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FIRST AMENDMENT
TO CREDIT AGREEMENT
(Multi-Year Revolving Credit Facility)
THIS FIRST AMENDMENT TO CREDIT AGREEMENT dated as of April 19, 2001 (the "First Amendment"),
among ENTERPRISE PRODUCTS OPERATING L.P., a Delaware limited partnership (the "Borrower"), the lenders party
hereto (the "Lenders"), and FIRST UNION NATIONAL BANK, individually, as Issuing Bank and as Administrative Agent
(the "Administrative Agent").
W I T N E S S E T H:
WHEREAS, the Borrower, the Lenders, and the Administrative Agent are parties to that certain
Credit Agreement dated as of November 17, 2000 (the "Credit Agreement"), whereby, pursuant to the terms and
conditions contained therein, the Lenders agreed to make loans to and extensions on behalf of the Borrower under
a multi-year revolving credit facility; and
WHEREAS, the parties to the Credit Agreement intend to amend the Credit Agreement to increase
the sublimit for the issuance of Letters of Credit from $50,000,000 to $75,000,000;
NOW, THEREFORE, the parties to the Credit Agreement hereby agree as follows:
SECTION 1. Amendments to Credit Agreement.
(a) The term "Agreement," as defined in Section 1.01 of the Credit Agreement is hereby
amended in its entirety to read as follows:
"Agreement" means this Credit Agreement dated as of November 17, 2000, among
the Borrower, the Lenders, the Administrative Agent and the Issuing Bank, as amended by the
First Amendment, and as the same may be further amended, waived or otherwise modified from time
to time in accordance herewith.
(b) Section 1.01 of the Credit Agreement hereby is amended by inserting the following
definition in its appropriate alphabetical order:
"First Amendment" means that certain First Amendment to Credit Agreement
dated as of April 19, 2001, among the Borrower, the Lenders party thereto, the Administrative
Agent and the Issuing Bank.
(c) Section 2.06(b) of the Credit Agreement is hereby amended by deleting the amount
"$50,000,000" contained in the sixteenth (16th) line thereof and substituting therefor the amount "$75,000,000."
Page 1
SECTION 2. Conditions Precedent to Effectiveness. This First Amendment shall become effective as of the
date first set forth above upon satisfaction of the following conditions precedent:
(a) the Administrative Agent shall have received counterparts of this First Amendment duly
executed by the Borrower, the Required Lenders, the Administrative Agent and the Issuing Bank (or, in the case of
any party as to which an executed counterpart shall not have been received, telegraphic, telex, or other written
confirmation from such party of execution of a counterpart hereof by such party); and
(b) no Default or Event of Default shall have occurred and be continuing as of the date of
this First Amendment.
SECTION 3. Reaffirmation of Representations and Warranties. To induce the Required Lenders, the
Administrative Agent and the Issuing Bank to enter into this First Amendment, the Borrower hereby reaffirms, as
of the date hereof, its representations and warranties in their entirety contained in Article III of the Credit
-----------
Agreement and in all other documents executed pursuant thereto (except to the extent such representations and
warranties relate solely to an earlier date) and additionally represents and warrants as follows:
(a) The execution, delivery and performance by the Borrower of this First Amendment are
within the Borrower's powers, have been duly authorized by all necessary action of the Borrower, require, in
respect of the Borrower, no action by or in respect of, or filing with, any governmental body, agency or official
and do not contravene or constitute a default under, any provision of law or regulation (including Regulation X
issued by the Federal Reserve Board) applicable to the Borrower or Regulation U or the limited partnership
agreement of the Borrower or any judgment, injunction, order, decree or material agreement binding upon the
Borrower or result in or require the creation or imposition of any Lien on any asset of the Borrower.
(b) This First Amendment has been duly executed and delivered by the Borrower. This First
Amendment, the Credit Agreement, as amended by this First Amendment, and each other Loan Document to which the
Borrower is a party are legal, valid and binding obligations of the Borrower enforceable against the Borrower in
accordance with their respective terms, except as the enforceability thereof may be limited by any applicable
bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors' rights generally and by
general principles of equity.
(c) Since December 31, 2000, no event or circumstance has occurred that has resulted in or
could reasonably be expected to have a Material Adverse Effect. No Event of Default has occurred and is
continuing as of the date hereof.
(d) There is no action, suit or proceeding pending against the Borrower or any of its
Subsidiaries or, to the knowledge of the Borrower, threatened against the Borrower or any of its Subsidiaries,
before any court or arbitrator or any governmental body, agency or official in which there is a reasonable
possibility of an adverse decision which could reasonably be expected to have a Material Adverse Effect or which
involves this First Amendment, the Credit Agreement, as amended hereby, or any other Loan Document.
Page 2
SECTION 4. Defined Terms. Except as amended hereby, terms used herein when defined in the Credit
Agreement shall have the same meanings herein unless the context otherwise requires.
SECTION 5. Reaffirmation of Credit Agreement. This First Amendment shall be deemed to be an amendment to
the Credit Agreement, and the Credit Agreement, as amended hereby, is hereby ratified, approved and confirmed in
each and every respect. All references to the Credit Agreement herein and in any other document, instrument,
agreement or writing shall hereafter be deemed to refer to the Credit Agreement as amended hereby.
SECTION 6. Governing Law; Entire Agreement. This First Amendment and the Notes shall be governed by, and
construed in accordance with, the laws of the State of New York. The Credit Agreement, as amended by this First
Amendment, the Notes and the other Loan Documents constitute the entire understanding among the parties hereto
with respect to the subject matter hereof and supersede any prior agreements, written or oral, with respect
thereto.
SECTION 7. Severability of Provisions. Any provision in this First Amendment that is held to be
inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative,
unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation,
enforceability, or validity of that provision in any other jurisdiction, and to this end the provisions of this
First Amendment are declared to be severable.
SECTION 8. Counterparts. This First Amendment may be executed in any number of counterparts, all of which
taken together shall constitute one agreement, and any of the parties hereto may execute this First Amendment by
signing any such counterpart.
SECTION 9. Headings. Article and section headings in this First Amendment are for convenience of
reference only, and shall not govern the interpretation of any of the provisions of this First Amendment.
SECTION 10. Successors and Assigns. This First Amendment shall be binding upon and inure to the benefit of
the parties hereto and their respective successors and assigns.
[SIGNATURES BEGIN ON FOLLOWING PAGE]
Page 3
[First Amendment to Credit Agreement - Signature Page 16]
Houston:515145_2.DOC
IN WITNESS WHEREOF, the Borrower, the Required Lenders, the Administrative Agent, the
Syndication Agent, the Documentation Agent, the Managing Agents, the Co-Agents and the Issuing Bank have executed
this First Amendment as of the date first above written.
ENTERPRISE PRODUCTS OPERATING L.P.
By: Enterprise Products GP, LLC,
its General Partner
By: /s/ W. Randall Fowler
Name: W. Randall Fowler
Title: Vice President and Treasurer
FIRST UNION NATIONAL BANK, individually and as
Administrative Agent,
By: /s/ Russell Clingman
Name: Russell Clingman
Title: Vice President
THE CHASE MANHATTAN BANK, individually and as Syndication
Agent
By: /s/ Robert C. Mertensotto
Name: Robert C. Mertensotto
Title: Managing Director
BANK ONE, NA (Main Office - Chicago), individually and as
Documentation Agent
By: /s/ Dianne L.Russell
Name: Dianne L.Russell
Title: Vice President
THE FUJI BANK, LIMITED, individually and as Managing Agent
By: /s/Jacques Azagury
Name: Jacques Azagury
Title: Senior Vice President and Manager
GUARANTY FEDERAL BANK, F.S.B.
By: /s/ Jim R. Hamilton
Name: Jim R. Hamilton
Title: Senior Vice President
HIBERNIA NATIONAL BANK
By: /s/ Nancy G. Moragas
Name: Nancy G. Moragas
Title: Vice President
NATIONAL AUSTRALIA BANK LIMITED, A.C.N. 004044937,
individually and as Managing Agent
By: /s/ Frank L. Campiglia
Name: Frank L. Campiglia
Title: Vice President
TORONTO DOMINION (TEXAS), INC., individually and as Managing
Agent
By: N/A
Name:
Title:
FLEET NATIONAL BANK, individually and as Managing Agent
By: /s/ Christopher C. Holmgren
Name: Christopher C. Holmgren
Title: Managing Director
THE DAI-ICHI KANGYO BANK, LIMITED, individually and as
Managing Agent
By: /s/ Perzemek T. Blakiak
Name: Perzemek T. Blaziak
Title: Account Officer
BANK OF TOKYO-MITSUBISHI, LTD., Houston Agency, individually
and as Co-Agent
By: /s/ John W. McGhee
Name: John W. McGhee
Title: Vice President and Manager
SUNTRUST BANK, individually and as Co-Agent
By: /s/ David J. Edge
Name: David J. Edge
Title: Director
WESTDEUTSCHE LANDESBANK GIROZENTRALE, NEW YORK BRANCH,
individually and as Co-Agent
By: N/A
Name:
Title:
CITIBANK, N.A.
By: /s/ Rob T. Jokhai
Name: Rob T. Jokhai
Title:Vice President
THE BANK OF NOVA SCOTIA
By: /s/ F.C.H. Ashby
Name: F.C.H. Ashby
Title: Senior Manager Loan Operations
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2001
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number: 1-14323
Enterprise Products Partners L.P.
(Exact name of Registrant as specified in its charter)
Delaware 76-0568219
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2727 North Loop West
Houston, Texas
77008-1037
(Address of principal executive offices) (Zip code)
(713) 880-6500
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days.
Yes _X_ No ___
The registrant had 46,524,515 Common Units outstanding as of May 14, 2001.
Enterprise Products Partners L.P. and Subsidiaries
TABLE OF CONTENTS
Page
No.
---
Part I. Financial Information
Item 1. Consolidated Financial Statements
Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets, March 31, 2001 and December 31, 2000 1
Statements of Consolidated Operations
for the three months ended March 31, 2001 and 2000 2
Statements of Consolidated Cash Flows
for the three months ended March 31, 2001 and 2000 3
Statements of Consolidated Partners' Equity and Comprehensive Income
for the three months ended March 31, 2001 and 2000 4
Notes to Unaudited Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operation 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk 28
Part II. Other Information
Item 2. Use of Proceeds 31
Item 6. Exhibits and Reports on Form 8-K 32
Signature Page
PART 1. FINANCIAL INFORMATION.
Item 1. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Dollar amounts in thousands)
March 31,
2001 December 31,
ASSETS (Unaudited) 2000
---------------------------------------
Current Assets
Cash and cash equivalents $ 379,411 $ 60,409
Accounts receivable - trade, net of allowance for doubtful accounts of
$10,227 at March 31, 2001 and $10,916 at December 31, 2000 323,897 409,085
Accounts receivable - affiliates 2,105 6,533
Inventories 24,770 93,222
Prepaid and other current assets 21,494 12,107
---------------------------------------
Total current assets 751,677 581,356
Property, Plant and Equipment, Net 991,216 975,322
Investments in and Advances to Unconsolidated Affiliates 405,182 298,954
Intangible assets, net of accumulated amortization of $6,624 at
March 31, 2001 and $5,374 at December 31, 2000 91,619 92,869
Other Assets 9,931 2,867
---------------------------------------
Total $2,249,625 $1,951,368
=======================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $82,700 $96,559
Accounts payable - affiliate 38,498 56,447
Accrued gas payables 276,811 377,126
Accrued expenses 10,097 21,488
Other current liabilities 28,099 34,759
---------------------------------------
Total current liabilities 436,205 586,379
Long-Term Debt 855,773 403,847
Other Long-Term liabilities 15,555 15,613
Minority Interest 9,738 9,570
Commitments and Contingencies
Partners' Equity
Common Units (46,257,315 Units outstanding at March 31, 2001
and December 31, 2000) 526,364 514,896
Subordinated Units (21,409,870 Units outstanding at March 31, 2001
and December 31, 2000) 170,462 165,253
Special Units (16,500,000 Units outstanding at March 31, 2001
and December 31, 2000) 251,132 251,132
Treasury Units acquired by Trust, at cost (267,200 Common Units
outstanding at March 31, 2001 and December 31, 2000) (4,727) (4,727)
General Partner 9,575 9,405
Accumulated other comprehensive loss (see Note 8) (20,452)
---------------------------------------
Total Partners' Equity 932,354 935,959
---------------------------------------
Total $2,249,625 $1,951,368
=======================================
See Notes to Unaudited Consolidated Financial Statements
Page 1
Enterprise Products Partners L.P.
