross operating margin for Processing was
$87.1 million in 2000 compared to $6.7 million in 1999. Due to the TNGL
acquisition, the 1999 margin includes only two months of gas processing
operations whereas the 2000 period includes nine months. This segment benefited
from the strong NGL pricing environment in 2000 versus 1999 and a rise in equity
NGL production from 65 MBPD in 1999 to 72 MBPD in 2000.
Octane Enhancement. The Company's gross operating margin for Octane
Enhancement increased to $13.0 million in 2000 from $4.8 million in 1999. This
segment consists entirely of the Company's equity earnings and 33.33% investment
in BEF, a joint venture facility that currently produces MTBE. The 1999 results
included the impact of a $4.5 million non-cash write-off of the unamortized
balance of deferred start-up costs. The Company's share of this non-cash charge
was $1.5 million. The 2000 results reflect the impact of higher than normal MTBE
market prices during the second quarter and early third quarter and lower debt
service costs. BEF made its final note payment in May 2000 and now owns the MTBE
facility debt-free. MTBE production, on an equity basis, was 4 MBPD in 1999 and
5 MBPD in 2000.
Other. The Company's gross operating margin for the Other segment was
$1.9 million in 2000 compared to $0.7 million in 1999. The increase is primarily
due to fee-based marketing services added in the fourth quarter of 1999.
Selling, general and administrative expenses. SG&A expenses increased
to $20.0 million in 2000 from $9.2 million during 1999. The higher costs result
from an increase in the administrative services fee charged by EPCO to $1.6
million per month beginning in January 2000 versus the approximately $1.0
million per month charged in 1999. The remainder of the increase is attributable
to the additional staff and resources deemed necessary to support the Company's
ongoing expansion activities resulting from acquisitions and other business
development.
Interest expense. The Company's interest expense increased to $23.3
million in 2000 from $8.9 million in 1999. The increase is primarily
attributable to a rise in average debt levels to $395 million in 2000 from $170
million in 1999. Debt levels have increased over the last year due to
acquisitions and various capital expenditures.
Loss on sale of assets. During the second quarter of 2000, the Company
recognized a one-time $2.3 million non-cash charge on the sale of its Longview
Terminal to Huntsman Corporation. The Longview Terminal was part of the
Pipelines segment and was used to unload polymer grade propylene from NGL tank
trucks.
26
<PAGE>
Pro Forma impact of Acquisitions
As noted above under 1999 Acquisitions, the Company acquired TNGL and
MBA in the third quarter of 1999. As a result of these acquisitions, revenues,
operating costs and expenses, interest expense, and other amounts shown on the
Statements of Consolidated Operations for the three and nine months ended
September 30, 2000 have increased significantly over the amounts shown for the
three and nine months ended September 30, 1999. The following table presents
certain unaudited pro forma information as if the TNGL and MBA acquisition had
been made as of January 1, 1999:
<TABLE>
<CAPTION>
Three Nine
Months Months
Ended Ended
-------------------------------------
September 30, 1999
-------------------------------------
<S> <C> <C>
Revenues $ 506,944 $ 1,151,444
=====================================
Net income $ 40,586 $ 80,698
=====================================
Allocation of net income to
Limited partners $ 40,180 $ 79,891
=====================================
General Partner $ 406 $ 807
=====================================
Units used in earning per Unit calculations
Basic 66,696 66,715
=====================================
Diluted 81,196 81,215
=====================================
Income per Unit before minority interest
Basic $ 0.61 $ 1.21
=====================================
Diluted $ 0.50 $ 0.99
=====================================
Net income per Unit
Basic $ 0.60 $ 1.20
=====================================
Diluted $ 0.49 $ 0.98
=====================================
</TABLE>
The unaudited pro forma information does not include the impact of the pending
Acadian acquisition. As noted above, completion of this transaction is still
subject to certain conditions, including regulatory approvals.
Liquidity and Capital Resources
General. The Company's primary cash requirements, in addition to normal
operating expenses, are for capital expenditures (both maintenance and
expansion-related), business acquisitions, distributions to the partners and
debt service. The Company expects to fund its short-term needs for such items as
maintenance capital expenditures and quarterly distributions to the partners
from operating cash flows. Capital expenditures for long-term needs resulting
from future expansion projects and business acquisitions are expected to be
funded by a variety of sources including (either separately or in combination)
cash flows from operating activities, borrowings under bank credit facilities
and the issuance of additional Common Units and public debt. The Company's debt
service requirements are expected to be funded by operating cash flows or
refinancing arrangements.
As noted above, certain of the Company's liquidity and capital resource
requirements are met using borrowings under bank credit facilities and/or the
issuance of additional Common Units or public debt (separately or in
combination). As of September 30, 2000, availability under the Operating
Partnership's $350 Million Bank Credit Facility was $300.0 million plus $26.7
million for letters of credit. The Company is in the process of refinancing this
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<PAGE>
credit facility with a $400 million long-term revolving bank credit facility
(increasing to $500 million under certain conditions). The refinancing effort is
expected to be completed in the fourth quarter of 2000.
In addition to the existing and potential bank credit facilities,
approximately $450 million of shelf availability remains outstanding under the
Company's $800 million December 1999 universal shelf registration statement (the
"Registration Statement") which may be used for general partnership purposes.
$350 million of shelf availability was used in March 2000 with the issuance of
the $350 Million Senior Notes. For a broader discussion of the Company's
outstanding debt and changes therein since December 31, 1999, see the section
below labeled "Long-term Debt". In June 2000, the Company received approval from
its Unitholders to increase by 25,000,000 the number of Common Units available
(and unreserved) to the Company for general partnership purposes during the
Subordination Period. This increase has improved the future financial
flexibility of the Company in any potential business acquisition (see "Amendment
to Partnership Agreement" below for further details).
