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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, 2001
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number: 1-14323
Enterprise Products Partners L.P.
(Exact name of Registrant as specified in its charter)
Delaware 76-0568219
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2727 North Loop West
Houston, Texas
77008-1037
(Address of principal executive offices) (Zip code)
(713) 880-6500
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days.
Yes _X_ No ___
The registrant had 51,055,715 Common Units outstanding as of November 13, 2001.
Enterprise Products Partners L.P. and Subsidiaries
TABLE OF CONTENTS
Page
No.
----
Glossary
Part I. Financial Information
Item 1. Consolidated Financial Statements
Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets, September 30, 2001 and December 31, 2000 1
Statements of Consolidated Operations
for the three and nine months ended September 30, 2001 and 2000 2
Statements of Consolidated Cash Flows
for the nine months ended September 30, 2001 and 2000 3
Statements of Consolidated Partners' Equity and Comprehensive Income
for the nine months ended September 30, 2001 and 2000 4
Notes to Unaudited Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operation 22
Item 3. Quantitative and Qualitative Disclosures about Market Risk 38
Part II. Other Information
Item 2. Use of Proceeds 42
Item 6. Exhibits and Reports on Form 8-K 42
Signature Page
Glossary
The following abbreviations, acronyms or terms used in this Form 10-Q are defined below:
Acadian Gas Acadian Gas, LLC
BBtu/d Billion British thermal units per day, a measure of heating value
Bcf Billion cubic feet
Bcf/d Billion cubic feet per day
BPD Barrels per day
Btu British thermal unit, a measure of heating value
Company Enterprise Products Partners L.P. and subsidiaries
EPCO Enterprise Products Company, an affiliate of the Company
EPE El Paso Corporation, its subsidiaries and affiliates
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
General Partner Enterprise Products GP, LLC, the general partner of the Company and Operating
Partnership
Manta Ray A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Manta Ray
Offshore Gathering Company, LLC
MBFC Mississippi Business Finance Corporation
MBPD Thousand barrels per day
MLP Denotes Enterprise Products Partners L.P. as guarantor of certain debt obligations of
the Operating Partnership
MMBbls Millions of barrels
MMBtus Million British thermal units, a measure of heating value
MMcf Million cubic feet
MMcf/d Million cubic feet per day
MTBE Methyl tertiary butyl ether
Nautilus A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Nautilus
Pipeline Company, LLC
NGL or NGLs Natural gas liquid(s)
NYSE New York Stock Exchange
Operating Partnership Enterprise Products Operating L.P. and subsidiaries
Operating Surplus As defined within the Partnership Agreement
Partnership Agreement Second Amended and Restated Agreement of Limited Partnership of the Company
PTR Plant thermal reduction
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
Shell Shell Oil Company, its subsidiaries and affiliates
Subordination Period As defined within the Partnership Agreement
TNGL acquisition Refers to the acquisition of Tejas Natural Gas Liquids, LLC from Shell effective
August 1, 1999
PART 1. FINANCIAL INFORMATION.
Item 1. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Dollar amounts in thousands)
September 30,
2001 December 31,
ASSETS (Unaudited) 2000
-------------------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of $ 67,076 $ 60,409
$9,032 at September 30, 2001)
Accounts receivable - trade, net of allowance for doubtful accounts of
$17,007 at September 30, 2001 and $10,916 at December 31, 2000 322,519 409,085
Accounts receivable - affiliates 16,184 6,533
Inventories 152,058 93,222
Prepaid and other current assets 68,109 12,107
-------------------------------------
Total current assets 625,946 581,356
Property, Plant and Equipment, Net 1,261,155 975,322
Investments in and Advances to Unconsolidated Affiliates 408,290 298,954
Intangible assets, net of accumulated amortization of $10,208 at
September 30, 2001 and $5,374 at December 31, 2000 205,102 92,869
Other Assets 9,505 2,867
-------------------------------------
Total $2,509,998 $1,951,368
=====================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $ 53,680 $ 96,559
Accounts payable - affiliate 33,135 56,447
Accrued gas payables 285,411 377,126
Accrued expenses 17,536 21,488
Other current liabilities 81,578 34,759
-------------------------------------
Total current liabilities 471,340 586,379
Long-Term Debt 855,443 403,847
Other Long-Term Liabilities 17,197 15,613
Minority Interest 11,887 9,570
Commitments and Contingencies
Partners' Equity
Common Units (51,055,715 Units outstanding at September 30, 2001
and 46,257,315 at December 31,2000) 664,287 514,896
Subordinated Units (21,409,870 Units outstanding at September 30, 2001
and December 31,2000) 198,387 165,253
Special Units (14,500,000 Units outstanding at September 30, 2001
and 16,500,000 at December 31,2000) 295,644 251,132
Treasury Units acquired by Trust, at cost (468,800 Common Units
outstanding at September 30,2001 and 267,200 at December 31,2000) (13,566) (4,727)
General Partner 11,700 9,405
Accumulated other comprehensive income (2,321)
-------------------------------------
Total Partners' Equity 1,154,131 935,959
-------------------------------------
Total $2,509,998 $ 1,951,368
=====================================
See Notes to Unaudited Consolidated Financial Statements
Page 1
Enterprise Products Partners L.P.
Statements of Consolidated Operations
(Unaudited)
(Dollar amounts in thousands, except per Unit amounts)
Three Months Nine Months
Ended September 30, Ended September 30,
------------------------------- -------------------------------
2001 2000 2001 2000
------------------------------- -------------------------------
REVENUES
Revenues from consolidated operations $723,329 $717,113 $2,519,041 $2,056,307
Equity income in unconsolidated affiliates 6,289 4,750 17,350 23,290
------------------------------- -------------------------------
Total 729,618 721,863 2,536,391 2,079,597
------------------------------- -------------------------------
COST AND EXPENSES
Operating costs and expenses 634,496 659,021 2,263,876 1,878,233
Selling, general and administrative 7,716 6,978 21,621 20,020
------------------------------- -------------------------------
Total 642,212 665,999 2,285,497 1,898,253
------------------------------- -------------------------------
OPERATING INCOME 87,406 55,864 250,894 181,344
OTHER INCOME (EXPENSE)
Interest expense (12,610) (7,486) (35,928) (23,330)
Interest income from unconsolidated affiliates (88) 31 182
Dividend income from unconsolidated affiliates 392 2,241 2,024 6,236
Interest income - other 861 317 6,338 3,023
Other, net (275) (71) (806) (496)
------------------------------- -------------------------------
Other income (expense) (11,632) (5,087) (28,341) (14,385)
------------------------------- -------------------------------
INCOME BEFORE MINORITY INTEREST 75,774 50,777 222,553 166,959
MINORITY INTEREST (767) (514) (2,245) (1,689)
------------------------------- -------------------------------
NET INCOME $ 75,007 $ 50,263 $ 220,308 $ 165,270
=============================== ===============================
ALLOCATION OF NET INCOME TO:
Limited partners $ 73,408 $ 49,566 $ 216,339 $ 163,423
=============================== ===============================
General partner $ 1,599 $ 697 $ 3,969 $ 1,847
=============================== ===============================
BASIC EARNINGS PER UNIT
Income before minority interest $ 1.05 $ 0.74 $ 3.18 $ 2.47
=============================== ===============================
Net income per Common and Subordinated unit $ 1.04 $ 0.74 $ 3.15 $ 2.44
=============================== ===============================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 0.86 $ 0.60 $ 2.58 $ 2.02
=============================== ===============================
Net income per Common, Subordinated
and Special unit $ 0.85 $ 0.60 $ 2.55 $ 2.00
=============================== ===============================
See Notes to Unaudited Consolidated Financial Statements
Page 2
Enterprise Products Partners L.P.
Statements of Consolidated Cash Flows
(Unaudited)
(Dollar amounts in Thousands)
Nine Months Ended
September 30,
-------------------------------------
2001 2000
-------------------------------------
OPERATING ACTIVITIES
Net income $ 220,308 $ 165,270
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 37,245 27,952
Equity in income of unconsolidated affiliates (17,350) (23,290)
Distributions received from unconsolidated affiliates 30,602 25,997
Leases paid by EPCO 7,900 7,904
Minority interest 2,245 1,689
Loss (gain) on sale of assets (392) 2,276
Changes in fair market value of financial instruments (see Note 10) (39,430)
Net effect of changes in operating accounts (116,362) (27,001)
-------------------------------------
Operating activities cash flows 124,766 180,797
-------------------------------------
INVESTING ACTIVITIES
Capital expenditures (92,641) (200,157)
Proceeds from sale of assets 567 85
Business acquisitions, net of cash received (225,665)
Collection of notes receivable from unconsolidated affiliates 6,519
Investments in and advances to unconsolidated affiliates (119,865) (2,307)
-------------------------------------
Investing activities cash flows (437,604) (195,860)
-------------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 449,717 513,818
Long-term debt repayments (355,000)
Debt issuance costs (3,125) (2,759)
Cash dividends paid to partners (117,125) (103,347)
Cash dividends paid to minority interest by Operating Partnership (1,203) (1,055)
Unit repurchases (465)
Cash contributions from EPCO to minority interest 80 84
Units purchased by Trust (8,839)
Increase in restricted cash associated with commodity hedging activities (9,032)
-------------------------------------
Financing activities cash flows 310,473 51,276
-------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (2,365) 36,213
CASH AND CASH EQUIVALENTS, JANUARY 1 60,409 5,230
-------------------------------------
CASH AND CASH EQUIVALENTS, SEPTEMBER 30 $ 58,044 $ 41,443
=====================================
See Notes to Unaudited Consolidated Financial Statements
Page 3
Enterprise Products Partners L.P.
Statements of Consolidated Partners' Equity and Comprehensive Income
(Unaudited, dollar amounts in thousands)
Partners' Equity
---------------------------------------------------------------------
at September 30, 2001 at September 30, 2000
--------------------------------- ---------------------------------
Units Amount Units Amount
--------------------------------- ---------------------------------
Limited Partners
Balance, beginning of year 84,434 $ 931,280 81,463 $786,250
Net income 216,339 163,423
Leases paid by EPCO 7,820 7,825
Special Units issued to Shell
in connection with
contingency agreement 3,000 117,067 3,000 55,241
Units repurchased and retired in
connection with buy-back program (17) (462)
Cash distributions (114,188) (102,118)
--------------------------------- ---------------------------------
Balance, end of period 87,434 1,158,318 84,446 910,159
--------------------------------- ---------------------------------
Treasury Units acquired by Trust
Balance, beginning of year (267) (4,727) (267) (4,727)
Units purchased by Trust (202) (8,839)
--------------------------------- ---------------------------------
Balance, end of period (469) (13,566) (267) (4,727)
--------------------------------- ---------------------------------
General Partner
Balance, beginning of year 9,405 7,942
Net income 3,969 1,847
Leases paid by EPCO 80 79
Units repurchased and retired in
connection with buy-back program (3)
Cash contributions 1,183 557
Cash distributions (2,937) (1,228)
---------------- -----------------
Balance, end of period 11,700 9,194
---------------- -----------------
Accumulated Other
Comprehensive Loss
Balance, beginning of year
Cumulative transition adjustment
recorded on January 1, 2001
upon adoption of SFAS 133 (42,190)
(see Note 10)
Reclassification of cumulative
transition adjustment to
earnings 39,869
----------------
Balance, end of period (2,321)
--------------------------------- ---------------------------------
Total Partners' Equity 86,965 $1,154,131 84,179 $914,626
================================= =================================
Comprehensive Income for Nine Months Ended
--------------------------------- ---------------------------------
at September 30, 2001 at September 30, 2000
--------------------------------- ---------------------------------
Net Income $ 220,308 $165,270
Less: Accumulated Other
Comprehensive Loss (2,321)
---------------- -----------------
Comprehensive Income $ 217,987 $165,270
================ =================
See Notes to Unaudited Consolidated Financial Statements
Page 4
Enterprise Products Partners L.P.
Notes to Unaudited Consolidated Financial Statements
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, 2001, consolidated results of
operations for the three and nine month periods ended September 30, 2001 and 2000, and cash flows, partners'
equity and comprehensive income for the nine month periods ended September 30, 2001 and 2000. Although the
Company believes the disclosures in these financial statements are adequate to make the information presented not
misleading, certain information and footnote disclosures normally included in annual financial statements
prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to
the rules and regulations of the Securities and Exchange Commission. These unaudited financial statements should
be read in conjunction with the financial statements and notes thereto included in the Company's annual report on
Form 10-K (File No. 1-14323) for the year ended December 31, 2000.
The preparation of financial statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and expenses during the accounting
period. Actual results could differ from those estimates.
The results of operations for the three and nine month periods ended September 30, 2001 are not necessarily
indicative of the results to be expected for the full year due to the effects of, among other things, (a)
seasonal variations in NGL and natural gas prices, (b) timing of maintenance and other expenditures and (c)
acquisitions of assets and other interests.
Certain reclassifications have been made to prior years' financial statements to conform to the presentation of
the current period financial statements. These reclassifications do not affect historical net income of the
Company.
Dollar amounts presented in the tabulations within the notes to the consolidated financial statements are stated
in thousands of dollars, unless otherwise indicated.
2. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
The Company owns interests in a number of related businesses that are accounted for under the equity method or
cost method. The investments in and advances to these unconsolidated affiliates are grouped according to the
operating segment to which they relate. For a general discussion of the Company's business segments, see Note
11.
At September 30, 2001, the Company's equity method investments (grouped by operating segment) included:
Fractionation segment:
o Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in a natural gas liquid ("NGL")
fractionation facility located in southeastern Louisiana.
o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest in a propylene concentration unit
located in southeastern Louisiana that became operational in July 2000.
o K/D/S Promix LLC ("Promix") - a 33.33% interest in a NGL fractionation facility and related storage
facilities located in south Louisiana. The Company's investment includes excess cost over the underlying
equity in the net assets of Promix of $8.0 million which is being amortized using the straight-line method
over a period of 20 years (the excess cost is attributable to the fair market value of the plant assets).
The unamortized balance of excess cost over the underlying equity in the net assets of Promix was $7.1
million at September 30, 2001.
Page 5
Pipeline segment:
o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate interest in a
refrigerated NGL marine terminal loading facility located in southeast Texas.
o Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in a NGL pipeline system located in
southeastern Louisiana.
o Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% interest in a NGL pipeline system
located in Louisiana, Mississippi, and Alabama.
o Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.67% interest in a NGL pipeline system located in
south Louisiana.
o Dixie Pipeline Company ("Dixie") - an aggregate 19.9% interest in a 1,301-mile propane pipeline and
associated facilities extending from Mont Belvieu, Texas to North Carolina. The Company's investment
includes excess cost over the underlying equity in the net assets of Dixie of $37.4 million which is being
amortized using the straight-line method over a period of 35 years (the excess cost is attributable to the
fair market value of the pipeline assets). The unamortized balance of excess cost over the underlying
equity in the net assets of Dixie was $36.0 million at September 30, 2001.
o Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural gas gathering system and
related dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore
Louisiana.
o Ocean Breeze Pipeline Company LLC ("Ocean Breeze") - a 25.67% interest in a limited liability company
owning a 1% interest in the natural gas gathering and transmission systems owned by Manta Ray Offshore
Gathering Company, LLC ("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") located in the Gulf of
Mexico offshore Louisiana.
o Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in a limited liability company owning a 99%
interest in the Manta Ray and Nautilus natural gas gathering and transmission systems.
o Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas gathering system located in
the Gulf of Mexico offshore Louisiana that became operational in August 2001.
o Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, "Evangeline") - an
approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana. The
Company acquired its interests in these entities as a result of the Acadian Gas, LLC acquisition (see Note 3
for a description of this acquisition).