Statements of Consolidated Operations
(Unaudited)
(Amounts in thousands, except per Unit amounts)
Three Months
Ended March 31,
-------------------------------
2001 2000
-------------------------------
REVENUES
Revenues from consolidated operations $836,315 $746,281
Equity income in unconsolidated affiliates 2,011 7,443
-------------------------------
Total 838,326 753,724
COST AND EXPENSES
Operating costs and expenses 777,741 672,906
Selling, general and administrative 6,168 5,384
-------------------------------
Total 783,909 678,290
-------------------------------
OPERATING INCOME 54,417 75,434
OTHER INCOME (EXPENSE)
Interest expense (6,987) (7,774)
Interest income from unconsolidated affiliates 24 144
Dividend income from unconsolidated affiliates 1,632 1,234
Interest income - other 3,998 1,481
Other, net (280) (363)
-------------------------------
Other income (expense) (1,613) (5,278)
-------------------------------
INCOME BEFORE MINORITY INTEREST 52,804 70,156
MINORITY INTEREST (534) (709)
-------------------------------
NET INCOME $ 52,270 $ 69,447
===============================
BASIC EARNINGS PER UNIT
Income before minority interest $ 0.77 $ 1.04
===============================
Net income per Common and Subordinated unit $ 0.76 $ 1.03
===============================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 0.62 $ 0.86
===============================
Net income per Common, Subordinated
and Special unit $ 0.61 $ 0.85
===============================
See Notes to Unaudited Consolidated Financial Statements
Page 2
Enterprise Products Partners L.P.
Statements of Consolidated Cash Flows
(Unaudited)
(Dollar amounts in thousands)
Three Months Ended
March 31,
-------------------------------------
2001 2000
-------------------------------------
OPERATING ACTIVITIES
Net income $ 52,270 $ 69,447
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 10,781 9,048
Equity in income of unconsolidated affiliates (2,011) (7,443)
Distributions received from unconsolidated affiliates 8,866 7,149
Leases paid by EPCO 2,633 2,637
Minority interest 534 709
Gain on sale of assets (381)
Changes in fair market value of financial instruments (see Note 8) (16,361)
Net effect of changes in operating accounts (7,634) 5,265
-------------------------------------
Operating activities cash flows 48,697 86,812
-------------------------------------
INVESTING ACTIVITIES
Capital expenditures (25,338) (111,449)
Proceeds from sale of assets 557 2
Collection of notes receivable from unconsolidated affiliates 3,287
Investments in and advances to unconsolidated affiliates (113,083) (5,972)
-------------------------------------
Investing activities cash flows (137,864) (114,132)
-------------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 449,716 463,818
Long-term debt repayments - (355,000)
Debt issuance costs (3,125) (2,451)
Cash dividends paid to partners (38,056) (33,820)
Cash dividends paid to minority interest by Operating Partnership (393) (345)
Cash contributions from EPCO to minority interest 27 30
-------------------------------------
Financing activities cash flows 408,169 72,232
-------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 319,002 44,912
CASH AND CASH EQUIVALENTS, JANUARY 1 60,409 5,230
-------------------------------------
CASH AND CASH EQUIVALENTS, MARCH 31 $379,411 $ 50,142
=====================================
See Notes to Unaudited Consolidated Financial Statements
Page 3
Enterprise Products Partners L.P.
Statements of Consolidated Partners' Equity and
Comprehensive Income
(Unaudited, amounts in thousands)
Partners' Equity
----------------------------------------------------------------------------
March 31, 2001 March 31, 2000
------------------------------------- -------------------------------------
Units Amount Units Amount
------------------------------------- -------------------------------------
Limited Partners
Balance, beginning of year 84,434 $931,281 81,463 $786,250
Net income 51,288 68,753
Leases paid by EPCO 2,606 2,611
Cash distributions (37,217) (33,483)
------------------------------------- -------------------------------------
Balance, end of period 84,434 947,958 81,463 824,131
------------------------------------- -------------------------------------
------------------------------------- -------------------------------------
Treasury Units (267) (4,727) (267) (4,727)
------------------------------------- -------------------------------------
General Partner
Balance, beginning of year 9,405 7,942
Net income 982 694
Leases paid by EPCO 27 26
Cash distributions (839) (337)
------------------- ------------------
Balance, end of period 9,575 8,325
------------------- ------------------
Accumulated Other
Comprehensive Loss
Cumulative transition adjustment
recorded on January 1, 2001
upon adoption of SFAS 133 (42,190)
(see Note 8)
Reclassification of cumulative
transition adjustment to
earnings 21,738
-------------------
Balance, end of period (20,452)
-------------------
------------------------------------- -------------------------------------
Total Partners' Equity 84,167 $932,354 81,196 $827,729
===================================== =====================================
Comprehensive Income
For Three Months Ended
----------------------------------------------------------------------------
March 31, 2001 March 31, 2000
------------------------------------- -------------------------------------
Net Income $ 52,270 $ 69,447
Less: Accumulated Other
Comprehensive Loss (20,452)
------------------- ------------------
Comprehensive Income $ 31,818 $ 69,447
=================== ==================
See Notes to Unaudited Consolidated Financial Statements
Page 4
Enterprise Products Partners L.P.
Notes to Consolidated Financial Statements
(Unaudited)
1. GENERAL
In the opinion of Enterprise Products Partners L.P. (the "Company"), the accompanying unaudited consolidated
financial statements include all adjustments consisting of normal recurring accruals necessary for a fair
presentation of the Company's consolidated financial position as of March 31, 2001 and consolidated results of
operations, cash flows, partners' equity and comprehensive income for the three month periods ended March 31,
2001 and 2000. Although the Company believes the disclosures in these financial statements are adequate to make
the information presented not misleading, certain information and footnote disclosures normally included in
annual financial statements prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. These
unaudited financial statements should be read in conjunction with the financial statements and notes thereto
included in the Company's annual report on Form 10-K (File No. 1-14323) for the year ended December 31, 2000.
The results of operations for the three month period ended March 31, 2001 are not necessarily indicative of the
results to be expected for the full year.
Certain reclassifications have been made to prior years' financial statements to conform to the presentation of
the current period financial statements.
Dollar amounts presented in the tabulations within the notes to the consolidated financial statements are stated
in thousands of dollars, unless otherwise indicated.
All references to "Shell," unless the context indicates otherwise, shall refer collectively to Shell Oil Company,
its subsidiaries and affiliates. Likewise, all references herein to "EPE," shall refer collectively to El Paso
Corporation, its subsidiaries and affiliates.
2. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
The Company owns interests in a number of related businesses that are accounted for under the equity method or
cost method. The investments in and advances to these unconsolidated affiliates are grouped according to the
operating segment to which they relate. For a general discussion of the Company's business segments, see Note
9.
At March 31, 2001, the Company's equity method investments (grouped by operating segment) included:
Fractionation segment:
o Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in a natural gas liquid ("NGL")
fractionation facility located in southeastern Louisiana.
o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest in a propylene concentration unit
located in southeastern Louisiana that became operational in July 2000.
o K/D/S Promix LLC ("Promix") - a 33.33% interest in a NGL fractionation facility and related storage
facilities located in south Louisiana. The Company's investment includes excess cost over the underlying
equity in the net assets of Promix of $8.0 million which is being amortized using the straight-line method
over a period of 20 years. The unamortized balance of excess cost over the underlying equity in the net
assets of Promix was $7.3 million at March 31, 2001.
Pipeline segment:
o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate interest in a
refrigerated NGL marine terminal loading facility located in southeast Texas.
Page 5
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 41.7% interest in a NGL pipeline system located in south
Louisiana.
o Dixie Pipeline Company ("Dixie") - a 19.9% interest in a 1,301-mile propane pipeline and associated
facilities extending from Mont Belvieu, Texas to North Carolina.
o Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural gas gathering system and
related dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore
Louisiana.
o Ocean Breeze Pipeline Company LLC ("Ocean Breeze") - a 25.67% interest in a limited liability company
("LLC") owning a 1% interest in the natural gas gathering and transmission systems owned by Manta Ray
Offshore Gathering Company, LLC ("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") located in the
Gulf of Mexico offshore Louisiana.
o Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in a limited liability company owning a 99%
interest in the Manta Ray and Nautilus natural gas gathering and transmission systems.
o Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas gathering system being
constructed in the Gulf of Mexico offshore Louisiana. The system is scheduled for completion in late
2001.
The Company's investment in Ocean Breeze and Neptune includes excess cost over the underlying equity in the net
assets of these entities of $24.0 million which is being amortized using the straight-line method over a period
of 35 years (as a pipeline asset). The unamortized balance of excess cost over the underlying equity in the net
assets of Ocean Breeze and Neptune was $23.8 million at March 31, 2001. Likewise, the Company's investment in
Nemo includes excess cost over the underlying equity in the net assets of $0.8 million which will be amortized
using the straight-line method over a period of 35 years (as a pipeline asset) when Nemo becomes operational in
late 2001. See Note 3 for further information regarding the Company's investments in Starfish, Ocean Breeze,
Neptune and Nemo.
Octane Enhancement segment:
o Belvieu Environmental Fuels ("BEF") - a 33.3% interest in a Methyl Tertiary Butyl Ether ("MTBE")
production facility located in southeast Texas. The production of MTBE is driven by oxygenated fuels
programs enacted under the federal Clean Air Act Amendments of 1990 and other legislation. Any changes to
these programs that enable localities to elect not to participate in these programs, lessen the requirements
for oxygenates or favor the use of non-isobutane based oxygenated fuels reduce the demand for MTBE and could
have an adverse effect on the Company's results of operations.
In recent years, MTBE has been detected in water supplies. The major source of the ground water
contamination appears to be leaks from underground storage tanks. Although these detections have been
limited and the great majority have been well below levels of public health concern, there have been calls
for the phase-out of MTBE in motor gasoline in various federal and state governmental agencies and advisory
bodies.
In light of these developments, the owners of BEF have been formulating a contingency plan for use of the
BEF facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion
of the BEF facility from MTBE production to alkylate production. Depending upon the type of alkylate
process chosen and the level of alkylate production desired, the cost to convert the facility from MTBE
production to alkylate production can range from $20 million to $90 million, with the Company's share of
these costs ranging from $6.7 million to $30 million.
At March 31, 2001, the Company's investments in and advances to unconsolidated affiliates also includes Venice
Energy Services Company, LLC ("VESCO"). The VESCO investment consists of a 13.1% interest in a LLC owning a
natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in Louisiana. This
investment is accounted for using the cost method.