If deemed necessary, management believes that additional financing
arrangements can be obtained at reasonable terms. Management believes that the
maintenance of its investment grade credit ratings of its Operating Partnership
(currently, Baa3 by Moody's Investor Service and BBB by Standard and Poors)
combined with a continued ready access to debt and equity capital at reasonable
rates and sufficient trade credit to operate its businesses efficiently are a
solid foundation to providing the Company with ample resources to meet its long
and short-term liquidity and capital resource requirements.
Operating, Investing and Financing Cash Flows for Nine Months Ended September
30, 2000 and 1999
Cash flows from operating activities were a $177.9 million inflow in
2000 compared to a $54.7 million inflow in 1999. Cash flows from operating
activities primarily reflect the effects of net income, depreciation and
amortization, extraordinary items, equity income and distributions from
unconsolidated affiliates and changes in working capital. Net income increased
significantly in 2000 over 1999 due to reasons mentioned previously under
"Results of Operations of the Company." Depreciation and amortization expense
increased a combined $10.7 million in 2000 over 1999 primarily the result of
additional capital expenditures and acquisitions. Of the $10.7 million increase,
$3.4 million is attributable to increases in amortization expense associated
with the 20-year Shell natural gas processing agreement, excess cost related to
past acquisitions and loan origination and bond issue costs. The Company
received $26.0 million in distributions from its equity method investments in
2000 compared to $4.6 million in 1999. Of the $21.4 million increase in
distributions, $7.5 million was from BEF and $5.3 million from EPIK.
Distributions from BEF improved period to period due to the strong MTBE prices
and margins during the second quarter of 2000. EPIK's distributions increased as
a result of higher export activity during the first six months of 2000. In
addition, the first nine months of 2000 included $5.5 million in cash receipts
from Promix which was acquired as a result of the TNGL acquisition. The net
effect of changes in operating accounts from year to year is generally the
result of timing of NGL sales and purchases near the end of the period.
Cash used for investing activities was $195.9 million in 2000 compared
to $260.4 million in 1999. Cash outflows included capital expenditures of $200.2
million in 2000 versus $10.6 million in 1999. Capital expenditures in 2000
include $99.6 million for the purchase of the Lou-Tex Propylene Pipeline and
related assets, $71.5 million in construction costs for the Lou-Tex NGL Pipeline
and $4.1 million in construction costs for the Neptune gas processing facility.
In addition, capital expenditures include maintenance capital project costs of
$2.3 million in 2000 and $1.7 million in 1999. The 1999 period reflects $208.1
million in net cash payments resulting from the TNGL and MBA acquisitions.
Investing cash outflows in 2000 include $2.3 million in advances to and
investments in unconsolidated affiliates compared to $58.5 million in 1999. The
$56.2 million decrease is primarily due to the completion of the BRF facility
and the Tri-States and Wilprise pipeline systems in 1999. The first nine months
of 1999 included $35.3 million in investments in and advances to these
companies. Lastly, the Company received $6.5 million in payments from its
participation in the BEF note that was purchased during 1998 with the proceeds
from the Company's IPO. BEF made its final note payment in May 2000. With BEF's
final payment, the Company's receivable relating to its participation in the BEF
note was extinguished.
On March 8, 2000, the Company's offer of February 23, 2000 to buy the
remaining 88.5% ownership interests in Dixie from the other seven owners
expired, with no interest being purchased. On October 6, 2000, the Company
announced that a subsidiary had purchased an additional 3,521 shares of common
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stock of Dixie from Conoco Pipe Line Company for approximately $19.4 million.
The purchase brings the Company's economic interest in Dixie to approximately
19.9%.
Cash inflows from financing activities were $54.2 million in 2000
compared to $203.3 million in 1999. Cash flows from financing activities are
primarily affected by repayments of debt, borrowings under debt agreements and
distributions to partners. The first nine months of 2000 include proceeds from
the $350 Million Senior Notes and the $54 Million MBFC Loan and the associated
repayments on the $200 Million Bank Credit Facility and $350 Million Bank Credit
Facility. For a complete discussion of the $350 Million Senior Notes and the $54
Million MBFC Loan and the use of proceeds thereof, see the section labeled
"Long-term Debt" below. Financing activities in 1999 include the borrowings
associated with the TNGL and MBA acquisitions and outflows of $4.7 million
related to the purchase of Common Units by a consolidated trust. Distributions
to partners and the minority interest increased to $104.4 million in 2000 from
$82.2 million in 1999 primarily due to an increase in the quarterly distribution
rate (see Note 6 in the Notes to the Consolidated Financial Statements for a
history of the quarterly distribution rates since the first quarter of 1999).
In July 2000, the Company announced a 1,000,000 Unit buy-back program
of its publicly-owned Common Units to be executed over a two-year period.
Management's intent is to opportunistically acquire Common Units during periods
of temporary market weakness at price levels that would be accretive to the
Company's remaining Unitholders. The repurchase program will be balanced with
plans to grow the Company through investments in internally developed projects
and acquisitions, while maintaining an investment grade debt rating. The
redemption program will be funded by increased cash distributions from the
Operating Partnership from operating cash flows and borrowings under its bank
credit facilities. During the third quarter of 2000, 17,200 Common Units were
repurchased by the buy-back program at a cost of approximately $0.5 million.
