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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2002
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________.
Commission file numbers: 1-14323
333-93239-01
ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
(Exact name of registrants as specified in their charters)
Delaware 76-0568219
Delaware 76-0568220
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation of organization)
2727 North Loop West, Houston, Texas 77008-1037
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 880-6500
Indicate by check mark whether the registrants (1) have 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 registrants were required to file
such reports), and (2) have been subject to such filing requirements for the past 90 days.
YES [X] NO [ ]
Limited Partner interests (e.g. Common Units) of Enterprise Products Partners L.P. trade on the New York Stock Exchange under symbol
"EPD". As of May 14, 2002, 56,876,983 Common Units were outstanding. Enterprise Products Operating L.P. is owned 98.9899% by
Enterprise Products Partners L.P. and 1.0101% by the General Partner of both registrants, Enterprise Products GP, LLC. No common
equity securities of Enterprise Products Operating L.P. are publicly traded.
EXPLANATORY NOTE
This report constitutes a combined report for Enterprise Products Partners L.P. (the "Company")(Commission File No. 1-14323) and its
98.9899% owned subsidiary, Enterprise Products Operating L.P. (the "Operating Partnership")(Commission File No. 33-93239-01). Since
the Operating Partnership owns substantially all of the Company's consolidated assets and conducts substantially all of the Company's
business and operations, the information set forth herein, except for Part I, Item 1, constitutes combined information for the
Company and the Operating Partnership. In accordance with Rule 3-10 of Regulation S-X, Part I, Item 1 contains separate financial
statements for the Company and the Operating Partnership.
ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
TABLE OF CONTENTS
Page No.
-----------
PART I
Glossary
Item 1. Financial Statements.
Item 1A. Enterprise Products Partners L.P. 1
Item 1B. Enterprise Products Operating L.P. 21
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 39
Item 3. Quantitative and Qualitative Disclosures about Market Risk. 55
PART II
Item 6. Exhibits and Reports on Form 8-K. 58
Signatures page 61
Glossary
The following abbreviations, acronyms or terms used in this Form 10-Q are defined below:
Acadian Gas Acadian Gas LLC and subsidiaries, acquired from Shell in April 2001
BBtu Billion British thermal units, a measure of heating value
BEF Belvieu Environmental Fuels, an equity investment of EPOLP
Belle Rose Belle Rose NGL Pipeline LLC, an equity investment of EPOLP
BPD Barrels per day
BRF Baton Rouge Fractionators LLC, an equity investment of EPOLP
BRPC Baton Rouge Propylene Concentrator, LLC, an equity investment of EPOLP
Company Enterprise Products Partners L.P. and its consolidated subsidiaries, including
the Operating Partnership
CPG Cents per gallon
Diamond-Koch Refers to affiliates of Valero Energy Corporation and Koch Industries, Inc.
Dixie Dixie Pipeline Company, an equity investment of EPOLP
EBITDA Earnings before interest, taxes, depreciation and amortization
EPCO Enterprise Products Company, an affiliate of the Company and our ultimate
parent company
EPIK EPIK Terminalling L.P. and EPIK Gas Liquids, LLC, collectively, an equity
investment of EPOLP
EPOLP Enterprise Products Operating L.P., the operating subsidiary of the Company
(also referred to as the "Operating Partnership")
EPU Earnings per Unit
FASB Financial Accounting Standards Board
GAAP Generally Accepted Accounting Principles of the United States of America
General Partner Enterprise Products GP, LLC, the general partner of the Company and the
Operating Partnership
HSC Denotes our Houston Ship Channel pipeline system
Kinder Morgan Kinder Morgan Operating LP "A"
La Porte La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively, an equity
investment of the Company
LIBOR London interbank offering rate
MBA acquisition Refers to the acquisition of Mont Belvieu Associates' remaining interest in the
Mont Belvieu NGL fractionation facility in 1999
MBFC Mississippi Business Finance Corporation
MBPD Thousand barrels per day
MMBtu/d Million British thermal units per day, a measure of heating value
MMBtus Million British thermal units, a measure of heating value
Mont Belvieu Mont Belvieu, Texas
Mont Belvieu III Refers to the propylene fractionation facility acquired from Diamond-Koch
MTBE Methyl tertiary butyl ether
NGL or NGLs Natural gas liquid(s)
NYSE New York Stock Exchange
Operating Partnership Enterprise Products Operating L.P. and its subsidiaries
OTC Olefins Terminal Corporation, an equity investment of the Company
Promix K/D/S Promix LLC, an equity investment of EPOLP
SEC U.S. Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards issued by the FASB
Shell Shell Oil Company, its subsidiaries and affiliates
TNGL acquisition Refers to the acquisition of Tejas Natural Gas Liquids, LLC, an affiliate of
Shell, in 1999
Tri-States Tri-States NGL Pipeline LLC, an equity investment of EPOLP
VESCO Venice Energy Services Company, LLC, a cost method investment of EPOLP
Wilprise Wilprise Pipeline Company, LLC, an equity investment of EPOLP
PART I. FINANCIAL INFORMATION.
Item 1A. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Dollars in thousands)
March 31,
2002 December 31,
ASSETS (unaudited) 2001
-------------------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of $14,521 at
March 31, 2002 and $5,752 at December 31, 2001) $ 44,553 $ 137,823
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $20,615 at March 31, 2002 and $20,642 at December 31, 2001 257,191 256,927
Accounts receivable - affiliates 2,490 4,375
Inventories 100,329 69,443
Prepaid and other current assets 44,943 50,207
-------------------------------------
Total current assets 449,506 518,775
Property, Plant and Equipment, Net 1,535,196 1,306,790
Investments in and Advances to Unconsolidated Affiliates 411,292 398,201
Intangible assets, net of accumulated amortization of $16,156 at
March 31, 2002 and $13,084 at December 31, 2001 252,142 202,226
Goodwill 81,135
Other Assets 6,991 5,201
-------------------------------------
Total $2,736,262 $2,431,193
=====================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of debt $50,000
Accounts payable - trade 59,294 $54,269
Accounts payable - affiliates 15,301 29,885
Accrued gas payables 258,550 233,536
Accrued expenses 15,979 22,460
Accrued interest 8,165 24,302
Other current liabilities 58,665 44,764
-------------------------------------
Total current liabilities 465,954 409,216
Long-Term Debt 1,168,596 855,278
Other Long-Term Liabilities 7,981 8,061
Minority Interest 11,120 11,716
Commitments and Contingencies
Partners' Equity
Common Units (51,319,915 Units outstanding at March 31, 2002
and 51,360,915 at December 31, 2001) 608,333 651,872
Subordinated Units (21,409,870 Units outstanding at March 31, 2002
and December 31, 2001) 174,973 193,107
Special Units (14,500,000 Units outstanding at March 31, 2002
and December 31, 2001) 296,634 296,634
Treasury Units acquired by Trust, at cost (204,600 Common Units
outstanding at March 31, 2002 and 163,600 at December 31, 2001) (8,237) (6,222)
General Partner 10,908 11,531
-------------------------------------
Total Partners' Equity 1,082,611 1,146,922
-------------------------------------
Total $2,736,262 $2,431,193
=====================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 1
Enterprise Products Partners L.P.
Statements of Consolidated Operations
(Dollars in thousands, except per Unit amounts)
(Unaudited)
Quarter Ended
March 31,
-------------------------------
2002 2001
-------------------------------
REVENUES
Revenues from consolidated operations $662,054 $836,315
Equity income in unconsolidated affiliates 9,227 2,011
-------------------------------
Total 671,281 838,326
COST AND EXPENSES
Operating costs and expenses 664,423 777,741
Selling, general and administrative 7,962 6,168
-------------------------------
Total 672,385 783,909
-------------------------------
OPERATING INCOME (LOSS) (1,104) 54,417
-------------------------------
OTHER INCOME (EXPENSE)
Interest expense (18,513) (6,987)
Interest income from unconsolidated affiliates 30 24
Dividend income from unconsolidated affiliates 954 1,632
Interest income - other 1,334 3,998
Other, net (77) (280)
-------------------------------
Other income (expense) (16,272) (1,613)
-------------------------------
INCOME (LOSS) BEFORE MINORITY INTEREST (17,376) 52,804
MINORITY INTEREST 173 (534)
-------------------------------
NET INCOME (LOSS) $(17,203) $ 52,270
===============================
ALLOCATION OF NET INCOME (LOSS) TO:
Limited partners $(18,449) $ 51,288
===============================
General partner $ 1,246 $ 982
===============================
BASIC EARNINGS PER UNIT
Income (loss) before minority interest $ (0.26) $ 0.77
===============================
Net income (loss) per Common and Subordinated unit $ (0.25) $ 0.76
===============================
DILUTED EARNINGS PER UNIT
Income (loss) before minority interest $ (0.26) $ 0.62
===============================
Net income (loss) per Common, Subordinated
and Special unit $ (0.25) $ 0.61
===============================
See Notes to Unaudited Consolidated Financial Statements
PAGE 2
Enterprise Products Partners L.P.
Statements of Consolidated Cash Flows
(Dollars in thousands)
(Unaudited)
Quarter Ended
March 31,
----------------------------------
2002 2001
----------------------------------
OPERATING ACTIVITIES
Net income (loss) $(17,203) $ 52,270
Adjustments to reconcile net income (loss) to cash flows provided by
(used for) operating activities:
Depreciation and amortization 17,947 10,781
Equity in income of unconsolidated affiliates (9,227) (2,011)
Distributions received from unconsolidated affiliates 14,438 8,866
Leases paid by EPCO 2,281 2,633
Minority interest (173) 534
Loss (gain) on sale of assets 14 (381)
Changes in fair market value of financial instruments (see Note 12) 30,141 (16,361)
Net effect of changes in operating accounts (48,191) (7,634)
----------------------------------
Operating activities cash flows (9,973) 48,697
----------------------------------
INVESTING ACTIVITIES
Capital expenditures (17,112) (25,338)
Proceeds from sale of assets 10 557
Business acquisitions, net of cash received (368,631)
Investments in and advances to unconsolidated affiliates (10,752) (113,083)
----------------------------------
Investing activities cash flows (396,485) (137,864)
----------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 383,000 449,716
Long-term debt repayments (20,000)
Debt issuance costs (3,125)
Cash distributions paid to partners (47,374) (38,056)
Cash distributions paid to minority interest by Operating Partnership (485) (393)
Cash contributions from EPCO to minority interest 23 27
Cash contributions from minority interest 39
Treasury Units purchased by Trust (2,015)
Increase in restricted cash (8,769)
----------------------------------
Financing activities cash flows 304,419 408,169
----------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (102,039) 319,002
CASH AND CASH EQUIVALENTS, JANUARY 1 132,071 60,409
----------------------------------
CASH AND CASH EQUIVALENTS, MARCH 31 $ 30,032 $379,411
==================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 3
Enterprise Products Partners L.P.
Notes to Unaudited Consolidated Financial Statements
1. GENERAL
In the opinion of Enterprise Products Partners L.P., the accompanying unaudited consolidated financial statements include all
adjustments consisting of normal recurring accruals necessary for a fair presentation of its consolidated financial position as of
March 31, 2002 and consolidated results of operations and cash flows for the quarter ended March 31, 2002 and 2001. Within these
footnote disclosures of Enterprise Products Partners L.P., references to "we","us","our" or "the Company" shall mean the consolidated
financial statements of Enterprise Products Partners L.P.. References to "Operating Partnership" shall mean the consolidated
financial statements of our primary operating subsidiary, Enterprise Products Operating L.P.
Although we believe 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 SEC. These unaudited
financial statements should be read in conjunction with our annual report on Form 10-K (File No. 1-14323) for the year ended December
31, 2001.
The results of operations for the quarter ended March 31, 2002 are not necessarily indicative of the results to be expected for the
full year.
Dollar amounts presented within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.
Certain abbreviated entity names and other capitalized terms are described within the glossary of this quarterly report on Form 10-Q.
Two-for-one split of Limited Partner Units
On February 27, 2002, we announced that the General Partner had approved a two-for-one split for each class of our partnership
Units. The partnership Unit split will be accomplished by distributing one additional partnership Unit for each partnership Unit
outstanding to holders of record on April 30, 2002. The Units will be distributed on May 15, 2002. All references to number of
Units or earnings per Unit contained in this document relate to the pre-split Units, unless otherwise indicated.
2. BUSINESS ACQUISITIONS
Acquisition of Diamond-Koch propylene fractionation business in February 2002
In February 2002, we completed the purchase of various propylene fractionation assets and certain inventories of refinery grade
propylene, propane, and polymer grade propylene from Diamond-Koch. These include a 66.7% interest in a polymer grade propylene
fractionation facility located in Mont Belvieu, Texas (the "Mont Belvieu III" facility), a 50% interest in an entity which owns a
polymer grade propylene export terminal located on the Houston Ship Channel in La Porte, Texas, and varying interests in several
supporting distribution pipelines and related equipment. Mont Belvieu III has the capacity to produce approximately 41 MBPD of
polymer grade propylene. We will integrate these assets into our Mont Belvieu operations. The purchase price of $239.0 million was
funded by a drawdown on our Multi-Year and 364-Day Credit Facilities (see Note 7).
Acquisition of Diamond-Koch storage business in January 2002
In January 2002, we completed the purchase of various hydrocarbon storage assets from Diamond-Koch. The storage facilities consist
of 30 salt dome storage caverns with a useable capacity of 68 million barrels, local distribution pipelines and related equipment.
PAGE 4
The facilities provide storage services for mixed natural gas liquids, ethane, propane, butanes, natural gasoline and olefins (such
as ethylene), polymer grade propylene, chemical grade propylene and refinery grade propylene.
The facilities are located in Mont Belvieu, Texas and serve the largest petrochemical and refinery complex in the United States.
Collectively, they represent the largest underground storage operation of its kind in the world, containing 14% of the world's
underground storage capacity. The size and location of the business provide it with a competitive position to increase its services
to expanding Gulf Coast petrochemical complexes. We will integrate these assets into our existing storage operations located in
Mont Belvieu. The purchase price of $129.6 million was funded by utilizing cash on hand.
Allocation of purchase price of Diamond-Koch acquisitions
The Diamond-Koch acquisitions will be accounted for under the purchase method of accounting and, accordingly, the initial purchase
price of each has been allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows:
Estimated Fair Values at
----------------------------------------
Feb. 1, 2002 Jan. 1, 2002
----------------------------------------
Propylene
Fractionation Storage Total
------------------------------------------------------------
Inventories $ 4,994 $ 4,994
Prepaid and other current assets 2,701 $ 890 3,591
Property, plant and equipment 97,626 120,854 218,480
Investments in unconsolidated affiliates 7,550 7,550
Intangible assets (see Note 6) 53,000 7,844 60,844
Goodwill 73,279 73,279
Current liabilities (107) (107)
------------------------------------------------------------
Total purchase price $239,043 $ 129,588 $368,631
============================================================
The balances related to the Diamond-Koch acquisitions included in the consolidated balance sheet dated March 31, 2002 are based upon
preliminary information and are subject to change as additional information is obtained. The fair value estimates were developed by
independent appraisers using recognized business valuation techniques. The initial purchase price is subject to certain post-closing
adjustments that are expected to be finalized during the second quarter of 2002.
The purchase price paid for the propylene fractionation business resulted in $73.3 million in goodwill. The goodwill represents the
value management has attached to future earnings improvements, the strategic location of the assets and their connections and cost
advantaged assets. Earnings from the propylene business are expected to improve substantially from the last few years with the
years 2003 and 2004 projected to be peak years in the petrochemical business cycle. Additionally, the demand for chemical grade and
polymer grade propylene is forecast to grow at an average of 4.4% per year from 2002 to 2006.
The propylene fractionation assets are located in Mont Belvieu, Texas on the Gulf Coast, the largest natural gas liquids and
petrochemical marketplace in the U.S. The assets have access to substantial supply from major Gulf Coast and central U.S. producers
of refinery grade propylene. The polymer grade products produced at the facility have competitive advantages because of distribution
direct to customers via affiliated pipelines and through an affiliated export facility. In addition, we believe this facility has
achieved operating cost efficiencies that are much lower than historical levels and are among the lowest in the industry.