2001 Gulf of Mexico natural gas pipeline equity investments
The Company acquired its equity interests in Ocean Breeze, Neptune, Nemo and Starfish and their underlying
investments on January 29, 2001 from EPE using proceeds from the issuance of the $450 Million Senior Notes
(see Note 5 for discussion of long-term debt). The cash purchase price of the Ocean Breeze, Neptune and
Nemo interests was $86.9 million with the purchase price of the Starfish interests being $25.1 million.
As a result of its investment in Ocean Breeze and Neptune, the Company acquired a 25.67% interest in each of
the Manta Ray and Nautilus systems and a 33.92% interest in the Nemo system. Affiliates of Shell own an
interest in all three systems, and an affiliate of Marathon Oil Company owns an interest in the Manta Ray
and Nautilus systems. The Manta Ray system comprises approximately 225 miles of pipeline with a capacity
of 750 MMcf/d and related equipment, the Nautilus system comprises approximately 101 miles of pipeline with
a capacity of 600 MMcf/d, and the Nemo system comprises approximately 24 miles of pipeline with a capacity
of 300 MMcf/d. Shell is responsible for the commercial and physical operations of these pipeline systems.
The Company's investment in Ocean Breeze, Neptune and Nemo includes excess cost over the underlying equity
in the net assets of these entities of $23.7 million which is being amortized using the straight-line method
over a period of 35 years (the excess cost amounts are attributable to the fair market value of the pipeline
assets). The unamortized balance of excess cost over the underlying equity in the net assets of Ocean
Breeze, Neptune and Nemo was $23.1 million at September 30, 2001.
As a result of its investment in Starfish, the Company acquired a 50% interest in the Stingray system and a
related onshore natural gas dehydration facility. The Company's sole partner in Starfish is an affiliate of
Shell. The Stingray system comprises approximately 375 miles of pipeline with a capacity of 1.2 Bcf/d and
Page 6
is located offshore Louisiana in the Gulf of Mexico. Shell is responsible for the commercial and physical
operations of the Stingray system and related facilities.
Historical information for periods prior to January 1, 2001 do not reflect any impact associated with the
Company's equity investments in Ocean Breeze, Neptune, Nemo and Starfish. See Note 3 for combined pro
forma impact of these investments on selected financial information of the Company.
Octane Enhancement segment:
o Belvieu Environmental Fuels ("BEF") - a 33.33% interest in a MTBE production facility located in
southeast Texas. The production of MTBE is driven by oxygenated fuels programs enacted under the federal
Clean Air Act Amendments of 1990 and other legislation and as an additive to increase octane in motor
gasoline. Any changes to these programs that enable localities to elect not to participate in these
programs, lessen the requirements for oxygenates or favor the use of non-isobutane based oxygenated fuels
reduce the demand for MTBE and could have an adverse effect on the Company's results of operations.
In recent years, MTBE has been detected in water supplies. The major source of the ground water
contamination appears to be leaks from underground storage tanks. Although these detections have been
limited and the great majority have been well below levels of public health concern, there have been calls
for the phase-out of MTBE in motor gasoline in various federal and state governmental agencies and advisory
bodies.
In light of these developments, the owners of BEF have been formulating a contingency plan for use of the
BEF facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion
of the BEF facility from MTBE production to alkylate production. Management believes if MTBE usage is
banned or significantly curtailed, the motor gasoline industry would need a substitute additive to maintain
octane levels in motor gasoline. Management believes alkylate would be an attractive substitute. Depending
upon the type of alkylate process chosen and the level of alkylate production desired, the cost to convert
the facility from MTBE production to alkylate production can range from $20 million to $90 million, with the
Company's share of these costs ranging from $6.7 million to $30 million.
At September 30, 2001, the Company's investments in and advances to unconsolidated affiliates also includes
Venice Energy Services Company, LLC ("VESCO"). The VESCO investment consists of a 13.1% interest in a company
owning a natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in
Louisiana. This investment is accounted for using the cost method under the Processing segment.
Page 7
The following table summarizes investments in and advances to unconsolidated affiliates at:
September 30, December 31,
2001 2000
-------------------------------------
Accounted for on equity basis:
Fractionation:
BRF $ 29,664 $ 30,599
BRPC 19,069 25,925
Promix 45,497 48,670
Pipeline:
EPIK 17,691 15,998
Wilprise 8,950 9,156
Tri-States 27,277 27,138
Belle Rose 11,655 11,653
Dixie 37,585 38,138
Starfish 25,875
Ocean Breeze 967
Neptune 75,046
Nemo 11,745
Evangeline 2,697
Octane Enhancement:
BEF 61,572 58,677
Accounted for on cost basis:
Processing:
VESCO 33,000 33,000
-------------------------------------
Total $408,290 $298,954
=====================================
The following table shows equity in income (loss) of unconsolidated affiliates for the periods indicated:
For Three Months Ended For Nine Months Ended
September 30, September 30,
------------------------------------- -------------------------------------
2001 2000 2001 2000
------------------------------------- -------------------------------------
Fractionation:
BRF $ 672 $ 434 $ 732 $ 1,171
BRPC 221 134 625 115
Promix 1,055 1,170 2,844 4,378
Pipeline:
EPIK 150 (124) (944) 1,846
Wilprise 370 135 233 297
Tri-States 789 694 889 2,215
Belle Rose 62 117 2 266
Dixie 240 1,200
Starfish 789 2,762
Ocean Breeze 8 22
Neptune 1,035 2,824
Nemo (52) (42)
Evangeline 41 (108)
Octane Enhancement:
BEF 909 2,190 6,311 13,002
------------------------------------- -------------------------------------
Total $ 6,289 $ 4,750 $ 17,350 $ 23,290
===================================== =====================================
Page 8
The following table presents summarized income statement information for the unconsolidated affiliates accounted
for by the equity method for the periods indicated (on a 100% basis):
Summarized Income Statement data for the Three Months ended
-----------------------------------------------------------------------------------------------
September 30, 2001 September 30, 2000
---------------------------------------------- -----------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
---------------------------------------------- -----------------------------------------------
Fractionation:
BRF $ 5,827 $ 2,057 $ 2,084 $ 4,774 $ 1,282 $ 1,347
BRPC 2,414 717 738 2,333 398 448
Promix 11,122 3,439 3,461 12,242 3,956 4,019
Pipeline:
EPIK 2,583 272 302 1,817 (323) (282)
Wilprise 1,057 989 992 726 397 406
Tri-States 3,632 2,328 2,365 3,430 2,060 2,088
Belle Rose 489 144 149 536 279 279
Dixie (a) 14,534 6,860 4,138
Starfish (b) 3,916 1,649 2,227
Ocean Breeze (b) 34 4 26
Neptune (b) 7,940 3,354 3,363
Nemo (b) 213 (44) (38)
Evangeline (c) 43,486 1,287 32
Octane Enhancement:
BEF 54,955 2,060 2,725 77,331 6,202 6,570
---------------------------------------------- -----------------------------------------------
Total $152,202 $25,116 $22,564 $103,189 $14,251 $14,875
============================================== ===============================================
Summarized Income Statement data for the Nine Months ended
-----------------------------------------------------------------------------------------------
September 30, 2001 September 30, 2000
---------------------------------------------- -----------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
---------------------------------------------- -----------------------------------------------
Fractionation:
BRF $ 13,652 $ 2,357 $ 2,434 $ 13,989 $ 3,504 $ 3,631
BRPC 9,247 1,949 2,085 2,333 211 383
Promix 32,465 9,327 9,425 36,968 14,097 14,274
Pipeline:
EPIK 4,550 (1,510) (1,423) 14,789 3,561 3,699
Wilprise 1,950 611 625 2,149 867 891
Tri-States 7,585 2,590 2,664 10,677 6,530 6,650
Belle Rose 1,043 (61) (43) 1,802 645 645
Dixie (a) 38,570 15,161 8,967
Starfish (b) 17,383 6,039 6,143
Ocean Breeze (b) 121 91 91
Neptune (b) 24,687 12,002 11,944
Nemo (b) 213 (86) (2)
Evangeline (c) 91,095 2,297 (112)
Octane Enhancement:
BEF 168,873 17,982 18,932 214,761 38,575 39,007
---------------------------------------------- -----------------------------------------------
Total $411,434 $68,749 $61,730 $297,468 $67,990 $69,180
============================================== ===============================================
Page 9
Notes to Summarized Income Statement data tables:
(a) Dixie became an equity method investment in October 2000.
(b) These entities became equity method investments of the Company beginning in January 2001.
(c ) This entity became an equity method investment of the Company in April 2000 as a result of the Acadian Gas
acquisition (see Note 3).
3. ACQUISITIONS
Since January 1, 2001, the Company has invested approximately $338 million (net of cash acquired) in natural gas
pipeline businesses. These include:
o a combined $112 million in Ocean Breeze, Neptune, Nemo and Starfish (see Note 2 for a discussion of
these equity investments); and,
o an initial $226 million for the purchase of Acadian Gas, LLC ("Acadian Gas").
Acquisition of Acadian Gas
On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an affiliate of Shell, for
approximately $226 million in cash using proceeds from the issuance of the $450 Million Senior Notes (see Note 5
for a discussion of long-term debt). The cash purchase price is subject to certain post-closing adjustments
expected to be completed during the fourth quarter of 2001. The effective date of the transaction was April 1,
2001.
Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. Acadian
Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline
systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are wholly-owned by
Acadian Gas with the exception of the Evangeline system in which Acadian Gas owns an aggregate 49.5% interest.
The assets acquired include a leased natural gas storage facility located in Napoleonville, Louisiana.
The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and, through
connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies, electric
generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor.
In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.
The Acadian Gas acquisition was accounted for under the purchase method of accounting and, accordingly, the
initial purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated
fair values at April 1, 2001, as follows:
Current assets $ 83,123
Investments in unconsolidated affiliates 2,723
Property, plant and equipment 225,169
Current liabilities (83,890)
Other long-term liabilities (1,460)
---------------
Total purchase price $225,665
===============
The balances related to the Acadian Gas acquisition included in the consolidated balance sheet dated September
30, 2001 are based upon preliminary information and are subject to change as additional information is
obtained. As noted earlier, the initial purchase price is subject to certain post-closing adjustments
attributable to working capital items expected to be finalized during the fourth quarter of 2001.
Historical information for periods prior to April 1, 2001 do not reflect any impact associated with the Acadian
Gas acquisition.
Page 10
Pro Forma effect of Acadian Gas acquisition and recently acquired equity investments
The following table presents selected unaudited pro forma information for the three month period ended September
30, 2000 and nine month periods ended September 30, 2001 and 2000 as if the acquisition of the Acadian Gas
natural gas pipeline systems had been made as of the beginning of the years presented. This table also
incorporates selected unaudited pro forma information for the three and nine month periods ended September 30,
2000 relating to the Company's equity investments in Starfish, Ocean Breeze and Neptune.
The pro forma information is based upon data currently available to and certain estimates and assumptions by
management and, as a result, are not necessarily indicative of the financial results of the Company had the
transactions actually occurred on these dates. Likewise, the unaudited pro forma information is not necessarily
indicative of future financial results of the Company.
Three
Months Ended Nine Months Ended
September 30, September 30,
------------------------------------
2000 2001 2000
-------------------------------------------------------
Revenues $875,197 $2,748,318 $2,483,449
Income before extraordinary item
and minority interest $ 51,201 $ 226,837 $ 166,388
Net income $ 50,683 $ 224,549 $ 164,705
Allocation of net income to
Limited partners $ 49,983 $ 221,387 $ 162,864
General Partner $ 700 $ 3,162 $ 1,841
Units used in earnings per Unit calculations
Basic 67,356 68,759 66,917
Diluted 83,182 84,819 81,862
Income per Unit before minority interest
Basic $0.75 $3.25 $2.46
Diluted $0.61 $2.64 $2.01
Net income per Unit
Basic $0.74 $3.22 $2.43
Diluted $0.60 $2.61 $1.99
4. RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the FASB issued two new pronouncements: Statement of Financial Accounting Standards ("SFAS") No.
141, " Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits
the use of the pooling-of-interest method for business combinations initiated after June 30, 2001 and also
applies to all business combinations accounted for by the purchase method that are completed after June 30,
2001. There are also transition provisions that apply to business combinations completed before July 1, 2001,
that were accounted for by the purchase method. SFAS No. 142 is effective for the Company's fiscal year
beginning January 1, 2002 for all goodwill and other intangible assets recognized in its consolidated balance
sheet at that date, regardless of when those assets were initially recognized.
Page 11
At present, the Company's intangible assets include the values assigned to the 20-year Shell natural gas
processing agreement and the excess cost of the purchase price over the fair market value of the assets acquired
from Mont Belvieu Associates, both of which were initially recorded in 1999. The value of the Shell Processing
Agreement is being amortized over its contract term and the excess cost of the purchase price over the fair
market value of the assets acquired from Mont Belvieu Associates is being amortized over 20 years. Based upon
initial interpretations of the new accounting standards, the Company anticipates that the Shell Processing
Agreement will continue to be amortized over its contract term; however, the excess cost attributable to Mont
Belvieu Associates will be reclassified to goodwill in accordance with the new standard and its amortization will
cease (currently, $0.5 million in amortization expense annually). This goodwill would then be subject to
impairment testing as prescribed in SFAS No. 142.
The Company is continuing to evaluate the complex provisions of SFAS No. 141 and SFAS No. 142 and has not adopted
such provisions in its September 30, 2001 financial statements.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset Retirement
Obligations", in June 2001. This statement establishes accounting standards for the recognition and
measurement of a liability for an asset retirement obligation and the associated asset retirement cost. This
statement is effective for the Company's fiscal year beginning January 1, 2003. In August 2001, the FASB issued
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". This statement addresses
financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be
disposed of. This statement is effective for the Company's fiscal year beginning January 1, 2002. Management
is currently studying both SFAS No. 143 and No. 144 for their possible impact, if any, on the consolidated
financial statements when they are adopted.
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
September 30, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 350,000 350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
---------------------------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt (see Note 10) 1,833
Less unamortized discount on:
$350 Million Senior Notes (126) (153)
$450 Million Senior Notes (264)
Less current maturities of long-term debt
---------------------------------------
Long-term debt $855,443 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility and $150
Million 364-Day Credit Facility. The $150 Million 364-Day Credit Facility has an original maturity date of
November 16, 2001. An amendment to the 364-Day Credit Facility to extend this date through November 15, 2002
was consented to by the lenders in early November 2001. No amount was outstanding under either of these two
revolving credit facilities at September 30, 2001 or December 31, 2000.
At September 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its
$250 Million Multi-Year Credit Facility of which $14.9 million was outstanding.