Dividends received from unconsolidated affiliates. The Company received
$2.2 million in cash distributions from its cost method investments in Dixie
($0.4 million) and VESCO ($1.8 million) during the third quarter of 2000. For
the nine months ended September 30, 2000, cash distributions were $1.1 million
from Dixie and $5.1 million from VESCO. Cash distributions received from the
Company's cost method investments are recorded as "Dividend income from
unconsolidated affiliates" in the Statements of Consolidated Operations. Both
Dixie and VESCO were acquired in August 1999 as part of the TNGL acquisition.
Future Capital Expenditures
The Company estimates that its share of currently approved capital
expenditures in the projects of its unconsolidated affiliates will be
approximately $1.7 million during the remainder of 2000 (including $0.7 million
for the BRPC propylene fractionator) and $0.1 million in 2001. In addition, the
Company forecasts that $48.2 million will be spent during the fourth quarter of
2000 on currently approved capital projects that will be recorded as property,
plant and equipment. For 2001 and beyond, this amount is projected to be $41.8
million. Of the cumulative $90.0 million forecast to be spent on property, plant
and equipment, the most significant projects and their remaining expenditures
are as follows:
- $ 18.8 million for the Garyville, Louisiana to Norco, Louisiana butane
pipelines;
- $ 12.9 million for the Port Arthur, Texas to Lake Charles, Louisiana
propylene pipeline system;
- $ 12.5 million for the Venice, Louisiana to Grande Isle, Louisiana
pipeline;
- $ 8.2 million for the Lou-Tex NGL Pipeline; and
- $ 4.6 million for the Norco fractionator ethane liquefaction facility.
As of September 30, 2000, the Company had $13.7 million in outstanding
purchase commitments attributable to its capital projects. Of this amount, $4.5
million is related to the construction of the Lou-Tex NGL Pipeline and $0.6
million is associated with capital projects which will be recorded as additional
investments in unconsolidated affiliates.
Long-term Debt
Long-term debt at September 30, 2000 was comprised of $350 million in
5-year public Senior Notes (the "$350 Million Senior Notes") issued by
Enterprise Products Operating L.P. (the "Operating Partnership"), a 10-year $54
million loan agreement with the Mississippi Business Finance Corporation ("MBFC"
and the "$54 Million MBFC Loan") and $50 million outstanding under the $350
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<PAGE>
Million Bank Credit Facility. The issuance of the $350 Million Senior Notes
represented a partial takedown of the $800 million Registration Statement that
was filed with the Securities and Exchange Commission in December 1999. The
proceeds from the $350 Million Senior Notes and the $54 Million MBFC Loan were
used to extinguish all outstanding balances owed under the $200 Million Bank
Credit Facility and the $350 Million Bank Credit Facility at the time of the
offerings.
The following table summarizes long-term debt at:
September 30, December 31,
2000 1999
--------------------------------------
Borrowings under:
$200 Million Bank Credit Facility $ 129,000
$350 Million Bank Credit Facility $ 50,000 166,000
$350 Million Senior Notes 350,000
$54 Million MBFC Loan 54,000
--------------------------------------
Total 454,000 295,000
Less current maturities of long-term debt 50,000 129,000
--------------------------------------
Long-term debt $ 404,000 $ 166,000
======================================
At September 30, 2000, the Operating Partnership had a total of $40
million of standby letters of credit available of which approximately $13.3
million were outstanding under letter of credit agreements with the banks.
Bank Credit Facilities
$200 Million Bank Credit Facility. In July 1998, the Operating
Partnership entered into a $200 million bank credit facility that included a $50
million working capital facility and a $150 million revolving credit facility.
On March 15, 2000, the Operating Partnership used $169 million of the proceeds
from the issuance of the $350 Million Senior Notes to retire this credit
facility in accordance with its agreement with the banks.
$350 Million Bank Credit Facility. In July 1999, the Operating
Partnership entered into a $350 Million Bank Credit Facility that includes a $50
million working capital facility and a $300 million revolving credit facility.
The $300 million revolving credit facility includes a sublimit of $40 million
for letters of credit. Borrowings under the $350 Million 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 Operating Partnership
elects the basis for the interest rate at the time of each borrowing.
This facility is scheduled to 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. In March 2000, the Operating
Partnership used $179 million of the proceeds from the issuance of the $350
Million Senior Notes and $47 million from the $54 Million MBFC Loan to payoff
the outstanding balance on this credit facility. Due to borrowings in the third
quarter for investment and working capital purposes, $50 million was outstanding
under this facility at September 30, 2000.
The credit agreement relating to this facility contains a prohibition
on distributions to or purchases 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 Operating Partnership 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 credit agreement generally prohibits
redemptions of Units except for those transactions related to the 1,000,000 Unit
Buy-back Program announced in July 2000. In August 2000, the lenders and Company
executed a waiver allowing for this program. 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
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<PAGE>
Indebtedness (as defined in the bank credit facility) to EBITDA of no more than
3.0 to 1.0. The Operating Partnership was in compliance with the restrictive
covenants at September 30, 2000.
As noted above, the Company is pursuing a refinancing arrangement with
a group of banks to terminate this facility and replace it with a new $400
Million Bank Credit Facility (increasing to $500 million under certain
conditions). The completion of this refinancing project is subject to continuing
negotiations between the parties involved and is expected to be finalized during
the fourth quarter of 2000.
Senior Notes and MBFC Loan
$350 Million Senior Notes. On March 13, 2000, the Operating Partnership
completed a public offering of $350 million in principal amount of 8.25%
fixed-rate Senior Notes due March 15, 2005 at a price to the public of 99.948%
per Senior Note. In the offering, the Operating Partnership received proceeds,
net of underwriting discounts and commissions, of approximately $347.7 million.