Page 6
The following table summarizes investments in and advances to unconsolidated affiliates at:
March 31, December 31,
2001 2000
-------------------------------------
Accounted for on equity basis:
Fractionation:
BRF $ 30,552 $ 30,599
BRPC 20,752 25,925
Promix 47,233 48,670
Pipeline:
EPIK 15,195 15,998
Wilprise 8,747 9,156
Tri-States 27,103 27,138
Belle Rose 11,714 11,653
Dixie 38,110 38,138
Starfish 26,097
Ocean Breeze 970
Neptune 77,472
Nemo 9,151
Octane Enhancement:
BEF 59,086 58,677
Accounted for on cost basis:
Processing:
VESCO 33,000 33,000
-------------------------------------
Total $405,182 $298,954
=====================================
The following table shows equity in income (loss) of unconsolidated affiliates for the periods indicated:
For Three Months Ended
March 31,
-------------------------------------
2001 2000
-------------------------------------
Fractionation:
BRF $ 18 $ 529
BRPC 152 10
Promix 393 1,662
Pipeline:
EPIK (922) 1,792
Wilprise (222) 88
Tri-States (35) 678
Belle Rose (89) 179
Dixie 891
Starfish 951
Ocean Breeze 2
Neptune 694
Nemo 9
Octane Enhancement:
BEF 169 2,505
-------------------------------------
Total $2,011 $7,443
=====================================
Page 7
The following table presents summarized income statement information for the unconsolidated subsidiaries
accounted for by the equity method for the periods indicated (on a 100% basis):
Summarized Income Statement data for the Three Months ended
-----------------------------------------------------------------------------------------------
March 31, 2001 March 31, 2000
---------------------------------------------- -----------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
---------------------------------------------- -----------------------------------------------
Fractionation:
BRF $ 4,023 $ 35 $ 56 $ 4,971 $ 1,653 $ 1,636
BRPC 3,433 439 505 - - 34
Promix 9,002 1,440 1,477 12,484 5,236 5,285
Pipeline:
EPIK 691 (1,891) (1,862) 9,156 3,560 3,594
Wilprise 398 (602) (594) 732 258 263
Tri-States 1,632 (126) (105) 3,734 1,980 2,035
Belle Rose 147 (219) (213) 857 430 430
Dixie (a) 19,327 9,649 5,834
Starfish (b) 6,616 2,098 1,902
Ocean Breeze (b) 20 12 12
Neptune (b) 7,409 3,148 3,369
Nemo (b) - (16) 28
Octane Enhancement:
BEF 37,864 413 507 53,333 7,607 7,516
---------------------------------------------- -----------------------------------------------
Total $ 90,562 $14,380 $10,916 $85,267 $20,724 $20,793
============================================== ===============================================
Notes to Summarized Income Statement data table:
- ------------------------------------------------
(a) Dixie became an equity method investment in October 2000.
(b) These entities became equity method investments of the Company in January 2001, see Note 3 for description of
acquisitions.
3. ACQUISITIONS
Manta Ray, Nautilus and Nemo Pipeline Systems
On January 29, 2001, the Company acquired interests in three natural gas pipeline systems and related equipment
located in the Gulf of Mexico offshore Louisiana from EPE for $88.1 million in cash. These systems total
approximately 350 miles of pipeline. The Company acquired a 25.67% interest in each of the Manta Ray and
Nautilus pipeline systems (as a result of its investment in Ocean Breeze and Neptune) and a 33.92% interest in
the Nemo pipeline system. Affiliates of Shell own an interest in all three systems, and an affiliate of Marathon
Oil Company owns an interest in the Manta Ray and Nautilus systems. The Manta Ray system comprises
approximately 225 miles of pipeline with a capacity of 750 million cubic feet ("MMcf") per day and related
equipment, the Nautilus system comprises approximately 101 miles of pipeline with a capacity of 600 MMcf per day,
and the Nemo system, when completed in the fourth quarter of 2001, will comprise approximately 24 miles of
pipeline with a capacity of 300 MMcf per day.
Stingray Pipeline System and Related Facilities
On January 29, 2001, the Company and an affiliate of Shell acquired, through their 50/50 ownership of Starfish,
the Stingray natural gas pipeline system and related facilities from EPE for $50.2 million in cash. The Stingray
system comprises approximately 375 miles of pipeline with a capacity of 1.2 billion cubic feet ("Bcf") per day
Page 8
offshore Louisiana in the Gulf of Mexico. Shell will be responsible for the commercial and physical operations
of the Stingray system.
The pro forma results of operations incorporating these investments for the three-month period ending March 31,
2000 is not materially different than the Company's historical results for the quarter ended March 31, 2000. In
addition, the cash payments made to EPE for these acquisitions are subject to certain post-closing adjustments
expected to be finalized in the second quarter of 2001.
4. LONG-TERM DEBT
Long-term debt consisted of the following at:
March 31, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 $350,000 $350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
---------------------------------------
Total principal amount 854,000 404,000
Increase in fair value related to hedging a portion of fixed-rate debt
(see Note 8) 2,196
Less unamortized discount on:
$350 Million Senior Notes (144) (153)
$450 Million Senior Notes (279)
Less current maturities of long-term debt - -
---------------------------------------
Long-term debt $855,773 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility and $150
Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit
facilities at March 31, 2001 or December 31, 2000.
At March 31, 2001, the Company had a total of $75 million of standby letters of credit available under its $250
Million Multi-Year Credit Facility of which $54.1 million was outstanding.
$450 Million Senior Notes. On January 24, 2001, a subsidiary of the Company completed a public offering of $450
million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of
99.937% per Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting
discounts and commissions, of approximately $446.8 million. The proceeds from this offering were used to
acquire the Acadian and EPE natural gas pipeline systems for $339.2 million (with $226 million of this amount
paid on April 2, 2001 for Acadian - see Note 10) and to finance the cost to construct certain NGL pipelines and
related projects and for working capital and other general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is also
applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As with
the $350 Million Senior Notes, the $450 Million Senior Notes:
o are subject to a make-whole redemption right;
o are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness; and,
o are guaranteed by the Company through an unsecured and unsubordinated guarantee.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 $800 million
universal registration statement; therefore, the amount of securities available under this registration statement
Page 9
was reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration
statement (the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity
or debt securities or a combination thereof. The Company expects to use the net proceeds from any sale of
securities under the February 2001 Registration Statement for future business acquisitions and other general
corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or
the repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will
be applied to partnership purposes will depend on a number of factors, including the Company's funding
requirements and the availability of alternative funding sources. The Company routinely reviews acquisition
opportunities.
The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and
variable-rate debt instruments at March 31, 2001.
Increase in fair value of fixed-rate debt. Upon adoption of Statement of Financial Accounting Standards No. 133
("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities (as amended and interpreted) on
January 1, 2001, the Company recorded a $2.3 million non-cash increase in the fair value of its fixed-rate debt.
SFAS 133 required that the Company's interest rate swaps and their associated hedged fixed-rate debt be recorded
at fair value upon adoption of the standard. After adoption of the standard, the interest rate swaps were
dedesignated due to differences in the estimated maturity dates of the interest rate swaps versus the fixed-rate
debt. As a result, the fair value of the hedged fixed-rate debt will not be adjusted for future changes in fair
value and the $2.3 million increase in the fair value of the debt will be amortized to earnings over the
remaining life of the fixed-rate debt to which it applies, which approximates 10 years. The fair value
adjustment of $2.3 million is not a cash obligation of the Company and does not alter the amount of the Company's
indebtedness. See Note 8 for additional information concerning the Company's financial instruments.
Page 10
5. EARNINGS PER UNIT
Basic earnings per Unit is computed by dividing net income available to limited partner interests by the
weighted-average number of Common and Subordinated Units outstanding during the period. Diluted earnings per
Unit is computed by dividing net income available to limited partner interests by the weighted-average number of
Common, Subordinated and Special Units outstanding during the period. The following table reconciles the
number of shares used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three
months ended March 31, 2001 and 2000:
For the Three Months Ended
March 31,
2001 2000
-------------------------------------
Income before minority interest $52,804 $70,156
General partner interest (982) (694)
-------------------------------------
Income before minority interest available to Limited Partners 51,822 69,462
Minority interest (534) (709)
-------------------------------------
Net income available to Limited Partners $51,288 $68,753
=====================================
BASIC EARNINGS PER UNIT
Numerator
Income before minority interest available to
Limited Partners $51,822 $69,462
=====================================
Net income available to Limited Partners $51,288 $68,753
=====================================
Denominator
Common Units outstanding 46,257 45,286
Subordinated Units outstanding 21,410 21,410
-------------------------------------
Total 67,667 66,696
=====================================
Basic Earnings per Unit
Income before minority interest available to
Limited Partners $ 0.77 $ 1.04
=====================================
Net income available to Limited Partners $ 0.76 $ 1.03
=====================================
DILUTED EARNINGS PER UNIT
Numerator
Income before minority interest available to
Limited Partners $51,822 $69,462
=====================================
Net income available to Limited Partners $51,288 $68,753
=====================================
Denominator
Common Units outstanding 46,257 45,286
Subordinated Units outstanding 21,410 21,410
Special Units outstanding 16,500 14,500
-------------------------------------
Total 84,167 81,196
=====================================
Basic Earnings per Unit
Income before minority interest available to
Limited Partners $ 0.62 $ 0.86
=====================================
Net income available to Limited Partners $ 0.61 $ 0.85
=====================================
Page 11
6. DISTRIBUTIONS
The Company intends, to the extent there is sufficient available cash from Operating Surplus, as defined by the
Partnership Agreement, to distribute to each holder of Common Units at least a minimum quarterly distribution of
$0.45 per Common Unit. The minimum quarterly distribution is not guaranteed and is subject to adjustment as set
forth in the Partnership Agreement. With respect to each quarter during the Subordination Period, the Common
Unitholders will generally have the right to receive the minimum quarterly distribution, plus any arrearages
thereon, and the General Partner will have the right to receive the related distribution on its interest before
any distributions of available cash from Operating Surplus are made to the Subordinated Unitholders. As an
incentive, the General Partner's interest in quarterly distributions is increased after certain specified target
levels are met. The Company made incentive cash distributions to the General Partner of $0.5 million during the
three months ended March 31, 2001 and none during the same period in 2000.
On January 17, 2000, the Company declared an increase in its quarterly cash distribution to $0.50 per Unit.
This amount was subsequently raised to $0.525 per Unit on July 17, 2000 and $0.55 per Unit on December 7, 2000.
On May 3, 2001, the Board of Directors of the General Partner approved an increase in the quarterly distribution
rate to $.5875 per Unit beginning with the distribution pertaining to the second quarter of 2001.
The following is a summary of cash distributions to partnership interests since the first quarter of 1999:
Cash Distributions
--------------------------------------------------------------------
Per
Per Common Subordinated Record Payment
Unit Unit Date Date
--------------------------------------------------------------------
1999 First Quarter $ 0.450 $ 0.450 Jan. 29, 1999 Feb. 11, 1999
Second Quarter $ 0.450 $ 0.070 Apr. 30, 1999 May 12, 1999
Third Quarter $ 0.450 $ 0.370 Jul. 30, 1999 Aug. 11, 1999
Fourth Quarter $ 0.450 $ 0.450 Oct. 29, 1999 Nov. 10, 1999
2000 First Quarter $ 0.500 $ 0.500 Jan. 31, 2000 Feb. 10, 2000
Second Quarter $ 0.500 $ 0.500 Apr. 28, 2000 May 10, 2000
Third Quarter $ 0.525 $ 0.525 Jul. 31, 2000 Aug. 10, 2000
Fourth Quarter $ 0.525 $ 0.525 Oct. 31, 2000 Nov. 10, 2000
2001 First Quarter $ 0.550 $ 0.550 Jan. 31, 2001 Feb. 9, 2001
Second Quarter $ 0.550 $ 0.550 Apr. 30, 2001 May 10, 2001
(through May 14, 2001)
Page 12
7. SUPPLEMENTAL CASH FLOW DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows for the periods indicated:
Three Months Ended
March 31,
------------------------------------------
2001 2000
------------------------------------------
(Increase) decrease in:
Accounts receivable $89,620 $(25,840)
Inventories 68,452 30,085
Prepaid and other current assets (1,824) 3,291
Intangible assets (4,351)
Other assets (1,128) (600)
Increase (decrease) in: -
Accounts payable (31,808) (32,848)
Accrued gas payable (100,315) 49,473
Accrued expenses (11,391) (10,941)
Other current liabilities (19,182) (2,964)
Other liabilities (58) (40)
------------------------------------------
Net effect of changes in operating accounts $(7,634) $ 5,265
==========================================
During the first quarter of 2001, the Company purchased various equity interests in natural gas pipeline
companies from EPE for approximately $113.2 million in cash. This amount is reflected in "Investments in and
advances to unconsolidated affiliates" for the 2001 period. Capital expenditures for 2000 included $99.5 million
for the purchase of the Lou-Tex Propylene Pipeline and related assets.