Page 12
$450 Million Senior Notes. On January 24, 2001, a subsidiary of the Company completed a public offering of $450
million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of
99.937% per Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting
discounts and commissions, of approximately $446.8 million. The proceeds from this offering were used to
acquire the Acadian Gas, Ocean Breeze, Neptune, Nemo and Starfish natural gas pipeline systems for $338 million
and to finance the cost to construct certain NGL pipelines and related projects and for working capital and other
general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is also
applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As with
the $350 Million Senior Notes, the $450 Million Senior Notes:
o are subject to a make-whole redemption right;
o are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness; and,
o are guaranteed by the Company through an unsecured and unsubordinated guarantee.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 $800 million
universal registration statement; therefore, the amount of securities available under this registration statement
was reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration
statement (the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity
or debt securities or a combination thereof.
The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and
variable-rate debt instruments at September 30, 2001.
Increase in fair value of fixed-rate debt. Upon adoption of SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3 million
non-cash increase in the fair value of its fixed-rate debt. SFAS No. 133 required that the Company's interest
rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption of the standard.
After adoption of the standard, the interest rate swaps were dedesignated due to differences in the estimated
maturity dates of the interest rate swaps versus the fixed-rate debt. As a result, the fair value of the hedged
fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million increase in the fair
value of the debt will be amortized to earnings over the remaining life of the fixed-rate debt to which it
applies, which approximates 10 years. The fair value adjustment of $2.3 million is not a cash obligation of the
Company and does not alter the amount of the Company's indebtedness. See Note 10 for additional information
concerning the Company's financial instruments.
6. CAPITAL STRUCTURE
Final issue of Special Units. On or about June 30, 2001, Shell met certain year 2001 performance criteria for
the issuance of the last installment of 3.0 million non-distribution bearing, convertible Contingency Units
(referred to as Special Units once they are issued). Under a contingent unit agreement with Shell executed as
part of the 1999 TNGL acquisition, the Company issued these Special Units on August 2, 2001.
The value of these Special Units was determined to be $117.1 million using present value techniques. This
amount increased the purchase price of the TNGL acquisition and the value of the Shell Processing Agreement when
the issue was recorded in August 2001. This amount also increased the equity position of Shell in the Company
by $117.1 million with the General Partner contributing $1.2 million to maintain its respective ownership in the
Company. The $117.1 million increase in value of the 20-year Shell Processing Agreement will be amortized over
the remaining life of the contract. As a result, amortization expense will increase by approximately $1.6
million per quarter ($6.5 million annually).
Conversion of Special Units to Common Units. In accordance with existing agreements with Shell, 5.0 million of
Shell's original issue of Special Units converted into Common Units on August 2, 2001.
Page 13
7. EARNINGS PER UNIT
Basic earnings per Unit is computed by dividing net income available to limited partner interests by the
weighted-average number of Common and Subordinated Units outstanding during the period. Diluted earnings per
Unit is computed by dividing net income available to limited partner interests by the weighted-average number of
Common, Subordinated and Special Units outstanding during the period. The following table reconciles the
number of shares used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three
and nine months ended September 30, 2001 and 2000:
For Three Months Ended For Nine Months Ended
September 30, September 30,
-------------------------------- --------------------------------
2001 2000 2001 2000
-------------------------------- --------------------------------
Income before minority interest $75,774 $50,777 $222,553 $166,959
General partner interest (1,599) (697) (3,969) (1,847)
-------------------------------- --------------------------------
Income before minority interest 74,175 50,080 218,584 165,112
available to Limited Partners
Minority interest (767) (514) (2,245) (1,689)
-------------------------------- --------------------------------
Net income available to Limited Partners $73,408 $49,566 $216,339 $163,423
================================ ================================
BASIC EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $74,175 $50,080 $218,584 $165,112
================================ ================================
Net income available
to Limited Partners $73,408 $49,566 $216,339 $163,423
================================ ================================
Denominator
Common Units outstanding 49,497 45,946 47,349 45,507
Subordinated Units outstanding 21,410 21,410 21,410 21,410
-------------------------------- --------------------------------
Total 70,907 67,356 68,759 66,917
================================ ================================
Basic Earnings per Unit
Income before minority interest
available to Limited Partners $ 1.05 $ 0.74 $ 3.18 $ 2.47
================================ ================================
Net income available
to Limited Partners $ 1.04 $ 0.74 $ 3.15 $ 2.44
================================ ================================
DILUTED EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $74,175 $50,080 $218,584 $165,112
================================ ================================
Net income available
to Limited Partners $73,408 $49,566 $216,339 $163,423
================================ ================================
Denominator
Common Units outstanding 49,497 45,946 47,349 45,507
Subordinated Units outstanding 21,410 21,410 21,410 21,410
Special Units outstanding 15,196 15,826 16,060 14,945
-------------------------------- --------------------------------
Total 86,103 83,182 84,819 81,862
================================ ================================
Diluted Earnings per Unit
Income before minority interest
available to Limited Partners $ 0.86 $ 0.60 $ 2.58 $ 2.02
================================ ================================
Net income available
to Limited Partners $ 0.85 $ 0.60 $ 2.55 $ 2.00
================================ ================================
Page 14
8. DISTRIBUTIONS
The Company intends, to the extent there is sufficient available cash from Operating Surplus, as defined by the
Partnership Agreement, to distribute to each holder of Common Units at least a minimum quarterly distribution of
$0.45 per Common Unit. The minimum quarterly distribution is not guaranteed and is subject to adjustment as set
forth in the Partnership Agreement. With respect to each quarter during the Subordination Period, the Common
Unitholders will generally have the right to receive the minimum quarterly distribution, plus any arrearages
thereon, and the General Partner will have the right to receive the related distribution on its interest before
any distributions of available cash from Operating Surplus are made to the Subordinated Unitholders. As an
incentive, the General Partner's interest in quarterly distributions is increased after certain specified target
levels are met. The Company made incentive cash distributions to the General Partner of $0.9 million and $1.3
million during the three and nine months ended September 30, 2001, respectively, and $0.2 million during the
three months ended September 30, 2000.
The following is a summary of cash distributions to partnership interests since the first quarter of 1999:
Cash Distributions
--------------------------------------------------------------------
Per
Per Common Subordinated Record Payment
Unit Unit Date Date
--------------------------------------------------------------------
1999 First Quarter $ 0.450 $ 0.450 Jan. 29, 1999 Feb. 11, 1999
Second Quarter $ 0.450 $ 0.070 Apr. 30, 1999 May 12, 1999
Third Quarter $ 0.450 $ 0.370 Jul. 30, 1999 Aug. 11, 1999
Fourth Quarter $ 0.450 $ 0.450 Oct. 29, 1999 Nov. 10, 1999
2000 First Quarter $ 0.500 $ 0.500 Jan. 31, 2000 Feb. 10, 2000
Second Quarter $ 0.500 $ 0.500 Apr. 28, 2000 May 10, 2000
Third Quarter $ 0.525 $ 0.525 Jul. 31, 2000 Aug. 10, 2000
Fourth Quarter $ 0.525 $ 0.525 Oct. 31, 2000 Nov. 10, 2000
2001 First Quarter $ 0.550 $ 0.550 Jan. 31, 2001 Feb. 9, 2001
Second Quarter $ 0.550 $ 0.550 Apr. 30, 2001 May 10, 2001
Third Quarter $ 0.5875 $ 0.5875 Jul. 31, 2001 Aug. 10, 2001
Fourth Quarter $ 0.6250 $ 0.6250 Oct. 31, 2001 Nov. 9, 2001
(through November 12, 2001)
Page 15
9. SUPPLEMENTAL CASH FLOW DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows for the periods indicated:
Nine Months Ended
September 30,
------------------------------------------
2001 2000
------------------------------------------
(Increase) decrease in:
Accounts receivable $ 153,224 $(15,409)
Inventories (51,753) (66,270)
Prepaid and other current assets (8,732) 1,841
Intangible assets (4,805)
Other assets (122) (3,022)
Increase (decrease) in:
Accounts payable (79,413) 7,109
Accrued gas payable (146,041) 47,517
Accrued expenses (6,500) (6,314)
Other current liabilities 22,851 12,749
Other liabilities 124 (397)
------------------------------------------
Net effect of changes in operating accounts $(116,362) $(27,001)
==========================================
Business acquisitions (net of cash received) for the 2001 period reflects a net $226 million paid to an affiliate
of Shell for Acadian Gas. Investments in and advances to unconsolidated affiliates for the 2001 period reflects
$112 million paid to EPE for equity interests in various Gulf of Mexico natural gas pipeline systems. Capital
expenditures for 2000 included $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets.
As a result of the Company's adoption of SFAS No. 133 on January 1, 2001, the Company records various financial
instruments relating to interest rate and commodity positions at their respective fair values. For the nine
months ended September 30, 2001, the Company recognized a net $39.4 million in non-cash mark-to-market gains
related to increases in the fair value of these financial instruments ($34.6 million of this amount was
attributable to financial instruments used in the Company's Processing segment with the remainder resulting from
interest rate hedging activities). See Note 10 below for a further description of the Company's financial
instruments.
Cash and cash equivalents at September 30, 2001 per the Statements of Consolidated Cash Flows excludes $9.0
million of restricted cash associated with hedging activities.
10. FINANCIAL INSTRUMENTS
The Company holds and issues financial instruments for the purpose of hedging the risks of certain identifiable
and anticipated transactions primarily in its Processing segment. In general, the types of risks hedged are
those relating to the variability of future earnings and cash flows caused by changes in commodity prices and
interest rates.
Commodity Financial Instruments
In its Processing segment, the Company's margin is directly exposed to commodity price risk. In order to manage
this risk, the Company may enter into swaps, forwards, commodity futures, options and other commodity financial
instruments with similar characteristics that are permitted by contract or business custom to be settled in cash
or with another financial instrument. The purpose of these risk management activities is to hedge exposure to
price risks associated with natural gas, NGL production and inventories, firm commitments and certain anticipated
transactions.
The Company has adopted a commercial policy to manage its exposure to the risks associated with its Processing
segment. The objective of this policy is to assist the Company in achieving its profitability goals while
Page 16
maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits
established by the General Partner. The Company enters into risk management transactions to manage price risk,
basis risk, physical risk, or other risks related to the energy commodities on both a short-term (less than 30
days) and long-term basis, not to exceed 18 months. The General Partner oversees the strategies of the Company
associated with physical and financial risks (such as those mentioned previously), approves specific activities
of the Company subject to the policy (including authorized products, instruments and markets) and establishes
specific guidelines and procedures for implementing and ensuring compliance with the policy.
On January 1, 2001, the Company adopted SFAS No. 133 which required the Company to record the fair market value
of the commodity financial instruments on the balance sheet based upon then current market conditions. The
fair market value of the then outstanding commodity financial instruments was a net liability of $42.2 million
(the "cumulative transition adjustment") with an offsetting equal amount recorded in Other Comprehensive
Income. The amounts in Other Comprehensive Income are reclassified to earnings in the accounting period
associated with the hedged transaction (e.g. production month). The $42.2 million cumulative transition
adjustment was or will be reclassified to earnings as follows:
- $21.7 million during the first quarter of 2001;
- $10.7 million during the second quarter of 2001;
- $7.3 million during the third quarter of 2001; with the remaining
- $2.5 million reclassified during the fourth quarter of 2001.
The cumulative transition adjustment recorded in Other Comprehensive Income at adoption of SFAS No. 133 will not
be adjusted for changes in fair value; rather, any change in the fair value of these commodity financial
instruments will be recorded in earnings (i.e., mark-to-market accounting treatment). The decision to record
changes in the fair value of these commodity financial instruments directly to earnings rather than Other
Comprehensive Income is based upon the determination by management that on an ongoing basis these commodity
financial instruments would be ineffective under the guidelines of SFAS No. 133.
The Company has entered into commodity financial instruments for time periods extending through December 2002.
These commodity financial instruments may not qualify for hedge accounting treatment under the specific
guidelines of SFAS No. 133. The Company continues to refer to these financial instruments as hedges inasmuch as
this was the intent when such contracts were executed. This characterization is consistent with the actual
economic performance of the contracts to date and the Company expects these financial instruments should continue
to mitigate commodity price risk in the future. The specific accounting for these contracts, however, is
consistent with the requirements of SFAS No. 133. As such, since these contracts do not qualify for hedge
accounting under the specific guidelines of SFAS No. 133, the change in fair value of these commodity financial
instruments are reflected on the balance sheet and in earnings (i.e., mark-to-market accounting treatment). The
Company recognized income associated with its commodity financial instruments of $48.2 million and $118.5 million
for the three and nine months ended September 30, 2001, respectively.
Other Financial Instruments - Interest rate swaps
The objective of holding interest rate swaps is to manage debt service costs by converting a portion of
fixed-rate debt into variable-rate debt or a portion of variable-rate debt into fixed-rate debt. An interest
rate swap, in general, requires one party to pay a fixed-rate on the notional amount while the other party pays a
floating-rate based on the notional amount. Management believes that it is prudent to maintain an appropriate
mixture of variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate exposure
that impact future cash flows and evaluating hedging opportunities. The Company uses analytical techniques to
measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the
expected impact of changes in interest rates on the Company's future cash flows. The General Partner oversees
the strategies of the Company associated with financial risks and approves instruments that are appropriate for
the Company's requirements.
Page 17
On January 1, 2001, the Company adopted SFAS No. 133 which required the Company to record the fair market value
of the interest rate swaps on the balance sheet since the swaps were considered fair value hedges. SFAS No. 133
required that management determine (at the standard's adoption date) (a) the fair value of the swaps based upon
then current market conditions and (b) the estimated maturity date of the swaps (including an estimate of the
impact of any early termination clauses). The recording of the fair market value of the swaps was offset by an
equal increase in the fair value of the associated hedged debt instruments and, therefore, had no impact on
earnings upon transition. See Note 5 for further information regarding the impact of SFAS No. 133 on the
Company's fixed-rate long-term debt.
After adoption, the interest rate swaps were dedesignated as hedging instruments due to differences between the
maturity dates of the swaps and the associated hedged debt instruments. Dedesignation means that the financial
instrument (in this case, the interest rate swaps) will not be accounted for using hedge accounting under SFAS
No. 133. Upon dedesignation, any future changes in the fair value of the interest rate swap agreements will be
recorded on the balance sheet through earnings. Dedesignation also entails that the previously associated
hedged item (in this case, the debt instrument) will not be adjusted for future changes in its fair value. As a
result, the $2.3 million change in fair value of the debt instrument recorded at the adoption date of SFAS No.
133 will be amortized to earnings over the life of the previously associated debt instrument of approximately 10
years.
The Company recognized income associated with its interest rate swaps of $4.0 million and $9.4 million for the
three and nine months ended September 30, 2001. In October 2001, the Company realized $4.7 million of
incremental cash flow through the early termination of a swap agreement.
Future issues
Due to the complexity of SFAS No. 133, the FASB is continuing to provide guidance about implementation issues.
Since this guidance is still continuing, the initial conclusions reached by the Company regarding the application
of SFAS No. 133 upon adoption may be altered. As a result, additional SFAS No. 133 transition adjustments may be
recorded in future periods as the Company adopts new FASB interpretations.