The proceeds were used to pay (a) the entire $169 million outstanding principal
balance on the $200 Million Bank Credit Facility and (b) $179 million of the
$226 million then outstanding principal balance on the $350 Million Bank Credit
Facility.
The notes are subject to a make-whole redemption right by the Operating
Partnership. They are an unsecured obligation of the Operating Partnership and
rank equally with its existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness. The notes are
guaranteed by the Company through an unsecured and unsubordinated guarantee and
were issued under an indenture containing certain restrictive covenants. These
covenants restrict the ability of the Company and the Operating Partnership,
with certain exceptions, to incur debt secured by liens and engage in sale and
leaseback transactions. The Company and Operating Partnership were in compliance
with these restrictive covenants at September 30, 2000.
Settlement was completed on March 15, 2000. The offering of the $350
Million Senior Notes was a takedown under the Company's $800 million
Registration Statement; therefore, the amount of securities available under the
Registration Statement is reduced to $450 million.
$54 Million MBFC Loan. On March 27, 2000, the Operating Partnership
executed a $54 million loan agreement with the MBFC which was funded by the
proceeds from the sale of Revenue Bonds by the MBFC. The Revenue Bonds issued by
the MBFC are 10-year bonds with a maturity date of March 1, 2010 and bear a
fixed-rate interest coupon of 8.70 percent. The Operating Partnership received
proceeds from the sale of the Revenue Bonds, net of underwriting discounts and
commissions, of approximately $53.6 million. The proceeds were used to pay the
remaining $47 million then outstanding principal balance on the $350 Million
Bank Credit Facility and for working capital and other general partnership
purposes. In general, the proceeds of the Revenue Bonds were used to reimburse
the Operating Partnership for costs it incurred in acquiring and constructing
the Pascagoula, Mississippi natural gas processing plant.
The Revenue Bonds were issued at par and are subject to a make-whole
redemption right by the Operating Partnership. The Revenue Bonds are guaranteed
by the Company through an unsecured and unsubordinated guarantee. The loan
agreement contains certain covenants including maintaining appropriate levels of
insurance on the Pascagoula natural gas processing facility and restrictions
regarding mergers. The Company was in compliance with these restrictive
covenants at September 30, 2000.
Interest Rate Swaps. The Company's interest rate exposure results from
variable-rate borrowings from commercial banks and fixed-rate borrowings
pursuant to the $350 Million Senior Notes and the $54 Million MBFC Loan. The
company manages its exposure to changes in interest rates in its consolidated
debt portfolio by utilizing interest rate swaps. An interest rate swap, in
general, requires one party to pay a fixed-rate on the notional amount while the
other party pays a floating-rate based on the notional amount.
In March 2000, after the issuance of the $350 Million Senior Notes and
the execution of the $54 Million MBFC Loan, 100% of the Operating Partnership's
consolidated debt were fixed-rate obligations. To maintain a balance between
variable-rate and fixed-rate exposure, the Operating Partnership entered into
interest rate swap agreements with a notional amount of $154 million by which
the Operating Partnership receives payments based on a fixed-rate and pays an
amount based on a floating-rate. At September 30, 2000, the Operating
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Partnership's consolidated debt portfolio interest rate exposure was 55 percent
fixed and 45 percent floating, after considering the effect of the interest rate
swap agreements. The notional amount does not represent exposure to credit loss.
The Operating Partnership monitors its positions and the credit ratings of its
counterparties. Management believes the risk of incurring a credit related loss
is remote, and that if incurred, such losses would be immaterial.
The effect of these swaps (none of which are leveraged) was to decrease
the Company's interest expense by $0.4 million and $0.9 million for the three
and nine months ended September 30, 2000, respectively. For further information
regarding the interest rate swaps, see Note 9 of the unaudited Notes to the
Consolidated Financial Statements.
Amendment to Partnership Agreement
The Partnership Agreement generally authorizes the Company to issue an
unlimited number of additional limited partner interests and other equity
securities of the Company for such consideration and on such terms and
conditions as shall be established by the General Partner in its sole discretion
without the approval of the Unitholders. During the Subordination Period,
however, the Company is limited with regards to the number of equity securities
that it may issue that rank senior to Common Units (except for Common Units upon
conversion of Subordinated Units, pursuant to employee benefit plans, upon
conversion of the general partner interest as a result of the withdrawal of the
General Partner or in connection with acquisitions or capital improvements that
are accretive on a per Unit basis) or an equivalent number of securities ranking
on a parity with the Common Units, without the approval of the holders of at
least a Unit Majority. A Unit Majority is defined as at least a majority of the
outstanding Common Units (during the Subordination Period), excluding Common
Units held by the General Partner and its affiliates, and at least a majority of
the outstanding Common Units (after the Subordination Period).
In April 2000, the Company mailed a Proxy Statement to its public
Unitholders asking them to consider and vote for a proposal to amend the
Partnership Agreement to increase the number of additional Common Units that may
be issued during the Subordination Period without the approval of a Unit
Majority from 22,775,000 Common Units to 47,775,000 Common Units. The primary
purpose of the requested increase was to improve the future financial
flexibility of the Company since 20,500,000 Common Units of the 22,775,000
Common Units available to the partnership during the Subordination Period were
reserved for issuance in connection with the TNGL acquisition. At a special
meeting of the Unitholders and General Partner held on June 9, 2000, this
proposal was approved by 90.7% of the public Unitholders. The amendment
increases the number of Common Units available (and unreserved) to the Company
for general partnership purposes during the Subordination Period from 2,275,000
to 27,275,000.