Pro forma effect of business acquisitions
Our results of operations for the first quarter of 2002 includes two full months (February and March) of the propylene fractionation
business and three full months of the storage business. Our 2001 results of operations do not include any impact from these
acquisitions. The following table presents selected unaudited pro forma information for the quarters ended March 31, 2002 and 2001
PAGE 5
based on historical financial information of the Diamond-Koch propylene fractionation and storage businesses as if both acquisitions
had occurred at the beginning of the periods presented.
The pro forma information is based upon data currently available to and certain estimates and assumptions by management and, as a
result, are not necessarily indicative of our financial results had the transactions actually occurred on these dates. Likewise, the
unaudited pro forma information is not necessarily indicative of our future financial results.
Pro Forma Amounts for
Quarter Ended March 31,
-------------------------------------
2002 2001
-------------------------------------
Revenues $677,807 $939,874
Income (loss) before extraordinary item
and minority interest $(16,014) $ 52,568
Net income (loss) $(15,855) $ 52,036
Allocation of net income (loss) to
Limited partners $(17,101) $ 51,055
General Partner $ 1,246 $ 982
Units used in earnings per Unit calculations
Basic 72,763 67,667
Diluted 72,763 84,167
Income (loss) per Unit before minority interest
Basic $ (0.24) $ 0.76
Diluted $ (0.24) $ 0.61
Net income (loss) per Unit
Basic $ (0.24) $ 0.75
Diluted $ (0.24) $ 0.61
3. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation are as follows:
Estimated
Useful Life March 31, December 31,
in Years 2002 2001
---------------------------------------------------
Plants and pipelines 5-35 $1,562,015 $ 1,398,843
Underground and other storage facilities 5-35 249,108 127,900
Transportation equipment 3-35 3,682 3,736
Land 15,437 15,517
Construction in progress 57,153 98,844
-------------------------------------
Total 1,887,395 1,644,840
Less accumulated depreciation 352,199 338,050
-------------------------------------
Property, plant and equipment, net $1,535,196 $1,306,790
=====================================
PAGE 6
4. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
We own interests in a number of related businesses that are accounted for under the equity or cost method. The investments in and
advances to these unconsolidated affiliates are grouped according the operating segment to which they relate. For a general
discussion of our operating segments, see Note 13.
We acquired three equity method unconsolidated affiliates as part of our acquisition of Diamond-Koch's propylene fractionation
business (see Note 2). We purchased an aggregate 50% interest in La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.
(collectively, "La Porte") which together own a private polymer grade propylene pipeline extending from Mont Belvieu to La Porte,
Texas. In addition, we acquired 50% of the outstanding capital stock of Olefins Terminal Corporation ("OTC") which owns a polymer
grade propylene storage facility and related dock infrastructure (located on the Houston Ship Channel) for loading waterborne
propylene vessels. Both the La Porte and OTC investments are an integral part of our Mont Belvieu III propylene fractionation
operations. These investments are classified as part of our Fractionation operating segment.
The following table shows investments in and advances to unconsolidated affiliates at:
Ownership March 31, December 31,
Percentage 2002 2001
--------------------------------------------------------
Accounted for on equity basis:
Fractionation:
BRF 32.25% $ 29,309 $ 29,417
BRPC 30% 18,360 18,841
Promix 33.33% 44,186 45,071
La Porte 50% 5,740
OTC 50% 1,690
Pipeline:
EPIK 50% 14,870 14,280
Wilprise 37.35% 8,671 8,834
Tri-States 33.33% 26,812 26,734
Belle Rose 41.67% 11,559 11,624
Dixie 19.88% 38,276 37,558
Starfish 50% 25,968 25,352
Neptune 25.67% 76,857 76,880
Nemo 33.92% 12,167 12,189
Evangeline 49.5% 2,546 2,578
Octane Enhancement:
BEF 33.33% 61,281 55,843
Accounted for on cost basis:
Processing:
VESCO 13.1% 33,000 33,000
----------------------------------------
Total $411,292 $398,201
========================================
PAGE 7
The following table shows equity in income (loss) of unconsolidated affiliates for the quarters ended March 31, 2002 and 2001:
Ownership Quarter Ended March 31,
----------------------------------
Percentage 2002 2001
---------------------------------------------------
Fractionation:
BRF 32.25% $549 $18
BRPC 30% 249 152
Promix 33.33% 1,043 393
La Porte 50% (92)
OTC 50% (110)
Pipelines:
EPIK 50% 1,683 (922)
Wilprise 37.35% 147 (222)
Tri-States 33.33% 469 (35)
Belle Rose 41.67% 74 (89)
Dixie 19.88% 717 891
Starfish 50% 812 951
Ocean Breeze 25.67% 2
Neptune 25.67% 778 694
Nemo 33.92% (22) 9
Evangeline 49.5% (76)
Octane Enhancement:
BEF 33.33% 3,006 169
----------------------------------
Total $9,227 $2,011
==================================
The initial investment we made in certain equity method unconsolidated affiliates exceeded our share of the historical cost of
underlying net assets of such entities. Under this scenario, "excess cost" is recorded for the excess of the purchase price (or
cost) of the investment over our share of the underlying net assets of the investee. We have excess cost associated with our
investments in Promix, La Porte, Dixie, Neptune and Nemo. The excess cost of these investments is reflected in our investments in
and advances to unconsolidated affiliates for these entities. Since each of these excess cost amounts relates to the plant and
pipeline assets of each entity, the excess cost of each is amortized to equity earnings from these entities in a manner similar to
depreciation. The following table summarizes our excess cost information:
Amortization
Charged to
Initial Unamortized balance at Equity Earnings
----------------------------------
Excess March 31, December 31, during Amortization
Cost 2002 2001 2002 Period
-----------------------------------------------------------------------------------------
Fractionation segment:
Promix $ 7,955 $ 6,894 $ 7,083 $ 99 20 years
La Porte 873 866 n/a 7 35 years
Pipelines segment:
Dixie 37,694 35,445 35,714 269 35 years
Neptune 12,768 12,312 12,404 91 35 years
Nemo 727 713 718 5 35 years
PAGE 8
The following table presents summarized income statement information for our unconsolidated investments accounted for under the
equity method (for the periods indicated on a 100% basis).
Summarized Income Statement Data for the Quarter Ended
-------------------------------------------------------------------------------------------------
March 31, 2002 March 31, 2001
----------------------------------------------- ------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
----------------------------------------------- ------------------------------------------------
Fractionation:
BRF $ 4,606 $ 1,665 $ 1,702 $ 4,023 $ 35 $ 56
BRPC 2,951 819 829 3,433 439 505
Promix 9,864 3,410 3,428 9,002 1,440 1,477
La Porte (234) (235)
OTC 619 (308) (352)
Pipelines:
EPIK 8,305 3,388 3,400 691 (1,891) (1,862)
Wilprise 772 393 394 398 (602) (594)
Tri-States 3,099 1,401 1,406 1,632 (126) (105)
Belle Rose 507 176 177 147 (219) (213)
Dixie 15,128 7,402 4,520 19,327 9,649 5,834
Starfish 6,429 1,936 1,626 6,616 2,098 1,902
Ocean Breeze 20 12 12
Neptune 7,703 3,516 3,307 7,409 3,148 3,369
Nemo 395 (74) (70) (16) 28
Evangeline 25,509 850 (179)
Octane Enhancement:
BEF 47,929 8,978 9,019 37,864 413 507
----------------------------------------------- ------------------------------------------------
Total $133,816 $33,318 $28,972 $90,562 $14,380 $10,916
=============================================== ================================================
5. RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other
Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June
30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001.
There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by
the purchase method. SFAS No. 142 was effective for our fiscal year that began January 1, 2002 for all goodwill and other intangible
assets recognized in our consolidated balance sheet at that date, regardless of when those assets were initially recognized. We
adopted SFAS No. 141 and SFAS No. 142 on January 1, 2002.
At December 31, 2001, our intangible assets were comprised of the values associated with the Shell natural gas processing agreement
and the goodwill related to the 1999 MBA acquisition. In accordance with the new standard, we reclassified the goodwill to a
separate line item on our consolidated balance sheet apart from the Shell contract. Based upon our initial interpretation of the
standard, the Shell natural gas processing agreement will continue to be amortized over its 20-year contract term; however,
amortization of the MBA acquisition goodwill will cease due to its indefinite life. Our goodwill will be subject to periodic
impairment testing in accordance with SFAS No. 142. For additional information regarding our intangible assets and goodwill
including additions to both classes of assets as a result of the Diamond-Koch acquisitions, see Note 6.
Within six months of our adoption of SFAS No. 142 (by June 30, 2002), we will have completed a transitional impairment review to
identify if there is an impairment to the December 31, 2001 recorded goodwill or intangible assets of indefinite life using a fair
value methodology. Professionals in the business valuation industry will be consulted to validate the assumptions used in such
methodologies. Any impairment loss resulting from the transitional impairment test will be recorded as a cumulative effect of a
PAGE 9
change in accounting principle for the quarter ended June 30, 2002. Subsequent impairment losses will be reflected in operating
income in the Statements of Consolidated Operations. We are continuing to evaluate the complex provisions of SFAS No. 142 and will
fully adopt the standard during 2002 within the prescribed time periods.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset Retirement Obligations", in June
2001. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement
obligation and the associated asset retirement cost. This statement is effective for our fiscal year beginning January 1, 2003. We
are continuing to evaluate the provisions of this statement. In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". This statement addresses financial accounting and reporting for the impairment and/or
disposal of long-lived assets. We adopted this statement effective January 1, 2002 and determined that it did not have any
significant impact on our financial statements as of that date.
6. INTANGIBLE ASSETS
Intangible assets
Our recorded intangible assets primarily include the estimated value assigned to certain contract-based assets representing the
rights we own arising from contractual agreements. According to SFAS No. 141, a contract-based intangible with a finite useful life
is amortized over its estimated useful life, which is the period over which the asset is expected to contribute directly or
indirectly to the future cash flows of the entity. It is based on an analysis of all pertinent factors including (a) the expected
use of the asset by the entity, (b) the expected useful life or related assets (i.e., fractionation facility, storage well, etc.),
(c) any legal, regulatory or contractual provisions, including renewal or extension periods that would not cause substantial costs or
modifications to existing agreements, (d) the effects of obsolescence, demand, competition, and other economic factors and (e) the
level of maintenance required to obtain the expected future cash flows.
At March 31, 2002, our intangible assets primarily consisted of the Shell natural gas processing agreement that we acquired as a
result of the TNGL acquisition in August 1999 and certain propylene fractionation and storage contracts we acquired in connection
with our Diamond-Koch acquisitions in January and February 2002. The value of the Shell natural gas processing agreement is being
amortized on a straight-line basis over its 20-year contract term (currently $11.1 million annually from 2002 through 2019). If the
economic life of this contract were later determined to be impaired due to negative changes in Shell's natural gas exploration and
production activities in the Gulf of Mexico, then we might need to reduce the amortization period of this asset to less than the
contractually-stated 20-year life of the agreement. Such a change would increase the annual amortization charge at that time. At
March 31, 2002, the unamortized value of the Shell contract was $191.6 million.
The value of the propylene fractionation and storage contracts acquired from Diamond-Koch is being amortized on a straight-line basis
over the economic life of the assets to which they relate, which is currently estimated at 35 years. Although the majority of these
contracts have terms of one to two years, we have assumed that our relationship with these customers will extend beyond the
contractually-stated term primarily based on historical low customer contract turnover rates within these operations. If the
economic life of the assets were later determined to be impaired due to negative changes within the industry or otherwise, then we
might need to reduce the amortization period of these contract-based assets to less than 35 years. Such a change would increase
amortization expense at that time. At March 31, 2002, the unamortized value of these contracts was $60.5 million.
The specific, identifiable intangible assets of a business enterprise depend largely upon the nature of its operations. Potential
intangible assets include intellectual property such as technology, patents, trademarks and trade names, customer contracts and
relationships, and non-compete agreements, as well as other intangible assets. The approach to the valuation of each intangible
asset will vary depending upon the nature of the asset, the business in which it is utilized, and the economic returns it is
generating or is expected to generate.
PAGE 10
Goodwill
At March 31, 2002, the value of recorded goodwill was $81.1 million. Our goodwill is attributable to the excess of the purchase
price over the fair value of assets acquired from Diamond-Koch in early 2002 and from Kinder Morgan and EPCO in July 1999. Since
our adoption of SFAS No. 142 on January 1, 2002, our goodwill amounts are no longer amortized. Instead, we will periodically review
the reporting units to which the goodwill amounts relate for indications of possible impairment. If such indicators are present
(i.e., loss of a significant customer, economic obsolescence of plant assets, etc.), the fair value of the reporting unit, including
its related goodwill, will be calculated and compared to its combined book value. Our goodwill is recorded as part of the
Fractionation operating segment since it is wholly attributed to acquired assets included in this operating segment.
The fair value of a reporting unit refers to the amount at which it could be bought or sold in a current transaction between willing
parties. Quoted market prices in active markets are the best evidence of fair value and are used to the extent they are available.
If quoted market prices are not available, an estimate of fair value is determined based on the best information available to us,
including prices of similar assets and the results of using other valuation techniques such as discounted cash flow analysis and
multiples of earnings approaches. The underlying assumptions in such models rely on information available to us at a given point in
time and are viewed as reasonable and supportable considering available evidence.
If the fair value of the reporting unit exceeds its book value, goodwill is not considered impaired and no adjustment to earnings
would be required. Should the fair value of the reporting unit (including its goodwill) be less than its book value, a charge to
earnings would be recorded to adjust goodwill to its implied fair value.
Pro Forma impact of discontinuation of amortization of goodwill
The following table discloses the pro forma impact on earnings of our discontinuation of the amortization of goodwill related to the
MBA acquisition (for the first quarter of 2001).
Reported net income $52,270
Discontinue goodwill amortization 111
Adjust minority interest expense (1)
----------------
Adjusted net income $52,380
================
On a pro forma basis, earnings per Unit (both basic and diluted) were not affected by the discontinuation of goodwill amortization
due to the immaterial nature of the pro forma adjustment.
PAGE 11
7. DEBT OBLIGATIONS
Our long-term debt consisted of the following at:
March 31, December 31,
2002 2001
---------------------------------------
Borrowings under:
Senior Notes A, 8.25% fixed rate, due March 2005 $ 350,000 $350,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000 450,000
Multi-Year Credit Facility, due November 2005 230,000
364-Day Credit Facility, due November 2002 (a) 83,000
First Union Facility, due April 2002 50,000
---------------------------------------
Total principal amount 1,217,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,955 1,653
Less unamortized discount on:
$350 Million Senior Notes (108) (117)
$450 Million Senior Notes (251) (258)
Less current maturities of debt (50,000) -
---------------------------------------
Long-term debt $1,168,596 $855,278
=======================================
(a) Under the terms of this facility, the Operating Partnership has the option to convert this facility into a term loan due
November 15, 2003. Management intends to refinance this obligation with a similar obligation at maturity.
At March 31, 2002, we had a total of $75 million of standby letters of credit capacity under our Multi-Year Credit Facility of which
$18.6 million was outstanding.
Enterprise Products Partners L.P. acts as guarantor of certain debt obligations of the Operating Partnership. This parent-subsidiary
guaranty provision exists under our Senior Notes, MBFC Loan, Multi-Year and 364-Day Credit Facility.
In April 2002, we increased the amount that we can borrow under the Multi-Year Credit Facility by $20 million and the 364-Day Credit
Facility by $80 million, up to an amount not exceeding $500 million in the aggregate for both facilities. At March 31, 2002, we had
borrowed $313 million under these two facilities; the majority of which was related to the acquisition of Diamond-Koch's propylene
fractionation business in February 2002 (see Note 2). In anticipation of the increased borrowing limits under the Multi-Year and
364-Day Credit Facilities, we borrowed $50 million under a short-term supplemental credit facility that was repaid in late April 2002
with proceeds from the increased availability under the Multi-Year and 364-Day Credit Facility.