As a result of the Company's adoption of SFAS 133 on January 1, 2001, the Company recorded various financial
instruments relating to interest rate risk and commodity positions at their respective fair values. For the
three months ended March 31, 2001, the Company recognized a net $16.4 million in non-cash mark-to-market gains
related to increases in the fair value of these financial instruments ($13.5 million of this amount was
attributable to commodity financial instruments with the remainder resulting from interest rate hedging
activities). See Note 8 below for a further description of the Company's financial instruments.
8. FINANCIAL INSTRUMENTS
The Company holds and issues financial instruments for the purpose of hedging the risks of certain identifiable
and anticipated transactions. In general, the types of risks hedged are those relating to the variability of
future earnings and cash flows caused by changes in commodity prices and interest rates.
Commodity Financial Instruments - Gas Processing and related NGL and natural gas businesses
The Company is exposed to commodity price risk through its natural gas processing and related NGL and natural gas
businesses. In order to effectively manage this risk, the Company may enter into swaps, forwards, commodity
futures, options and other commodity financial instruments with similar characteristics that are permitted by
contract or business custom to be settled in cash or with another financial instrument. The purpose of these
risk management activities is to hedge exposure to price risks associated with natural gas, NGL production and
inventories, firm commitments and certain anticipated transactions.
The Company has adopted a commercial policy to manage its exposure to the risks generated by its gas processing
and related NGL and natural gas businesses. The objective of this policy is to assist the Company in achieving
its profitability goals while maintaining a portfolio of conservative risk, defined as remaining within the
position limits established by the General Partner. The Company will enter into risk management transactions to
manage price risk, basis risk, physical risk, or other risks related to the energy commodities on both a
Page 13
short-term (less than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the
strategies of the Company associated with physical and financial risks, approves specific activities of the
Company subject to the policy (including authorized products, instruments and markets) and establishes specific
guidelines and procedures for implementing and ensuring compliance with the policy.
On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of
the commodity financial instruments on the balance sheet based upon then current market conditions. The fair
market value of the then outstanding commodity financial instruments was a net liability of $42.2 million (the
"cumulative transition adjustment") with an offsetting equal amount recorded in Other Comprehensive Income. The
amounts in Other Comprehensive Income are reclassified to earnings in the accounting period associated with the
hedged transaction (e.g. production month). Of the $42.2 million cumulative transition adjustment, $21.7
million was reclassified to earnings during the first quarter of 2001 with the remaining balance scheduled to be
reclassified as follows: $10.7 million during the second quarter of 2001, $7.3 million during the third quarter
of 2001 and $2.5 million during the fourth quarter of 2001. The amounts recorded in Other Comprehensive Income
at adoption of SFAS 133 will not be adjusted for changes in fair value; rather, any change in the fair value of
these commodity financial instruments will be recorded in earnings (i.e., mark-to-market accounting
treatment). The decision to record changes in the fair value of these commodity financial instruments
directly to earnings rather than Other Comprehensive Income is based upon the determination by management that on
an ongoing basis these commodity financial instruments would be ineffective under the guidelines of SFAS 133.
In addition to the commodity financial instruments outstanding at January 1, 2001, the Company has continued to
enter into commodity financial instruments to manage its risks in the gas processing and related NGL and natural
gas businesses. Collectively, these financial instruments pertain to time periods extending to October 2001.
These commodity financial instruments may not qualify for hedge accounting treatment under the specific
guidelines of SFAS 133. The Company continues to refer to these financial instruments as hedges in as much as
this was the intent when such contracts were executed. This characterization is consistent with the actual
economic performance of the contracts and the Company expects these financial instruments to continue to mitigate
commodity price risk in the future. The specific accounting for these contracts, however, is consistent with
the requirements of SFAS 133. As such, if these contracts do not qualify for hedge accounting under the
specific guidelines of SFAS 133, the change in fair value of these commodity financial instruments will be
reflected on the balance sheet and in earnings (i.e., mark-to-market accounting treatment).
The Company recorded a net $5.6 million benefit in its operating costs and expenses during the first quarter of
2001 relating to the change in fair value of the commodity financial instruments in place as of January 1, 2001
and the change in fair value of commodity financial instruments executed after January 1, 2001. Of this amount,
$13.5 million represents net non-cash benefits related to mark-to-market accounting adjustments recorded in
earnings at March 31, 2001. The offsetting $7.9 million relates primarily to losses on settlements realized
during the quarter.
Other Financial Instruments - Interest rate swaps
The objective of holding interest rate swaps is to manage debt service costs by converting a portion of the
fixed-rate debt into variable-rate debt. An interest rate swap, in general, requires one party to pay a
fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount.
Management believes that it is prudent to maintain a balance between variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate exposure
that impact future cash flows and evaluating hedging opportunities. The Company uses analytical techniques to
measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the
expected impact of changes in interest rates on the Company's future cash flows. The General Partner oversees
the strategies of the Company associated with financial risks and approves instruments that are appropriate for
the Company's requirements.
On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of
the interest rate swaps on the balance sheet since the swaps were considered fair value hedges. SFAS 133
required that management determine (at the standard's adoption date) (a) the fair value of the swaps based upon
then current market conditions and (b) the estimated maturity date of the swaps (including an estimate of the
Page 14
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 4 for further information regarding the impact of SFAS 133 on the Company's
fixed-rate long-term debt.
After adoption, the interest rate swaps were dedesignated as hedging instruments due to differences between the
maturity dates of the swaps and the associated hedged debt instruments. Dedesignation means that the financial
instrument (in this case, the interest rate swaps) will not be accounted for using hedge accounting under SFAS
133. Upon dedesignation, any future changes in the fair value of the interest rate swap agreements will be
recorded on the balance sheet through earnings. Dedesignation also entails that the previously associated
hedged item (in this case, the debt instrument) will not be adjusted for future changes in its fair value. As a
result, the $2.3 million change in fair value of the debt instrument recorded at the adoption date of SFAS 133
will amortized to earnings over the life of the previously associated debt instrument of approximately 10
years.
Despite the dedesignation of the interest rate swaps, these financial instruments continue to be effective in
achieving the risk management objectives for which they were intended. Interest expense during the first
quarter of 2001 decreased $5.2 million due to the change in fair value of the interest rate swaps. The change
in fair value of the interest rate swaps does not represent a cash gain or loss for the Company. The actual
cash gain or loss on the interest rate swap agreements will be based upon the market interest rates in effect on
the specified settlement dates in the swap agreements. The $5.2 million benefit recorded in the first quarter
of 2001 was primarily due to the decision of one counterparty not to exercise its early termination right under
its swap agreement with the Company (which accounted for $4.3 million of the benefit) and, to a lesser extent,
the decision by the U.S. Federal Reserve to lower interest rates.
Due to the complexity of SFAS 133, the Financial Accounting Standards Board ("FASB") organized a formal
committee, the Derivatives Implementation Group ("DIG"), to provide ongoing recommendations to the FASB about
implementation issues. Implementation guidance issued through the DIG process is still continuing; therefore,
the initial conclusions reached by the Company concerning the application of SFAS 133 upon adoption may be
altered. As a result, additional SFAS 133 transition adjustments may be recorded in future periods as the
Company adopts new DIG interpretations approved by the FASB.
9. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing
performance. Generally, financial information is required to be reported on the basis that it is used internally
for evaluating segment performance and deciding how to allocate resources to segments.
The Company has five reportable operating segments: Fractionation, Pipeline, Processing, Octane Enhancement and
Other. The reportable segments are generally organized according to the type of services rendered or process
employed and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief
Executive Officer of the General Partner. Fractionation includes NGL fractionation, butane isomerization
(converting normal butane into high purity isobutane) and polymer grade propylene fractionation services.
Pipeline consists of pipeline, storage and import/export terminal services. Processing includes the natural
gas processing business and its related NGL merchant activities. Octane Enhancement represents the Company's
33.33% ownership interest in a facility that produces motor gasoline additives to enhance octane (currently
producing MTBE). The Other operating segment consists of fee-based marketing services and other plant support
functions.
The Company evaluates segment performance on the basis of gross operating margin. Gross operating margin
reported for each segment represents operating income before depreciation and amortization, lease expense
obligations retained by EPCO, gains and losses on the sale of assets and general and administrative expenses.
In addition, segment gross operating margin is exclusive of interest expense, interest income (from
unconsolidated affiliates or others), dividend income from unconsolidated affiliates, minority interest,
extraordinary charges and other income and expense transactions. The Company's equity earnings from
unconsolidated affiliates are included in segment gross operating margin.
Page 15
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.
Information by operating segment, together with reconciliations to the consolidated totals, is presented in the
following table:
Operating Segments Adjustments
-------------------------------------------------------------------
Octane and Consolidated
Fractionation Pipelines Processing Enhancement Other Eliminations Totals
----------------------------------------------------------------------------------------------
Revenues from external customers
for the three months ended:
March 31, 2001 $89,679 $7,187 $738,769 $680 $836,315
March 31, 2000 91,897 7,012 646,857 515 746,281
Intersegment revenues
for the three months ended:
March 31, 2001 41,652 20,779 110,309 95 (172,835)
March 31, 2000 35,465 13,199 142,231 94 (190,989)
Equity income in unconsolidated
affiliates for the three
months
ended:
March 31, 2001 562 1,280 169 2,011
March 31, 2000 2,201 2,737 2,505 7,443
Total revenues
for the three months ended:
March 31, 2001 131,893 29,246 849,078 169 775 (172,835) 838,326
March 31, 2000 129,563 22,948 789,088 2,505 609 (190,989) 753,724
Gross operating margin by
segment for the three months
ended:
March 31, 2001 25,668 18,123 28,398 169 535 72,893
March 31, 2000 34,331 14,635 39,554 2,505 554 91,579
Segment property, net at:
March 31, 2001 352,682 446,772 125,685 8,413 57,664 991,216
December 31, 2000 356,207 448,920 126,895 8,942 34,358 975,322
Investments in and advances
to unconsolidated affiliates
at:
March 31, 2001 98,537 214,560 33,000 59,085 405,182
December 31, 2000 105,194 102,083 33,000 58,677 298,954
All consolidated revenues were earned in the United States. The operations of the Company are centered along
the Texas, Louisiana and Mississippi Gulf Coast areas.
Page 16
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
For Three Months Ended
March 31,
2001 2000
---------------------------------
Total segment gross operating margin $72,893 $91,579
Depreciation and amortization (10,029) (8,124)
Retained lease expense, net (2,660) (2,637)
Gain on sale of assets 381 -
Selling, general and administrative (6,168) (5,384)
---------------------------------
Consolidated operating income 54,417 75,434
Interest expense (6,987) (7,774)
Interest income from unconsolidated affiliates 24 144
Dividend income from unconsolidated affiliates 1,632 1,234
Interest income - other 3,998 1,481
Other, net (280) (363)
---------------------------------
Consolidated income before minority interest $52,804 $70,156
=================================
10. SUBSEQUENT EVENTS
Acadian Acquisition
On April 2, 2001, the Company announced that it had completed its acquisition of Acadian Gas, LLC ("Acadian")
from Shell US Gas and Power LLC (formerly Coral Energy LLC), an affiliate of Shell for approximately $226 million
in cash (utilizing cash on hand at March 31, 2001). The effective date of the transaction was April 1, 2001.
Acadian's assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas
pipeline systems, which together have over one billion cubic feet per day of capacity. These natural gas
pipeline systems are wholly-owned by Acadian with the exception of the Evangeline system in which Acadian holds
an approximate 49.5% interest. The system includes a leased natural gas storage facility at Napoleonville,
Louisiana.
These systems link supplies of natural gas from onshore developments and, through connections with offshore
pipelines, Gulf of Mexico production to local gas distribution companies, electric generation and industrial
customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. In addition, these
pipelines have interconnects with 12 interstate pipelines and four intrastate pipelines and a bi-directional
interconnect with the U.S. natural gas marketplace at the Henry Hub.
Page 17
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION.
For the Interim Periods ended March 31, 2001 and 2000
The following discussion and analysis should be read in conjunction with the unaudited consolidated
financial statements and notes thereto of Enterprise Products Partners L.P. (the "Company") included elsewhere
herein. All references herein to "Shell", unless the context indicates otherwise, shall refer collectively to
Shell Oil Company, its subsidiaries and affiliates. Likewise, all references herein to "EPE," shall refer
collectively to El Paso Corporation, its subsidiaries and affiliates.