MTBE Facility
The Company owns a 33.33% economic interest in the BEF partnership that
owns the MTBE production facility located within the Company'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.
In recent years, MTBE has been detected in water supplies. The major
source of the ground water contamination appears to be leaks from underground
storage tanks. Although these detections have been limited and the great
majority of these detections have been well below levels of public health
concern, there have been actions calling for the phase-out of MTBE in motor
gasoline in various federal and state governmental agencies.
In light of these developments, the Company is formulating a
contingency plan for use of the BEF facility if MTBE were banned or
significantly curtailed. Management is exploring a possible conversion of the
BEF facility from MTBE production to alkylate production. At present the
forecast cost 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 spot market margins comparable to those of MTBE. Greater alkylate
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<PAGE>
production would be expected to increase isobutane consumption nationwide and
result in improved isomerization margins for the Company.
Sun, the MTBE facility's major customer and one of the partners of BEF,
has entered into a contract with BEF to take all of the MTBE production through
September 2004.
Year 2000 Readiness Disclosure
The Company's efforts at preparing its computer systems for the Year
2000 were successful and no significant problems were encountered. The Year 2000
Readiness team reported that all systems functioned properly as the date changed
from December 31, 1999 to January 1, 2000. The Company is also pleased to note
that no problems were reported to it by its customers or vendors as a result of
the Year 2000 issue. The Company continues to be vigilant in monitoring its
systems for any potential Year 2000 problems that may arise in the short-term.
There is no assurance that residual Year 2000 issues will not arise in the
future which could have a material adverse effect on the operations of the
Company.
Accounting Standards
In December 1999, the Securities and Exchange Commission ("SEC") issued
Staff Accounting Bulletin ("SAB") No. 101 " Revenue Recognition in Financial
Statements." SAB 101 summarizes certain of the staff's views in applying
generally accepted accounting principles to revenue recognition in financial
statements. On June 26, 2000, the SEC issued an amendment to SAB 101 effectively
delaying its implementation until the fourth quarter of fiscal years beginning
after December 15, 1999. The Company believes that the adoption of SAB 101 will
not have a material effect on its results of operations.
In June 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 the application of SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities" for one year, to fiscal years beginning after June 15,
2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - an amendment of FASB
Statement No. 133" which amends and supercedes various sections of SFAS No. 133.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to financial market risks, including changes in
interest rates with respect to a portion of its debt obligations and changes in
commodity prices. The Company may use derivative financial instruments (i.e.,
futures, forwards, swaps, options, and other financial instruments with similar
characteristics) to mitigate these risks. The Company does not use derivative
financial instruments for speculative (or trading) purposes.
The Company adopted a commercial policy to manage exposures to the
risks generated by the NGL businesses acquired in the TNGL acquisition. 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
with 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.
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Interest rate risk
Variable-rate Debt. At September 30, 2000 and December 31, 1999, the
Company had no derivative instruments in place to cover any potential interest
rate risk on its variable-rate debt obligations. Variable interest rate debt
obligations do expose the Company to possible increases in interest expense and
decreases in earnings if interest rates were to rise. The Company's long-term
debt associated with the $350 Million Bank Credit Facility is at variable
interest rates. At September 30, 2000, $50 million was outstanding under this
credit facility.
If the weighted average base interest rates selected on the
variable-rate long-term debt during 1999 were to have been 10% higher than the
weighted average of the actual base interest rates selected, assuming no changes
in weighted average variable debt levels, interest expense would have increased
by approximately $1.4 million with a corresponding decrease in earnings before
minority interest. If the same calculation were performed on the variable-rate
long-term debt outstanding during 2000, interest expense would have increased by
approximately $0.5 million with a corresponding decrease in earnings before
minority interest.
Fixed-rate Debt. In March 2000, the Operating Partnership entered into
interest rate swaps whereby the fixed-rate of interest on a portion of the $350
Million Senior Notes and the $54 Million MBFC Loan was effectively swapped for
floating-rates tied to the six month London Interbank Offering Rate ("LIBOR").
Interest rate swaps are used to manage the Company's exposure to changes in
interest rates and to lower overall costs of financing. An interest rate swap,
in general, requires one party to pay a fixed-rate on the notional amount while
the other party pays a floating-rate based on the notional amount.
After the issuance of the $350 Million Senior Notes and the execution
of the $54 Million MBFC Loan in March 2000, 100% of the Operating Partnership's
consolidated debt were fixed-rate obligations. To maintain a balance between
variable-rate and fixed-rate exposure, the Operating Partnership entered into
interest rate swap agreements with a notional amount of $154 million by which
the Operating Partnership receives payments based on a fixed-rate and pays an
amount based on a floating-rate. At September 30, 2000, the Operating
Partnership's consolidated debt portfolio interest rate exposure was 55 percent
fixed and 45 percent floating, after considering the effect of the interest rate
swap agreements. The notional amount does not represent exposure to credit loss.
The Operating Partnership monitors its positions and the credit ratings of its
counterparties. Management believes the risk of incurring a credit related loss
is remote, and that if incurred, such losses would be immaterial.
The effect of these swaps (none of which are leveraged) was to decrease
the Company's interest expense by $0.4 million and $0.9 million for the three
and nine months ended September 30, 2000, respectively. Following is selected
information on the Company's portfolio of interest rate swaps at June 30, 2000:
Interest Rate Swap Portfolio at September 30, 2000 (1) :
(Dollars in millions)
Early Fixed /
Notional Termination Floating
Amount Period Covered Date (2) Rate (3)
--------------------------------------------------------------------------------
$ 50.0 March 2000 - March 2005 March 2001 8.25% / 7.3100%
$ 50.0 March 2000 - March 2005 March 2001 8.25% / 7.3150%
$ 54.0 March 2000 - March 2010 March 2003 8.70% / 7.6575%
Notes:
(1) All swaps outstanding at September 30, 2000 were entered into for the
purpose of managing the Operating Partnership's exposure to fluctuations in
market interest rates.