The indentures under which the Senior Notes and the MBFC Loan were issued contain various restrictive covenants. We were in
compliance with these covenants at March 31, 2001.
In April 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were amended to allow for increased financial
flexibility. The significant changes are as follows (capitalized terms used herein are defined within the credit agreements):
o We were granted increased flexibility under our Consolidated Indebtedness to Consolidated EBITDA ratio for the rolling four
quarter period which ends on September 30, 2002. The maximum ratio allowed by our lenders was temporarily raised to 4.5 to
1.0 from 4.0 to 1.0 This modification was required as a result of the hedging losses we incurred during the first quarter
of 2002.
o In addition, we are allowed to exclude from the calculation of Consolidated EBITDA up to $50 million in losses resulting
from hedging NGLs that utilized natural gas-based financial instruments entered into on or prior to April 24, 2002. This
exclusion applies to our quarterly Consolidated EBITDA calculations in which the financial impact of such specific
PAGE 12
instruments were recorded (ending with the calculation for the third quarter of 2003 due to the rolling-four quarter nature
of the calculation).
We were in compliance with the covenants of our revolving credit agreements at March 31, 2002.
8. TREASURY UNITS
During the first quarter of 1999, the Operating Partnership established the EPOLP 1999 Grantor Trust (the "Trust") to fund potential
future obligations under EPCO's long-term incentive plan (through the exercise of Common Unit options granted to directors of the
General Partner and EPCO employees who participate in the business of the Operating Partnership). The Common Units purchased by the
Trust are accounted for in a manner similar to treasury stock under the cost method of accounting. At March 31, 2002, the Trust
held 204,600 Common Units that are classified as Treasury Units. The Trust purchased 41,000 Common Units during the first quarter
of 2002 at a cost of $2.0 million.
Beginning in July 2000 and later modified in September 2001, the General Partner authorized the Company (specifically, Enterprise
Products Partners L.P.) and the Trust to repurchase up to 1.0 million of our publicly-held Common Units through July 2002 (the
"Buy-Back Program"). The repurchases will be made during periods of temporary market weakness at price levels that would be accretive
to our remaining Unitholders. Under the terms of the Buy-Back Program, Common Units repurchased by the Company were to be retired
and Common Units repurchased by the Trust were to remain outstanding and be accounted for as Treasury Stock. In April 2002, the
General Partner modified the program to allow for Common Units repurchased by the Company to remain outstanding as Treasury Stock
rather than being retired. At March 31, 2002, 534,200 Common Units could be repurchased under the Buy-Back Program.
9. 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. In general, 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. In a period of operating losses, the Special Units are excluded from the calculation of diluted earnings per Unit
due to their antidilutive effect. The following table reconciles the number of Units used in the calculation of basic earnings per
Unit and diluted earnings per Unit for each of the quarters ended March 31, 2002 and 2001.
PAGE 13
Quarter Ended March 31,
----------------------------------
2002 2001
----------------------------------
Income (loss) before minority interest $(17,376) $52,804
General partner interest (1,246) (982)
----------------------------------
Income (loss) before minority interest (18,622) 51,822
available to Limited Partners
Minority interest 173 (534)
----------------------------------
Net income (loss) available to Limited Partners $(18,449) $51,288
==================================
BASIC EARNINGS PER UNIT
Numerator
Income (loss) before minority interest
available to Limited Partners $(18,622) $51,822
==================================
Net income (loss) available
to Limited Partners $(18,449) $51,288
==================================
Denominator
Common Units outstanding 51,353 46,257
Subordinated Units outstanding 21,410 21,410
----------------------------------
Total 72,763 67,667
==================================
Basic Earnings per Unit
Income (loss) before minority interest
available to Limited Partners $ (0.26) $ 0.77
==================================
Net income (loss) available
to Limited Partners $ (0.25) $ 0.76
==================================
DILUTED EARNINGS PER UNIT
Numerator
Income (loss) before minority interest
available to Limited Partners $(18,622) $51,822
==================================
Net income (loss) available
to Limited Partners $(18,449) $51,288
==================================
Denominator
Common Units outstanding 51,353 46,257
Subordinated Units outstanding 21,410 21,410
Special Units outstanding 16,500
----------------------------------
Total 72,763 84,167
==================================
Diluted Earnings per Unit
Income (loss) before minority interest
available to Limited Partners $ (0.26) $ 0.62
==================================
Net income (loss) available
to Limited Partners $ (0.25) $ 0.61
==================================
The Special Units are excluded from the calculation of diluted earnings per Unit for the first quarter of 2002 due to their
antidilutive effect. If the Special Units were to be considered in the calculation, the dilutive earnings per Unit would have been a
loss of 21 cents. The Special Units will convert into Common Units over the next two years: 9.5 million will convert in August
2002 and the remaining 5.0 million in August 2003. Due to the short-term conversion schedule for this class of equity, management
views the Special Units as equivalent to Common Units when internally evaluating diluted earnings per Unit.
PAGE 14
10. DISTRIBUTIONS
We intend, 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. Apart from its pro rata share
of the quarterly distributions, the General Partner's interest in quarterly distributions is increased after certain specified target
levels are met (the "incentive distributions").
The distribution paid on February 11, 2002 (based on fourth quarter 2001 results) was $0.625 per Common and Subordinated Unit. As a
result of this distribution rate, the General Partner received $1.4 million in incentive distributions.
The distribution rate declared by the General Partner for the first quarter of 2002 was $0.67 per Common Unit to Unitholders of
record on April 30, 2002. The distribution will be paid on May 10, 2002.
11. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Quarter Ended March 31,
----------------------------------
2002 2001
----------------------------------
(Increase) decrease in:
Accounts and notes receivable $1,623 $89,620
Inventories (25,892) 68,452
Prepaid and other current assets (2,494) (1,824)
Other assets (3,186) (1,128)
Increase (decrease) in:
Accounts payable (9,559) (31,808)
Accrued gas payable 25,014 (100,315)
Accrued expenses (6,588) (11,391)
Accrued interest (16,137) (2,521)
Other current liabilities (10,892) (16,661)
Other liabilities (80) (58)
----------------------------------
Net effect of changes in operating accounts $(48,191) $(7,634)
==================================
In January and February of 2002, we paid Diamond-Koch $368.6 million for its propylene fractionation and NGL and petrochemical
storage businesses located in Mont Belvieu, Texas. The allocation of the purchase price affected various balance sheet accounts.
See Note 2 for information regarding the allocation of the purchase price for these acquisitions.
We record various financial instruments relating to commodity positions and interest rate swaps at their respective fair values using
mark-to-market accounting. For the quarter ended March 31, 2002, we recognized a net $30.1 million in non-cash mark-to-market losses
related to decreases in the fair value of these financial instruments, primarily in our commodity financial instruments portfolio.
For the quarter ended March 31, 2001, we recognized a net $16.4 million in non-cash mark-to-market income from our financial
instruments portfolio.
Cash and cash equivalents at March 31, 2002 per the Statements of Consolidated Cash Flows excludes $14.5 million of restricted cash
representing amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for physical
purchase transactions made on the NYMEX exchange.
PAGE 15
12. FINANCIAL INSTRUMENTS
We are exposed to financial market risks, including changes in commodity prices in our natural gas and NGL businesses and in interest
rates with respect to a portion of our debt obligations. We may use financial instruments (i.e., futures, forwards, swaps, options,
and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated
transactions, primarily in our Processing segment. As a matter of policy, we do not use financial instruments for speculative (or
trading) purposes.
Commodity financial instruments
Our Processing and Octane Enhancement segments are directly exposed to commodity price risk through their respective business
operations. The prices of natural gas, NGLs and MTBE are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with our
Processing segment, we may enter into swaps, forwards, commodity futures, options and other commodity financial instruments with
similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial
instrument. The primary purpose of these risk management activities (or hedging strategies) is to hedge exposure to price risks
associated with natural gas, NGL inventories, firm commitments and certain anticipated transactions. We do not hedge our exposure
to the MTBE markets. Also, in our Pipelines segment, we may utilize a limited number of commodity financial instruments to manage
the price Acadian Gas charges certain of its customers for natural gas.
We have adopted a commercial policy to manage our exposure to the risks of its natural gas and NGL businesses. The objective of this
policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined
as remaining within the position limits established by the General Partner. Under this policy, we enter into risk management
transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term
(less than one month) and long-term basis, generally not to exceed 24 months. The General Partner oversees our hedging strategies
associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy
(including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and
ensuring compliance with the policy.
We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some
financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on
the specific exposure. When this occurs, we may enter into a new commodity financial instrument to reestablish the economic hedge to
which the closed instrument relates.
Our commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133
because of ineffectiveness. A hedge is normally regarded as effective if, among other things, at inception and throughout the term
of the financial instrument, we could expect changes in the fair value of the hedged item to be almost fully offset by the changes in
the fair value of the financial instrument. When financial instruments do not qualify as effective hedges under the guidelines of
SFAS No. 133, changes in the fair value of these positions are recorded on the balance sheet and in earnings through mark-to-market
accounting. The use of mark-to-market accounting for these ineffective instruments results in a degree of non-cash earnings
volatility that is dependent upon changes in the underlying commodity prices. Although our financial instruments may from time to
time be regarded as ineffective hedges under SFAS No. 133, we continue to view these instruments as hedges (i.e., "economic hedges")
inasmuch as this was the intent when such contracts were executed. This characterization is consistent with the actual economic
performance of these contracts to date and we expect our economic hedges to continue to mitigate (or offset) commodity price risk in
the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS No. 133.
We recognized a loss of $45.1 million in the first quarter of 2002 from our commodity hedging activities that is treated as an
increase in operating costs and expenses in our Statements of Consolidated Operations. Of this amount, $16.4 million has been
realized (e.g., paid out to counterparties). The remaining $28.7 million represents the negative change in value of
the open positions between December 31, 2001 and March 31, 2002 (based on market prices at those dates). The market value of our open
positions at March 31, 2002 was $20.8 million payable (a loss). For the first quarter of 2001, we recognized income of $5.6 million
PAGE 16
from these activities, which included the positive impact of the portfolio's March 31, 2001 value of $13.5 million receivable
(recorded as income).
Interest rate swaps
Our interest rate exposure results from variable-rate borrowings from commercial banks and fixed-rate borrowings pursuant to the
Company's Senior Notes and MBFC Loan. We manage a portion of our exposure to changes in interest rates by utilizing interest rate
swaps. The objective of holding interest rate swaps is to manage debt service costs by converting a portion of fixed-rate debt into
variable-rate debt or a portion of variable-rate debt into fixed-rate debt. An interest rate swap, in general, requires one party to
pay a fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount.
The General Partner oversees the strategies associated with financial risks and approves instruments that are appropriate for our
requirements. At March 31, 2002, we had one interest rate swap outstanding having a notional amount of $54 million extending
through March 2010 . Under this agreement, we exchanged a fixed-rate of 8.70% for a market-based variable-rate. If it elects to
do so, the counterparty may terminate this swap in March 2003.
We recognized income of $0.1 million during the first quarter of 2002 from our interest rate swaps that is treated as a reduction of
interest expense. The fair value of the interest rate swap at March 31, 2002 was a receivable of $2.4 million. We recognized
income of $5.2 million during the first quarter of 2001 from interest rate swaps. The benefit recorded in 2001 was primarily due to
the election of a counterparty to not terminate its interest rate swap early.
13. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial information is available and that are regularly
evaluated by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Generally,
financial information is required to be reported on the basis that it is used internally for evaluating segment performance and
deciding how to allocate resources to segments.
We have five reportable operating segments: Fractionation, Pipelines, Processing, Octane Enhancement and Other. The reportable
segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold,
as applicable. The segments are regularly evaluated by the Chief Executive Officer of the General Partner. Fractionation primarily
includes NGL fractionation, isomerization, and polymer grade propylene fractionation services. Pipelines consists of both liquids
and natural gas pipeline systems, storage and import/export terminal services. Processing includes the natural gas processing
business and its related merchant activities. Octane Enhancement represents our equity interest in BEF, 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.
We evaluate segment performance based on gross operating margin. Gross operating margin reported for each segment represents
operating income before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of
assets and general and administrative expenses. In addition, segment gross operating margin is exclusive of interest expense,
interest income (from unconsolidated affiliates or others), dividend income from unconsolidated affiliates, minority interest,
extraordinary charges and other income and expense transactions.
We include equity earnings from unconsolidated affiliates in segment gross operating margin and as a component of revenues. Our
equity investments with industry partners are a vital component of our business strategy and a means by which we conduct our
operations to align our interests with a supplier of raw materials to a facility or a consumer of finished products from a facility.
This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business
risk assumed versus what we could accomplish on a stand alone basis. Many of these businesses perform supporting or complementary
roles to our other business operations. For example, we use the Promix NGL fractionator to process NGLs extracted by our gas
plants. The NGLs received from Promix then can be sold by our merchant businesses. Another example would be our relationship with
PAGE 17
the BEF MTBE facility. Our isomerization facilities process normal butane for this plant and our HSC pipeline transports MTBE for
delivery to BEF's storage facility on the Houston Ship Channel.
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.
Consolidated intangible assets and goodwill are allocated to the segments based on the classification of the assets to which they
relate. The increase in intangible assets and goodwill during the first quarter of 2002 is attributable to the Diamond-Koch
acquisitions (see Note 2).
Segment gross operating margin is inclusive of intersegment revenues, which are generally based on transactions made at
market-related rates. These revenues have been eliminated from the consolidated totals.
PAGE 18
Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table:
Operating Segments Adjs.
-------------------------------------------------------------------
-------------------------------------------------------------------
Octane and Consol.
Fractionation Pipelines Processing Enhancement Other Elims. Totals
---------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------
Revenues from
external customers:
First Quarter 2002 $109,422 $99,081 $453,034 $517 $662,054
First Quarter 2001 89,679 7,187 738,769 680 836,315
Intersegment revenues:
First Quarter 2002 33,397 24,510 126,260 100 $(184,267)
First Quarter 2001 41,652 20,779 110,309 95 (172,835)
Equity income in
unconsolidated affiliates:
First Quarter 2002 1,639 4,582 $3,006 9,227
First Quarter 2001 562 1,280 169 2,011
Total revenues:
First Quarter 2002 144,458 128,173 579,294 3,006 617 (184,267) 671,281
First Quarter 2001 131,893 29,246 849,078 169 775 (172,835) 838,326
Gross operating margin
by segment:
First Quarter 2002 24,377 32,668 (33,376) 3,006 (262) 26,413
First Quarter 2001 25,668 18,123 28,398 169 535 72,893
Segment assets:
At March 31, 2002 444,793 897,139 127,842 8,269 57,153 1,535,196
At December 31, 2001 357,122 717,348 124,555 8,921 98,844 1,306,790
Investments in and advances
to unconsolidated
affiliates:
At March 31, 2002 99,285 217,726 33,000 61,281 411,292
At December 31, 2001 93,329 216,029 33,000 55,843 398,201
Intangible Assets:
At March 31, 2002 52,748 7,788 191,606 252,142
At December 31, 2001 7,857 194,369 202,226
Goodwill:
At March 31, 2002 81,135 81,135
Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Our operations are
centered along the Texas, Louisiana and Mississippi Gulf Coast areas.
PAGE 19
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
Quarter Ended March 31,
----------------------------------
2002 2001
----------------------------------
Total segment gross operating margin $26,413 $72,893
Depreciation and amortization (17,237) (10,029)
Retained lease expense, net (2,305) (2,660)
(Gain) loss on sale of assets (13) 381
Selling, general and administrative (7,962) (6,168)
----------------------------------
Consolidated operating income (loss) (1,104) 54,417
Interest expense (18,513) (6,987)
Interest income from unconsolidated affiliates 30 24
Dividend income from unconsolidated affiliates 954 1,632
Interest income - other 1,334 3,998
Other, net (77) (280)
----------------------------------
Consolidated income (loss) before minority interest $(17,376) $52,804
==================================
PAGE 20
PART I. FINANCIAL INFORMATION.