Uncertainty of Forward-Looking Statements and Information
This quarterly report on Form 10-Q contains various forward-looking statements and information that are
based on the belief of the Company and the General Partner, as well as assumptions made by and information
currently available to the Company and the General Partner. When used in this document, words such as
"anticipate," "estimate," "project," "expect," "plan," "forecast," "intend," "could," "believe," "may" and similar
expressions and statements regarding the plans and objectives of the Company for future operations, are intended
to identify forward-looking statements. Although the Company and the General Partner believe that the
expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such
expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and
assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, actual results may vary materially from those anticipated, estimated, projected, or expected.
Among the key risk factors that may have a direct bearing on the Company's results of operations and
financial condition are: (a) competitive practices in the industries in which the Company competes, (b)
fluctuations in oil, natural gas, and natural gas liquid ("NGL") product prices and production due to weather and
other natural and market forces, (c) operational and systems risks, (d) environmental liabilities that are not
covered by indemnity or insurance, (e) the impact of current and future laws and governmental regulations
(including environmental regulations) affecting the NGL industry in general, and the Company's operations in
particular, (f) loss of a significant customer, and (g) failure to complete one or more new projects on time or
within budget.
In addition, the Company's expectations regarding its future capital expenditures as described in
"Liquidity and Capital Resources" are only its forecasts regarding these matters. These forecasts may be
substantially different from actual results due to the factors described in the previous paragraph as well as
uncertainties related to the following: (a) the accuracy of the Company's estimates regarding its spending
requirements, (b) the occurrence of any unanticipated acquisition opportunities, (c) the need to replace any
unanticipated losses in capital assets, (d) changes in the strategic direction of the Company and (e)
unanticipated legal, regulatory and contractual impediments with regards to its construction projects.
Company Overview
The Company is a leading integrated North American provider of natural gas processing and natural gas
liquids fractionation, transportation and storage services to producers of NGLs and consumers of NGL products.
Beginning in the first quarter of 2001, the Company is also engaged in the transportation of natural gas
production from various fields located in Gulf of Mexico offshore Louisiana developments. The Company's natural
gas business expanded to encompass the purchase, sale, transportation and storage of natural gas in Louisiana
beginning in the second quarter of 2001 as a result of completion of the Acadian Gas, LLC ("Acadian") acquisition
from Shell effective April 1, 2001.
The Company is a publicly traded master limited partnership (NYSE, symbol "EPD") that conducts
substantially all of its business through Enterprise Products Operating L.P. (the "Operating Partnership"), the
Operating Partnership's subsidiaries, and a number of joint ventures with industry partners. The Company was
formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise
Products Company ("EPCO"). The general partner of the Company, Enterprise Products GP, LLC, a majority-owned
Page 18
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 currently provides a wide range of midstream energy services to its customers along the
central and western Gulf Coast including the:
o gathering, transmission and storage of natural gas from both onshore and offshore Louisiana developments;
o purchase and sale of natural gas in south Louisiana;
o processing of natural gas into a merchantable and transportable form of energy that meets industry
quality specifications by removing NGLs and impurities;
o fractionating for a processing fee mixed NGLs produced as by-products of oil and natural gas production
into their component products: ethane, propane, isobutane, normal butane and natural gasoline;
o converting normal butane to isobutane through the process of isomerization;
o producing MTBE from isobutane and methanol;
o transporting NGL products to end users by pipeline and railcar;
o separating high purity propylene from refinery-sourced propane/propylene mix; and
o transporting high purity propylene to plastics manufacturers by pipeline.
Natural gas transported, processed and/or sold by the Company generally is consumed as fuel by residential,
electric and industrial centers. NGL and petrochemical products processed by the Company generally are used as
feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential and
commercial heating.
Company Operations and Assets
The Company's operations are concentrated in the Texas, Louisiana, and Mississippi Gulf Coast area. A
large portion of these operations take place in Mont Belvieu, Texas, which is the hub of the domestic NGL
industry and is adjacent to the largest concentration of refineries and petrochemical plants in the United
States. The facilities the Company operates at Mont Belvieu include: (a) one of the largest NGL fractionation
facilities in the United States with a net processing capacity of 131 thousand barrels per day ("MBPD"); (b) the
largest commercial butane isomerization complex in the United States with a potential isobutane production
capacity of 116 MBPD; (c) a MTBE production facility with a net production capacity of 5 MBPD; and (d) two
propylene fractionation units with a combined production capacity of 31 MBPD. The Company owns all of the assets
at its Mont Belvieu facility except for the NGL fractionation facility, in which it owns an effective 62.5%
interest; one of the propylene fractionation units, in which it owns a 54.6% interest and controls the remaining
interest through a long-term lease; the MTBE production facility, in which it owns a 33.3% interest; and one of
its three isomerization units and one deisobutanizer which are held under long-term leases with purchase options.
The Company's operations in Louisiana and Mississippi include varying interests in twelve natural gas
processing plants with a combined capacity of 11.6 billion cubic feet per day ("Bcfd") and net capacity of 3.2
Bcfd, six NGL fractionation facilities with a combined net processing capacity of 159 MBPD and a propylene
fractionation facility with a net capacity of 7 MBPD.
The Company owns, operates or has an interest in approximately 65.0 million barrels of gross storage
capacity (44.3 million barrels of net capacity) in Texas, Louisiana and Mississippi that are an integral part of
its processing operations. The Company also leases and operates one of only two commercial NGL import/export
terminals on the Gulf Coast. In addition, the Company has operating and non-operating ownership interests in
over 2,900 miles of NGL and petrochemical pipelines.
Page 19
Beginning in January 2001, the Company owns varying interests in four offshore natural gas gathering and
transmission systems totaling 725 miles of pipeline (with an aggregate gross capacity of 2.85 Bcfd) and an
onshore natural gas dehydration facility. Equity interests in these assets were purchased from EPE at a cost
of approximately $113.2 million (subject to certain post-closing adjustments). These pipelines and their
associated assets are strategically located to serve expanding continental shelf and deepwater developments in
the Gulf of Mexico.
With the completion of the Acadian acquisition in April 2001 (a second quarter 2001 event), the Company
now owns varying interests in an additional 1,042 miles of natural gas gathering and transmission pipelines (with
an aggregate gross capacity of over 1.0 Bcfd) and related facilities. The cost of the acquisition was
approximately $226 million. The Acadian acquisition:
o gives the Company an extensive intrastate natural gas pipeline system with access to both supply and
markets;
o positions the Company to compete for incremental natural gas supplies from new discoveries onshore, the
offshore Louisiana continental shelf and Gulf of Mexico deepwater developments;
o enables the Company to compete for growing industrial and petrochemical demand (including new gas-fired
power generation projects); and
o allows for additional natural gas processing opportunities.
The acquisition of these natural gas businesses from EPE and Shell represents a strategic investment for
the Company. Management believes that these assets have attractive growth attributes given the expected
long-term increase in natural gas demand for industrial and power generation uses. In addition, these assets
extend the Company's midstream energy service relationship with long-term NGL customers (producers, petrochemical
suppliers and refineries) and provide opportunities for enhanced services to customers as well as generating
additional fee-based cash flows.
The Company's operating margins are primarily derived from services provided to its tolling customers
and from merchant activities. In its tolling operations, the Company is paid a fee based on volumes processed,
transported, stored or handled. The Company generally does not take title to products as part of its tolling
operations; however, in those instances where title to products does transfer to the Company, the Company matches
the timing and purchase price of the products with those of the sale of the products so as to reduce or eliminate
exposure to fluctuations in commodity prices. Examples of the Company's tolling operations include the Gulf of
Mexico natural gas pipelines, NGL fractionation services, isomerization tolling arrangements, propylene
fractionation, liquids pipeline transportation services and fee-based marketing services.
In its merchant activities, the Company is exposed to fluctuations in commodity prices. In the
Company's isobutane merchant business (and to a certain extent its propylene fractionation activities), the
Company takes title to feedstock products and sells processed end products. The Company's profitability from
this type merchant activity is dependent upon the prices of feedstocks and end products, which may vary on a
seasonal basis. In order to limit the exposure to commodity price fluctuations in these business areas, the
company attempts to match the timing and price of its feedstock purchases with those of the sales of end
products. Operating margins from the company's natural gas processing (and related merchant businesses) are
generally derived from the price spread earned on the sale of purity NGL products extracted from natural gas
stream. To the extent the Company takes title to the NGLs removed from the natural gas stream and reimburses the
producer for the reduction in the Btu content and/or the natural gas used as fuel (the "PTR" or "shrinkage"), the
Company's operating margins are affected by the prices of NGLs and natural gas. The Company uses commodity
financial instruments to reduce its exposure to the change in the prices of NGLs and natural gas.
Current Business Environment
The first quarter of 2001 was a challenging quarter for the natural gas processing and NGL industry.
In the gas processing business, with natural gas prices approaching record high levels of $10 per MMBtu early in
the quarter, natural gas processing plants industry-wide operated at significantly reduced extraction rates or
temporarily shutdown. In the case of a natural gas processing plant, high natural gas prices may result in the
cost of fuel and shrinkage exceeding the value of the NGLs extracted. As a result of the high natural gas
prices encountered in January 2001, the Company, along with other participants in the natural gas processing
industry, elected to minimize their recovery of NGLs or, in some instances, to bypass the natural gas streams
around gas processing plants altogether. As a result of minimal or no NGL extraction, natural gas volumes
Page 20
downstream of the processing plants became higher in NGL content than allowed by pipeline specifications. The
natural gas pipeline operators responded by issuing operational flow orders that threatened to shut-in some of
the rich natural gas from the deepwater developments unless the NGL content of these natural gas streams was
reduced to lower levels. In order to meet the specifications of the natural gas pipeline operators, the Company
and producers negotiated interim reductions in fuel and shrinkage costs to levels that were significantly below
the prevailing cost of natural gas. With these interim provisions in place, the Company's gas processing plants
increased NGL extraction rates with the objective to lower the NGL content of the natural gas stream to a level
satisfactory to the pipeline operators.
Overall, equity NGL production rates at the Company's natural gas processing facilities declined to 46
MBPD in the first quarter of 2001 compared with 72 MBPD during the fourth quarter of 2000. The decrease in the
Company's equity NGL production combined with reduced extraction rates at (or the temporary shutdown of)
third-party natural gas processing facilities led to a decline in NGL volumes available for fractionation and/or
transportation at the Company's other facilities and pipelines. This situation, however, also created regional
shortages of NGLs, especially propane, which resulted in large regional pricing differences. This provided the
Company with opportunities to serve these supply-short markets through the sale of inventory by its merchant
businesses. As natural gas prices have begun to normalize, equity NGL production rates at the Company's
facilities have returned to the 60 MBPD to 65 MBPD range. The Company expects NGL fractionation and
transportation volumes to rebound as NGL production throughout the industry improves in response to moderating
fuel costs.
Management anticipates that the demand for its commercial isomerization services will strengthen in the
coming quarter as refiners increase production of both alkylates and MTBE for gasoline blending. In addition,
the Company is utilizing its spare capacity to take advantage of interim favorable pricing spreads between normal
butane and isobutane. The market for MTBE is expected to be strong in the second quarter of 2001 as gasoline
refiners increase the production of cleaner-burning fuels for the upcoming summer driving season. To illustrate,
MTBE prices have increased from approximately $1.13 per gallon in January 2001 to over $1.50 per gallon in April
2001.