(2) In each case, the counterparty has the option to terminate the interest
rate swap on the Early Termination Date
(3) In each case, the Operating Partnership is the floating-rate payor. The
floating rate was the rate in effect as of September 30, 2000.
If the six month LIBOR rates on the notional amounts of fixed-rate
long-term debt at September 30, 2000 were to have been 10% higher than the six
month LIBOR rates actually used in the swap agreements, assuming no changes in
weighted average fixed-rate debt levels, interest expense for the three and nine
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months ended September 30, 2000 would have increased by approximately $0.3
million and $0.5 million, respectively, with a corresponding decrease in
earnings before minority interest.
Other. At September 30, 2000 and December 31, 1999, the Company had
$41.4 million and $5.2 million invested in cash and cash equivalents,
respectively. All cash equivalent investments other than cash are highly liquid,
have original maturities of less than three months, and are considered to have
insignificant interest rate risk.
Commodity price risk
The Company is exposed to commodity price risk through its NGL
businesses acquired in the TNGL acquisition. In order to effectively manage this
risk, the Company may enter into swaps, forwards, commodity futures, options and
other derivative commodity instruments with similar characteristics that are
permitted by contract or business custom to be settled in cash or with another
financial instrument. The purpose of these risk management activities is to
hedge exposure to price risks associated with natural gas, NGL inventories,
commitments and certain anticipated transactions. The table below presents the
hypothetical changes in fair values arising from immediate selected potential
changes in the quoted market prices of derivative commodity instruments
outstanding at December 31, 1999 and September 30, 2000. Gain or loss on these
derivative commodity instruments would be offset by a corresponding gain or loss
on the hedged commodity positions, which are not included in the table. The fair
value of the commodity futures at December 31, 1999 and September 30, 2000 was
estimated at $0.5 million payable and $ 3.5 million receivable, respectively,
based on quoted market prices of comparable contracts and approximate the gain
or loss that would have been realized if the contracts had been settled at the
balance sheet date. The change in fair value of the commodity futures since
December 31, 1999 is primarily due to an increase in volumes hedged, change in
composition of commodities hedged and higher natural gas prices. The change in
fair value between September 30, 2000 and November 1, 2000 is due to the change
in the composition of commodities hedged and settlement of November 2000 natural
gas future contracts.
<TABLE>
<CAPTION>
(Millions of Dollars) No Change 10% Increase 10% Decrease
--------- ------------ ------------
Impact of changes in quoted Fair Fair Increase Fair Increase
Market prices on: Value Value (Decrease) Value (Decrease)
------------------------------------------------------------------------------------------------------------------
Commodity futures
<S> <C> <C> <C> <C> <C>
At December 31, 1999 $ (0.5) $ 1.2 $ 1.7 $ (2.2) $ (1.7)
At September 30, 2000 $ 3.5 $ 4.0 $ (0.5) $ 3.1 $ (0.4)
At November 1, 2000 $ 2.2 $ 4.2 $ 2.0 $ .2 $ (2.0)
</TABLE>
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.
In April 2000, the Company mailed a Proxy Statement to its public
Unitholders asking them to consider and vote for a proposal to amend the
Partnership Agreement. For a discussion of these matters and the voting results,
see Item 4 of the Company's Form 10-Q for the period ended June 30, 2000.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
*1.1 Underwriting Agreement dated March 10, 2000, among Enterprise Products
Partners L.P., Enterprise Products Operating L.P., Chase Securities
Inc., Lehman Brothers Inc., Banc One Capital Markets, Inc., FleetBoston
Robertson Stephens Inc., First Union Securities, Inc., Scotia Capital
(USA) Inc. and SG Cowen Securities Corp. (Exhibit 1.1 on Form 8-K filed
March 10, 2000).
35
<PAGE>
*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).
3.6 Amendment No. 1 to Second Amended and Restated Agreement of Limited
Partnership of Enterprise Products Partners L.P. dated June 9, 2000.
*4.1 Form of Common Unit certificate (Exhibit 4.1 to Registration Statement
on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*4.2 $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).
*4.6 Form of Indenture dated as of March 15, 2000, among Enterprise Products
Operating L.P., as Issuer, Enterprise Products Partners L.P., as
Guarantor, and First Union National Bank, as Trustee. (Exhibit 4.1 on
Form 8-K filed March 10, 2000).
*4.7 Form of Global Note representing all 8.25% Senior Notes Due 2005.
(Exhibit 4.2 on Form 8-K filed March 10, 2000).
36
<PAGE>
*4.8 Second Amendment, dated as of January 24, 2000, to $200 Million Credit
Agreement dated as of July 27, 1998, as Amended and Restated as of
September 30, 1998, among Enterprise Products Operating L.P. and the
several banks thereto. (Exhibit 4.3 on Form 8-K filed March 10, 2000).
*4.9 First Amendment, dated as of January 24, 2000, to $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, BankOne N.A., as Co- Arranger and as Documentation
Agent, The Bank of Nova Scotia, as Co-Arranger and as Syndication Agent,
and the several Banks from time to time parties thereto, with First
Union Capital Markets acting as Managing Agent and Chase Securities Inc.
acting as Lead Arranger and Manager dated as of July 28, 1999. (Exhibit
4.4 on Form 8-K filed March 10, 2000).