Item 1B. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Operating L.P.
Consolidated Balance Sheets
(Dollars in thousands)
March 31,
2002 December 31,
ASSETS (unaudited) 2001
---------------------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of $14,521 at
March 31, 2002 and $5,752 at December 31, 2001) $ 44,553 $ 137,823
Accounts and notes receivable - trade, net of allowance for doubtful
accounts of $20,615 in 2002 and $20,642 in 2001 257,191 256,927
Accounts receivable - affiliates 2,704 4,405
Inventories 100,329 69,443
Prepaid and other current assets 44,943 50,207
---------------------------------------
Total current assets 449,720 518,805
Property, Plant and Equipment, Net 1,535,196 1,306,790
Investments in and Advances to Unconsolidated Affiliates 411,292 398,201
Intangible assets, net of accumulated amortization of $16,156 in
2002 and $13,084 in 2001 252,142 202,226
Goodwill 81,135
Other Assets 6,991 5,201
---------------------------------------
Total $2,736,476 $2,431,223
=======================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of debt $50,000
Accounts payable - trade 59,291 $54,269
Accounts payable - affiliate 15,300 33,691
Accrued gas payables 258,550 233,536
Accrued expenses 15,752 22,233
Accrued interest 8,165 24,302
Other current liabilities 58,669 44,767
---------------------------------------
Total current liabilities 465,727 412,798
Long-Term Debt 1,168,596 855,278
Other Long-Term Liabilities 7,980 8,061
Minority Interest 1,531 1,468
Commitments and Contingencies
Partners' Equity
Limited Partner 1,089,759 1,148,124
General Partner 11,120 11,716
Parent's Units acquired by Trust (8,237) (6,222)
---------------------------------------
Total Partners' Equity 1,092,642 1,153,618
---------------------------------------
Total $2,736,476 $2,431,223
=======================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 21
Enterprise Products Operating L.P.
Statements of Consolidated Operations
(Dollars in thousands)
(Unaudited)
Quarter Ended
March 31,
----------------------------------
2002 2001
----------------------------------
REVENUES
Revenues from consolidated operations $662,054 $836,315
Equity income in unconsolidated affiliates 9,227 2,011
----------------------------------
Total 671,281 838,326
COST AND EXPENSES
Operating costs and expenses 664,423 777,741
Selling, general and administrative 7,786 6,168
----------------------------------
Total 672,209 783,909
----------------------------------
OPERATING INCOME (LOSS) (928) 54,417
----------------------------------
OTHER INCOME (EXPENSE)
Interest expense (18,513) (6,987)
Interest income from unconsolidated affiliates 30 12
Dividend income from unconsolidated affiliates 954 1,632
Interest income - other 1,436 4,145
Other, net (77) (280)
----------------------------------
Other income (expense) (16,170) (1,478)
----------------------------------
INCOME (LOSS) BEFORE MINORITY INTEREST (17,098) 52,939
MINORITY INTEREST (53) (23)
----------------------------------
NET INCOME (LOSS) $(17,151) $52,916
==================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 22
Enterprise Products Operating L.P.
Statements of Consolidated Cash Flows
(Dollars in thousands)
(Unaudited)
Quarter Ended
March 31,
---------------------------------
---------------------------------
2002 2001
---------------------------------
---------------------------------
OPERATING ACTIVITIES
Net income (loss) $(17,151) $52,916
Adjustments to reconcile net income (loss) to cash flows provided by
(used for) operating activities:
Depreciation and amortization 17,947 10,781
Equity in income of unconsolidated affiliates (9,227) (2,011)
Distributions received from unconsolidated affiliates 14,438 8,866
Leases paid by EPCO 2,305 2,660
Minority interest 53 23
Loss (gain) on sale of assets 14 (381)
Changes in fair market value of financial instruments (see Note 10) 30,141 (16,361)
Net effect of changes in operating accounts (52,185) (7,949)
---------------------------------
Operating activities cash flows (13,665) 48,544
---------------------------------
INVESTING ACTIVITIES
Capital expenditures (17,112) (25,338)
Proceeds from sale of assets 10 557
Business acquisitions, net of cash acquired (368,631)
Investments in and advances to unconsolidated affiliates (10,752) (113,083)
---------------------------------
Investing activities cash flows (396,485) (137,864)
---------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 383,000 449,716
Long-term debt repayments (20,000)
Debt issuance costs (3,125)
Cash distributions to partners (44,154) (38,901)
Cash contribution from General Partner 39
Cash contributions from minority interest 10 17
Parent's Units acquired by consolidated Trust (2,015)
Increase in restricted cash (8,769)
---------------------------------
Financing activities cash flows 308,111 407,707
---------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (102,039) 318,387
CASH AND CASH EQUIVALENTS, JANUARY 1 132,071 58,446
---------------------------------
CASH AND CASH EQUIVALENTS, MARCH 31 $30,032 $376,833
=================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 23
Enterprise Products Operating L.P.
Notes to Unaudited Consolidated Financial Statements
1. GENERAL
In the opinion of Enterprise Products Operating L.P., the accompanying unaudited consolidated financial statements include all
adjustments consisting of normal recurring accruals necessary for a fair presentation of its consolidated financial position as of
March 31, 2002 and consolidated results of operations and cash flows for the quarter ended March 31, 2002 and 2001. Within these
footnote disclosures of Enterprise Products Operating L.P., references to "we","us","our" or "the Company" shall mean the
consolidated financial statements of Enterprise Products Operating L.P.
Although we believe 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 SEC. These unaudited
financial statements should be read in conjunction with our annual report on Form 10-K (File No. 333-93239-01) for the year ended
December 31, 2001.
The results of operations for the quarter ended March 31, 2002 are not necessarily indicative of the results to be expected for the
full year.
Dollar amounts presented within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.
Certain abbreviated entity names and other capitalized terms are described within the glossary of this quarterly report on Form 10-Q.
2. BUSINESS ACQUISITIONS
Acquisition of Diamond-Koch propylene fractionation business in February 2002
In February 2002, we completed the purchase of various propylene fractionation assets and certain inventories of refinery grade
propylene, propane, and polymer grade propylene from Diamond-Koch. These include a 66.7% interest in a polymer grade propylene
fractionation facility located in Mont Belvieu, Texas (the "Mont Belvieu III" facility), a 50% interest in an entity which owns a
polymer grade propylene export terminal located on the Houston Ship Channel in La Porte, Texas, and varying interests in several
supporting distribution pipelines and related equipment. Mont Belvieu III has the capacity to produce approximately 41 MBPD of
polymer grade propylene. We will integrate these assets into our Mont Belvieu operations. The purchase price of $239.0 million was
funded by a drawdown on our Multi-Year and 364-Day Credit Facilities (see Note 7).
Acquisition of Diamond-Koch storage business in January 2002
In January 2002, we completed the purchase of various hydrocarbon storage assets from Diamond-Koch. The storage facilities consist
of 30 salt dome storage caverns with a useable capacity of 68 million barrels, local distribution pipelines and related equipment.
The facilities provide storage services for mixed natural gas liquids, ethane, propane, butanes, natural gasoline and olefins (such
as ethylene), polymer grade propylene, chemical grade propylene and refinery grade propylene.
The facilities are located in Mont Belvieu, Texas and serve the largest petrochemical and refinery complex in the United States.
Collectively, they represent the largest underground storage operation of its kind in the world, containing 14% of the world's
underground storage capacity. The size and location of the business provide it with a competitive position to increase its services
to expanding Gulf Coast petrochemical complexes. We will integrate these assets into our existing storage operations located in
Mont Belvieu. The purchase price of $129.6 million was funded by utilizing cash on hand.
PAGE 24
Allocation of purchase price of Diamond-Koch acquisitions
The Diamond-Koch acquisitions will be accounted for under the purchase method of accounting and, accordingly, the initial purchase
price of each has been allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows:
Estimated Fair Values at
----------------------------------------
Feb. 1, 2002 Jan. 1, 2002
----------------------------------------
Propylene
Fractionation Storage Total
------------------------------------------------------------
Inventories $ 4,994 $ 4,994
Prepaid and other current assets 2,701 $ 890 3,591
Property, plant and equipment 97,626 120,854 218,480
Investments in unconsolidated affiliates 7,550 7,550
Intangible assets (see Note 6) 53,000 7,844 60,844
Goodwill 73,279 73,279
Current liabilities (107) (107)
------------------------------------------------------------
Total purchase price $239,043 $129,588 $368,631
============================================================
The balances related to the Diamond-Koch acquisitions included in the consolidated balance sheet dated March 31, 2002 are based upon
preliminary information and are subject to change as additional information is obtained. The fair value estimates were developed by
independent appraisers using recognized business valuation techniques. The initial purchase price is subject to certain post-closing
adjustments that are expected to be finalized during the second quarter of 2002.
The purchase price paid for the propylene fractionation business resulted in $73.3 million in goodwill. The goodwill represents the
value management has attached to future earnings improvements, the strategic location of the assets and their connections and cost
advantaged assets. Earnings from the propylene business are expected to improve substantially from the last few years with the
years 2003 and 2004 projected to be peak years in the petrochemical business cycle. Additionally, the demand for chemical grade and
polymer grade propylene is forecast to grow at an average of 4.4% per year from 2002 to 2006.
The propylene fractionation assets are located in Mont Belvieu, Texas on the Gulf Coast, the largest natural gas liquids and
petrochemical marketplace in the U.S. The assets have access to substantial supply from major Gulf Coast and central U.S. producers
of refinery grade propylene. The polymer grade products produced at the facility have competitive advantages because of distribution
direct to customers via affiliated pipelines and through an affiliated export facility. In addition, we believe this facility has
achieved operating cost efficiencies that are much lower than historical levels and are among the lowest in the industry.
PAGE 25
Pro forma effect of business acquisitions
Our results of operations for the first quarter of 2002 includes two full months (February and March) of the propylene fractionation
business and three full months of the storage business. Our 2001 results of operations do not include any impact from these
acquisitions. The following table presents selected unaudited pro forma information for the quarters ended March 31, 2002 and 2001
based on historical financial information of the Diamond-Koch propylene fractionation and storage businesses as if both acquisitions
had occurred at the beginning of the periods presented.
The pro forma information is based upon data currently available to and certain estimates and assumptions by management and, as a
result, are not necessarily indicative of our financial results had the transactions actually occurred on these dates. Likewise, the
unaudited pro forma information is not necessarily indicative of our future financial results.
Quarter Ended March 31,
-------------------------------------
2002 2001
-------------------------------------
Revenues $677,807 $939,874
Income (loss) before extraordinary item
and minority interest $(15,736) $52,703
Net income (loss) $(15,803) $52,682
3. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation are as follows:
Estimated
Useful Life March 31, December 31,
in Years 2002 2001
---------------------------------------------------
Plants and pipelines 5-35 $1,562,015 $1,398,843
Underground and other storage facilities 5-35 249,108 127,900
Transportation equipment 3-35 3,682 3,736
Land 15,437 15,517
Construction in progress 57,153 98,844
-------------------------------------
Total 1,887,395 1,644,840
Less accumulated depreciation 352,199 338,050
-------------------------------------
Property, plant and equipment, net $1,535,196 $1,306,790
=====================================
4. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
We own interests in a number of related businesses that are accounted for under the equity or cost method. The investments in and
advances to these unconsolidated affiliates are grouped according the operating segment to which they relate. For a general
discussion of our operating segments, see Note 11.
We acquired three equity method unconsolidated affiliates as part of our acquisition of Diamond-Koch's propylene fractionation
business (see Note 2). We purchased an aggregate 50% interest in La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C.
(collectively, "La Porte") which together own a private polymer grade propylene pipeline extending from Mont Belvieu to La Porte,
Texas. In addition, we acquired 50% of the outstanding capital stock of Olefins Terminal Corporation ("OTC") which owns a polymer
grade propylene storage facility and related dock infrastructure (located on the Houston Ship Channel) for loading waterborne
propylene vessels. Both the La Porte and OTC investments are an integral part of our Mont Belvieu III propylene fractionation
PAGE 26
operations. These investments are classified as part of our Fractionation operating segment.
The following table shows investments in and advances to unconsolidated affiliates at:
Ownership March 31, December 31,
Percentage 2002 2001
--------------------------------------------------------
Accounted for on equity basis:
Fractionation:
BRF 32.25% $ 29,309 $ 29,417
BRPC 30% 18,360 18,841
Promix 33.33% 44,186 45,071
La Porte 50% 5,740
OTC 50% 1,690
Pipeline:
EPIK 50% 14,870 14,280
Wilprise 37.35% 8,671 8,834
Tri-States 33.33% 26,812 26,734
Belle Rose 41.67% 11,559 11,624
Dixie 19.88% 38,276 37,558
Starfish 50% 25,968 25,352
Neptune 25.67% 76,857 76,880
Nemo 33.92% 12,167 12,189
Evangeline 49.5% 2,546 2,578
Octane Enhancement:
BEF 33.33% 61,281 55,843
Accounted for on cost basis:
Processing:
VESCO 13.1% 33,000 33,000
----------------------------------------
Total $411,292 $398,201
========================================
PAGE 27
The following table shows equity in income (loss) of unconsolidated affiliates for the quarters ended March 31, 2002 and 2001:
Ownership Quarter Ended March 31,
----------------------------------
Percentage 2002 2001
---------------------------------------------------
Fractionation:
BRF 32.25% $ 549 $ 18
BRPC 30% 249 152
Promix 33.33% 1,043 393
La Porte 50% (92)
OTC 50% (110)
Pipelines:
EPIK 50% 1,683 (922)
Wilprise 37.35% 147 (222)
Tri-States 33.33% 469 (35)
Belle Rose 41.67% 74 (89)
Dixie 19.88% 717 891
Starfish 50% 812 951
Ocean Breeze 25.67% 2
Neptune 25.67% 778 694
Nemo 33.92% (22) 9
Evangeline 49.5% (76) -
Octane Enhancement:
BEF 33.33% 3,006 169
----------------------------------
Total $9,227 $2,011
==================================
The initial investment we made in certain equity method unconsolidated affiliates exceeded our share of the historical cost of
underlying net assets of such entities. Under this scenario, "excess cost" is recorded for the excess of the purchase price (or
cost) of the investment over our underlying net assets of the investee. We have excess cost associated with our investments in
Promix, La Porte, Dixie, Neptune and Nemo. The excess cost of these investments is reflected in our investments in and advances to
unconsolidated affiliates for these entities. Since each of these excess cost amounts relates to the plant and pipeline assets of
each entity, the excess cost of each is amortized to equity earnings from these entities in a manner similar to depreciation. The
following table summarizes our excess cost information:
Amortization
Charged to
Initial Unamortized balance at Equity Earnings
----------------------------------
Excess March 31, December 31, during Amortization
Cost 2002 2001 2002 Period
-----------------------------------------------------------------------------------------
Fractionation segment:
Promix $7,955 $6,894 $7,083 $99 20 years
La Porte 873 866 n/a 7 35 years
Pipelines segment:
Dixie 37,694 35,445 35,714 269 35 years
Neptune 12,768 12,312 12,404 91 35 years
Nemo 727 713 718 5 35 years
PAGE 28
The following table presents summarized income statement information for our unconsolidated investments accounted for under the
equity method (for the periods indicated on a 100% basis).