The following table illustrates selected average quarterly prices for natural gas, crude oil, selected
NGL products and polymer grade propylene since the first quarter of 1999:
Polymer
Natural Normal Grade
Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene,
$/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound
-----------------------------------------------------------------------------------------
(a) (b) (c) (c) (c) (c) (c)
Fiscal 1999:
First quarter $1.70 $13.05 $0.20 $0.24 $0.29 $0.31 $0.12
Second quarter $2.12 $17.66 $0.27 $0.31 $0.37 $0.38 $0.13
Third quarter $2.56 $21.74 $0.34 $0.42 $0.49 $0.49 $0.16
Fourth quarter $2.52 $24.54 $0.30 $0.41 $0.52 $0.52 $0.19
Fiscal 2000:
First quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21
Second quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26
Third quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26
Fourth quarter $5.22 $31.98 $0.49 $0.67 $0.75 $0.73 $0.24
Fiscal 2001:
First quarter $7.00 $28.81 $0.43 $0.55 $0.63 $0.69 $0.23
(c)
- -------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL and polymer grade propylene prices represent an average of index prices
(b) Crude Oil price is representative of West Texas Intermediate
(c) Natural gas prices averaged $9.87 per MMBtu for January, $6.17 per MMBtu for February
and $4.96 per MMBtu for March.
Page 21
Results of Operation of the Company
The Company has five reportable operating segments: Fractionation, Pipeline, Processing, Octane
Enhancement and Other. Fractionation includes NGL fractionation, butane isomerization (converting normal butane
into high purity isobutane) and polymer grade propylene fractionation services. Pipeline consists of pipeline,
storage and import/export terminal services. Processing includes the natural gas processing business and its
related NGL merchant activities. Octane Enhancement represents the Company's 33.3% ownership interest in a
facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating
segment consists of fee-based marketing services and other plant support functions.
The management of the Company evaluates segment performance on the basis of gross operating margin
("gross operating margin" or "margin"). Gross operating margin reported for each segment represents operating
income before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the
sale of assets and selling, general and administrative expenses. In addition, segment gross operating margin is
exclusive of interest expense, interest income (from unconsolidated affiliates or others), dividend income from
unconsolidated affiliates, minority interest, extraordinary charges and other income and expense transactions.
The Company's equity earnings from unconsolidated affiliates are included in segment gross operating margin.
The Company's gross operating margin by segment (in thousands of dollars) along with a reconciliation to
consolidated operating income for the quarters ended March 31, 2001 and 2000 were as follows:
For the Quarter Ended
March 31,
-----------------------------------
2001 2000
-----------------------------------
Gross Operating Margin by segment:
Fractionation $25,668 $34,331
Pipeline 18,123 14,635
Processing 28,398 39,554
Octane enhancement 169 2,505
Other 535 554
-----------------------------------
Gross Operating margin total 72,893 91,579
Depreciation and amortization 10,029 8,124
Retained lease expense, net 2,660 2,637
Gain on sale of assets (381) -
Selling, general and administrative expenses 6,168 5,384
-----------------------------------
Consolidated operating income $54,417 $75,434
===================================
Page 22
The Company's significant production and other volumetric data (on a net basis) for the quarters ended
March 31, 2001 and 2000 were as follows:
For the Quarter Ended
March 31,
2001 2000
------------------------------------
MBPD, Net
- ---------
Equity NGL Production 46 71
NGL Fractionation 165 218
Isomerization 70 67
Propylene Fractionation 30 30
Octane Enhancement 3 4
Major NGL and Petrochemical Pipelines 356 374
Mdth/D, Net (a)
- ---------------
Natural Gas Pipelines 506 n/a
(a) Throughput on the Company's natural gas pipeline systems is measured in thousands of
decatherms per day (Mdth/D), a commercial unit of measure used in the natural gas industry.
Recent Acquisitions
The Company has recently completed the acquisition of the following Louisiana-based natural gas pipeline
systems:
o Acadian Gas, LLC ("Acadian");
o Stingray Pipeline Company, LLC ("Stingray") and West Cameron Dehydration, LLC ("West Cameron"); and
o Sailfish Pipeline Company, LLC ("Sailfish") and Moray Pipeline Company, LLC ("Moray").
Acadian. On April 2, 2001, the Company announced that it had completed the purchase of Acadian from
Shell US Gas and Power LLC, an affiliate of Shell, for $226 million in cash, inclusive of working capital. The
acquisition of Acadian integrates its natural gas pipeline systems in South Louisiana with the Company's Gulf
Coast natural gas processing and NGL fractionation, pipeline and storage system. The Acadian acquisition gives
the Company an extensive intrastate natural gas pipeline system with access to both supply and markets; positions
the Company to compete for incremental natural gas supplies from new discoveries onshore, the offshore Louisiana
continental shelf and Gulf of Mexico deepwater developments; enables the Company to take advantage of growing
industrial and petrochemical demand (including new gas-fired power generation projects) along with additional
natural gas processing opportunities.
Acadian's assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural
gas pipeline systems, which together have over one billion cubic feet ("Bcf") per day of capacity. These natural
gas pipeline systems are wholly-owned by Acadian with the exception of the Evangeline system in which Acadian
holds an approximate 49.5% economic interest. The system includes a leased natural gas storage facility at
Napoleonville, Louisiana.
Stingray, West Cameron, Sailfish and Moray (collectively, the "El Paso acquisition"). On January 29,
2001, Starfish Pipeline Company LLC, a 50/50 joint venture between the Company and Shell, completed the purchase
of the Stingray natural gas pipeline system, West Cameron dehydration facility and certain offshore Louisiana
lateral pipelines from EPE. The Company's share of the cash purchase price of these assets was $25.1 million.
In addition, the Company purchased 100% of the membership interests of Sailfish and Moray from EPE for
approximately $88.1 million in cash. Sailfish owns 25.67% of the Manta Ray Offshore Gathering Company, LLC
("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") through its ownership interests in Ocean Breeze
Pipeline Company LLC and Neptune Pipeline Company LLC. Moray holds a 33.92% interest in the Nemo Gathering
Page 23
Company, LLC ("Nemo"). The cash payments made to EPE for these acquisitions are subject to certain post-closing
adjustments expected to be finalized in the second quarter of 2001.
Collectively, the Company acquired interests in four natural gas gathering and transmission pipeline
systems in the Gulf of Mexico totaling approximately 725 miles of pipeline with an aggregate gross capacity of
2.85 Bcfd. These pipelines and their associated assets are strategically located to serve continental shelf and
deepwater developments in the central Gulf of Mexico. As with the Acadian acquisition, the El Paso acquisition
broadens the Company's midstream business by providing additional services to customers, and it benefits from
increased natural gas production from deepwater Gulf of Mexico development. Management believes that the
assets acquired from EPE complement and integrate well with those of the Acadian acquisition.
Stingray owns a 375-mile FERC-regulated two phase natural gas pipeline system that transports natural
gas and injected condensate from the High Island, West Cameron, East Cameron, Vermillion and Garden Banks areas
in the Gulf of Mexico to onshore transmission systems at Holly Beach and Cameron Parish, Louisiana. West Cameron
is an unregulated dehydration facility located at and connected to the onshore terminal of Stingray in south
Louisiana. Shell is the operator of the Stingray and West Cameron facilities.
Manta Ray (which is jointly owned by Sailfish, Shell and Marathon Gas Transmission Company Inc.) owns
225 miles of unregulated natural gas transmission lines primarily located on the outer continental shelf offshore
Louisiana. Nautilus (which is owned by Sailfish, Shell and Marathon Gas Transmission Company Inc.) owns 101
miles of FERC-regulated natural gas pipelines and related facilities extending from points offshore Louisiana to
interconnecting pipelines near the Garden City and Neptune gas processing facilities. Nemo (which is jointly
owned by Moray and Shell) is a development stage enterprise that is constructing and will operate an offshore
Louisiana natural gas gathering pipeline and related facilities that will connect certain Shell offshore platform
assets to Manta Ray. Management believes that these assets have a significant upside potential, since Shell and
Marathon have dedicated production from over 1,000 square miles of offshore natural gas leases to these systems
and only a small portion of this total has been developed to date. Shell is the operator of the Manta Ray,
Nautilus and Nemo systems.
Equistar storage facility. In addition to the natural gas pipeline acquisitions, the Company announced
on February 1, 2001 that it had acquired a NGL storage facility from Equistar Chemicals, LP for approximately
$3.4 million. The salt dome storage cavern, which is located near the Company's Mont Belvieu, Texas complex,
has a capacity of one million barrels. The purchase also includes adjacent acreage which would support the
development of additional storage capacity.
Three Months Ended March 31, 2001 compared with Three Months Ended March 31, 2000
Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 11% to $838.3
million in 2001 compared to $753.7 million in 2000. The Company's operating costs and expenses increased by
16% to $777.7 million in 2001 versus $672.9 million in 2000. Operating income decreased 28% to $54.4 million in
2001 from $75.4 million in 2000. The principal factors behind the decrease in operating income were lower
volumes and higher energy costs both of which were related to the increase in natural gas prices.
Fractionation. The Company's gross operating margin for the Fractionation segment decreased to $25.7
million in 2001 from $34.3 million in 2000. NGL fractionation margin for the first quarter of 2001 decreased
$10.4 million compared to 2000 due to lower volumes and higher energy costs. NGL fractionation net volumes
decreased to 165 MBPD in 2001 from 218 MBPD in 2000 as a result of lower extraction rates at gas processing
facilities in 2001 versus 2000 when the industry was maximizing NGL production. For the first quarter of 2001,
gross operating margin from isomerization services increased $4.5 million compared to 2000 primarily due to an
increase in volumes and toll processing fees. Isomerization volumes increased to 70 MBPD during the first
quarter of 2001 versus 67 MBPD during the same period in 2000 due to solid demand for the Company's services.
Gross operating margin for the first quarter of 2001 from propylene fractionation decreased $2.3 million compared
to the first quarter of 2000 primarily due to higher energy costs and moderating prices. Net propylene
fractionation volumes were 30 MBPD for both periods.
Page 24
Pipeline. The Company's gross operating margin for the Pipeline segment was $18.1 million in the first
quarter of 2001 compared to $14.6 million in 2000. The improvement in gross margin was due to strong demand for
transportation services on the Lou-Tex NGL Pipeline, which was operational for the entire first quarter of 2001;
increased demand and a larger ownership interest in the Dixie propane pipeline and the January 29, 2001
acquisition of interests in four Gulf of Mexico offshore Louisiana natural gas pipeline systems from EPE. Net
liquids throughput on the Company's major NGL and petrochemical pipeline systems averaged 356 MBPD for the first
quarter of 2001 compared to 374 MBPD for the first quarter of 2000. Net natural gas throughput for the recently
acquired natural gas pipelines was 506 thousand decatherms per day ("Mdth/D").
Processing. For the first quarter of 2001, the Processing segment generated gross operating margin of
$28.4 million compared to $39.6 million in 2000. The Processing segment includes the Company's natural gas
processing business and related merchant activities. The Company's equity NGL production was 46 MBPD for the
current quarter versus 71 MBPD for the same period in 2000. As mentioned previously under Current Business
Environment, higher natural gas prices caused the Company and other participants in the processing industry to
minimize recoveries of NGLs for most of the first quarter of 2001 versus the first quarter of 2000 when NGL
recoveries were maximized. This situation, however, also created regional shortages of NGLs, especially
propane, which resulted in large regional pricing differences. This provided the Company with opportunities to
serve these supply-short markets through the sale of inventory by its merchant business. Lastly, gross
operating margin for this segment includes approximately $13.5 million of non-cash mark-to-market gains related
to the Company's natural gas and NGL hedging activities. See Note 8 of the Notes to Consolidated Financial
Statements for further information regarding the Company's use of commodity financial instruments.
Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $2.3 million
in the first quarter of 2001 compared with 2000 levels. The decline is attributable to a maintenance outage
which began in early December 2000 and lasted until February 2001. MTBE production, on a net basis, was 3 MBPD
in 2001 compared to 4 MBPD during the first quarter of 2000.
Selling, general and administrative expenses ("SG and A"). SG and A expenses increased $0.8 million in the
first quarter of 2001 compared to the first quarter of 2000. The increase is attributable to a slight rise in
the administrative services fee charged by EPCO versus year-ago levels and the costs associated with the
additional staff and resources deemed necessary to support the Company's ongoing expansion activities resulting
from acquisitions and other business development.