Page 18
11. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial information is available and that
are regularly evaluated by the chief operating decision maker in deciding how to allocate resources and in
assessing performance. Generally, financial information is required to be reported on the basis that it is used
internally for evaluating segment performance and deciding how to allocate resources to segments.
The Company has five reportable operating segments: Fractionation, Pipelines, Processing, Octane Enhancement and
Other. The reportable segments are generally organized according to the type of services rendered (or process
employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief
Executive Officer of the General Partner. Fractionation primarily includes NGL fractionation, butane
isomerization (converting normal butane into high purity isobutane) and polymer grade propylene fractionation
services. Pipelines consists of both liquids and natural gas pipeline systems, storage and import/export
terminal services. Processing includes the natural gas processing business and its related NGL merchant
activities. Octane Enhancement represents the Company's 33.33% ownership interest in a facility that produces
motor gasoline additives to enhance octane (currently producing MTBE). The Other operating segment consists of
fee-based marketing services and other plant support functions.
The Company evaluates segment performance based on gross operating margin. Gross operating margin reported for
each segment represents operating income before depreciation and amortization, lease expense obligations retained
by EPCO, gains and losses on the sale of assets and general and administrative expenses. In addition, segment
gross operating margin is exclusive of interest expense, interest income (from unconsolidated affiliates or
others), dividend income from unconsolidated affiliates, minority interest, extraordinary charges and other
income and expense transactions. The Company's equity earnings from unconsolidated affiliates are included in
segment gross operating margin.
Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are
allocated to each segment on the basis of each asset's or investment's principal operations. The principal
reconciling item between consolidated property, plant and equipment and segment property is
construction-in-progress. Segment property represents those facilities and projects that contribute to gross
operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not
generally contribute to segment gross operating margin, these assets are not included in the operating segment
totals until they are deemed operational.
Segment gross operating margin is inclusive of intersegment revenues, which are generally based on transactions
made at market-related rates. These revenues have been eliminated from the consolidated totals.
Page 19
Information by operating segment, together with reconciliations to the consolidated totals, is presented in the
following table:
Operating Segments Adjs.
------------------------------------------------------------------
Octane and Consol.
Fractionation Pipelines Processing Enhancement Other Elims. Totals
---------------------------------------------------------------------------------------------
Revenues from
external customers
for three months ended:
September 30, 2001 $75,842 $127,687 $519,165 $635 $723,329
September 30, 2000 113,180 (2,735) 605,875 793 717,113
for nine months ended:
September 30, 2001 252,087 313,832 1,951,176 1,946 2,519,041
September 30, 2000 302,081 21,191 1,730,976 2,059 2,056,307
Intersegment revenues
for three months ended:
September 30, 2001 41,273 22,464 244,145 99 $(307,981)
September 30, 2000 46,538 12,083 165,761 93 (224,475)
for nine months ended:
September 30, 2001 127,058 67,874 486,111 290 (681,333)
September 30, 2000 129,266 40,108 447,646 282 (617,302)
Equity income in
unconsolidated affiliates:
for three months ended:
September 30, 2001 1,948 3,432 $909 6,289
September 30, 2000 1,738 822 2,190 4,750
for nine months ended:
September 30, 2001 4,201 6,838 6,311 17,350
September 30, 2000 5,664 4,624 13,002 23,290
Total revenues
for three months ended:
September 30, 2001 119,063 153,583 763,310 909 734 (307,981) 729,618
September 30, 2000 161,456 10,170 771,636 2,190 886 (224,475) 721,863
for nine months ended:
September 30, 2001 383,346 388,544 2,437,287 6,311 2,236 (681,333) 2,536,391
September 30, 2000 437,011 65,923 2,178,622 13,002 2,341 (617,302) 2,079,597
Gross operating margin
by segment
for three months ended:
September 30, 2001 35,189 22,415 52,026 909 310 110,849
September 30, 2000 32,510 10,292 29,083 2,190 429 74,504
for nine months ended:
September 30, 2001 93,660 65,234 148,536 6,311 1,256 314,997
September 30, 2000 96,432 39,120 87,123 13,002 1,854 237,531
Segment assets at:
September 30, 2001 354,012 698,766 125,071 9,572 73,734 1,261,155
December 31, 2000 356,207 448,920 126,895 8,942 34,358 975,322
Investments in and advances
to unconsolidated
affiliates at:
September 30, 2001 94,230 219,488 33,000 61,572 408,290
December 31, 2000 105,194 102,083 33,000 58,677 298,954
Page 20
All consolidated revenues were earned in the United States. The operations of the Company are centered along
the Texas, Louisiana and Mississippi Gulf Coast areas.
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
For Three Months Ended For Nine Months Ended
September 30, September 30,
--------------------------------- ---------------------------------
2001 2000 2001 2000
---------------------------------------------------------------------
Total segment gross operating margin $110,849 $74,504 $314,997 $237,531
Depreciation and amortization (13,072) (9,029) (34,894) (25,907)
Retained lease expense, net (2,660) (2,660) (7,980) (7,984)
(Gain) loss on sale of assets 5 27 392 (2,276)
Selling, general and administrative (7,716) (6,978) (21,621) (20,020)
--------------------------------- ---------------------------------
Consolidated operating income 87,406 55,864 250,894 181,344
Interest expense (12,610) (7,486) (35,928) (23,330)
Interest income from unconsolidated affiliates (88) 31 182
Dividend income from unconsolidated affiliates 392 2,241 2,024 6,236
Interest income - other 861 317 6,338 3,023
Other expense, net (275) (71) (806) (496)
--------------------------------- ---------------------------------
Consolidated income before minority interest $ 75,774 $50,777 $222,553 $166,959
================================= =================================
Page 21
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION.
For the Interim Periods ended September 30, 2001 and 2000
The following discussion and analysis should be read in conjunction with the unaudited consolidated
financial statements and notes thereto of the Company included elsewhere herein.
Cautionary Statement regarding Forward-Looking Information and Risk Factors
This quarterly report on Form 10-Q contains various forward-looking statements and information that are
based on the belief of the Company and the General Partner, as well as assumptions made by and information
currently available to the Company and the General Partner. When used in this document, words such as
"anticipate," "estimate," "project," "expect," "plan," "forecast," "intend," "could," "believe," "may" and similar
expressions and statements regarding the plans and objectives of the Company for future operations, are intended
to identify forward-looking statements. Although the Company and the General Partner believe that the
expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such
expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and
assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, actual results may vary materially from those anticipated, estimated, projected, or expected.
Risk Factors. An investment in the Company's securities involves a degree of risk. Among the key risk
factors that may have a direct bearing on the Company's results of operations and financial condition are: (a)
competitive practices in the industries in which the Company competes, (b) fluctuations in oil, natural gas, and
natural gas liquid ("NGL") prices and production due to weather and other natural and economic forces, (c)
operational and systems risks, (d) environmental liabilities that are not covered by indemnity or insurance, (e)
the impact of current and future laws and governmental regulations (including environmental regulations)
affecting the NGL industry in general, and the Company's operations in particular, (f) loss of a significant
customer, (g) the use of financial instruments to hedge commodity and interest rate risks which prove to be
economically ineffective and (h) failure to complete one or more new projects on time or within budget.
The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond the Company's control. These factors include
the level of domestic oil, natural gas and NGL production and development, the availability of imported oil and
natural gas, actions taken by foreign oil and natural gas producing nations, the availability of transportation
systems with adequate capacity, the availability of competitive fuels and products, fluctuating and seasonal
demand for oil, natural gas and NGLs and conservation and the extent of governmental regulation of production and
the overall economic environment.
The products that the Company processes, sells or transports are principally used as feedstocks in
petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and commercial
heating. A reduction in demand for the Company's products or processing or transportation services by the
petrochemical, refining or heating industries, whether because of general economic conditions, reduced demand by
consumers for the end products made with NGL products, increased competition from petroleum-based products due to
pricing differences, adverse weather conditions, governmental regulations affecting prices and production levels
of natural gas or the content of motor gasoline or other reasons, could have a negative impact on the Company's
results of operations. A material decrease in natural gas production or crude oil refining, as a result of
depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in
the volumes of NGLs processed or sold by the Company, thereby reducing revenue and operating income.
In addition, the Company's expectations regarding its future capital expenditures as described in
"Liquidity and Capital Resources" are only its forecasts regarding these matters. These forecasts may be
substantially different from actual results due to various uncertainties including the following key factors:
(a) the accuracy of the Company's estimates regarding its spending requirements, (b) the occurrence of any
Page 22
unanticipated acquisition opportunities, (c) the need to replace any unanticipated losses in capital assets, (d)
changes in the strategic direction of the Company and (e) unanticipated legal, regulatory and contractual
impediments with regards to its construction projects.
For a further description of the tax and other risks of owning limited partner interests in the Company,
see the Company's registration documents (together with any amendments thereto) filed with the SEC on Form S-1/A
dated July 21,1998, Form S-3 dated December 21, 1999 and Form S-3 dated February 23, 2001.
Company Overview
The Company is a publicly traded master limited partnership (NYSE, symbol "EPD") that conducts
substantially all of its business through Enterprise Products Operating L.P. (the "Operating Partnership"), the
Operating Partnership's subsidiaries, and a number of joint ventures with industry partners. The Company was
formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise
Products Company ("EPCO"). The general partner of the Company, Enterprise Products GP, LLC, a majority-owned
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.
The Company is a leading North American provider of a wide range of midstream energy services to its
customers along the central and western Gulf Coast. The Company's services include the:
o gathering, transmission and storage of natural gas from both onshore
and offshore Louisiana developments;
o purchase and sale of natural gas in south Louisiana;
o processing of natural gas into a merchantable and transportable form
of energy that meets industry quality specifications by removing NGLs
and impurities;
o fractionating for a processing fee mixed NGLs produced as by-products
of oil and natural gas production into their component products:
ethane, propane, isobutane, normal butane and natural gasoline;
o converting normal butane to isobutane through the process of
isomerization;
o producing MTBE from isobutane and methanol;
o transporting NGL products to end users by pipeline and railcar;
o separating high purity propylene from refinery-sourced
propane/propylene mix; and
o transporting high purity propylene to plastics manufacturers by
pipeline.
Natural gas transported, processed and/or sold by the Company generally is consumed as fuel by residential,
electric and industrial centers. NGL and petrochemical products processed by the Company generally are used as
feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential and
commercial heating.
Company Operations and Assets
The Company's operations are concentrated in the Texas, Louisiana, and Mississippi Gulf Coast area. A
large portion of these operations take place in Mont Belvieu, Texas, which is the hub of the domestic NGL
industry and is adjacent to the largest concentration of refineries and petrochemical plants in the United
States. The facilities the Company operates at Mont Belvieu include: (a) one of the largest NGL fractionation
facilities in the United States with a net processing capacity of 131 MBPD; (b) the largest commercial butane
isomerization complex in the United States with a potential isobutane production capacity of 116 MBPD; (c) a MTBE
production facility with a net production capacity of 5 MBPD; and (d) two propylene fractionation units with a
combined production capacity of 31 MBPD. The Company owns all of the assets at its Mont Belvieu facility except
for the NGL fractionation facility, in which it owns an effective 62.5% interest; one of the propylene
fractionation units, in which it owns a 54.6% interest and controls the remaining interest through a long-term
Page 23
lease; the MTBE production facility, in which it owns a 33.3% interest; and one of its three isomerization units
and one deisobutanizer which are held under long-term leases with purchase options.
The Company's operations in Louisiana and Mississippi include varying interests in twelve natural gas
processing plants with a combined capacity of 11.6 Bcf/d and net capacity of 3.2 Bcf/d, six NGL fractionation
facilities with a combined net processing capacity of 159 MBPD and a propylene fractionation facility with a net
capacity of 7 MBPD.
The Company owns, operates or has an interest in approximately 65.0 million barrels of gross NGL and
petrochemical storage capacity (44.3 million barrels of net capacity) in Texas, Louisiana and Mississippi that
are an integral part of its processing operations. The Company also leases and operates one of only two
commercial NGL import/export terminals on the Gulf Coast. In addition, the Company has operating and
non-operating ownership interests in over 2,900 miles of NGL and petrochemical pipelines.
Beginning in January 2001, the Company owns varying equity interests in four Gulf of Mexico offshore
Louisiana natural gas pipeline systems totaling 725 miles of pipeline (with an aggregate gross throughput
capacity of 2.85 Bcf/d) and related assets. These equity interests were purchased from EPE at a cost of
approximately $112 million. With the completion of the Acadian Gas, LLC ("Acadian Gas") acquisition in April
2001, the Company now owns varying interests in an additional 1,042 miles of natural gas pipeline systems (with
an aggregate gross throughput capacity of over 1.1 Bcf/d) and related facilities located in south Louisiana. For
additional information regarding these recent investments and business acquisitions, see "Recent acquisitions and
other investments" below.
The Company's operating margins are primarily derived from services provided to its tolling customers
and from merchant activities. In its tolling operations, the Company is paid a fee based on volumes processed,
transported, stored or handled. The Company generally does not take title to products as part of its tolling
operations; however, in those instances where title to products does transfer to the Company, the Company
generally matches the timing and purchase price of the products with those of the sale of the products so as to
reduce or eliminate exposure to fluctuations in commodity prices. Examples of the Company's tolling operations
include isomerization tolling arrangements, propylene fractionation, liquids pipeline transportation services,
fee-based marketing services and most NGL fractionation services. In addition, the Company's newly acquired
natural gas pipeline businesses are viewed as fee-based operations. See "Recent acquisitions and other
investments" below for a further discussion of the impact of commodity price risk on these operations.
In its merchant activities which are primarily reported in the Processing and Octane Enhancement
segments, the Company is directly exposed to fluctuations in certain commodity prices. In the Company's
isobutane merchant business (and to a certain extent its propylene fractionation activities), the Company takes
title to feedstock products and sells processed end products. The Company's profitability from this type of
merchant activity is dependent upon the prices of feedstocks and end products, which may vary on a seasonal
basis. In order to limit the exposure to commodity price fluctuations in these business areas, the company
attempts to match the timing and price of its feedstock purchases with those of the sales of end products.
Operating margins from the company's natural gas processing (and related merchant businesses) are generally
derived from the price spread earned on the sale of purity NGL products extracted from natural gas streams. To
the extent the Company takes title to the NGLs removed from the natural gas stream and reimburses the producer
for the reduction in the Btu content and/or the natural gas used as fuel (the "PTR" or "shrinkage"), the
Company's operating margins are affected by the prices of NGLs and natural gas. As part of its natural gas
processing and related merchant activities, the Company uses commodity financial instruments to reduce its
exposure to the market risks associated with changes in natural gas and NGL prices.
Recent acquisitions and other investments
Natural gas pipelines
General. Since January 1, 2001, the Company has invested approximately $338 million (net of cash
acquired) in natural gas pipeline businesses. These include an initial $226 million paid to Shell for the
purchase of Acadian Gas (an onshore Louisiana system) and a combined $112 million paid to EPE for equity
Page 24
interests in four Gulf of Mexico natural gas pipelines (primarily offshore Louisiana systems). The acquisition
of these natural gas pipeline businesses from EPE and Shell represent strategic investments for the Company.