Summarized Income Statement Data for the Quarter Ended
-------------------------------------------------------------------------------------------------
March 31, 2002 March 31, 2001
----------------------------------------------- ------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
----------------------------------------------- ------------------------------------------------
Fractionation:
BRF $ 4,606 $ 1,665 $ 1,702 $ 4,023 $ 35 $ 56
BRPC 2,951 819 829 3,433 439 505
Promix 9,864 3,410 3,428 9,002 1,440 1,477
La Porte (234) (235)
OTC 619 (308) (352)
Pipelines:
EPIK 8,305 3,388 3,400 691 (1,891) (1,862)
Wilprise 772 393 394 398 (602) (594)
Tri-States 3,099 1,401 1,406 1,632 (126) (105)
Belle Rose 507 176 177 147 (219) (213)
Dixie 15,128 7,402 4,520 19,327 9,649 5,834
Starfish 6,429 1,936 1,626 6,616 2,098 1,902
Ocean Breeze 20 12 12
Neptune 7,703 3,516 3,307 7,409 3,148 3,369
Nemo 395 (74) (70) (16) 28
Evangeline 25,509 850 (179)
Octane Enhancement:
BEF 47,929 8,978 9,019 37,864 413 507
----------------------------------------------- ------------------------------------------------
Total $133,816 $33,318 $28,972 $90,562 $14,380 $10,916
=============================================== ================================================
5. RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other
Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June
30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001.
There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by
the purchase method. SFAS No. 142 was effective for our fiscal year that began January 1, 2002 for all goodwill and other intangible
assets recognized in our consolidated balance sheet at that date, regardless of when those assets were initially recognized. We
adopted SFAS No. 141 and SFAS No. 142 on January 1, 2002.
At December 31, 2001, our intangible assets were comprised of the values associated with the Shell natural gas processing agreement
and the goodwill related to the 1999 MBA acquisition. In accordance with the new standard, we reclassified the goodwill to a
separate line item on our consolidated balance sheet apart from the Shell contract. Based upon our initial interpretation of the
standard, the Shell natural gas processing agreement will continue to be amortized over its 20-year contract term; however,
amortization of the MBA acquisition goodwill will cease due to its indefinite life. Our goodwill will be subject to periodic
impairment testing in accordance with SFAS No. 142. For additional information regarding our intangible assets and goodwill
including additions to both classes of assets as a result of the Diamond-Koch acquisitions, see Note 2.
Within six months of our adoption of SFAS No. 142 (by June 30, 2002), we will have completed a transitional impairment review to
identify if there is an impairment to the December 31, 2001 recorded goodwill or intangible assets of indefinite life using a fair
value methodology. Professionals in the business valuation industry will be consulted to validate the assumptions used in such
methodologies. Any impairment loss resulting from the transitional impairment test will be recorded as a cumulative effect of a
PAGE 29
change in accounting principle for the quarter ended June 30, 2002. Subsequent impairment losses will be reflected in operating
income in the Statements of Consolidated Operations. We are continuing to evaluate the complex provisions of SFAS No. 142 and will
fully adopt the standard during 2002 within the prescribed time periods.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset Retirement Obligations", in June
2001. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement
obligation and the associated asset retirement cost. This statement is effective for our fiscal year beginning January 1, 2003. We
are continuing to evaluate the provisions of this statement. In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". This statement addresses financial accounting and reporting for the impairment and/or
disposal of long-lived assets. We adopted this statement effective January 1, 2002 and determined that it did not have any
significant impact on our financial statements as of that date.
6. INTANGIBLE ASSETS
Intangible assets
Our recorded intangible assets primarily include the estimated value assigned to certain contract-based assets representing the
rights we own arising from contractual agreements. According to SFAS No. 141, a contract-based intangible with a finite useful life
is amortized over its estimated useful life, which is the period over which the asset is expected to contribute directly or
indirectly to the future cash flows of the entity. It is based on an analysis of all pertinent factors including (a) the expected
use of the asset by the entity, (b) the expected useful life or related assets (i.e., fractionation facility, storage well, etc.),
(c) any legal, regulatory or contractual provisions, including renewal or extension periods that would not cause substantial costs or
modifications to existing agreements, (d) the effects of obsolescence, demand, competition, and other economic factors and (e) the
level of maintenance required to obtain the expected future cash flows.
At March 31, 2002, our intangible assets primarily consisted of the Shell natural gas processing agreement that we acquired as a
result of the TNGL acquisition in August 1999 and certain propylene fractionation and storage contracts we acquired in connection
with our Diamond-Koch acquisitions in January and February 2002. The value of the Shell natural gas processing agreement is being
amortized on a straight-line basis over its 20-year contract term (currently $11.1 million annually from 2002 through 2019). If the
economic life of this contract were later determined to be impaired due to negative changes in Shell's natural gas exploration and
production activities in the Gulf of Mexico, then we might need to reduce the amortization period of this asset to less than the
contractually-stated 20-year life of the agreement. Such a change would increase the annual amortization charge at that time. At
March 31, 2002, the unamortized value of the Shell contract was $191.6 million.
The value of the propylene fractionation and storage contracts acquired from Diamond-Koch is being amortized on a straight-line basis
over the economic life of the assets to which they relate, which is currently estimated at 35 years. Although the majority of these
contracts have terms of one to two years, we have assumed that our relationship with these customers will extend beyond the
contractually-stated term primarily based on historical low customer contract turnover rates within these operations. If the
economic life of the assets were later determined to be impaired due to negative changes within the industry or otherwise, then we
might need to reduce the amortization period of these contract-based assets to less than 35 years. Such a change would increase
amortization expense at that time. At March 31, 2002, the unamortized value of these contracts was $60.5 million
The specific, identifiable intangible assets of a business enterprise depend largely upon the nature of its operations. Potential
intangible assets include intellectual property such as technology, patents, trademarks and trade names, customer contracts and
relationships, and non-compete agreements, as well as other intangible assets. The approach to the valuation of each intangible
asset will vary depending upon the nature of the asset, the business in which it is utilized, and the economic returns it is
generating or is expected to generate.
PAGE 30
Goodwill
At March 31, 2002, the value of recorded goodwill was $81.1 million. Our goodwill is primarily attributable to the excess of the
purchase price over the fair value of assets acquired from Diamond-Koch in early 2002 and from Kinder Morgan and EPCO in July 1999.
Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill amounts are no longer amortized. Instead, we routinely review
the reporting units to which the goodwill amounts relate for indications of possible impairment. If such indicators are present
(i.e., loss of a significant customer, economic obsolescence of plant assets, etc.), the fair value of the reporting unit, including
its related goodwill, is calculated and compared to its combined book value. Our goodwill is recorded as part of the Fractionation
operating segment since it is wholly attributed to acquired assets included in this operating segment.
The fair value of a reporting unit refers to the amount at which it could be bought or sold in a current transaction between willing
parties. Quoted market prices in active markets are the best evidence of fair value and are used to the extent they are available.
If quoted market prices are not available, an estimate of fair value is determined based on the best information available to us,
including prices of similar assets and the results of using other valuation techniques such as discounted cash flow analysis and
multiples of earnings approaches. The underlying assumptions in such models rely on information available to us at a given point in
time and are viewed as reasonable and supportable considering available evidence.
If the fair value of the reporting unit exceeds its book value, goodwill is not considered impaired and no adjustment to earnings
would be required. Should the fair value of the reporting unit (including its goodwill) be less than its book value, a charge to
earnings would be recorded to adjust goodwill to its implied fair value.
Pro Forma impact of discontinuation of amortization of goodwill
The following table discloses the pro forma impact on earnings of our discontinuation of the amortization of goodwill related to the
MBA acquisition (for the first quarter of 2001).
Reported net income $52,270
Discontinue goodwill amortization 111
Adjust minority interest expense (1)
----------------
Adjusted net income $52,380
================
On a pro forma basis, earnings per Unit (both basic and diluted) were not affected by the discontinuation of goodwill amortization
due to the immaterial nature of the pro forma adjustment.
PAGE 31
7. DEBT OBLIGATIONS
Our long-term debt consisted of the following at:
March 31, December 31,
2002 2001
---------------------------------------
Borrowings under:
Senior Notes A, 8.25% fixed rate, due March 2005 $ 350,000 $350,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000 450,000
Multi-Year Credit Facility, due November 2005 230,000
364-Day Credit Facility, due November 2002 (a) 83,000
First Union Facility, due April 2002 50,000
---------------------------------------
Total principal amount 1,217,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,955 1,653
Less unamortized discount on:
$350 Million Senior Notes (108) (117)
$450 Million Senior Notes (251) (258)
Less current maturities of debt (50,000) -
---------------------------------------
Long-termdebt $1,168,596 $855,278
=======================================
(a) Under the terms of this facility, the Operating Partnership has the option to convert this facility into a term loan due November
15, 2003. Management intends to refinance this obligation with a similar obligation at maturity.
At March 31, 2002, we had a total of $75 million of standby letters of credit capacity under our Multi-Year Credit Facility of which
$18.6 million was outstanding.
Our parent, Enterprise Products Partners L.P. acts as guarantor of certain of our debt obligations. This parent-subsidiary guaranty
provision exists under our Senior Notes, MBFC Loan, Multi-Year and 364-Day Credit Facility.
In April 2002, we increased the amount that we can borrow under the Multi-Year Credit Facility by $20 million and the 364-Day Credit
Facility by $80 million, up to an amount not exceeding $500 million in the aggregate for both facilities. At March 31, 2002, we had
borrowed $313 million under these two facilities; the majority of which was related to the acquisition of Diamond-Koch's propylene
fractionation business in February 2002 (see Note 2). In anticipation of the increased borrowing limits under the Multi-Year and
364-Day Credit Facilities, we borrowed $50 million under a short-term supplemental credit facility that was repaid in late April 2002
with proceeds from the increased availability under the Multi-Year and 364-Day Credit Facility.
The indentures under which the Senior Notes and the MBFC Loan were issued contain various restrictive covenants. We were in
compliance with these covenants at March 31, 2001.
In April 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were amended to allow for increased financial
flexibility. The significant changes are as follows (capitalized terms used herein are defined within the credit agreements):
o We were granted increased flexibility under our Consolidated Indebtedness to Consolidated EBITDA ratio for the rolling-four
quarter period which ends on September 30, 2002. The maximum ratio allowed by our lenders was temporarily raised to 4.5 to
1.0 from 4.0 to 1.0. This modification was required as a result of the hedging losses we incurred during the first quarter
of 2002.
o In addition, we are allowed to exclude from the calculation of Consolidated EBITDA up to $50 million in losses resulting
from hedging NGLs that utilized natural gas-based financial instruments entered into on or prior to April 24, 2002. This
exclusion applies to our quarterly Consolidated EBITDA calculations in which in the financial impact of such specific
PAGE 32
instruments were recorded (ending with the calculation for the third quarter of 2003 due to the rolling-four quarter nature
of the calculation).
We were in compliance with the covenants of our revolving credit agreements at March 31, 2002.
8. PARENT'S UNITS ACQUIRED BY TRUST
During the first quarter of 1999, we established the EPOLP 1999 Grantor Trust (the "Trust") to fund potential future obligations
under EPCO's long-term incentive plan (through the exercise of Common Unit options granted to directors of the General Partner and
EPCO employees who participate in our business). The Common Units of our parent purchased by the Trust are accounted for in a manner
similar to treasury stock under the cost method of accounting. At March 31, 2002, the Trust held 204,600 Common Units. The Trust
purchased 41,000 Common Units during the first quarter of 2002 at a cost of $2.0 million.
The Trust is a party to our parent's Unit Buy-Back Program under which the Trust and our parent can repurchase up to 1.0 million
Common Units through July 2002. The Common Unit purchases made during the first quarter of 2002 were under this program. At March
31, 2002, 534,200 Common Units could be repurchased under this program by the Trust or our parent separately or in combination.
Purchases made by our parent will be funded by intercompany loans between us and our parent that will be settled on a quarterly basis.
9. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Quarter Ended March 31,
-------------------------------------
2002 2001
-------------------------------------
(Increase) decrease in:
Accounts and notes receivable $1,439 $ 89,185
Inventories (25,892) 68,452
Prepaid and other current assets (2,494) (1,824)
Other assets (3,186) (1,128)
Increase (decrease) in:
Accounts payable (13,369 (31,689)
Accrued gas payable 25,014 (100,315)
Accrued expenses (6,588) (11,391)
Accrued interest (16,137) (2,521)
Other current liabilities (10,891) (16,661)
Other liabilities (81) (57)
-------------------------------------
Net effect of changes in operating accounts $(52,185) $ (7,949)
=====================================
In January and February of 2002, we paid Diamond-Koch $368.6 million for its propylene fractionation and NGL and petrochemical
storage businesses located in Mont Belvieu, Texas. The allocation of the purchase price affected various balance sheet accounts.
See Note 2 for information regarding the allocation of the purchase price for these acquisitions.
We record various financial instruments relating to commodity positions and interest rate swaps at their respective fair values using
mark-to-market accounting. For the quarter ended March 31, 2002, we recognized a net $30.1 million in non-cash mark-to-market losses
related to decreases in the fair value of these financial instruments, primarily in our commodity financial instruments portfolio.
For the quarter ended March 31, 2001, we recognized a net $16.4 million in non-cash mark-to-market income from our financial
instruments portfolio.
PAGE 33
Cash and cash equivalents at March 31, 2002 per the Statements of Consolidated Cash Flows excludes $14.5 million of restricted cash
representing amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for physical
purchase transactions made on the NYMEX exchange.
10. FINANCIAL INSTRUMENTS
We are exposed to financial market risks, including changes in commodity prices in our natural gas and NGL businesses and in interest
rates with respect to a portion of our debt obligations. We may use financial instruments (i.e., futures, forwards, swaps, options,
and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated
transactions, primarily in our Processing segment. As a matter of policy, we do not use financial instruments for speculative (or
trading) purposes.
Commodity financial instruments
Our Processing and Octane Enhancement segments are directly exposed to commodity price risk through their respective business
operations. The prices of natural gas, NGLs and MTBE are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with our
Processing segment, we may enter into swaps, forwards, commodity futures, options and other commodity financial instruments with
similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial
instrument. The primary purpose of these risk management activities (or hedging strategies) is to hedge exposure to price risks
associated with natural gas, NGL inventories, firm commitments and certain anticipated transactions. We do not hedge our exposure
to the MTBE markets. Also, in our Pipelines segment, we may utilize a limited number of commodity financial instruments to manage
the price Acadian Gas charges certain of its customers for natural gas.
We have adopted a commercial policy to manage our exposure to the risks of its natural gas and NGL businesses. The objective of this
policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined
as remaining within the position limits established by the General Partner. Under this policy, we enter into risk management
transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term
(less than one month) and long-term basis, generally not to exceed 24 months. The General Partner oversees our hedging strategies
associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy
(including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and
ensuring compliance with the policy.
We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some
financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on
the specific exposure. When this occurs, we may enter into a new commodity financial instrument to reestablish the economic hedge to
which the closed instrument relates.
Our commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133
because of ineffectiveness. A hedge is normally regarded as effective if, among other things, at inception and throughout the term
of the financial instrument, we could expect changes in the fair value of the hedged item to be almost fully offset by the changes in
the fair value of the financial instrument. When financial instruments do not qualify as effective hedges under the guidelines of
SFAS No. 133, changes in the fair value of these positions are recorded on the balance sheet and in earnings through mark-to-market
accounting. The use of mark-to-market accounting for these ineffective instruments results in a degree of non-cash earnings
volatility that is dependent upon changes in the underlying commodity prices. Although our financial instruments may from time to
time be regarded as ineffective hedges under SFAS No. 133, we continue to view these instruments as hedges (i.e., "economic hedges")
inasmuch as this was the intent when such contracts were executed. This characterization is consistent with the actual economic
performance of these contracts to date and we expect our economic hedges to continue to mitigate (or offset) commodity price risk in
the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS No. 133.
PAGE 34
We recognized a loss of $45.1 million in the first quarter of 2002 from our commodity hedging activities that is treated as an
increase in operating costs and expenses in our Statements of Consolidated Operations. Of this amount, $16.4 million has been
realized (e.g., paid out to counterparties). The remaining $28.7 million represents the negative change in value of
the open positions between December 31, 2001 and March 31, 2002 (based on market prices at those dates). The market value of our open
positions at March 31, 2002 was $20.8 million payable (a loss). For the first quarter of 2001, we recognized income of $5.6 million
from these activities, which included the positive impact of the portfolio's March 31, 2001 value of $13.5 million receivable
(recorded as income).