Liquidity and Capital Resources
General. The Company's primary cash requirements, in addition to normal operating expenses and debt
service, are for capital expenditures (both maintenance and expansion-related), business acquisitions and
distributions to the partners. The Company expects to fund its short-term needs for such items as maintenance
capital expenditures and quarterly distributions to the partners from operating cash flows. Capital expenditures
for long-term needs resulting from future expansion projects and business acquisitions are expected to be funded
by a variety of sources including (either separately or in combination) cash flows from operating activities,
borrowings under bank credit facilities and the issuance of additional Common Units and public debt. The
Company's debt service requirements are expected to be funded by operating cash flows or refinancing arrangements.
As noted above, certain of the Company's liquidity and capital resource requirements are met using
borrowings under bank credit facilities and/or the issuance of additional Common Units or public debt (separately
or in combination). As of March 31, 2001, availability under the Company's revolving bank credit facilities
was $400 million (which may be increased to $500 million under certain conditions). In addition to the existing
revolving bank credit facilities, a subsidiary of the Company issued $450 million of public debt in January 2001
(the "$450 Million Senior Notes") using the remaining shelf availability under its $800 million December 1999
universal shelf registration (the "December 1999 Registration Statement"). The proceeds from this offering were
used to acquire the Acadian and EPE natural gas pipeline systems for $339.2 million (with $226 million of this
amount paid in April 2001 for Acadian) and to finance the cost to construct certain NGL pipelines and related
projects and for working capital and other general partnership purposes. On February 23, 2001, the Company filed
a $500 million universal shelf registration (the "February 2001 Registration Statement") covering the issuance of
Page 25
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
acquisition.
If deemed necessary, management believes that additional financing arrangements can be obtained at
reasonable terms. Management believes that maintenance of the Company's investment grade credit ratings
(currently, Baa3 by Moody's Investor Service and BBB by Standard and Poors) combined with a continued ready
access to debt and equity capital at reasonable rates and sufficient trade credit to operate its businesses
efficiently are a solid foundation to providing the Company with ample resources to meet its long and short-term
liquidity and capital resource requirements.
Operating, Investing and Financing Cash Flows for the three months ended March 31, 2001 and 2000. Cash
flows from operating activities were a $48.7 million inflow for 2001 compared to a $86.8 million inflow in 2000.
Cash flows from operating activities primarily reflect the effects of net income, depreciation and amortization,
extraordinary items, equity income and distributions from unconsolidated affiliates, fluctuations in fair values
of financial instruments and changes in working capital. Net income decreased in 2001 from 2000 levels due to reasons
mentioned previously under "Results of Operation of the Company." Depreciation and amortization increased a combined
$1.7 million in 2001 over 2000 primarily the result of additional capital expenditures and acquisitions. The Company
received $8.9 million in distributions from its equity method investments in 2001 compared to $7.1 million in 2000.
Of the $1.8 million increase in distributions, $1.5 million is attributable to the natural gas pipeline assets
purchased from EPE in January 2001. Operating cash flow for 2001 also includes an adjustment for the $16.4 million
in non-cash mark-to-market gains related to natural gas, NGL and interest rate hedging activities. The net effect
of changes in operating accounts from year to year is generally the result of timing of NGL sales and purchases
near the end of the period.
Cash used for investing activities was $137.9 million in 2001 compared to $114.1 million in 2000. Cash
outflows included capital expenditures of $25.3 million in 2001 versus $111.4 million in 2000. Capital
expenditures for the first quarter of 2000 included $99.5 million for the purchase of the Lou-Tex Propylene
Pipeline and related assets. In addition, capital expenditures include maintenance capital project costs of
$1.0 million in 2001 and $0.3 million in 2000. The 2000 period includes $3.3 million in cash receipts related
to the Company's participation in the BEF note, which was extinguished in May 2000 with BEF's final principal
payment. Investing cash outflows in 2001 includes $113.1 million in advances to and investments in
unconsolidated affiliates compared to $6.0 million in 2000. The increase is due to purchase of the natural gas
pipeline systems from EPE in January 2001.
Cash receipts from financing activities were $408.2 million during the first quarter of 2001 compared
to $72.2 million during the same period in 2000. Cash flows from financing activities are primarily affected by
repayments of debt, borrowings under debt agreements and distributions to partners. The 2001 period includes
proceeds from the $450 Million Senior Notes issued in January 2001 whereas the 2000 period includes proceeds from
the $350 Million Senior Notes and the $54 Million MBFC Loan and the associated repayments on various bank credit
facilities. Distributions to partners and the minority interest increased to $38.4 million in 2001 from $34.2
million in 2000 primarily due to an increase in the quarterly distribution rate.
The Company is exposed to various market risks including commodity price risk (through its gas
processing and related NGL businesses) and interest rate risk. These risks may entail significant cash outlays
in the future that are not offset by their underlying hedged positions. For a complete description of the
Company's risk management policies and potential exposures, see "Item 3. Quantitative and Qualitative
Disclosures about Market Risk" on page 28 of this Form 10-Q report and Note 8 of the Notes to Consolidated
Financial Statements.
Future Capital Expenditures. The Company estimates that its share of currently approved capital
expenditures in the projects of its unconsolidated affiliates will be approximately $7.0 million for the
remainder of 2001. In addition, the Company forecasts that $118.7 million will be spent during the remainder
Page 26
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).
As of March 31, 2001, the Company had $9.6 million in outstanding purchase commitments attributable to
its capital projects. Of this amount, $7.1 million is related to the construction of assets that will be
recorded as property, plant and equipment and $2.5 million is associated with capital projects which will be
recorded as additional investments in unconsolidated affiliates.
New Texas environmental regulations may necessitate extensive redesign and modification of the Company's
Mont Belvieu facilities to achieve the air emissions reductions needed for federal Clean Air Act compliance in
the Houston-Galveston area. Until litigation challenging these regulations is resolved, the technology to be
employed and the cost for modifying the facilities to achieve enough reductions cannot be determined, and capital
funds have not been budgeted for such work. Regardless of the outcome of this litigation, expenditures for
emissions reduction projects will be spread over several years, and management believes the Company will have
adequate liquidity and capital resources to undertake them. For additional information about this litigation,
see the discussion under the topic Clean Air Act--General on page 22 of the Company's Form 10-K for fiscal 2000.
Long-term Debt. Long-term debt consisted of the following at:
March 31, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 $350,000 $350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
---------------------------------------
Total principal amount 854,000 404,000
Increase in fair value related to hedging a portion of fixed-rate debt 2,196
Less unamortized discount on:
$350 Million Senior Notes (144) (153)
$450 Million Senior Notes (279)
Less current maturities of long-term debt - -
---------------------------------------
Long-term debt $855,773 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility and $150
Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit
facilities at March 31, 2001 or December 31, 2000.
At March 31, 2001, the Company had a total of $75 million of standby letters of credit available under
its $250 Million Multi-Year Credit Facility of which $54.1 million was outstanding.
On January 24, 2001, a subsidiary of the Company completed a public offering of $450 million in
principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per
Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting discounts and
commissions, of approximately $446.8 million. The proceeds from this offering were used to acquire the Acadian
and EPE natural gas pipeline systems for $339.2 million and to finance the cost to construct certain NGL
pipelines and related projects and for working capital and other general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is
also applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As
with the $350 Million Senior Notes, the $450 Million Senior Notes are:
o subject to a make-whole redemption right;
o an unsecured obligation and rank equally with existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness; and,
o guaranteed by the Company through an unsecured and unsubordinated guarantee.
Page 27
The Company was in compliance with the restrictive covenants associated with the $350 Million and $450 Million
Senior Notes at March 31, 2001.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 Registration
Statement; therefore, the amount of securities available under this universal shelf registration statement was
reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement
(the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt
securities or a combination thereof. The Company expects to use the net proceeds from any sale of securities
under the February 2001 Registration Statement for future business acquisitions and other general corporate
purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the
repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be
applied to partnership purposes will depend on a number of factors, including the Company's funding requirements
and the availability of alternative funding sources. The Company routinely reviews acquisition opportunities.
Upon adoption of Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for
Derivative Instruments and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company
recorded a $2.3 million non-cash increase in the fair value of its fixed-rate debt. SFAS 133 required that the
Company's interest rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption
of the standard. After adoption of the standard, the interest rate swaps were dedesignated due to differences
in the estimated maturity dates of the interest rate swaps versus the fixed-rate debt. As a result, the fair
value of the hedged fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million
increase in the fair value of the debt will be amortized to earnings over the remaining life of the fixed-rate
debt to which it applies, which approximates 10 years. See Note 4 and Note 8 of the Notes to Unaudited
Consolidated Financial Statements for additional information regarding interest rate swaps and the associated
change in the fair value of the fixed-rate debt.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to financial market risks, including changes in commodity prices in its natural
gas and NGL businesses and in interest rates with respect to a portion of its debt obligations . The Company may
use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar
characteristics) to mitigate these risks. The Company generally does not use financial instruments for
speculative (or trading) purposes.
Commodity Price Risk
The Company is exposed to commodity price risk through its natural gas and related NGL businesses. In
order to effectively manage this risk, the Company may enter into swaps, forwards, commodity futures, options and
other commodity financial instruments with similar characteristics that are permitted by contract or business
custom to be settled in cash or with another financial instrument. The purpose of these risk management
activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm
commitments and certain anticipated transactions.
The Company has adopted a commercial policy to manage its exposure to the risks generated by its gas
processing and related NGL and natural gas businesses. The objective of this policy is to assist the Company in
achieving its profitability goals while maintaining a portfolio of conservative risk, defined as remaining within
the position limits established by the General Partner. The Company will enter into risk management transactions
to manage price risk, basis risk, physical risk, or other risks related to the energy commodities on both a
short-term (less than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the
strategies of the Company associated with physical and financial risks, approves specific activities of the
Company subject to the policy (including authorized products, instruments and markets) and establishes specific
guidelines and procedures for implementing and ensuring compliance with the policy.
The following table presents the hypothetical changes in fair values arising from immediate selected
potential changes in the quoted market prices of the Company's commodity financial instruments outstanding at the
Page 28
dates noted within the table. The sensitivity analysis model used to estimate the fair values of the commodity
financial instruments takes into account the following primary factors/assumptions:
o the current quoted market cost of natural gas;
o the current quoted market cost of related NGL production;
o changes in the composition of commodities hedged (i.e., the mix between natural gas and related NGL
hedges outstanding);
o fluctuations in the overall volume of commodities hedged (for both natural gas and related NGL hedges
outstanding);
o market interest rates, which are used in determining the present value; and,
o a liquid market for such financial instruments.
An increase in fair value of the commodity financial instruments (based upon the assumptions noted
above) approximates the gain that would be recognized in earnings if all of the commodity financial instruments
were settled at the respective balance sheet dates. Conversely, a decrease in fair value of the commodity
financial instruments would result in the recording of a loss at the respective balance sheet date. To the
extent the commodity financial instruments are effective in hedging their associated commodity positions, the
gain or loss recognized on these commodity financial instruments would be offset by a corresponding gain or loss
on the hedged commodity positions, which are not included in the table below. The gains or losses resulting
from these hedging activities are a component of the Company's operating costs and expenses as reflected in its
Statements of Consolidated Operations.
Asset (liability) Impact of a 10% increase Impact of a 10% decrease
Estimated in quoted market prices in quoted market prices
Fair Value at date Increase (Decrease) Increase(Decrease)
indicated assuming Asset(liability) in Fair Value Asset(liability) in Fair Value
no change in Adjusted estimate due to increase in Adjusted estimate due to decrease in
quoted market prices of Fair Value quoted market prices of Fair Value quoted market prices
Estimated impact of changes
in quoted market prices on
commodity financial
instruments at:
(in millions of dollars)
December 31,2000 (38.6) (56.3) (17.7) (20.9) 17.7
March 31,2001 (4.6) (26.1) (21.5) 16.5 21.1
May 9,2001 24.0 8.3 (15.7) 39.7 15.7
The fair value of the commodity financial instruments at December 31, 2000 was estimated at $38.6
million payable. On March 31, 2001, the fair value of the commodity financial instruments outstanding was
estimated at $4.6 million payable. The change in fair value between December 31, and March 31, 2001 was
primarily due to the settlement of certain open positions, lower natural gas prices and a change in the
composition of commodities hedged. By May 9, 2001, the fair value of the commodity financial instruments was a
receivable position primarily due to a further decline in natural gas prices.