Management believes that these assets have attractive growth attributes given the expected long-term increase in
natural gas demand for industrial and power generation uses. In addition, these assets extend the Company's
midstream energy service relationship with long-term NGL customers (producers, petrochemical suppliers and
refineries) and provide opportunities for enhanced services to customers as well as generating additional
fee-based cash flows. These businesses are accounted for as part of the Company's Pipelines operating segment.
Natural gas pipeline systems receive natural gas from producers, other pipelines or shippers through
system interconnects and redeliver the natural gas at other points. Generally, natural gas transportation
agreements provide these systems with a fee per unit of volume (generally in MMBtus) transported. Natural gas
pipeline businesses (such as those of Acadian Gas) may also involve gathering and purchasing natural gas from
producers and suppliers and transporting and reselling such natural gas to electric utility companies, local
distribution companies, industrial customers, and affiliates of other pipeline and gas marketing companies as
well as transporting and gathering natural gas for shippers on a fee basis. Overall, the Company's Gulf of
Mexico systems do not take title to the natural gas that they transport; the shipper retains title and the
associated commodity price risk. In the Company's Acadian Gas operations, it does take title to certain natural
gas streams and is exposed to commodity price risk through its natural gas inventories and certain of its
contracts.
The results of operation for the nine months ended September 30, 2001 include six month's impact of the
Acadian Gas acquisition and nine month's impact of the Gulf of Mexico natural gas pipelines. See Note 3 of the
Notes to Unaudited Consolidated Financial Statements for selected pro forma financial data regarding these
transactions as if they had both occurred on January 1, 2001 and 2000.
Acadian Gas. On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an
affiliate of Shell, for approximately $226 million in cash using proceeds from the issuance of the $450 Million
Senior Notes. The cash purchase price is subject to certain post-closing adjustments expected to be completed
during the fourth quarter of 2001. The effective date of the transaction was April 1, 2001.
Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana.
Acadian Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas
pipeline systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are
wholly-owned by Acadian Gas with the exception of the Evangeline system in which Acadian Gas holds an approximate
49.5% interest. The assets acquired include a leased natural gas storage facility located in Napoleonville,
Louisiana.
The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and,
through connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies,
electric generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River
corridor. In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.
Interests in four Gulf of Mexico natural gas pipeline systems. On January 29, 2001, the Company
purchased equity interests in four Gulf of Mexico natural gas pipeline systems and related assets from EPE for
$112 million, after taking into account certain post-closing adjustments.
The Company acquired a 50% equity interest in Starfish Pipeline Company LLC ("Starfish") which owns the
Stingray natural gas pipeline system and a related natural gas dehydration facility. The Stingray system is a
375-mile FERC-regulated natural gas pipeline system that transports natural gas and injected condensate from
certain production areas located in the Gulf of Mexico offshore Louisiana to onshore transmission systems
located in south Louisiana. The natural gas dehydration facility is connected to the onshore terminal of the
Stingray system in south Louisiana.
In addition to Starfish, the Company acquired a 25.67% equity interest in Ocean Breeze Pipeline Company
LLC ("Ocean Breeze") and Neptune Pipeline Company LLC ("Neptune") as well as a 33.92% equity interest in Nemo
Gathering Company, LLC ("Nemo"). Ocean Breeze and Neptune collectively own the Manta Ray and Nautilus natural
gas gathering and transmission systems located in the Gulf of Mexico offshore Louisiana. The Manta Ray system
Page 25
comprises approximately 225 miles of unregulated pipelines with a capacity of 750 MMcf/d and related equipment,
the Nautilus system comprises approximately 101 miles of FERC-regulated pipelines with a capacity of 600 MMcf/d,
and the Nemo system comprises approximately 24 miles of pipeline with a capacity of 300 MMcf/d.
Affiliates of Shell own the remaining equity interests in Starfish and varying interests in Ocean
Breeze, Neptune and Nemo. An affiliate of Marathon Oil Company owns an interest in Ocean Breeze and Neptune.
In addition, Shell is the operator of the assets held by Starfish, Ocean Breeze, Neptune and Nemo.
These natural gas pipeline systems and related assets are strategically located to serve continental
shelf and deepwater developments in the central Gulf of Mexico. Management believes that the equity interests
acquired from EPE complement and integrate well with those of the Acadian Gas acquisition. These investments are
expected to benefit the Company's midstream focus by:
o broadening its midstream business by providing additional services to
customers; and by
o contributing to the Company's ability to obtain anticipated increases
in natural gas production from deepwater Gulf of Mexico development.
Management believes that these assets have a significant upside potential, since Shell and Marathon have
dedicated production from over 1,000 square miles of Gulf of Mexico offshore Louisiana natural gas leases to
these systems and only a small portion of this total has been developed to date.
Regulatory environment of natural gas systems. The Stingray and Nautilus natural gas pipeline systems
are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each system
operates under separate FERC approved tariffs that establish rates, terms and conditions under which each system
provides services to its customers. Generally, the FERC's authority extends to:
o transportation of natural gas, rates and charges;
o certification and construction of new facilities;
o extension or abandonment of services and facilities;
o maintenance of accounts and records;
o depreciation and amortization policies;
o acquisition and disposition of facilities;
o initiation and discontinuation of services; and
o various other matters.
As noted above, the Stingray and Nautilus systems have tariffs established through filings with the FERC that
have a variety of terms and conditions, each of which affect the operations of each system and their ability to
recover fees for the services they provide. Generally, changes to these fees or terms can only be implemented
upon approval by the FERC.
Collectively, the Acadian Gas and Gulf of Mexico pipeline systems acquired by the Company are subject to
various governmental and environmental legislation. Each of these systems has a continuing program of
inspection designed to ensure compliance with such legislation including pollution control and pipeline safety
requirements. The Company believes that these systems are in substantial compliance with the applicable
requirements.
Equistar storage facility
In addition to the natural gas pipeline acquisitions, the Company announced on February 1, 2001 that it
had acquired a NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million. The salt dome
storage cavern, which is located near the Company's Mont Belvieu, Texas complex, has a capacity of one million
barrels. The purchase also includes adjacent acreage which would support the development of additional storage
capacity.
Diamond-Koch Storage Assets
On October 29, 2001, the Company announced that it had executed a letter of intent to acquire storage
facilities from affiliates of Ultramar Diamond Shamrock Corporation and Koch Industries, Inc. The storage
Page 26
facilities consist of 30 salt dome storage caverns with a permitted capacity of 77 million barrels located near
the Company's Mont Belvieu complex. These caverns provide storage services for mixed NGLs, ethane, propane,
butanes, natural gasoline and olefins, such as ethylene, polymer grade propylene, chemical grade propylene and
refinery grade propylene. The completion of this transaction is subject to the execution of a definitive
agreement and regulatory approvals. The parties anticipate the transaction to be completed by the end of 2001.
Current Business Environment
During the third quarter of 2001, the U.S. NGL industry continued to recover from the first quarter of
2001 as a result of declining energy prices, particularly that of natural gas. The lower energy costs have
contributed to increased volumes and profitability across many of the Company's business operations. The
decline in natural gas prices from the record levels of the first quarter of 2001 resulted in increased NGL
extraction rates throughout the gas processing industry. Consequently, the Company is continuing to see an
increase in NGL volumes available for fractionation and/or transportation.
Natural gas prices continued to decline in the third quarter of 2001 compared to the first six months of
2001. After peaking at near $10 per MMBtu in January 2001, natural gas prices decreased to less than $3 per
MMBtu in October 2001 which is within the historical norm in terms of relative value to other forms of energy.
Industry expectations are that natural gas prices will remain within the historical norm relative to other forms
of energy for most of the upcoming winter due to the weak domestic economy and a strong supply picture.
Although the lower prices have led some producers to scale back their gas exploration and production projects,
the industry expects that the current short-term imbalance of excess supply is temporary.
In the third quarter of 2001, NGL prices declined along with those of other forms of energy. The
resultant loss of value has been mitigated (or in some cases, reversed) by the Company's hedging activities.
During the fourth quarter of 2001, the Company expects that natural gas and NGL prices will be within the
historical range in terms of relative value with other forms of energy.
The Company's recently acquired natural gas pipeline businesses have benefited from increased drilling
activities associated with expected long-term demand growth for natural gas. The expected long-term outlook for
natural gas is positive as new gas-fired electric generation facilities commence operations and the domestic
economy rebounds. Also, the Company's Nemo natural gas pipeline started operations in August 2001. This
system is currently transporting approximately 50,000 MMBtu/d of natural gas from the Shell Brutus field, which
began production during the third quarter of 2001. When fully developed in early 2002, the Shell Brutus field
is expected to produce up to 150,000 MMBtu/d of natural gas which will be transported through Nemo. This
additional volume will flow from Nemo into the Manta Ray/Nautilus pipeline systems and ultimately be processed at
the Company's Neptune gas processing plant (at full extraction rates in 2002, the Brutus field production is
expected to increase the Company's equity NGL production by up to 10 MBPD).
At the Company's gas processing facilities, equity NGL production volumes were 62 MBPD in the third
quarter of 2001, little changed from the second quarter of 2001 but significantly improved from the 46 MBPD of
the first quarter of 2001. The equity NGL production rate seen in the first quarter was the result of minimal
NGL extraction rates caused by the abnormally high cost of natural gas. As natural gas prices moderated in the
second and third quarters, NGL extraction rates at the Company's gas processing facilities and those of other
industry participants increased resulting in additional volumes throughout the NGL value chain; however, many gas
processing plants were still not operating at full extraction rates due to below average processing margins.
With the current natural gas price environment, management anticipates that the Company's natural gas processing
facilities will operate at full NGL extraction rates during the fourth quarter. Overall, the Company expects
equity NGL production to average approximately 80 MBPD during the fourth quarter of 2001.
During the third quarter, the Company's isomerization and related merchant businesses experienced
margins and volumes consistent with refinery demand associated with the end of the summer driving season.
Isomerization volumes are expected to remain near 80 MBPD during the fourth quarter of 2001. Propylene
fractionation margins are expected to remain flat during the fourth quarter due to the weak economy and
Page 27
additional supplies coming to the market from new third party facilities. Once domestic economic conditions
improve, the Company expects that demand for propylene fractionation services will increase as the market absorbs
the added supplies.
NGL fractionation services at Mont Belvieu are competitive due to continued excess NGL fractionation
capacity at this industry hub. With newly contracted volumes such as those from the Sea Robin gas processing
facility in Louisiana, the Company has raised the utilization rates of its Mont Belvieu NGL fractionator to near
capacity. The BRF NGL fractionation facility, an equity investment of the Company, is projected to run at or
near full capacity during the fourth quarter and the Promix NGL fractionation facility, another equity investment
of the Company, is expected to run at 110 MBPD, both on strong demand. Management anticipates that its Norco
NGL fractionation facility will process at rates near its capacity of 50 MBPD during the fourth quarter of 2001
and show margin improvement as in-kind fees increase with the expected rise in overall NGL pricing.
With regards to its major liquids pipelines, the Company expects its Louisiana Pipeline System to
benefit from the seasonal rise in propane shipments that are carried on the Dixie Pipeline with the strongest
movements anticipated during the fourth quarter of 2001. In addition, the Company expects that the projected
November 2001 completion of its Napoleonville to Sorrento pipeline (which is an expansion of its Louisiana
Pipeline System capacity) will result in increased shipments of natural gasoline to refineries along the
Mississippi River and transport of refinery grade propylene from Mississippi River refineries west to the Mont
Belvieu market. This increase in pipeline volumes is expected to be obtained by attracting volumes that have
historically been transported by barge which is a more costly means of transportation versus by pipeline. The
Company's Lou-Tex NGL Pipeline is expected to benefit from the addition of new customer volumes that will add
approximately 6 MBPD of throughput volume in November 2001.
EPIK's financial performance is expected to seasonally improve during the fourth quarter of 2001.
Exports of butane and propane are expected to increase as a result of moderating domestic prices for both
products relative to foreign markets. This situation should make these products more competitive on the world
market and EPIK should benefit from a higher utilization of the export terminal. Activity at the Company's
Houston Ship Channel import facility is expected to be consistent with the fourth quarters of previous years.
The Company's MTBE business is encountering the normal seasonal decline in spot MTBE prices. MTBE
spot prices are generally stronger during the April to September period of each year which corresponds with the
summer driving season. Management anticipates that equity earnings from its investment in BEF will be near
breakeven during the fourth quarter of 2001 as a result of this pricing environment.
Page 28
The following table illustrates selected average quarterly prices for natural gas, crude oil, selected
NGL products and polymer grade propylene since the first quarter of 1999:
Polymer
Natural Normal Grade
Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene,
$/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound
-----------------------------------------------------------------------------------------
(a) (b) (a) (a) (a) (a) (a)
Fiscal 1999:
First quarter $1.70 $13.05 $0.20 $0.24 $0.29 $0.31 $0.12
Second quarter $2.12 $17.66 $0.27 $0.31 $0.37 $0.38 $0.13
Third quarter $2.56 $21.74 $0.34 $0.42 $0.49 $0.49 $0.16
Fourth quarter $2.52 $24.54 $0.30 $0.41 $0.52 $0.52 $0.19
Fiscal 2000:
First quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21
Second quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26
Third quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26
Fourth quarter $5.22 $31.98 $0.49 $0.67 $0.75 $0.73 $0.24
Fiscal 2001:
First quarter (c) $7.00 $28.81 $0.43 $0.55 $0.63 $0.69 $0.23
Second quarter $4.61 $27.88 $0.33 $0.46 $0.53 $0.63 $0.19
Third quarter $2.84 $26.65 $0.25 $0.41 $0.50 $0.49 $0.16
- ----------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL and polymer grade propylene prices represent an average of index prices
(b) Crude Oil price is representative of West Texas Intermediate
(c) Natural gas prices peaked at approximately $10 per MMBtu in January 2001
Results of Operation of the Company
The Company has five reportable operating segments: Fractionation, Pipelines, Processing, Octane
Enhancement and Other. Fractionation primarily includes NGL fractionation, butane isomerization (converting
normal butane into high purity isobutane) and polymer grade propylene fractionation services. Pipelines consists
of liquids and natural gas pipeline systems, storage and import/export terminal services. Processing includes
the natural gas processing business and its related NGL merchant activities. Octane Enhancement represents the
Company's 33.3% ownership interest in a facility that produces motor gasoline additives to enhance octane
(currently producing MTBE). The Other operating segment consists of fee-based marketing services and other plant
support functions.
The management of the Company evaluates segment performance based on gross operating margin ("gross
operating margin" or "margin"). Gross operating margin reported for each segment represents operating income
before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of
assets and selling, general and administrative expenses. In addition, segment gross operating margin is
exclusive of interest expense, interest income (from unconsolidated affiliates or others), dividend income from
unconsolidated affiliates, minority interest, extraordinary charges and other income and expense transactions.
The Company's equity earnings from unconsolidated affiliates are included in segment gross operating margin.