Interest rate swaps
Our interest rate exposure results from variable-rate borrowings from commercial banks and fixed-rate borrowings pursuant to the
Company's Senior Notes and MBFC Loan. We manage a portion of our exposure to changes in interest rates by utilizing interest rate
swaps. The objective of holding interest rate swaps is to manage debt service costs by converting a portion of fixed-rate debt into
variable-rate debt or a portion of variable-rate debt into fixed-rate debt. An interest rate swap, in general, requires one party to
pay a fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount.
The General Partner oversees the strategies associated with financial risks and approves instruments that are appropriate for our
requirements. At March 31, 2002, we had one interest rate swap outstanding having a notional amount of $54 million extending
through March 2010 . Under this agreement, we exchanged a fixed-rate of 8.70% for a market-based variable-rate. If it elects to
do so, the counterparty may terminate this swap in March 2003.
We recognized income of $0.1 million during the first quarter of 2002 from our interest rate swaps that is treated as a reduction of
interest expense. The fair value of the interest rate swap at March 31, 2002 was a receivable of $2.4 million. We recognized
income of $5.2 million during the first quarter of 2001 from interest rate swaps. The benefit recorded in 2001 was primarily due to
the election of a counterparty to not terminate its interest rate swap early.
11. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial information is available and that are regularly
evaluated by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Generally,
financial information is required to be reported on the basis that it is used internally for evaluating segment performance and
deciding how to allocate resources to segments.
We have five reportable operating segments: Fractionation, Pipelines, Processing, Octane Enhancement and Other. The reportable
segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold,
as applicable. The segments are regularly evaluated by the Chief Executive Officer of the General Partner. Fractionation primarily
includes NGL fractionation, isomerization, and polymer grade propylene fractionation services. Pipelines consists of both liquids
and natural gas pipeline systems, storage and import/export terminal services. Processing includes the natural gas processing
business and its related merchant activities. Octane Enhancement represents our equity interest in BEF, 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.
We evaluate segment performance based on gross operating margin. Gross operating margin reported for each segment represents
operating income before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of
assets and general and administrative expenses. In addition, segment gross operating margin is exclusive of interest expense,
interest income (from unconsolidated affiliates or others), dividend income from unconsolidated affiliates, minority interest,
extraordinary charges and other income and expense transactions.
We include equity earnings from unconsolidated affiliates in segment gross operating margin and as a component of revenues. Our
equity investments with industry partners are a vital component of our business strategy and a means by which we conduct our
PAGE 35
operations to align our interests with a supplier of raw materials to a facility or a consumer of finished products from a facility.
This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business
risk assumed versus what we could accomplish on a stand alone basis. Many of these businesses perform supporting or complementary
roles to our other business operations. For example, we use the Promix NGL fractionator to process NGLs extracted by our gas
plants. The NGLs received from Promix then can be sold by our merchant businesses. Another example would be our relationship with
the BEF MTBE facility. Our isomerization facilities process normal butane for this plant and our HSC pipeline transports MTBE for
delivery to BEF's storage facility on the Houston Ship Channel.
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.
Consolidated intangible assets and goodwill are allocated to the segments based on the classification of the assets to which they
relate. The increase in intangible assets and goodwill during the first quarter of 2002 is attributable to the Diamond-Koch
acquisitions (see Note 2).
Segment gross operating margin is inclusive of intersegment revenues, which are generally based on transactions made at
market-related rates. These revenues have been eliminated from the consolidated totals.
PAGE 36
Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table:
Operating Segments
------------------------------------------------------------------- Adjs.
Octane and Consol.
Fractionation Pipelines Processing Enhancement Other Elims. Totals
---------------------------------------------------------------------------------------------
Revenues from
external customers:
First Quarter 2002 $109,422 $99,081 $453,034 $517 $662,054
First Quarter 2001 89,679 7,187 738,769 680 836,315
Intersegment revenues:
First Quarter 2002 33,397 24,510 126,260 100 $(184,267)
First Quarter 2001 41,652 20,779 110,309 95 (172,835)
Equity income in
unconsolidated affiliates:
First Quarter 2002 1,639 4,582 $3,006 9,227
First Quarter 2001 562 1,280 169 2,011
Total revenues:
First Quarter 2002 144,458 128,173 579,294 3,006 617 (184,267) 671,281
First Quarter 2001 131,893 29,246 849,078 169 775 (172,835) 838,326
Gross operating margin
by segment:
First Quarter 2002 24,377 32,668 (33,376) 3,006 (262) 26,413
First Quarter 2001 25,668 18,123 28,398 169 535 72,893
Segment assets:
At March 31, 2002 444,793 897,139 127,842 8,269 57,153 1,535,196
At December 31, 2001 357,122 717,348 124,555 8,921 98,844 1,306,790
Investments in and advances
to unconsolidated
affiliates:
At March 31, 2002 99,285 217,726 33,000 61,281 411,292
At December 31, 2001 93,329 216,029 33,000 55,843 398,201
Intangible Assets:
At March 31, 2002 52,748 7,788 191,606 252,142
At December 31, 2001 7,857 194,369 202,226
Goodwill:
At March 31, 2002 81,135 81,135
Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Our operations are
centered along the Texas, Louisiana and Mississippi Gulf Coast areas.
PAGE 37
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
Quarter Ended March 31,
----------------------------------
2002 2001
----------------------------------
Total segment gross operating margin $ 26,413 $72,893
Depreciation and amortization (17,237) (10,029)
Retained lease expense, net (2,305) (2,660)
(Gain) loss on sale of assets (13) 381
Selling, general and administrative (7,786) (6,168)
----------------------------------
Consolidated operating income (loss) (928) 54,417
Interest expense (18,513) (6,987)
Interest income from unconsolidated affiliates 30 12
Dividend income from unconsolidated affiliates 954 1,632
Interest income - other 1,436 4,145
Other, net (77) (280)
----------------------------------
Consolidated income (loss) before minority interest $(17,098) $52,939
==================================
PAGE 38
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
For the interim periods ended March 31, 2002 and 2001.
Enterprise Products Partners L.P. is a publicly-traded master limited partnership (NYSE, symbol "EPD") that conducts substantially
all of its business through its 98.9899% owned subsidiary, Enterprise Products Operating L.P. (the "Operating Partnership"), the
Operating Partnership's subsidiaries, and a number of investments with industry partners. Since the Operating Partnership owns
substantially all of Enterprise Products Partners L.P.'s consolidated assets and conducts substantially all of its business and
operations, the information set forth herein constitutes combined information for the two registrants. Unless the context requires
otherwise, references to "we","us","our" or the "Company" are intended to mean the consolidated business and operations of Enterprise
Products Partners L.P., which includes Enterprise Products Operating L.P. and its subsidiaries.
The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes
thereto of the Company and Operating Partnership included in Part I of this report on Form
10-Q.
General
Our Company was formed in April 1998 to acquire, own and operate all of the natural gas liquid ("NGL") processing and distribution
assets of Enterprise Products Company ("EPCO"). We are a leading North American provider of a wide range of midstream energy
services to our customers located primarily along the central and western Gulf Coast. Our services include the:
o gathering, transmission and storage of natural gas from both onshore and offshore Louisiana developments;
o purchase and sale of natural gas in south Louisiana;
o processing of natural gas into a saleable and transportable product that meets industry quality specifications by removing
NGLs and impurities;
o fractionation of 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 conversion of normal butane to isobutane through the process of isomerization;
o production of MTBE from isobutane and methanol;
o transportation of NGL products to customers by pipeline and railcar;
o production of high purity propylene from refinery-sourced propane/propylene mix;
o import and export of certain NGL and petrochemical products through our dock facilities;
o transportation of high purity propylene by pipeline; and
o storage of NGL and petrochemical products.
Our General Partner, Enterprise Products GP, LLC, owns a 1.0% general partner interest in the Company and a 1.0101% general partner
interest in the Operating Partnership. Our principal executive offices are located at 2727 North Loop West, Houston, Texas
77008-1038 and our telephone number is 713-880-6500.
Recent acquisitions and other investments
In January 2002, we completed the acquisition of Diamond-Koch's Mont Belvieu storage assets from affiliates of Valero Energy
Corporation and Koch Industries, Inc. for $129.6 million. These facilities include 30 storage wells with a useable capacity of 68
MMBbls and allow for the storage of mixed NGLs, ethane, propane, butanes, natural gasoline and olefins (such as ethylene), polymer
grade propylene, chemical grade propylene and refinery grade propylene. With the inclusion of the former D-K facilities we own and
operate 95 MMBbls of storage capacity at Mont Belvieu, one of the largest such facilities in the world. In addition, we completed
the purchase of Diamond-Koch's 66.7% interest in a propylene fractionation facility and related assets in February 2002 at a cost of
approximately $239 million. Including this purchase, we effectively own 58.3 MBPD of net propylene fractionation capacity in Mont
Belvieu and have access to additional customers at this key industry hub.
PAGE 39
Cautionary Statement regarding Forward-Looking Information and Risk Factors
This quarterly report on Form 10-Q contains various forward-looking statements and information that are based on our beliefs and
those of the General Partner, as well as assumptions made by and information currently available to us. When used in this document,
words such as "anticipate", "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 we and the General Partner believe that such expectations reflected in such forward-looking statements are
reasonable, neither we nor the General Partner can give any assurance that such expectations will prove to be correct. Such
statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties
materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those we anticipated,
estimated, projected or expected.
An investment in our debt or equity securities involves a degree of risk. Among the key risk factors that may have a direct bearing
on our results of operations and financial condition are:
o competitive practices in the industries in which we compete;
o fluctuations in oil, natural gas and NGL prices and production due to weather and other natural and economic forces;
o operational and systems risks;
o environmental liabilities that are not covered by indemnity or insurance;
o the impact of current and future laws and governmental regulations (including environmental regulations) affecting the
midstream energy industry in general and our NGL and natural gas operations in particular;
o the loss of a significant customer;
o the use of financial instruments to hedge commodity and other risks which prove to be economically ineffective; and
o the failure to complete one or more new projects on time or within budget.
The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of
additional factors that are beyond our control. These factors include the level of domestic oil, natural gas and NGL production and
development, the availability of imported oil and natural gas, actions taken by foreign oil and natural gas producing nations and
companies, the availability of transportation systems with adequate capacity, the availability of competitive fuels and products,
fluctuating and seasonal demand for oil, natural gas and NGLs, and conservation and the extent of governmental regulation of
production and the overall economic environment.
In addition we must obtain access to new natural gas volumes for our processing business in order to maintain or increase gas plant
throughput levels to offset natural declines in field reserves. The number of wells drilled by third parties to obtain new volumes
will depend on, among other factors, the price of gas and oil, the energy policy of the federal government and the availability of
foreign oil and gas, none of which is in our control.
The products that we process, sell or transport are principally used as feedstocks in petrochemical manufacturing and in the
production of motor gasoline and as fuel for residential and commercial heating. A reduction in demand for our products or services
by industrial customers, whether because of general economic conditions, reduced demand for the end products made with NGL products,
increased competition from petroleum-based products due to pricing differences, adverse weather conditions, governmental regulations
affecting prices and production levels of natural gas or the content of motor gasoline or other reasons, could have a negative impact
on our results of operation. A material decrease in natural gas production or crude oil refining, as a result of depressed commodity
prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in volumes processed and sold by us.
Lastly, our expectations regarding future capital expenditures are only forecasts regarding these matters. These forecasts may be
substantially different from actual results due to various uncertainties including the following key factors: (a) the accuracy of
our estimates regarding capital spending requirements, (b) the occurrence of any unanticipated acquisition opportunities, (c) the
need to replace unanticipated losses in capital assets, (d) changes in our strategic direction and (e) unanticipated legal,
\
PAGE 40
regulatory and contractual impediments with regards to our construction projects.
For a description of the tax and other risks of owning our Common Units or the Operating Partnership's debt securities, see our
registration documents (together with any amendments thereto) filed with the SEC on Forms S-1 and S-3. Our SEC File number is
1-14323 and our Operating Partnership's SEC File number is 333-93239-01.
Our accounting policies
In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements. These methods, estimates
and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware
that actual results could differ from these estimates should the underlying assumptions prove to be incorrect. Examples of these
estimates and assumptions include depreciation methods and estimated lives of property, plant and equipment, amortization methods and
estimated lives of qualifying intangible assets, methods employed to measure the fair value of goodwill, revenue recognition policies
and mark-to-market accounting procedures. The following describes the estimation risk in each of these significant financial
statement items:
o Property, plant and equipment. Property, plant and equipment is recorded at cost and is depreciated using the
straight-line method over the asset's estimated useful life. Our plants, pipelines and storage facilities have estimated
useful lives of five to 35 years. Our miscellaneous transportation equipment have estimated useful lives of three to 35
years. Depreciation is the systematic and rational allocation of an asset's cost, less its residual value (if any), to the
periods it benefits. Straight-line depreciation results in depreciation expense being incurred evenly over the life of the
asset. The determination of an asset's estimated useful life must take a number of factors into consideration, including
technological change, normal depreciation and actual physical usage. If any of these assumptions subsequently change, the
estimated useful life of the asset could change and result in an increase or decrease in depreciation expense.
Additionally, if we determine that an asset's undepreciated cost may not be recoverable due to economic obsolescence, the
business climate, legal or other factors, we would review the asset for impairment and record any necessary reduction in the
asset's value as a charge against earnings. At March 31, 2002 and December 31, 2001, the net book value of our property,
plant and equipment was $1.5 billion and $1.3 billion, respectively.
o Intangible assets. The specific, identifiable intangible assets of a business enterprise depend largely upon the
nature of its operations. Potential intangible assets include intellectual property such as technology, patents, trademarks
and trade names, customer contracts and relationships, and non-compete agreements, as well as other intangible assets. The
approach to the valuation of each intangible asset will vary depending upon the nature of the asset, the business in which
it is utilized, and the economic returns it is generating or is expected to generate.
Our recorded intangible assets primarily include the estimated value assigned to certain contract-based assets representing
the rights we own arising from contractual agreements. According to SFAS No. 141, a contract-based intangible with a finite
useful life is amortized over its estimated useful life, which is the period over which the asset is expected to contribute
directly or indirectly to the future cash flows of the entity. It is based on an analysis of all pertinent factors
including (a) the expected use of the asset by the entity, (b) the expected useful life or related assets (i.e.,
fractionation facility, storage well, etc.), (c) any legal, regulatory or contractual provisions, including renewal or
extension periods that would not cause substantial costs or modifications to existing agreements, (d) the effects of
obsolescence, demand, competition, and other economic factors and (e) the level of maintenance required to obtain the
expected future cash flows.
At March 31, 2002, our intangible assets primarily consisted of the Shell natural gas processing agreement that we acquired
as a result of the TNGL acquisition in August 1999 and certain propylene fractionation and storage contracts we acquired in
connection with our Diamond-Koch acquisitions in January and February 2002. The value of the Shell natural gas processing
PAGE 41
agreement is being amortized on a straight-line basis over its 20-year contract term (currently $11.1 million annually from
2002 through 2019). If the economic life of this contract were later determined to be impaired due to negative changes in
Shell's natural gas exploration and production activities in the Gulf of Mexico, then we might need to reduce the
amortization period of this asset to less than the contractually-stated 20-year life of the agreement. Such a change would
increase the annual amortization charge at that time. At March 31, 2002, the unamortized value of the Shell contract was
$191.6 million.
The value of the propylene fractionation and storage contracts acquired from Diamond-Koch is being amortized on a
straight-line basis over the economic life of the assets to which they relate, which is currently estimated at 35 years.