*4.10 Second Amendment, dated as of March 7, 2000, to $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, BankOne N.A., as Co- Arranger and as Documentation
Agent, The Bank of Nova Scotia, as Co-Arranger and as Syndication Agent,
and the several Banks from time to time parties thereto, with First
Union Capital Markets acting as Managing Agent and Chase Securities Inc.
acting as Lead Arranger and Manager dated as of July 28, 1999. (Exhibit
4.5 on Form 8-K filed March 10, 2000).
*4.11 Guaranty Agreement, dated as of March 7, 2000, by Enterprise Products
Partners L.P. in favor of The Chase Manhattan Bank, as Administrative
Agent, with respect to the $350 Million Credit Agreement referred to in
Exhibits 4.4 and 4.5. (Exhibit 4.6 on Form 8-K filed March 10, 2000).
4.12 Waiver Agreement, dated as of August 25, 2000, regarding Section 6.5 of
the $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, BankOne N.A., as Co- Arranger
and as Documentation Agent, The Bank of Nova Scotia, as Co-Arranger and
as Syndication Agent, and the several Banks from time to time parties
thereto, with First Union Capital Markets acting as Managing Agent and
Chase Securities Inc. acting as Lead Arranger and Manager dated as of
July 28, 1999.
*10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline
Partnership, L.P., Chunchula Pipeline Company, LLC, Propylene Pipeline
Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise Products
Texas Operating L.P. dated June 1, 1998 (Exhibit 10.1 to Registration
Statement on Form S-1/A, File No: 333-52537, filed on July 8, 1998).
*10.2 Form of EPCO Agreement between Enterprise Products Partners L.P.,
Enterprise Products Operating L.P., Enterprise Products GP, LLC and
Enterprise Products Company (Exhibit 10.2 to Registration Statement on
Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*10.3 Transportation Contract between Enterprise Products Operating L.P. and
Enterprise Transportation Company dated June 1, 1998 (Exhibit 10.3 to
Registration Statement on Form S-1/A, File No. 333-52537, filed on July
8, 1998).
*10.4 Venture Participation Agreement between Sun Company, Inc. (R&M), Liquid
Energy Corporation and Enterprise Products Company dated May 1, 1992
(Exhibit 10.4 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.5 Partnership Agreement between Sun BEF, Inc., Liquid Energy Fuels
Corporation and Enterprise Products Company dated May 1, 1992 (Exhibit
10.5 to Registration Statement on Form S-1, File No. 333-52537, filed on
May 13, 1998).
*10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu
Environmental Fuels and Sun Company, Inc. (R&M) dated August 16, 1995
(Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
37
<PAGE>
*10.7 Articles 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).
*10.8 First 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).
*10.9 Propylene Facility and Pipeline Agreement between Enterprise
Petrochemical Company and Hercules Incorporated dated December 13, 1978
(Exhibit 10.9 to Registration Statement on Form S-1, File No. 333-52537,
dated May 13, 1998).
*10.10 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).
*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).
*10.14 Fourth Amendment to Conveyance of Gas Processing Rights between Tejas
Natural Gas Liquids, LLC and Shell Oil Company, Shell Exploration &
Production Company, Shell Offshore Inc., Shell Deepwater Development
Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas Inc.
dated August 1, 1999. (Exhibit 10.14 to Form 10-Q filed on November 15,
1999).
*10.15 Purchase and Sale Agreement by and between Coral Energy, LLC and
Enterprise Products Operating L.P. dated as of September 22, 2000
(Exhibit 10.1 to Form 8-K filed on September 26, 2000).
*12.1 Computation of ratio of earnings to fixed charges for the year ended
December 31, 1999. (Exhibit 12.1 on Form 8-K filed March 10, 2000).
*25.1 Statement of Eligibility and Qualification under the Trust Indenture Act
of 1939 on Form T-1 of First Union National Bank. (Exhibit 25.1 on Form
8-K filed March 10, 2000).
*99.1 Contribution Agreement between Tejas Energy LLC, Tejas Midstream
Enterprises, LLC, Enterprise Products Partners L.P., Enterprise Products
Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC
and EPC Partners II, Inc. dated September 17, 1999. (The Company
incorporates by reference the above document included 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).
*99.2 Registration Rights Agreement between Tejas Energy LLC and Enterprise
Products Partners L.P. dated September 17, 1999. (The Company
incorporates by reference the above document included 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
38
<PAGE>
* Asterisk indicates exhibits incorporated by reference as indicated;
all other exhibits are filed herewith
(b) Reports on Form 8-K
On September 25, 2000, the Company filed a Form 8-K announcing that its
Operating Partnership has executed a definitive agreement to purchase Acadian
Gas, LLC ("Acadian") from Coral Energy, LLC, an affiliate of Shell Oil Company,
for $226 million in cash, inclusive of working capital. The acquisition of
Acadian integrates natural gas pipeline systems in South Louisiana with the
Company's Gulf Coast natural gas processing and NGL fractionation, pipeline and
storage system. Acadian's assets are comprised of the 438-mile Acadian, 577-mile
Cypress and 27-mile Evangeline natural gas pipeline systems, which together have
over one billion cubic feet ("Bcf") per day of capacity. These natural gas
pipeline systems are wholly-owned by Acadian with the exception of the
Evangeline system in which Acadian holds an approximate 49.5% economic interest.
The system includes a leased natural gas storage facility at Napoleonville,
Louisiana with 3.4 Bcf of capacity. Completion of this transaction is subject to
certain conditions, including regulatory approvals. The purchase is expected to
be completed in the fourth quarter of 2000.