Page 29
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, 2001 and 2000 were as
follows:
For Three Months Ended For Nine Months Ended
September 30, September 30,
------------------------------------- -------------------------------------
2001 2000 2001 2000
------------------------------------- -------------------------------------
Gross operating margin by segment:
Fractionation $35,189 $32,510 $ 93,660 $ 96,432
Pipeline 22,415 10,292 65,234 39,119
Processing 52,026 29,083 148,536 87,123
Octane enhancement 909 2,190 6,311 13,002
Other 310 429 1,256 1,855
------------------------------------- -------------------------------------
Gross operating margin total 110,849 74,504 314,997 237,531
Depreciation and amortization 13,072 9,029 34,894 25,907
Retained lease expense, net 2,660 2,660 7,980 7,984
Loss (gain) on sale of assets (5) (27) (392) 2,276
Selling, general and administrative expenses 7,716 6,978 21,621 20,020
------------------------------------- -------------------------------------
Consolidated operating income $87,406 $55,864 $250,894 $181,344
===================================== =====================================
The Company's significant production and other volumetric data (on a net basis) for the three and nine
month periods ended September 30, 2001 and 2000 were as follows:
For the three months ended For the nine months ended
September 30, September 30,
----------------------------------- -----------------------------------
2001 2000 2001 2000
----------------------------------- -----------------------------------
MBPD, Net
- ---------
Equity NGL Production 62 73 57 72
NGL Fractionation 224 214 198 216
Isomerization 81 84 82 77
Propylene Fractionation 34 34 31 34
Octane Enhancement 5 6 4 5
Major NGL and Petrochemical Pipelines 479 289 452 334
MMBtu/D, Net
- ------------
Natural Gas Pipelines 1,426,463 1,342,104
Three Months Ended September 30, 2001 compared with Three Months Ended September 30, 2000
Revenues, Costs and Expenses and Operating Income. The Company's revenues increased to $729.6 million
in 2001 compared to $721.9 million in 2000. The Company's operating costs and expenses decreased to $634.5
million versus $659.0 million in 2000. Operating income increased to $87.4 million in 2001 from $55.9 million
in 2000. Third quarter 2001 revenues and expenses for Fractionation, Processing, Octane Enhancement and Other
decreased relative to third quarter 2000 amounts primarily due to falling NGL prices and energy cost-related fees
and expenses. Offsetting these declines was an increase in revenues and expenses in the Pipelines segment
attributable to the acquisition of Acadian Gas and the Gulf of Mexico natural gas pipeline systems in 2001. The
majority of the increase in operating income for 2001 is attributable to $48.2 million in income relating to the
Company's commodity hedging activities.
Fractionation. The Company's gross operating margin for the Fractionation segment increased to $35.2
million in 2001 from $32.5 million in 2000. NGL fractionation margin declined $0.3 million quarter-to-quarter
Page 30
while net processing volumes increased to 224 MBPD in 2001 from 214 MBPD in 2000. The slight decline in margin
is attributable to lower processing fees at Norco which are tied to NGL prices that were lower quarter-to-quarter.
The increase in NGL fractionation volumes is primarily due to the receipt of Sea Robin mixed NGL volumes at the
Company's Mont Belvieu fractionation facilities via the Lou-Tex NGL pipeline. The Company's isomerization
business posted a slight $0.1 million decrease primarily due to a decline in volumes from 84 MBPD in 2000 to 81
MBPD in 2001. The impact of lower isomerization volumes was offset by a decrease in energy-related costs
and other expenses. Gross operating margin from propylene fractionation increased $2.2 million on volumes of 34
MBPD for both periods. The increase in propylene fractionation margin is attributable to lower energy costs and
other expenses.
Pipelines. The Company's gross operating margin for the Pipelines segment was $22.4 million in 2001
compared to $10.3 million in 2000. Of the $12.1 million increase, $4.2 million is attributable to natural gas
pipelines acquired in 2001 (i.e., Acadian Gas and the Gulf of Mexico systems). Natural gas pipeline volumes
averaged 1,426 BBtu/d on a net basis. Margin from the recently completed Lou-Tex NGL Pipeline increased $4.2
million quarter-to-quarter on volumes of 34 MBPD. The Lou-Tex NGL Pipeline was completed during the fourth
quarter of 2000. Overall, net liquids throughput volumes increased to 479 MBPD in 2001 compared with 289 MBPD in
2000. The majority of the 190 MBPD increase in liquids throughput volumes is attributable to (i) a 60 MBPD
increase on the Louisiana Pipeline System due to strong demand for services, (ii) a 78 MBPD combined increase at
the Houston Ship Channel import facility and on its related pipeline system related to seasonal butane import
activity and (iii) the 34 MBPD from the Lou-Tex NGL Pipeline mentioned previously. The volume increases on the
Louisiana Pipeline System and the import dock and its related pipeline system contributed to a combined $2.5
million increase in margin quarter-to-quarter.
Processing. For the third quarter of 2001, the Processing segment generated gross operating margin of
$52.0 million compared to $29.1 million during the same period in 2000. The Processing segment includes the
Company's natural gas processing business and related merchant activities. The Company's equity NGL production
was 62 MBPD for the 2001 quarter versus 73 MBPD for the same quarter in 2000. The decline in volume is related
to the 2000 period reflecting near maximized NGL recoveries supported by strong NGL economics. The 2001 equity
NGL production rate reflects slightly less favorable extraction economics but is greatly improved relative to the
first quarter of 2001's 46 MBPD when natural gas prices (a major expense of gas processing operations) peaked at
nearly $10 per MMBtu.
Gross operating margin for the Processing segment includes the results of the Company's commodity
hedging activities. The 2001 period includes $48.2 million in income from commodity financial instruments compared
to $5.4 million for the 2000 period. The Company employs various hedging strategies to mitigate the effects of
fluctuating commodity prices (primarily NGL prices) on its natural gas processing business and related merchant activities.
A large number of the Company's commodity financial instruments are based on the historical relationship
between natural gas prices and NGL prices. This type of hedging strategy utilizes the forward sale of natural
gas at a fixed-price with the expected margin on the settlement of the position offsetting or mitigating changes
in the anticipated margins on NGL merchant activities and the value of the Company's equity NGL production.
During the third quarter of 2001, the Company benefited from a decline in natural gas prices relative to its
fixed positions. The decline in natural gas prices allowed the Company to realize net cash gains on the
settlement and early closeout of certain positions of approximately $66.1 million. The $17.9 million
difference between the realized amount and the $48.2 million in income from commodity financial instruments is
related to changes in non-cash mark-to-market amounts. The non-cash mark-to-market income on positions open at
September 30, 2001 was $34.6 million (based on market prices at that date).
If natural gas prices had not declined to the degree seen during the quarter, less income or a loss
on hedging activities may have resulted offset somewhat by correlative higher NGL prices which would have
increased the value of the Company's equity NGL production. A variety of factors influence whether or not the
Company's hedging strategy is successful. For additional information regarding the Company's commodity financial
instruments, see Item 3 "Quantitative and Qualitative Disclosures about Market Risk" on page 38.
Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $1.2 million
in the third quarter of 2001 compared to 2000 levels. MTBE production, on a net basis, was 5 MBPD for the 2001
Page 31
quarter versus 6 MBPD for the 2000 quarter. The decline in margin is primarily due to the lower MTBE volumes
and a decrease in by-product revenues offset by lower energy-related costs quarter-to-quarter.
Interest expense. Interest expense for the third quarter of 2001 increased $5.1 million over the same
period in 2000. The increase is attributable higher average debt levels in 2001 of $854.0 million compared with
$437.0 million in 2000. The higher debt levels are associated with the issuance of the $450 Million Senior Notes
in January 2001 of which the proceeds were used to acquire Acadian Gas and interests in the Gulf of Mexico
natural gas pipeline systems.
Nine Months Ended September 30, 2001 compared with Nine Months Ended September 30, 2000
Revenues, Costs and Expenses and Operating Income. The Company's revenues increased to $2.5 billion in
2001 compared to $2.1 billion in 2000. The Company's operating costs and expenses increased to $2.3 billion in
2001 from $1.9 billion in 2000. Operating income increased to $250.9 million in 2001 from $181.3 million in
2000. The rise in year-to-date revenues is primarily due to the addition of Acadian Gas' revenues and increased
merchant business activities. The Acadian Gas acquisition was effective April 1, 2001. The rise in
year-to-date expenses is attributable to expenses of Acadian Gas, higher than normal natural gas prices during
the first half of 2001 which affected energy-related operating costs at the Company's facilities offset by
significant income from the Company's commodity hedging activities. As a result, operating income was positively
influenced by the above noted factors.
Fractionation. The Company's gross operating margin for the Fractionation segment decreased to $93.7
million in 2001 from $96.4 million in 2000. NGL fractionation margin decreased $14.9 million primarily due to
lower processing volumes and higher energy-related operating costs. NGL fractionation net volumes decreased to
198 MBPD for the first nine months of 2001 compared to 216 MBPD during the same period in 2000. The decrease is
the result of lower NGL extraction rates at gas processing facilities in early 2001 (due to the high cost of
natural gas) versus 2000 when the industry was maximizing NGL production. For the first nine months of 2001,
gross operating margin from isomerization services increased $11.1 million compared to 2000 primarily due to an
increase in volumes and toll processing fees. Isomerization volumes increased to 82 MBPD during the first nine
months of 2001 versus 77 MBPD during the same period in 2000 due to increased demand for the Company's
services. Gross operating margin from propylene fractionation decreased $0.5 million compared to the first nine
months of 2000 primarily due to higher energy costs, moderating prices and lower volumes. Net propylene
fractionation volumes were 31 MBPD in 2001 versus 34 MBPD in 2000.
Pipelines. The Company's gross operating margin for the Pipelines segment was $65.2 million in 2001
compared to $39.1 million in 2000. Of the $26.1 million increase, $11.0 million is attributable to natural gas
transportation investments acquired in 2001 (i.e., Acadian Gas and the Gulf of Mexico systems). The Company's
Lou-Tex NGL Pipeline (completed in the fourth quarter of 2000) added $9.3 million on volumes of 26 MBPD. In
addition, margin on the Company's Lou-Tex Propylene Pipeline for 2001 was $3.4 million higher than 2000
(primarily due to this asset being purchased in March 2000). Demand for imported mixed NGLs (particularly
commercial butanes) resulted in a $5.1 million increase in margins for the Houston Ship Channel import facility
and related pipeline system. The increase in commercial butane imports was related to the seasonal demand for
isobutane which occurred between February and May 2001.
Processing. For the first nine months of 2001, the Processing segment generated gross operating margin
of $148.5 million compared to $87.1 million during the same period in 2000. The $61.4 million increase in
margin is attributable to the Company's commodity hedging activities and merchant business offset by lower equity
NGL production and prices and higher energy-related costs.
As discussed earlier under the Processing segment's quarter-to-quarter variance explanation (see page
31), the Company employs various hedging strategies in an effort to mitigate the effects of fluctuating commodity
prices (primarily NGL prices) on its natural gas processing business and related merchant activities. Gross
operating margin for the first nine months of 2001 reflects $118.5 million in income from commodity financial
instruments compared with $8.4 million for the same period in 2000. Of the $118.5 million in hedging income
recognized during 2001, $83.9 million has been realized with the difference of $34.6 million attributable to
non-cash mark-to-market income on positions that were open at September 30, 2001. The September 30, 2001 $34.6
Page 32
million in mark-to-market income is based on market prices at that date. The change in hedging income between the
2001 and 2000 periods more than offset the effects of the lower equity NGL volumes and prices and higher
energy-related costs. A variety of factors influence whether or not the Company's hedging strategy is
successful. For additional information regarding the Company's commodity financial instruments, see Item 3
"Quantitative and Qualitative Disclosures about Market Risk" on page 38.
Processing's merchant business benefited from strong demand for propane in the first quarter of 2001 for
heating and isobutane in the second quarter of 2001 for refining. Equity NGL production averaged 57 MBPD during
the 2001 period versus 72 MBPD during the 2000 period. The 2001 rate of 57 MBPD reflects the very low 46 MBPD
NGL extraction rates of the first quarter of 2001 when natural gas prices (a major expense of gas processing
operations) were at their peak. As natural gas prices have declined since January 2001, equity NGL production
has returned to higher levels. The 2000 equity NGL production rate reflects a period in which gas processors
were operating facilities at near full NGL extraction rates.
Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $6.7 million
in the first nine months of 2001 compared with the same period in 2000. MTBE production, on a net basis, was 4
MBPD in 2001 and 5 MBPD in 2000. The decrease in volumes is attributable to a prolonged maintenance outage which
lasted from December 2000 until February 2001. The decline in margin is primarily due to the lower MTBE
volumes, a decrease by-product revenues and an increase in energy-related and other expenses period-to-period.
Interest expense. Interest expense for the first nine months of 2001 increased $12.6 million over the
first nine months of 2000. The increase is primarily due to additional interest expense associated with the
$450 Million Senior Notes issued in January 2001 of which the proceeds were used to acquire Acadian Gas and
interests in the Gulf of Mexico natural gas pipeline systems.
Liquidity and Capital Resources
General. The Company's primary cash requirements, in addition to normal operating expenses and debt
service, are for capital expenditures (both maintenance and expansion-related), business acquisitions and
distributions to its partners. The Company expects to fund its short-term needs for such items as maintenance
capital expenditures and quarterly distributions to its partners from operating cash flows. Capital expenditures
for long-term needs resulting from future expansion projects and business acquisitions are expected to be funded
by a variety of sources including (either separately or in combination) cash flows from operating activities,
borrowings under bank credit facilities 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, 2001, availability under the Company's revolving bank credit facilities
was $400 million (which may be increased to $500 million under certain conditions). In addition to the existing
revolving bank credit facilities, a subsidiary of the Company issued $450 million of public debt in January 2001
(the "$450 Million Senior Notes") using the remaining shelf availability under its $800 million December 1999
universal shelf registration (the "December 1999 Registration Statement"). The proceeds from this offering were
used to acquire the Acadian Gas and Gulf of Mexico natural gas pipeline systems, to finance the cost to construct
certain NGL pipelines and related projects and for working capital and other general partnership purposes. On
February 23, 2001, the Company filed a $500 million universal shelf registration (the "February 2001 Registration
Statement") covering the issuance of an unspecified amount of equity or debt securities or a combination
thereof. For a broader discussion of the Company's outstanding debt and changes therein, see the section below
labeled "Long-term Debt".
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
expansions or acquisitions.
Page 33
If deemed necessary, management believes that additional financing arrangements can be obtained at
reasonable terms. Management believes that maintenance of the Company's investment grade credit ratings
(currently, Baa2 by Moody's Investor Service and BBB by Standard and Poors) combined with a continued ready
access to debt and equity 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.
Consolidated Cash Flows for the nine months ended September 30, 2001 and 2000. Cash inflows from
operating activities were $124.8 million for the first nine months of 2001 compared to $180.8 million for the
same period in 2000. Cash flows from operating activities primarily reflect the effects of net income,
depreciation and amortization, equity income and distributions from unconsolidated affiliates, fluctuations in
fair values of financial instruments and changes in operating accounts. Net income increased $55.0 million for
2001 compared to 2000 primarily due to reasons mentioned previously under Results of Operation of the Company.
Depreciation and amortization increased a combined $9.3 million in 2001 over 2000 totals primarily due to
additional capital expenditures and business acquisitions.
Equity in income of unconsolidated affiliates decreased $5.9 million in 2001 compared with 2000 levels.