The Company's commodity financial instruments may not qualify for hedge accounting treatment under the
specific guidelines of SFAS 133, as amended and interpreted. The Company continues to refer to these commodity
financial instruments as hedges in as much as this was the intent when such contracts were executed. This
characterization is consistent with the actual economic performance of these financial instruments and the
Company expects such commodity financial instruments to continue to mitigate commodity price risk in the
future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS
133. As such, if these commodity financial instruments do not qualify for hedge accounting treatment under the
specific guidelines of SFAS 133, the change in fair value of these instruments will be reflected on the balance
sheet and in earnings using mark-to-market accounting. For additional information regarding the commodity
financial instruments, see Note 8 of the Notes to Consolidated Financial Statements that are part of this Form
10-Q quarterly report.
Page 29
Interest rate risk
Variable-rate Debt. At March 31, 2001 and 2000, the Company had no financial instruments in place to
cover any potential interest rate risk on its variable-rate debt obligations. Variable-rate debt obligations do
expose the Company to possible increases in interest expense and decreases in earnings if interest rates were to
rise. At March 31, 2001 and 2000, the Company had no variable-rate debt outstanding.
Fixed-rate Debt. In March 2000, the Company entered into interest rate swaps whereby the fixed-rate of
interest on a portion of the $350 Million Senior Notes and the $54 Million MBFC Loan was effectively swapped for
floating-rates tied to the six month London Interbank Offering Rate ("LIBOR"). The objective of holding
interest rate swaps is to manage debt service costs by effectively converting a portion of the fixed-rate debt
into variable-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the
notional amount while the other party pays a floating-rate based on the notional amount. Management believes
that it is prudent to maintain a balance between variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate
exposure that impact future cash flows any by evaluating hedging opportunities. The Company uses analytical
techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to
estimate the expected impact of changes in interest rates on the Company's future cash flows. The General
Partner oversees the strategies of the Company associated with financial risks and approves instruments that are
appropriate for the Company's requirements.
The following table presents the hypothetical changes in fair values arising from immediate selected
potential changes in quoted market prices of the Company's interest rate swaps outstanding at the dates noted
within the table. The sensitivity analysis model used to estimate the fair values of the interest rate swaps
takes into account the following primary factors/assumptions: (a) current market interest rates (including
forward LIBOR rates and current federal funds rate), (b) early termination options exercisable by the
counterparty (if the fair value of the swap indicates a receivable) and (c) a liquid market for interest rate
swaps. An increase in fair value of the interest rate swaps approximates the gain that would be recognized in
earnings if all of the interest rate swaps were settled at the respective balance sheet dates. Conversely, a
decrease in fair value of the interest rate swaps would result in the recording of a loss at the respective
balance sheet date. The gains or losses resulting from the interest rate hedging activities are a component of
the Company's interest expense as reflected in its Statements of Consolidated Operations.
Asset (liability) Impact of a 10% increase Impact of a 10% decrease
Estimated in quoted market prices in quoted market prices
Fair Value at date Increase (Decrease) Increase(Decrease)
indicated assuming Asset(liability) in Fair Value Asset(liability) in Fair Value
no change in Adjusted estimate due to increase in Adjusted estimate due to decrease in
quoted market prices of Fair Value quoted market prices of Fair Value quoted market prices
Estimated impact of changes
in quoted market prices on
interest rate swaps at:
(in millions of dollars)
December 31,2000 2.5 1.9 (0.6) 3.1 0.6
March 31,2001 7.1 5.8 (1.3) 8.4 1.3
May 9,2001 7.6 6.4 (1.2) 8.9 1.3
The interest rate swaps outstanding at December 31, 2000 reflected a notional amount of $154 million of
fixed-rate debt with the fair value of swaps estimated at $2.5 million. At March 31, 2001, the notional amount
was reduced to $104 million due to the early termination of one of the swaps by a counterparty with the aggregate
fair value of the remaining swaps estimated at $7.1 million. The change in fair value between December 31, 2000
and March 31, 2001 is primarily related to the decision by one counterparty not to exercise its early termination
right and lower interest rates. At May 9, 2001, the fair value of the interest rate swaps was estimated at $7.6
million. The change in fair value between March 31, 2001 and May 9, 2001 is attributable to slightly lower
interest rates.
Page 30
The Company's interest rate swap agreements were dedesignated for being accounted for as hedging
instruments after adoption of SFAS 133; therefore, the interest rate swap agreements are accounted for on a
mark-to-market basis. However, these financial instruments continue to be effective in achieving the risk
management activities for which they were intended. As a result, the change in fair value of these instruments
will be reflected on the balance sheet and in earnings (as an offset to interest expense) using mark-to-market
accounting. For additional information regarding the interest rate swaps, see Note 8 of the Notes to
Consolidated Financial Statements that are part of this Form 10-Q quarterly report.
Other. At March 31, 2001 and December 31, 2000, the Company had $379.4 million and $60.4 million
invested in cash and cash equivalents, respectively. All cash equivalent investments other than cash are highly
liquid, have original maturities of less than three months, and are considered to have insignificant interest
rate risk.
Due to the complexity of SFAS 133, the Financial Accounting Standards Board ("FASB") organized a formal
committee, the Derivatives Implementation Group ("DIG"), to provide ongoing recommendations to the FASB about
implementation issues. Implementation guidance issued through the DIG process is still continuing; therefore,
the initial conclusions reached by the Company concerning the application of SFAS 133 upon adoption may be
altered. As a result, additional SFAS 133 transition adjustments may be recorded in future periods as the
Company adopts new DIG interpretations approved by the FASB.
PART II. OTHER INFORMATION
Item 2. Use of Proceeds
The following table shows the Use of Proceeds from the $450 Million Senior Notes offering completed on
January 29, 2001. The $450 Million Senior Notes represented a takedown of the remaining shelf availability
under the Company's December 1999 Registration Statement filed with the Securities and Exchange Commission (File
Nos. 333-93239 and 333-93239-01, effective January 14, 2000).
The title of the registered debt securities was "7.50% Senior Notes Due 2011." The underwriters of the
offering were Goldman, Sachs & Co., Salomon Smith Barney Inc., Banc One Capital Markets, Inc., First Union
Securities, Inc., Scotia Capital (USA) Inc. and Tokyo-Mitsubishi International plc. The 10-year Senior Notes
have a maturity date of February 1, 2011 and bear a fixed-rate interest coupon of 7.50%.
Amounts
(in millions)
--------------
Proceeds:
Sale of $450 Million Senior Notes to public at 99.937% per Note $450
Less underwriting discount of 0.650% per Note (3)
--------------
Total proceeds $447
==============
Use of Proceeds:
To finance Acadian acquisition $(226)
To finance investment in various natural gas pipeline entities
purchased from EPE (113)
To finance remainder of the costs to construct certain NGL
pipelines and related projects, and for working capital
and other general Company purposes (108)
--------------
Total uses of funds $(447)
==============
The $226 million payment to Shell for Acadian was made in early April 2001. The $113 million in payments made to
EPE for the four natural gas pipeline systems were made in late January 2001.
Page 31
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 ad of
September 22, 2000. (Exhibit 10.1 to Form 8-K filed on September 26, 2000).
*3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P.
(Exhibit 3.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*3.2 Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "D"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*3.3 First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated
September 17, 1999. (Exhibit 99.8 on Form 8-K/A-1 filed October 27, 1999).
*3.4 Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Enterprise Products
Partners L.P. dated June 9, 2000. (Exhibit 3.6 to Form 10-Q filed August 11, 2000).
*4.1 Form of Common Unit certificate. (Exhibit 4.1 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 21, 1998).
*4.2 Unitholder Rights Agreement among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise
Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by
reference the above document included as Exhibit "C" to the Schedule 13D filed September 27, 1999 by
Tejas Energy, LLC.
*4.3 Contribution Agreement between Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise Products
Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise Products GP,
LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by reference the
above document included as Exhibit "B" to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*4.4 Registration Rights Agreement between Tejas Energy LLC and Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "E"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*4.5 Form of Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer,
Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee. (Exhibit
4.1 on Form 8-K filed March 10, 2000).
*4.6 Form of Global Note representing $350 million principal amount of 8.25% Senior Notes Due 2005.
(Exhibit 4.2 on Form 8-K filed March 10, 2000).
*4.7 $250 Million Multi-Year Revolving Credit Agreement among Enterprise Products Operating L.P., First Union
National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan
Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17,
2000. (Exhibit 4.2 on Form 8-K filed January 25, 2001).
*4.8 $150 Million 364-Day Revolving Credit Agreement between Enterprise Products Operating L.P. and First
Union National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase
Manhattan Bank, as syndication agent and the Several Banks from time to time parties thereto dated
November 17, 2000. (Exhibit 4.3 on Form 8-K filed January 25, 2001).
Page 32
*4.9 Guaranty Agreement (relating to the $250 Million Multi-Year Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001).
*4.10 Guaranty Agreement (relating to the $150 Million 364-Day Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001).
4.12 First Amendment to $250 million Multi-Year Revolving Credit Agreement dated April 19, 2001.
*4.11 Form of Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011. (Exhibit
4.1 to Form 8-K filed January 25, 2001).
*10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline Partnership, L.P., Chunchula Pipeline
Company, LLC, Propylene Pipeline Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise
Products Texas Operating L.P. dated June 1, 1998.(Exhibit 10.1 to Registration Statement on Form S-1/A,
File No: 333-52537, filed on July 8, 1998).
*10.2 Form of EPCO Agreement between Enterprise Products Partners L.P., Enterprise Products Operating
L.P., Enterprise Products GP, LLC and Enterprise Products Company. (Exhibit 10.2 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*10.3 Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company
dated June 1, 1998. (Exhibit 10.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on
July 8, 1998).
*10.4 Venture Participation Agreement between Sun Company, Inc. (R&M), Liquid Energy Corporation and
Enterprise Products Company dated May 1, 1992. (Exhibit 10.4 to Registration Statement on Form S-1,
File No. 333-52537, filed on May 13, 1998).
*10.5 Partnership Agreement between Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products
Company dated May 1, 1992. (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc.
(R&M) dated August 16, 1995. (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.7 Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules
Incorporated dated December 13, 1978. (Exhibit 10.9 to Registration Statement on Form S-1, File No.
333-52537, dated May 13, 1998).
*10.8 Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas
between Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin
Petroleum Company dated July 17, 1985. (Exhibit 10.10 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.9 Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities between Enterprise
Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum Company and
Mont Belvieu Associates dated July 17, 1985. (Exhibit 10.11 to Registration Statement on Form S-1/A,
File No. 333-52537, filed on July 8, 1998).
*10.10 Amendment to Propylene Facility and Pipeline Sales Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1993. (Exhibit 10.12 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
Page 33
*10.11 Amendment to Propylene Facility and Pipeline Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1995. (Exhibit 10.13 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.12 Fourth Amendment to Conveyance of Gas Processing Rights between Tejas Natural Gas Liquids, LLC and Shell
Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Deepwater Development
Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas Inc. dated August 1, 1999. (Exhibit
10.14 to Form 10-Q filed on November 15, 1999).
* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith
(b) Reports on Form 8-K
The following Form 8-K reports were filed during the quarter ending March 31, 2001:
8-K filed on January 25, 2001. On January 24, 2001, a subsidiary of the entered into an underwriting
agreement for the public offering by the of $450 million of 7.50% Senior Notes (the "$450 Million Senior Notes")
due in February 2011. The Senior Notes are unconditionally guaranteed by the Company. The closing and
issuance of the $450 Million Senior Notes occurred on January 29, 2001.
In addition, this current report was used to file as exhibits the documents relating to the $250 Million
Multi-Year Credit Facility and $150 Million 364-Day Credit Facility.
8-K filed on February 2, 2001. The Company published a press release relating to fourth quarter 2000
and fiscal 2000 earnings on January 30, 2001. The text of the release was filed as an exhibit to this current
report.
Page 34
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: May 14, 2001 Principal Accounting Officer