39
<PAGE>
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
/s/ Michael J. Knesek
---------------------
Date: November 13, 2000 Vice President, Controller
and Principal Accounting Officer
<PAGE>
ENTERPRISE PRODUCTS OPERATING L.P.
August 15, 2000
The Chase Manhattan Bank
270 Park Avenue, Floor 21
New York, New York 10017
Attn: Mr. Steve Wood
Re: Requested Waiver - Enterprise Products Operating L.P. ("Company") Credit
Agreement dated as of July 28, 1999, as amended ("Credit Agreement")
Dear Steve:
This letter ("Waiver Letter") is to seek a waiver from The Chase
Manhattan Bank, as Administrative Agent ("Agent") under the Credit Agreement,
and the Required Banks thereunder as set forth herein. All capitalized terms
used herein as definitions, but not defined herein, are defined in the Credit
Agreement.
As has been disclosed to you, Enterprise Products Partners L.P. ("LP")
intends to initiate a buy-back program (the "Program") whereby LP, over a
two-year time period, would buy back up to 1,000,000 publically held Units, as
set forth in our letter of August 14, 2000 to Bill Manias at Chase Securities
Inc. on this subject. Under Section 7.5 of the Credit Agreement, the Company
would be prohibited from making Restricted Payments consisting of up-stream
dividends to LP to fund the Program, and the LP would be prohibited from
conducting the Program under Section 8.1(n)(c) of the Credit Agreement.
By signing below, the Agent and the Required Banks hereby evidence
their consent to a one- time waiver (i) under said Section 7.5 in order for the
Company to make Restricted Payments consisting of up-stream dividends to LP
necessary to fund the Program and (ii) under said Section 8.1(n)(c) in order for
the LP to conduct the Program, which dividends and Program would be permitted as
long as no Default or Event of Default has occurred and is continuing under the
Credit Agreement either before or occasioned by any such Restricted Payment. In
addition, the waiver evidenced by this letter is a one-time event and is
permitted only through August 25, 2002. Henceforth, the Company shall not be in
Default under the Credit Agreement, including without limitation Sections 7.5
and 8.1(n)(c) of the Credit Agreement, solely by reason of any Restricted
Payment consisting of up-stream dividends to LP prior to August 26, 2002 made
consistent with this Waiver Letter or by the LP's conducting the Program
consistent with this Waiver Letter.
<PAGE>
Kindly indicate the aforementioned consent to waiver by signing and
returning a copy of this letter to the attention to the undersigned.
Sincerely,
ENTERPRISE PRODUCTS OPERATING L.P.
By: Enterprise Products GP, LLC, General Partner
By: /s/ Richard H. Bachmann
----------------------------------
Name: Richard H. Bachmann
Title: Executive Vice President &
Chief Legal Officer
Agreed to and Accepted as of the 25th day of August, 2000.
BANKS AND AGENTS:
----------------
THE CHASE MANHATTAN BANK, as
Administrative Agent and as a Bank
By: /s/ Steven Wood
----------------------------------
Name: Steven Wood
Title: Vice President
BANK ONE, NA (formerly known as The First
National Bank of Chicago), as Documentation
Agent and as a Bank
By: /s/ Dianne L. Russell
---------------------------------
Name: Dianne L. Russell
Title: Vice President
THE BANK OF NOVA SCOTIA, as Syndication
Agent and as a Bank
By: /s/ F.C.H. Ashby
---------------------------------
Name: F.C.H. Ashby
Title: Sr. Mgr. Loan Operations
FIRST UNION NATIONAL BANK
By: /s/ Russell Clingman
--------------------------------
Name: Russell Clingman
Title: Vice President
SOCIETE GENERALE, SOUTHWEST AGENCY
By: /s/ Paul E. Cornell
--------------------------------
Name: Paul E. Cornell
Title: Managing Director
FLEET NATIONAL BANK.
By: /s/ Christopher Holmgre
-------------------------------
Name: Christopher Holmgren
Title: Director
THE FUJI BANK, LIMITED, NEW YORK BRANCH
By: /s/ Nate Elllis
-------------------------------
Name: Nate Ellis
Title: Senior Vice President & Manager
BANK OF TOKYO-MITSUBISHI, LTD.,
HOUSTON AGENCY
By: /s/ Michael G. Meis
-------------------------------
Name: Michael G. Meiss
Title: Vice President
TORONTO DOMINION (TEXAS), INC.
By: /s/ Alva J. Jones
-------------------------------
Name: Alva J. Jones
Title: Vice President
CREDIT AGRICOLE INDOSUEZ
By: /s/ Patrick Cocquerel
-------------------------------
Name: Patick Cocquerel
Title: FVP, Managing Director
By: /s/ Douglas A. Whiddon
-------------------------------
Name: Douglas A. Whiddon
Title: Senior Relationship Manager
DG BANK DEUTSCHE GENOSSEN
SCHAFTBANK AG, CAYMAN ISLAND BRANCH
By: /s/ Craig Anderson
-------------------------------
Name: Craig Anderson
Title: Vice President
By: /s/ Lynne McCarthy
-------------------------------
Name: Lynne McCarthy
Title: Vice President
CREDIT LYONNAIS NEW YORK BRANCH
By: /s/ illegible signature
-------------------------------
Name:
Title:
FORTIS CAPITAL CORP.
By: /s/ Darrell W. Holley
------------------------------
Name: Darrell W. Holley
Title: Managing Director
HIBERNIA NATIONAL BANK
By: /s/ Trudy W. Nelson
------------------------------
Name: Trudy W. Nelson
Title: Vice President