The decrease is attributable to (i) lower earnings from NGL fractionation and pipeline investments in 2001
relative to 2000 primarily due to a decrease in available NGL volumes resulting from the low extraction rates in
early 2001 and (ii) a decline in BEF margins (see Octane Enhancement discussion under Results of Operation of the
Company) offset by equity earnings from the newly acquired Gulf of Mexico natural gas pipeline systems. The
Company received $30.6 million in distributions from its equity method investments in 2001 compared to $26.0
million in 2000. The $4.6 million increase is primarily related to distributions received from the Company's
newly acquired Gulf of Mexico natural gas pipeline systems. Of the operating accounts, changes in 2001
receivable and payable balances have been influenced by the decline in natural gas and NGL prices since the
beginning of the year. Overall, the net effect of changes in operating accounts from period to period is
generally the result of timing of NGL sales and purchases near the end of the period and changes in inventory
values related to pricing or volumes or a combination thereof.
Operating cash flows also includes an adjustment for the $39.4 million in non-cash mark-to-market income
related to commodity and interest rate hedging activities. Of this amount, $34.6 million is attributable to the
commodity financial instrument portfolio with the balance pertaining to interest rate swaps. For a more complete
description of the Company's risk management policies and potential exposures, see "Item 3. Quantitative and
Qualitative Disclosures about Market Risk" and Note 10 of the Notes to Unaudited Consolidated Financial
Statements.
Cash used for investing activities was $437.6 million in 2001 compared to $195.9 million in 2000. Cash
outflows included capital expenditures of $92.6 million in 2001 versus $200.2 million in 2000. Capital
expenditures for 2000 include $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets. In addition, capital expenditures include maintenance capital project costs of $3.8 million in 2001 and
$2.3 million in 2000. The Company's completion of the Acadian Gas business acquisition resulted in an initial
payment to Shell of $225.7 million in April 2001, subject to certain post-closing purchase price adjustments.
The 2000 period also includes $6.5 million in cash receipts related to the Company's participation in the BEF
note, which was extinguished in May 2000 with BEF's final principal payment. Lastly, investing cash outflows in
2001 includes $119.9 million in investments in and advances to unconsolidated affiliates compared to $2.3 million
in 2000. The increase is due to the purchase of the Gulf of Mexico natural gas pipeline systems in January
2001.
Cash receipts from financing activities were $310.5 million during 2001 compared to $51.3 million in
2000. Cash flows from financing activities are primarily affected by repayments of debt, borrowings under debt
agreements and distributions to partners. The 2001 period includes proceeds from the $450 Million Senior Notes
issued in January 2001 whereas the 2000 period includes proceeds from the $350 Million Senior Notes and $54
Million MBFC Loan and the associated repayments on various bank credit facilities. Cash outlays for financing
activities also include $8.8 million paid by a consolidated trust to purchase Common Units to fund a long-term
incentive plan (see "Units acquired by Trust" below).
Distributions to partners and the minority interest increased to $118.3 million in 2001 from $104.4
million in 2000 primarily due to an increase in the quarterly distribution rate. See Note 8 of the Notes to Unaudited
Page 34
Consolidated Financial Statements for a history of quarterly distribution rates and increases since the first
quarter of 1999. In October 2001, the Company announced that it had again increased its quarterly distribution
rate from $0.5875 per Common Unit to $0.625 per Common Unit beginning with the distribution payable in November
2001. This increase in the quarterly distribution rate in conjunction with the conversion of 5.0 million of the
Shell Special Units into Common Units in August 2001 (see "Issuance of last installment of Special Units to
Shell" below) will result in the quarterly cash outlay for distributions to the partners increasing by
approximately $5.7 million.
During the first nine months of 2001, the Company has invested $338 million in business acquisitions and
the purchase of equity interests in other companies. These investments include the acquisition of Acadian Gas
and interests in four natural gas pipelines in the Gulf of Mexico. The Company will continue to analyze
potential acquisitions, joint ventures or similar transactions with businesses that operate in complementary
markets and geographic regions. In recent years, major oil and gas companies have sold non-strategic assets
including assets in the midstream natural gas industry in which the Company operates. Management believes that
this trend will continue, and the Company expects independent oil and natural gas companies to consider similar
options. In addition, management believes that the Company is well positioned to continue to grow through
acquisitions that will expand its platform of assets and through internal growth. The Company anticipates that
it will achieve its conservative annual growth objective for 2001: investing over $400 million in energy
infrastructure projects and acquisitions while increasing its cash distribution rate to Unitholders by at least
10% for the full year.
The cash distribution policy (as managed by the General Partner at its sole discretion) has allowed the
Company to retain a significant amount of cash flow for reinvestment in the growth of the business. Over the
last two years, the Company has reinvested approximately $323.2 million to fund expansions and business
acquisitions. Management believes the cash distribution policy provides financial flexibility in executing the
Company's growth strategy.
Future Capital Expenditures. The Company forecasts that $72.1 million will be spent during the remainder
of 2001 on currently approved capital projects that will be recorded as property, plant and equipment (the
majority of which relate to various pipeline projects). In addition, the Company estimates that its share of
currently approved capital expenditures in the projects of its unconsolidated affiliates will be approximately
$0.5 million for the remainder of 2001.
As of September 30, 2001, the Company had $8.2 million in outstanding purchase commitments attributable
to its capital projects. Of this amount, $7.7 million is related to the construction of assets that will be
recorded as property, plant and equipment and $0.5 million is associated with capital projects which will be
recorded as additional investments in unconsolidated affiliates.
New environmental regulations in the state of Texas may necessitate extensive redesign and modification
of the Company's Mont Belvieu facilities to achieve the air emissions reductions needed for federal Clean Air Act
compliance in the Houston-Galveston area. The technical practicality and economic reasonableness of these
regulations have been challenged under state law in litigation filed on January 19, 2001, against the Texas
Natural Resource Conservation Commission and its principal officials in the District Court of Travis County,
Texas, by a coalition of major Houston-Galveston area industries including the Company. Until the litigation
is resolved, the precise level of technology to be employed and the cost for modifying the facilities to achieve
the required amount of reductions cannot be determined. The litigation has been stayed by agreement of the
parties pending the outcome of expanded, cooperative scientific research to more precisely define sources and
mechanisms of air pollution in the Houston-Galveston area. Completion of this research is anticipated in
mid-2002. Regardless of the results of the research and the outcome of the litigation, expenditures for emissions
reduction projects will be spread over several years, and management believes the Company will have adequate
liquidity and capital resources to undertake them. Capital funds have been budgeted for work in 2002 that will
begin making emissions reduction modifications on certain Mont Belvieu facilities. The methods employed to
achieve these reductions will be compatible with whatever regulatory requirements are eventually put in place.
For additional information about this litigation, see the discussion under the topic Clean Air Act--General on
page 22 of the Company's Form 10-K for fiscal 2000.
Page 35
Long-term Debt. Long-term debt consisted of the following at:
September 30, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 350,000 350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
---------------------------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt (see Note 10) 1,833
Less unamortized discount on:
$350 Million Senior Notes (126) (153)
$450 Million Senior Notes (264)
Less current maturities of long-term debt
---------------------------------------
Long-term debt $855,443 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility
and $150 Million 364-Day Credit Facility. The $150 Million 364-Day Credit Facility has an original maturity
date of November 16, 2001. An amendment to the 364-Day Credit Facility to extend this date through November 15,
2002 was consented to by the lenders in early November 2001. No amount was outstanding under either of these
two revolving credit facilities at September 30, 2001 or December 31, 2000.
At September 30, 2001, the Company had a total of $75 million of standby letters of credit capacity
under its $250 Million Multi-Year Credit Facility of which $14.9 million was outstanding.
On January 24, 2001, a subsidiary of the Company completed a public offering of $450 million in
principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per
Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting discounts and
commissions, of approximately $446.8 million. The proceeds from this offering were used to acquire the Acadian
Gas and Gulf of Mexico natural gas pipeline systems and to finance the cost to construct certain NGL pipelines
and related projects and for working capital and other general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is
also applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As
with the $350 Million Senior Notes, the $450 Million Senior Notes are:
- subject to a make-whole redemption right;
- an unsecured obligation and rank equally with existing and future
unsecured and unsubordinated indebtedness and senior to any future
subordinated indebtedness; and,
- guaranteed by the Company through an unsecured and unsubordinated
guarantee.
The Company was in compliance with the restrictive covenants associated with the $350 Million and $450 Million
Senior Notes at September 30, 2001.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 Registration
Statement; therefore, the amount of securities available under this universal shelf registration statement was
reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement
(the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt
securities or a combination thereof. The Company expects to use the net proceeds from any sale of securities
under the February 2001 Registration Statement for future business acquisitions and other general corporate
purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the
repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be
Page 36
applied to partnership purposes will depend on a number of factors, including the Company's funding requirements
and the availability of alternative funding sources. The Company routinely reviews acquisition opportunities.
Upon adoption of Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3
million non-cash increase in the fair value of its fixed-rate debt. SFAS No. 133 required that the Company's
interest rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption of the
standard. After adoption of the standard, the interest rate swaps were dedesignated due to differences in the
estimated maturity dates of the interest rate swaps versus the fixed-rate debt. As a result, the fair value of
the hedged fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million increase in
the fair value of the debt will be amortized to earnings over the remaining life of the fixed-rate debt to which
it applies, which approximates 10 years. See Note 5 and Note 10 of the Notes to Unaudited Consolidated Financial
Statements for additional information regarding interest rate swaps and the associated change in the fair value
of the fixed-rate debt.
Recently Issued Accounting Standards
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, " Business Combinations", and SFAS
No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest
method for business combinations initiated after June 30, 2001 and also applies to all business combinations
accounted for by the purchase method that are completed after June 30, 2001. There are also transition
provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the
purchase method. SFAS No. 142 is effective for the Company's fiscal year beginning January 1, 2002 for all
goodwill and other intangible assets recognized in its consolidated balance sheet at that date, regardless of
when those assets were initially recognized.
At present, the Company's intangible assets include the values assigned to the 20-year Shell natural gas
processing agreement and the excess cost of the purchase price over the fair market value of the assets acquired
from Mont Belvieu Associates, both of which were initially recorded in 1999. The value of the Shell Processing
Agreement is being amortized over its contract term and the excess cost of the purchase price over the fair
market value of the assets acquired from Mont Belvieu Associates is being amortized over 20 years. Based upon
initial interpretations of the new accounting standards, the Company anticipates that the Shell Processing
Agreement will continue to be amortized over its contract term; however, the excess cost attributable to Mont
Belvieu Associates will be reclassified to goodwill in accordance with the new standard and its amortization will
cease (currently, $0.5 million in amortization expense annually). This goodwill would then be subject to
impairment testing as prescribed in SFAS No. 142.
The Company is continuing to evaluate the complex provisions of SFAS No. 141 and SFAS No. 142 and has
not adopted such provisions in its September 30, 2001 financial statements.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset
Retirement Obligations", in June 2001. This statement establishes accounting standards for the recognition and
measurement of a liability for an asset retirement obligation and the associated asset retirement cost. This
statement is effective for the Company's fiscal year beginning January 1, 2003. In August 2001, the FASB issued
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". This statement addresses
financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be
disposed of. This statement is effective for the Company's fiscal year beginning January 1, 2002. Management
is currently studying both SFAS No. 143 and No. 144 for their possible impact on the consolidated financial
statements when they are adopted.
Issuance of last installment of Special Units to Shell
On or about June 30, 2001, Shell met certain year 2001 performance criteria for the issuance of the last
installment of 3.0 million non-distribution bearing, convertible Contingency Units (referred to as Special Units
once they are issued). Under a contingent unit agreement with Shell executed as part of the 1999 TNGL
acquisition, the Company issued these Special Units on August 2, 2001.
Page 37
The value of these Special Units was determined to be $117.1 million using present value techniques.
This amount increased the purchase price of the TNGL acquisition and the value of the Shell Processing Agreement
when the issue was recorded in August 2001. This amount also increased the equity position of Shell in the
Company by $117.1 million with the General Partner contributing $1.2 million to maintain its respective
ownership in the Company. The $117.1 million increase in value of the Shell Processing Agreement will be
amortized over the remaining life of the contract. As a result, amortization expense will increase by
approximately $1.6 million per quarter ($6.5 million annually).
In accordance with existing agreements with Shell, 5.0 million of Shell's original issue of Special
Units converted into Common Units on August 2, 2001. The issuance of the 3.0 million new Contingency Units had
a impact on diluted earnings per Unit beginning with the third quarter of 2001. Likewise, the conversion of the
5.0 million Special Units into Common Units had a impact on basic earnings per Unit beginning in the same quarter.
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 December 31, 2000, this consolidated 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. During September 2001, the Trust purchased an additional
201,600 Common Units at a cost of $8.8 million. The Trust Units are considered outstanding and will receive
distributions; however, they are excluded from the calculation of earnings per Unit.
In September 2001, the Board of Directors of the General Partner approved a modification to the
Company's 1,000,000 Unit buy-back program. This two-year program, announced in July 2000, originally allowed the
Company to repurchase and retire up to 1,000,000 of its publicly-owned Common Units. Management's intent under
the buy-back program 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. As of December 31, 2000, the Company had repurchased and
retired 28,400 of these Common Units. The Board of Directors approved a modification to the plan that allows
both the Company and the Trust to repurchase Common Units under the buy-back program. Under the terms of the
modification, purchases made by the Company will continue to be retired whereas purchases made by the Trust will
remain outstanding and not be retired.
As of September 30, 2001, 770,000 publicly-owned Common Units could be repurchased under the buy-back
program. Purchases made by the Company will be funded by increased cash distributions from the Operating
Partnership's operating cash flows and borrowings under its bank credit facilities. Purchases made by the Trust
will be funded by cash contributions from the Operating Partnership arising from similar sources.
Response to September 11, 2001 Terrorist Attacks
Following the recent terrorist attacks in the United States, the Company's management instituted a
review of security measures and practices and emergency response capabilities for all facilities and sensitive
infrastructure. In connection with this activity, the Company has participated in security coordination efforts
with law enforcement and public safety authorities, industry mutual-aid groups and regulatory agencies. As a
result of these steps, security measures, techniques and equipment have been enhanced as appropriate on a
location-by-location basis. Further evaluation will be ongoing, with additional measures to be taken as specific
governmental alerts, additional information about improving security and new facts come to the Company's
attention.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to financial market risks, including changes in commodity prices in its natural
gas and NGL businesses and in interest rates with respect to a portion of its debt obligations. The Company may
use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar
Page 38
characteristics) to mitigate these risks. The Company generally does not use financial instruments for
speculative (trading) purposes.
Commodity Price Risk
The Company's Processing and Octane Enhancement segments are directly exposed to commodity price risk
through their respective business operations. The prices of natural gas, NGLs and MTBE are subject to
fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are
beyond the Company's control. These factors include the level of domestic oil, natural gas and NGL production
and development, the availability of imported oil and natural gas, actions taken by foreign oil and natural gas
producing nations, the availability of transportation systems with adequate capacity, the availability of
alternative fuels and products, seasonal demand for oil, natural gas and NGLs, conservation, the extent of
governmental regulation of production and the overall economic environment.