Although the majority of these contracts have terms of one to two years, we have assumed that our relationship with these
customers will extend beyond the contractually-stated term primarily based on historical low customer contract turnover
rates within these operations. If the economic life of the assets were later determined to be impaired due to negative
changes within the industry or otherwise, then we might need to reduce the amortization period of these contract-based
assets to less than 35 years. Such a change would increase amortization expense at that time. At March 31, 2002, the
unamortized value of these contracts was $60.5 million.
o Goodwill. At March 31, 2002, the value of recorded goodwill was $81.1 million. Our goodwill is primarily
attributable to the excess of the purchase price over the fair value of assets acquired from Diamond-Koch in early 2002 and
from Kinder Morgan and EPCO in July 1999. Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill amounts are
no longer amortized. Instead, we have began to routinely review the reporting units to which the goodwill amounts relate
for indications of possible impairment. If such indicators are present (i.e., loss of a significant customer, economic
obsolescence of plant assets, etc.), the fair value of the reporting unit, including its related goodwill, is calculated and
compared to its combined book value. Our goodwill is recorded as part of the Fractionation operating segment.
The fair value of a reporting unit refers to the amount at which the it could be bought or sold in a current transaction
between willing parties. Quoted market prices in active markets are the best evidence of fair value and are used to the
extent they are available. If quoted market prices are not available, an estimate of fair value is determined based on the
best information available to us, including prices of similar assets and the results of using other valuation techniques
such as discounted cash flow analysis and multiples of earnings approaches. The underlying assumptions in such models rely
on information available to us at a given point in time and are viewed as reasonable and supportable considering available
evidence.
If the fair value of the reporting unit exceeds its book value, goodwill is not considered impaired and no adjustment to
earnings would be required. Should the fair value of the reporting unit (including its goodwill) be less than its book
value, a charge to earnings would be recorded to adjust goodwill to its implied fair value.
o Revenue recognition. In general, we recognize revenue from our customers when all of the following criteria are met:
(i) firm contracts are in place, (ii) delivery has occurred or services have been rendered, (iii) pricing is fixed and
determinable and (iv) collectibility is reasonably assured. When contracts settle (i.e., either physical delivery of
product has taken place or the services designated in the contract have been performed), we determine if an allowance is
necessary and record it accordingly. The revenues that we record are not materially based on estimates. We believe the
assumptions underlying any revenue estimates that we might use will not prove to be significantly different from actual
amounts due to the routine nature of these estimates and the stability of our operations.
Of the contracts that we enter into with customers, the majority fall within five main categories as described below:
o Tolling (or throughput) arrangements where we process or transport customer volumes for a cash fee (usually on a
per gallon or other unit of measurement basis);
o In-kind fractionation arrangements where we process customer mixed NGL volumes for a percentage of the end NGL
products in lieu of a cash fee (exclusive to our Norco NGL fractionation facility);
PAGE 42
o Merchant contracts where we sell products to customers at market-related prices for cash;
o Storage agreements where we store volumes or reserve storage capacity for customers for a cash fee; and
o Fee-based marketing services where we market volumes for customers for either a percentage of the final cash sales
price or a cash fee per gallon handled.
A number of tolling (or throughput) arrangements are utilized in our Fractionation and Pipeline segments. Examples include
NGL fractionation, isomerization and pipeline transportation agreements. Typically, we recognize revenue from tolling
arrangements once contract services have been performed. At times, the tolling fees we or our affiliates charge for
pipeline transportation services are regulated by such governmental agencies as the FERC. A special type of tolling
arrangement, an "in-kind" contract, is utilized by various customers at our Norco NGL fractionation facility. An in-kind
processing contract allows us to retain a contractually-determined percentage of NGL products produced for the customer in
lieu of a cash tolling fee per gallon. Revenue is recognized from these "in-kind" contracts when we sell (at market-related
prices) and deliver the fractionated NGLs that we retained.
Our Processing segment businesses employ tolling and merchant contracts. If a customer pays us a cash tolling fee for our
natural gas processing services, we record revenue to the extent that natural gas volumes have been processed and sent back
to the producer. If we retain mixed NGLs as our fee for natural gas processing services, we record revenue when the NGLs
(in mixed and/or fractionated product form) are sold and delivered to customers using merchant contracts. In addition to
the Processing segment, merchant contracts are utilized in the Fractionation segment to record revenues from the sale of
propylene volumes and in the Pipelines segment to record revenues from the sale of natural gas. Our merchant contracts are
generally based on market-related prices as determined by the individual agreements.
We have established an allowance for doubtful accounts to cover potential bad debts from customers. Our allowance amount
is generally determined as a percentage of revenues for the last twelve months. In addition, we may also increase the
allowance account in response to specific identification of customers involved in bankruptcy proceedings and the like. We
routinely review our estimates in this area to ascertain that we have recorded ample reserves to cover forecasted losses.
If unanticipated financial difficulties were to occur with a significant customer or customers, there is the possibility
that the allowance for doubtful accounts would need to be increased to bring the allowance up to an appropriate level based
on the new information obtained. Our allowance for doubtful accounts at March 31, 2002 and December 31, 2001 was $20.6
million.
o Fair value accounting for financial instruments. Our earnings are also affected by use of the mark-to-market method
of accounting required under GAAP for certain financial instruments. We use financial instruments such as swaps, forwards
and other contracts to manage price risks associated with inventories, firm commitments and certain anticipated
transactions, primarily within our Processing segment. Currently none of these financial instruments qualify for hedge
accounting treatment and thus the changes in fair value of these instruments are recorded on the balance sheet and through
earnings (i.e., using the "mark-to-market" method) rather than being deferred until the firm commitment or anticipated
transaction affects earnings. The use of mark-to-market accounting for financial instruments results in a degree of
non-cash earnings volatility that is dependent upon changes in underlying indexes, primarily commodity prices. Fair value
for the financial instruments we employ is determined using price data from highly liquid markets such as the NYMEX
commodity exchange.
For the quarter ending March 31, 2002, we recognized losses from our commodity hedging activities of $45.1 million. Of
this loss, $28.7 million is attributable to the negative change in market value of the portfolio since December 31, 2001
for positions still open at March 31, 2002. For additional information regarding our use of financial instruments to manage
risk and the earnings sensitivity of these instruments to changes in underlying commodity prices, see the Processing segment
discussion under "Our results of operations" and Item 3 of this report.
Additional information regarding our financial statements or those of the Operating Partnership can be found in the Notes to
Unaudited Consolidated Financial Statements of each entity included elsewhere in this report on
PAGE 43
Form 10-Q.
Our results of operations
We have five reportable operating segments: Fractionation, Pipelines, Processing, Octane Enhancement and Other. Fractionation
primarily includes NGL fractionation, isomerization and propylene fractionation. Pipelines consists of liquids and natural gas
pipeline systems, storage and import/export terminal services. Processing includes our natural gas processing business and related
merchant activities. Octane Enhancement represents our interest in a facility that produces motor gasoline additives to enhance
octane (currently producing MTBE). The Other operating segment primarily consists of fee-based marketing services.
Our management evaluates segment performance based on gross operating margin ("gross operating margin" or "margin"). Gross operating
margin 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. Segment gross operating margin is
exclusive of interest expense, interest income amounts, dividend income, minority interest, extraordinary charges and other income
and expense transactions.
We include equity earnings from unconsolidated affiliates in segment gross operating margin and as a component of revenues. Our
equity investments with industry partners are a vital component of our business strategy and a means by which we conduct our
operations to align our interests with a supplier of raw materials to a facility or a consumer of finished products from a facility.
This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business
risk assumed versus what we could accomplish on a stand alone basis. Many of these businesses perform supporting or complementary
roles to our other business operations. For example, we use the Promix NGL fractionator to process NGLs extracted by our gas
plants. The NGLs received from Promix then can be sold by our merchant businesses. Another example would be our relationship with
the BEF MTBE facility. Our isomerization facilities process normal butane for this plant and our HSC pipeline transports MTBE for
delivery to BEF's storage facility on the Houston Ship Channel.
Our gross operating margin by segment (in thousands of dollars) along with a reconciliation to consolidated operating income were as
follows for the periods indicated:
Quarter Ended March 31,
-----------------------------------
2002 2001
-----------------------------------
Gross Operating Margin by segment:
Fractionation $24,377 $25,668
Pipelines 32,668 18,123
Processing (33,376) 28,398
Octane enhancement 3,006 169
Other (262) 535
-----------------------------------
Gross Operating margin total 26,413 72,893
Depreciation and amortization 17,237 10,029
Retained lease expense, net 2,305 2,660
Loss (gain) on sale of assets 13 (381)
Selling, general and administrative expenses 7,962 6,168
-----------------------------------
Consolidated operating income (loss) $(1,104) $54,417
===================================
PAGE 44
Our significant plant production and other volumetric data were as follows for the periods indicated:
Quarter Ended March 31,
------------------------------------
2002 2001
------------------------------------
MBPD, Net
- ---------
Equity NGL Production 81 46
NGL Fractionation 204 165
Isomerization 74 70
Propylene Fractionation 63 30
Octane Enhancement 4 3
Major NGL and Petrochemical Pipelines 525 356
MMBtu/D, Net
- ------------
Natural Gas Pipelines 1,259,288 505,567
The following table illustrates selected average quarterly prices for natural gas, crude oil, selected NGL products and polymer grade
propylene since the January 2001:
Polymer
Natural Normal Grade
Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene,
$/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound
-----------------------------------------------------------------------------------------
(a) (b) (a) (a) (a) (a) (a)
Fiscal 2001:
First quarter (c) $7.00 $28.77 $0.49 $0.63 $0.70 $0.74 $0.23
Second quarter $4.61 $27.86 $0.37 $0.50 $0.56 $0.66 $0.19
Third quarter $2.84 $26.64 $0.27 $0.41 $0.49 $0.49 $0.16
Fourth quarter $2.38 $21.04 $0.21 $0.34 $0.40 $0.39 $0.18
Fiscal 2002:
First quarter $2.30 $21.41 $0.22 $0.30 $0.38 $0.44 $0.16
- ----------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL and polymer grade propylene prices represent an average of index prices
(b) Crude Oil price is representative of West Texas Intermediate
(c) Natural gas prices peaked at approximately $10 per MMBtu in January 2001
Three months ended March 31, 2002 compared to three months ended March 31, 2001
Revenues, costs and expenses and operating income (loss). Revenues were $671.3 million for the first quarter of
2002 compared to $838.3 million for the first quarter of 2001. Operating costs and expenses (including selling, general and
administrative charges) were $672.4 million for the first quarter of 2002 versus $783.9 million for the first quarter of 2001.
Operating results were a loss of $1.1 million for the first quarter of 2002 compared to income of $54.4 million for the first quarter
of 2001.
Revenues declined period to period primarily the result of lower NGL prices offset by an increase in revenues from our Pipeline
segment. Weighted-average NGL prices were 62 CPG in the first quarter of 2001 versus 33 CPG in the first quarter of 2002 primarily
due to the high price of natural gas and crude oil during the first quarter of 2001 which generally caused NGL prices to increase.
The decline in prices from period to period was offset by an overall increase in volumes handled at our facilities and pipelines in
the first quarter of 2002 relative to the same period in 2001. Revenues from our Pipelines segment increased primarily the result of
the Acadian acquisition which was completed during the second quarter of 2001.
PAGE 45
Operating costs and expenses decreased from period-to-period primarily due to a decline in natural gas expense: the average price of
natural gas declined from $7.00 per MMBtu in the first quarter of 2001 to $2.30 per MMBtu in the first quarter of 2002. The price
of natural gas in the first quarter of 2001 was initially driven by supply issues (particularly as they related to California and
other western U.S. states) and later turned into a more speculative market before prices began to moderate late in the first quarter
of 2001. Natural gas prices during most of the first quarter of 2002 were generally stable until mid-March 2002 when supply issues
began to resurface and create volatility in the marketplace.
As a result of this volatility in natural gas prices late in the first quarter of 2002, we recorded a $45.1 million loss on our
commodity hedging activities which is classified as an operating expense for the period. The loss was attributable to the
utilization of natural gas-based financial instruments to hedge the value of our NGL production related to our natural gas processing
operations. This compares to $5.6 million in income from these activities recorded during the first quarter of 2001 that was treated
as a reduction in operating expenses. This change resulted in a $50.7 million increase in operating costs and expenses
quarter-to-quarter. In addition to the commodity hedging loss, operating costs and expenses in our Pipelines segment increased as a
result of the Acadian acquisition mentioned previously. These increases were more than offset by the overall reduction in other
operating costs, particularly that of natural gas as a feedstock and as a fuel.
Fractionation. Gross operating margin from our Fractionation segment was $24.4 million for the first quarter of
2002 compared to $25.7 million for the first quarter of 2001. NGL fractionation margin decreased $1.1 million during the first
quarter of 2002 when compared to the first quarter of 2001. NGL fractionation net volumes improved to 204 MBPD during the first
quarter of 2002 versus 165 MBPD for the same period in 2001. NGL fractionation volumes during the first quarter of 2001 were
unusually low due to reduced NGL extraction rates at gas processing plants caused by abnormally high natural gas prices (which
resulted in a decrease in mixed NGL volumes available for fractionation). The decrease in NGL fractionation margin was primarily
due to certain non-routine maintenance charges at our Mont Belvieu facility and lower in-kind fees at our Norco plant (caused by
lower NGL prices in 2002 relative to 2001), partially offset by increased margins due to higher overall fractionation volumes at all
of our facilities.
Our isomerization business posted a $4.8 million decrease in margin for the first quarter of 2002 when compared to the first quarter
of 2001. Isomerization volumes increased to 74 MBPD during the 2002 period versus 70 MBPD during the 2001 period. The decrease in
margin is primarily due to lower isomerization revenues. Certain of our isomerization tolling fees are indexed to historical
natural gas prices and were positively impacted when the price of natural gas peaked during the first quarter of 2001.
For the first quarter of 2002, gross operating margin from propylene fractionation was $4.3 million higher than the first quarter of
2001. The first quarter of 2002 includes $3.1 million in margin from the propylene fractionation business we acquired from
Diamond-Koch in February 2002. The remainder of the increase in margin is primarily due to lower fuel costs at our other Mont
Belvieu propylene fractionation facilities attributable to the difference in natural gas prices between the two periods. Net
volumes at our propylene fractionation facilities increased to 63 MBPD for the first quarter of 2002 compared with 30 MBPD for the
first quarter of 2001. Of the increase in 2002 volumes, 34 MBPD is attributable to operations acquired from Diamond-Koch.
Pipelines. Our Pipelines segment posted a record quarterly gross operating margin of $32.7 million for the
first quarter of 2002, compared to $18.1 million for the first quarter of 2001. Liquids pipeline volumes increased to a record 525
MBPD during the first quarter of 2002 versus 356 MBPD during the first quarter of 2001. Natural gas pipeline throughput rates
increased to 1,259 Bbtu per day during the 2002 quarter compared to 506 Bbtu per day during the 2001 quarter. The increases are
attributable to a variety of sources, including the following:
o Our Acadian Gas natural gas pipeline business added $4.1 million in margin and accounted for 744 Bbtu/d of the increase in
natural gas throughput volumes. Acadian Gas was acquired from Shell in the second quarter of 2001.
o Margin from our Louisiana Pipeline System increased $3.2 million quarter-to-quarter primarily due to a 73% increase in
pipeline volumes to 185 MBPD for the 2002 period versus 107 MBPD during the 2001 period. NGL volumes transported by this
system were negatively impacted by the reduced NGL extraction rates at gas plants during the first quarter of 2001.
PAGE 46
o The Lou-Tex NGL pipeline posted a $2.3 million increase in margin quarter-to-quarter on a 76% increase in transport volumes
due to a strong demand for services. Volumes increased 17 MBPD quarter-to-quarter.
o Equity earnings from EPIK increased $2.6 million quarter-to-quarter on a 22 MBPD increase in export volumes for the first
quarter of 2002. Unusually high domestic prices for propane-related products in the first quarter of 2001 resulted in
decreased export opportunities. Product prices during the first quarter of 2002 presented EPIK with a more favorable
export environment.
o The acquisition of Diamond-Koch's NGL and petrochemical storage business in January 2002 contributed to a $1.9 million
increase in margin from our Mont Belvieu storage operations.
o For the first quarter of 2002, margin from our HSC pipeline system increased $0.9 million over the first quarter of 2001.