In order to manage this risk, the Company may enter into swaps, forwards, commodity futures, options and
other commodity financial instruments with similar characteristics that are permitted by contract or business
custom to be settled in cash or with another financial instrument. The primary purpose of these risk management
activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm
commitments and certain anticipated transactions in the Company's Processing segment. As an ancillary service,
Acadian Gas utilizes commodity financial instruments to manage the sales/purchase price of natural gas for certain
of its customers.
The Company has adopted a commercial policy to manage its exposure to the risks generated by its natural
gas and related NGL businesses. The objective of this policy is to assist the Company in achieving its
profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the
position limits established by the General Partner. The Company enters into risk management transactions to manage price
risk, basis risk, physical risk, or other risks related to its commodity positions on both a short-term (less
than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the strategies of the
Company associated with physical and financial risks (such as those mentioned previously), approves specific
activities of the Company subject to the policy (including authorized products, instruments and markets) and
establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.
The Company assesses the risk of its commodity financial instrument portfolio using a sensitivity
analysis model. The sensitivity analysis performed on this portfolio measures the potential gain or loss in
earnings (i.e., the change in fair value of the portfolio) based on a hypothetical 10% movement in the underlying
quoted market prices of the commodity financial instruments outstanding at the dates noted within the table.
The sensitivity analysis model takes into account the following primary factors and assumptions:
o the current quoted market price of natural gas;
o the current quoted market price of NGLs;
o changes in the composition of commodities hedged (i.e., the mix
between natural gas and related NGL hedges outstanding);
o fluctuations in the overall volume of commodities hedged (for both
natural gas and related NGL hedges outstanding);
o market interest rates, which are used in determining the present
value; and,
o a liquid market for such financial instruments.
An increase in fair value of the commodity financial instruments (based upon the factors and assumptions
noted above) approximates the income/gain that would be recognized in earnings if all of the commodity financial
instruments were settled at the respective balance sheet dates. Conversely, a decrease in fair value of the
commodity financial instruments would result in the recording of a loss at the respective balance sheet date.
The sensitivity analysis model does not include the impact that the same hypothetical price movement
would have on the hedged commodity positions to which they relate. Therefore, the impact on the fair value of
the commodity financial instruments of a change in commodity prices would be offset by a corresponding gain or
loss on the hedged commodity positions, assuming:
Page 39
o the commodity financial instruments are not closed out in advance of
their expected term,
o the commodity financial instruments function effectively as hedges of
the underlying risk, and
o as applicable, anticipated underlying transactions settle as expected.
The Company routinely reviews its open commodity financial instruments in light of current market
conditions. If market conditions warrant, some instruments may be closed out in advance of their contractual
settlement dates thus realizing income or loss depending on the specific exposure. When this occurs, the
Company may enter into new commodity financial instruments to reestablish the hedge of the commodity position to
which the closed instrument relates.
Under the guidelines of SFAS No. 133, as amended and interpreted, a hedge is normally regarded as
effective if, among other things, at inception and throughout the life of the hedge, the Company could expect
changes in the fair value of the hedged item to be almost fully offset by the changes in the fair value of the
hedging instrument. Currently, the Company's commodity financial instruments do not qualify as effective hedges
under the guidelines of SFAS No. 133, with the result being that changes in the fair value of these financial
instruments are recorded on the balance sheet and in earnings through mark-to-market accounting. The use of
mark-to-market accounting for the commodity financial instruments portfolio results in a degree of non-cash
earnings volatility that is dependant upon changes in the underlying commodity prices. Even though the commodity
financial instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS No.
133, the Company views these financial instruments as hedges inasmuch as this was the intent when such
contracts are executed. This characterization is consistent with the actual economic performance of the
contracts to date and the Company expects these financial instruments to continue to mitigate commodity price
risk in the future. For additional information regarding commodity financial instruments, see Note 10 of the
Notes to Unaudited Consolidated Financial Statements.
Sensitivity Analysis for Commodity Financial Instruments Portfolio
Estimates of Fair Value ("FV") and Earnings Impact ("EI")
due to selected changes in quoted market prices at dates selected
December September November
31, 2000 30, 2001 9, 2001
------------------------------------------
(in millions of dollars)
------------------------------------------
FV assuming no change in quoted market prices, Asset (Liability) $(38.6) $ 32.2 $ 13.6
FV assuming 10% increase in quoted market prices, Asset (Liability) $(56.3) $ 13.0 $ 1.5
EI assuming 10% increase in quoted market prices, Income (Loss) $(17.7) $ (19.2) $(12.1)
FV assuming 10% decrease in quoted market prices, Asset (Liability) $(20.9) $ 51.5 $ 25.7
EI assuming 10% decrease in quoted market prices, Income (Loss) $ 17.7 $ 19.3 $ 12.1
The fair value of the commodity financial instruments at December 31, 2000 was estimated at $38.6
million payable. On September 30, 2001, the fair value of the commodity financial instruments outstanding was
estimated at $32.2 million receivable. The change in fair value between December 31, 2000 and September 30, 2001
was primarily due to lower natural gas prices, settlement of certain open positions and a change in the
composition of commodities hedged. On November 9, 2001, the fair value of the commodity financial instruments
was $13.6 million receivable primarily due to an increase in quoted market prices since September 30, 2001.
Historical gains or losses resulting from these hedging activities are a component of the Company's
operating costs and expenses as reflected in its Statements of Consolidated Operations.
Page 40
Interest rate risk
Variable-rate Debt. At September 30, 2001 and 2000, the Company had no variable rate debt outstanding
and as such had no financial instruments in place to cover any potential interest rate risk on its variable-rate
debt obligations. Variable-rate debt obligations do expose the Company to possible increases in interest
expense and decreases in earnings if interest rates were to rise.
Fixed-rate Debt. In March 2000, the Company entered into interest rate swaps whereby the fixed-rate of
interest on a portion of the $350 Million Senior Notes and the $54 Million MBFC Loan was effectively swapped for
floating-rates tied to the six month London Interbank Offering Rate ("LIBOR"). The objective of holding
interest rate swaps is to manage debt service costs by effectively converting a portion of the fixed-rate debt
into variable-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the
notional amount while the other party pays a floating-rate based on the notional amount. Management believes
that it is prudent to maintain a balance between variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate
exposure that impact future cash flows and by evaluating hedging opportunities. The Company uses analytical
techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to
estimate the expected impact of changes in interest rates on the Company's future cash flows. The General
Partner oversees the strategies of the Company associated with financial risks and approves instruments that are
appropriate for the Company's requirements.
The interest rate swaps outstanding at December 31, 2000 reflected a notional amount of $154 million of
fixed-rate debt with the fair value of swaps estimated at $2.5 million. By September 30, 2001, the notional
amount had been reduced to $104 million due to the early termination of one of the swaps by a counterparty with
the aggregate fair value of the remaining swaps estimated at $9.5 million. The change in fair value between
December 31, 2000 and September 30, 2001 is related to lower interest rates and the decision by one counterparty
not to exercise its early termination right.
In October 2001, the Company and the counterparty to the swap related to the $350 Million Senior Notes
executed the early settlement of this swap. As a result, the Company realized $4.7 million of the $7.3 million
in non-cash mark-to-market income recognized through September 30, 2001 relating to its interest rate swaps.
Primarily due to this early termination, the fair value of the interest rate swap portfolio was $4.1 million receivable
on November 9, 2001.
The Company's interest rate swap agreements were dedesignated as hedging instruments after the adoption
of SFAS No. 133; therefore, the interest rate swap agreements are accounted for on a mark-to-market basis.
However, these financial instruments continue to be effective in achieving the risk management activities for
which they were intended. As a result, the change in fair value of these instruments will be reflected on the
balance sheet and in earnings (interest expense) using mark-to-market accounting. For additional information
regarding the interest rate swaps, see Note 10 of the Notes to Unaudited Consolidated Financial Statements that
are part of this Form 10-Q quarterly report.
Other. At September 30, 2001 and December 31, 2000, the Company had $67.1 million and $60.4 million
invested in cash and cash equivalents, respectively. All cash equivalent investments other than cash are highly
liquid, have original maturities of less than three months, and are considered to have insignificant interest
rate risk.
Counterparty risk
The Company has credit risk from its extension of credit for sales of products and services, and has
credit risk with its counterparties in terms of settlement risk associated with its financial instruments. On
all transactions where the Company is exposed to credit risk, the Company analyzes the counterparty's financial
condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of
these limits on an ongoing basis. The counterparty to a majority of the Company's commodity financial
instruments is a major Houston, Texas-based energy company. The credit risk to this party is somewhat mitigated
by cash or letters of credit held by the Company in an amount dependent upon the exposure with the counterparty.
Page 41
Related Accounting Developments
Due to the complexity of SFAS No. 133, the FASB is continuing to provide guidance about implementation
issues. Since this guidance is still continuing, the initial conclusions reached by the Company regarding the
application of SFAS No. 133 upon adoption may be altered. As a result, additional SFAS No. 133 transition
adjustments may be recorded in future periods as the Company adopts new FASB interpretations. For additional
information regarding SFAS No. 133, see Note 10 of the Notes to Unaudited Consolidated Financial Statements.
PART II. OTHER INFORMATION
Item 2. Use of Proceeds
The following table shows the Use of Proceeds from the $450 Million Senior Notes offering completed on
January 29, 2001. The $450 Million Senior Notes represented a takedown of the remaining shelf availability
under the Company's December 1999 Registration Statement filed with the Securities and Exchange Commission (File
Nos. 333-93239 and 333-93239-01, effective January 14, 2000).
The title of the registered debt securities was "7.50% Senior Notes Due 2011." The underwriters of the
offering were Goldman, Sachs and Co., Salomon Smith Barney Inc., Banc One Capital Markets, Inc., First Union
Securities, Inc., Scotia Capital (USA) Inc. and Tokyo-Mitsubishi International plc. The 10-year Senior Notes
have a maturity date of February 1, 2011 and bear a fixed-rate interest coupon of 7.50%.
Amounts
(in millions)
--------------
Proceeds:
Sale of $450 Million Senior Notes to public at 99.937% per Note $ 450
Less underwriting discount of 0.650% per Note (3)
--------------
Total proceeds $ 447
==============
Use of Proceeds:
Initial payment to finance Acadian Gas acquisition $(226)
To finance investment in various Gulf of Mexico
natural gas pipelines (112)
To finance remainder of the costs to construct certain NGL
pipelines and related projects, and for working capital
and other general Company purposes (109)
--------------
Total uses of funds $(447)
==============
The initial $226 million payment to Shell for Acadian Gas was made in April 2001, subject to certain post-closing
purchase price adjustments. Also, the Company paid EPE $112 million in January 2001 for the purchase of equity
interests in four Gulf of Mexico natural gas pipeline systems (Starfish, Ocean Breeze, Neptune and Nemo).
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
*2.1 Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated as of
September 22, 2000. (Exhibit 10.1 to Form 8-K filed on September 26, 2000).
*3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P.
(Exhibit 3.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
Page 42
*3.2 Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "D"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*3.3 First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated
September 17, 1999. (Exhibit 99.8 on Form 8-K/A-1 filed October 27, 1999).
*3.4 Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Enterprise Products
Partners L.P. dated June 9, 2000. (Exhibit 3.6 to Form 10-Q filed August 11, 2000).
*4.1 Form of Common Unit certificate. (Exhibit 4.1 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 21, 1998).
*4.2 Unitholder Rights Agreement among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise
Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by
reference the above document included as Exhibit "C" to the Schedule 13D filed September 27, 1999 by
Tejas Energy, LLC.
*4.3 Contribution Agreement by and among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise
Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by
reference the above document included as Exhibit "B" to the Schedule 13D filed September 27, 1999 by
Tejas Energy, LLC.
*4.4 Registration Rights Agreement between Tejas Energy LLC and Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "E"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*4.5 Form of Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer,
Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee. (Exhibit
4.1 on Form 8-K filed March 10, 2000).
*4.6 Form of Global Note representing $350 million principal amount of 8.25% Senior Notes Due 2005.
(Exhibit 4.2 on Form 8-K filed March 10, 2000).
*4.7 $250 Million Multi-Year Revolving Credit Agreement among Enterprise Products Operating L.P., First Union
National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan
Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17,
2000. (Exhibit 4.2 on Form 8-K filed January 25, 2001).
*4.8 $150 Million 364-Day Revolving Credit Agreement among Enterprise Products Operating L.P. and First Union
National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan
Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17,
2000. (Exhibit 4.3 on Form 8-K filed January 25, 2001).
*4.9 Guaranty Agreement (relating to the $250 Million Multi-Year Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001).
*4.10 Guaranty Agreement (relating to the $150 Million 364-Day Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001).
Page 48
*4.11 Form of Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011. (Exhibit
4.1 to Form 8-K filed January 25, 2001).
*4.12 First Amendment to $250 million Multi-Year Revolving Credit Agreement dated April 19, 2001.
*10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline Partnership, L.P., Chunchula Pipeline
Company, LLC, Propylene Pipeline Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise
Products Texas Operating L.P. dated June 1, 1998.(Exhibit 10.1 to Registration Statement on Form S-1/A,
File No: 333-52537, filed on July 8, 1998).
*10.2 Form of EPCO Agreement among Enterprise Products Partners L.P., Enterprise Products Operating
L.P., Enterprise Products GP, LLC and Enterprise Products Company. (Exhibit 10.2 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*10.3 Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company
dated June 1, 1998. (Exhibit 10.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on
July 8, 1998).
*10.4 Venture Participation Agreement among Sun Company, Inc. (R and 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 among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products
Company dated May 1, 1992. (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc.
(R and M) dated August 16, 1995. (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.7 Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules
Incorporated dated December 13, 1978. (Exhibit 10.9 to Registration Statement on Form S-1, File No.
333-52537, dated May 13, 1998).
*10.8 Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among
Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum
Company dated July 17, 1985. (Exhibit 10.10 to Registration Statement on Form S-1/A, File No. 333-52537,
filed on July 8, 1998).
*10.9 Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities among Enterprise
Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum Company and
Mont Belvieu Associates dated July 17, 1985. (Exhibit 10.11 to Registration Statement on Form S-1/A,
File No. 333-52537, filed on July 8, 1998).
*10.10 Amendment to Propylene Facility and Pipeline Sales Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1993. (Exhibit 10.12 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.11 Amendment to Propylene Facility and Pipeline Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1995. (Exhibit 10.13 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.12 Fourth Amendment to Conveyance of Gas Processing Rights among Tejas Natural Gas Liquids, LLC and Shell
Oil Company, Shell Exploration and Production Company, Shell Offshore Inc., Shell Deepwater Development
Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas Inc. dated August 1, 1999. (Exhibit
10.14 to Form 10-Q filed on November 15, 1999).
Page 44
*10.13 Fifth Amendment to Conveyance of Gas Processing Rights dated as of April 1, 2001 among Enterprise Gas
Processing, LLC, Shell Oil Company, Shell Exploration and Production Company, Shell Offshore, Inc., Shell
Consolidated Energy Resources, Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas, Inc.
(Exhibit 10.13 to Form 10-Q filed on August 13, 2001).
* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith
(b) Reports on Form 8-K
No Form 8-K reports were filed during the quarter ending September 30, 2001.
Page 45
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
---------------------------------------------------------------
Vice President, Controller and
Date: November 13, 2001 Principal Accounting Officer