The increase in margin was primarily due to a 47 MBPD increase in transportation volumes of which the increase in EPIK's
exports played a key role.
Processing. Gross operating margin from our Processing segment was a loss of $33.4 million for the first
quarter of 2002 versus income of $28.4 million for the first quarter of 2001. This segment is comprised of our natural gas
processing business and related merchant activities and includes results of our commodity hedging strategies.
The $61.8 million margin decrease quarter-to-quarter is primarily due to losses from commodity hedging activities during the first
quarter of 2002. The first quarter of 2001 also benefited from strong propane heating demand that did not recur in the first
quarter of 2002.
Equity NGL production averaged 81 MBPD for the first quarter of 2002 versus 46 MBPD for the first quarter of 2001. Equity NGL
production during the first quarter of 2002 was adversely impacted by approximately 14 MBPD due to downtime at certain Gulf of Mexico
production platforms caused by mechanical problems. Production during the 2001 period reflected reduced extraction rates caused by
abnormally high natural gas prices which increased operating costs at our gas processing plants. As a result of lower overall
natural gas prices in the first quarter of 2002 compared to the same period in 2001, processing economics have improved leading to
higher extraction rates (i.e., higher equity NGL production).
We have employed various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL and natural gas
prices) on our gas processing business and related merchant activities. Beginning in late 2000 and extending through March 2002, a
large number of our hedging transactions were based on the historical relationship between natural gas prices and NGL prices. This
type of hedging strategy utilized the forward sale of natural gas at a fixed-price with the expected margin on the settlement of the
position offsetting or mitigating changes in the anticipated margins on NGL merchant activities and the value of equity NGL
production. During most of 2001, this strategy proved successful as natural gas prices declined relative to our fixed positions.
During the first quarter of 2001, we recognized $5.6 million in income from our hedging activities of which $13.5 million was
mark-to-market income on positions that were open at March 31, 2001. For the year 2001, this strategy proved successful for us (as
the price of natural gas declined relative to our positions) and was responsible for most of the $101.3 million in income from
hedging activities we recorded.
As a result of our success, we continued using this strategy going into 2002. In late March 2002, the effectiveness of this hedging
strategy deteriorated due to a rapid increase in natural gas prices whereby the loss in the value of fixed-price natural gas
financial instruments was not offset by increased processing margins. A number of factors influenced this rapid increase in
natural gas prices including industry concerns that current drilling activity was not sufficient to support production levels needed
to support the U.S. economic recovery that is underway and the potential need for natural gas to replace nuclear power in some areas
in the U.S. as nuclear power facilities were taken offline for critical maintenance work. At March 31, 2002, we recognized a loss
on these hedging activities of $45.1 million of which $16.4 million had already been paid to counterparties.
Due to the inherent uncertainty that was controlling the markets, management decided that it was prudent for the Company to exit this
strategy completely, and we did so by late April 2002. By the time that the positions were effectively closed out, the March 31,
2002 market value of $20.8 million payable increased to $26.1 million payable. We forecast that the latter sum will be paid to
counterparties as follows during 2002: $15.5 million in the second quarter, $10.1 million in the third quarter and $0.5 million in
the fourth quarter.
As a result of the loss recognized in the first quarter of 2002, management has elected to take a more traditional approach to
hedging activities for the foreseeable future. We anticipate that the hedging strategies used by our natural gas processing and
PAGE 47
related NGL merchant activities (over the short-term) will be limited to those deemed prudent in managing the cost of natural gas
consumed as a feedstock in these operations. A variety of factors influence whether or not our hedging strategies are successful.
For additional information regarding our commodity financial instruments, see Item 3 of this report on Form 10-Q.
Octane Enhancement. Equity earnings from our BEF investment improved to $3.0 million for the first quarter of
2002 compared with $0.2 million for the first quarter of 2001. The improvement is attributable to a 64% increase in MTBE production
(due to less maintenance downtime during the 2002 period) and increased margins related to lower feedstock prices caused by lower
natural gas prices.
Selling, general and administrative expenses. These expenses increased to $8.0 million for the first quarter of 2002
from $6.2 million for the first quarter of 2001. The increase in expense is primarily due to the additional staff and resources
acquired as a result of the Acadian acquisition.
Interest expense. Interest expense increased to $18.5 million for the first quarter of 2002 from $7.0 million
for the first quarter of 2001. During the first quarter of 2001, we recognized a $9.3 million benefit related to our interest rate
swaps compared to $0.1 million for the first quarter of 2002. We use interest rate swaps to effectively convert a portion of our
fixed-rate debt into variable-rate debt. With the decline in variable interest rates, our swaps increased in value and provided cash
income. Also, the notional amounts of the swaps outstanding during the first quarter of 2001 ranged from $154 million to $104
million compared to $54 million outstanding during the 2002 period. The notional amount reflects that portion of debt principal
that we effectively converted to variable interest rates from fixed interest rates.
In addition, interest expense has increased as a result of additional borrowings. Our weighted-average principal balance for the
first quarter of 2002 was $1.1 billion compared to $854 million for the same period in 2001. Debt increased $363 million during the
first quarter of 2002 primarily the result of borrowings associated with the Diamond-Koch acquisitions.
General outlook for second quarter of 2002 and remainder of 2002
Our second quarter equity NGL production will be marginally impacted by temporary mechanical problems at certain Gulf of Mexico
production platforms. These platforms recommenced production in early May and are expected to return to full production by the end of
May. As a result, we expect that our second quarter equity NGL production will be similar to that seen in the first quarter of 2001
(approximately 80 MBPD). Rates should improve to near 85 MBPD over the remainder of the year as these fields come back onstream.
The mechanical problems at the platforms noted above will also temporarily reduce transportation volumes and margin on the Nemo,
Manta Ray and Nautilus pipelines in which we have an equity ownership. For the remainder of 2002, we expect quarterly earnings from
these investments to approach historical levels. We anticipate our Acadian Gas business to be stable for the remainder of the year
with normal margins.
Our propylene fractionation facilities should operate at near capacity for the remainder of 2002. We believe that margins will
improve in the second quarter of 2002 due to strong export demand. Propylene fractionation margins for the third and fourth quarter
should approximate those seen in the first quarter of 2002. Propylene fractionation volumes are expected to average near 65 MBPD
for the second, third and fourth quarters of 2002.
The isomerization business is expected to be stable for the remainder of 2002 with volumes averaging approximately 75 MBPD.
Likewise, margin and volume attributable to NGL fractionation services for the second quarter of 2002 is expected to be consistent
with that seen in the first quarter of 2002. We expect no significant changes in the third and fourth quarters of 2002 as well.
Equity earnings from BEF during the second quarter of 2002 are expected to improve relative to the first quarter of 2002 as demand
for MTBE strengthens as refiners begin purchasing MTBE in preparation for gasoline blending requirements of the upcoming summer
driving season. Our forecast of equity earnings from BEF for the third and fourth quarters of 2002 are expected to be seasonally
lower than those seen in the first and expected in the second quarters, but are expected to be similar to the levels experienced
historically.
PAGE 48
Our liquidity and capital resources
As noted at the beginning of Item 2, since the Operating Partnership owns substantially all of Enterprise Products Partners L.P.'s
consolidated assets and conducts substantially all of its business and operations, the following discussion of liquidity and capital
resources constitutes combined (or consolidated) information for the two registrants. References to equity securities in this
discussion pertain to the Units issued by Enterprise Products Partners L.P. References to public debt pertain to those obligations
issued by Enterprise Products Operating L.P.
General. Our primary cash requirements, in addition to normal operating expenses and debt service, are for capital
expenditures (both sustaining and expansion-related), business acquisitions and distributions to partners. We expect to fund our
short-term needs for such items as operating expenses, sustaining capital expenditures and quarterly distributions to partners with
operating cash flows. Capital expenditures for long-term needs resulting from internal growth 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. Our debt service requirements
are expected to be funded by operating cash flows and/or refinancing arrangements.
Operating cash flows primarily reflect the effects of net income adjusted for depreciation and amortization, equity income and cash
distributions from unconsolidated affiliates, fluctuations in fair values of financial instruments and changes in operating
accounts. The net effect of changes in operating accounts is generally the result of timing of sales and purchases near the end of
each period. Cash flows from operations are directly linked to earnings from our business activities. Like our results of
operations, these cash flows are exposed to certain risks including fluctuations in NGL and energy prices, competitive practices in
the midstream energy industry and the impact of operational and systems risks. The products that we process, sell or transport are
principally used as feedstocks in petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and
commercial heating. Reduced demand for our products or services by industrial customers, whether because of general economic
conditions, reduced demand for the end products made with NGL products, increased competition from petroleum-based products due to
pricing differences or other reasons, could have a negative impact on earnings and thus the availability of cash from operating
activities. For a more complete discussion of these and other risk factors pertinent to our businesses, see "Cautionary
Statement regarding Forward-Looking information and Risk Factors".
As noted above, certain of our 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, 2002, total borrowing
capacity under our revolving credit facilities was $400 million of which $87 million was available at the end of the first quarter of
2002 (we increased the borrowing capacity under our revolving credit facilities to $500 million in April 2002). On February 23,
2001, we filed a $500 million universal shelf registration (the "February 2001 Shelf") covering the issuance of an unspecified amount
of equity or debt securities or a combination thereof. For additional information regarding our debt, see the section below labeled
"Our debt obligations."
In June 2000, we received approval from our Unitholders to increase by 25,000,000 the number of Common Units available (and
unreserved) for general partnership purposes during the Subordination Period. This increase has improved our future financial
flexibility in any potential expansion project or business acquisition. After taking into account the Units issued in connection
with TNGL acquisition, 27,275,000 Units are available (and unreserved) on a pre-split basis (see "Two-for-one split of Limited
Partner Units" below) for general partnership purposes during the Subordination Period which generally extends until the first
day of any quarter beginning after June 30, 2003 when certain financial tests have be satisfied. After this period expires, we may
prudently issue an unlimited number of Units for general partnership purposes.
If deemed necessary, we believe that additional financing arrangements can be obtained at reasonable terms. Furthermore, we believe
that maintenance of our investment grade credit ratings combined with a continued ready access to debt and equity capital at
reasonable rates and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and
short-term liquidity and capital resource requirements.
PAGE 49
Credit ratings. Our current investment grade credit ratings of Baa2 by Moody's Investor Service and BBB by Standard and
Poors highlight our financial flexibility. The outlook for both of the ratings is stable. We maintain regular communications with
these rating agencies which independently judge our creditworthiness based on a variety of quantitative and qualitative factors. We
believe that the maintenance of an investment grade credit rating is important in managing our liquidity and capital resource
requirements.
Two-for-one split of Limited Partner Units.On February 27, 2002, we announced that the Board of
Directors of the General Partner had approved a two-for-one split for each class of our Units. The partnership Unit split will be
accomplished by distributing one additional partnership Unit for each partnership Unit outstanding to holders of record on April 30,
2002. The Units will be distributed on May 15, 2002. All references to number of Units or earnings per Unit contained in this
document relate to the pre-split Units, except if indicated otherwise.
Consolidated cash flows for three months ended March 31, 2002 compared to three months ended March 31, 2001
Operating cash flows. Cash flows from operating activities were an outflow of $10.0 million during the first quarter of 2002
compared to an inflow of $48.7 million during the first quarter of 2001. Excluding changes in operating accounts which are generally
the result of timing of sales and purchases near the end of each period, adjusted quarterly cash flow from operating activities would
be an inflow of $38.2 million in 2002 as compared to an inflow of $41.1million for 2001. Cash flow from operating activities before
changes in operating accounts is an important measure of our liquidity. It provides an indication of our success in generating core
cash flows from the assets and investments we own. The $2.9 million decrease in cash flows for the first quarter of 2002 is
primarily due to an increase in hedging losses realized between the quarters offset by additional cash flows from acquisitions
(Diamond-Koch in January and February of 2002 and Acadian Gas in April 2001).
As noted under "Our results of operations" section, we recorded $45.1 million in net commodity hedging losses for the first
quarter of 2002 compared to $5.6 million in net commodity hedging income for the first quarter of 2001. Of the net hedging loss for
the first quarter of 2002, we have realized (or paid out to counterparties) $16.4 million of this loss. The difference of $28.7
million represented the change in market value of the overall portfolio between December 31, 2001 and March 31, 2002. At
March 31, 2002, the market value of the commodity financial instruments that were outstanding was a payable of $20.8 million. Due
to continued volatility in the marketplace and losses, management elected to effectively exit the strategy underlying the commodity
hedging activities and moved to close out these positions in April 2002. Due to the increase in natural gas prices before we
effectively closed out all of these positions, we estimate that an additional $5.3 million in losses will be recorded in the second
quarter of 2002 pertaining to these instruments. Of the cumulative $26.1 million in post-first quarter 2002 cash losses, $15.5
million is expected to be paid out during the second quarter, $10.1 million in the third quarter and $0.5 million in the fourth
quarter. By comparison, our net hedging income of $5.6 million recorded in the first quarter of 2001 consisted of $13.5 million of
mark-to-market income on positions that were open at March 31, 2001 offset by $7.9 million in realized losses.
Investing cash flows. During the first quarter of 2002, we used $396.5 million in cash to finance investing activities
compared to $137.9 million for the first quarter of 2001. The 2002 period includes $368.7 million paid to affiliates of
Diamond-Koch to acquire their propylene fractionation and NGL and petrochemical storage businesses located in Mont Belvieu, Texas.
This amount is subject to certain post-closing adjustments expected to be completed during the second quarter of 2002. The 2001
period includes approximately $113 million paid to El Paso to acquire equity interests in several Gulf of Mexico natural gas pipeline
systems (our Neptune, Starfish and Nemo equity investments).
On a forward-looking basis, the post-closing purchase price adjustment related to Acadian Gas was completed in April 2002. As a
result, we paid an additional $18.0 million to Shell primarily related to working capital items during the second quarter of 2002.
Financing cash flows. Our financing activities generated $304.4 million in cash inflows during the first quarter of 2002
compared to $408.2 million during the first quarter of 2001. The first quarter of 2002 includes $383 million in borrowings under our
revolving credit facilities while the first quarter of 2001 reflects $450 million in proceeds from the issuance of the Senior Notes
B. Cash distributions paid to our partners increased quarter-to-quarter primarily due to increases in both the quarterly
distribution rate and the number of Units entitled to received distributions.
PAGE 50
Cash requirements for future growth
Acquisitions. We are committed to the long-term growth and viability of the Company. Our strategy involves expansion
through business acquisitions and internal growth projects. In recent years, major oil and gas companies have sold non-strategic
assets in the midstream natural gas industry in which we operate. We forecast that this trend will continue, and expect independent
oil and natural gas companies to consider similar disposal options. Management continues to analyze potential acquisitions, joint
venture or similar transactions with businesses that operate in complementary markets and geographic regions. We believe that the
Company is well positioned to continue to grow through acquisitions that will expand its platform of assets and through internal
growth projects. Our goal for fiscal 2002 is to invest at least $400 million in such opportunities that will be accretive to our
investors.
The funds needed to achieve this goal can be attained through a combination of operating cash flows, debt and/or equity. During
January and February 2002, we spent approximately $367.5 million to acquire hydrocarbon storage and propylene fractionation
facilities and related assets from D-K. Of this amount, approximately $238.5 million was funded by a drawdown on our Multi-Year and
364-Day credit facilities leaving $161.5 million of unused commitments available under these credit agreements. The increase in
outstanding debt will translate into additional debt service costs during 2002.
Distributions. Another stated goal of management is to increase the distribution rate to our investors by at least 10%
annually. At the end of 2001, the annual rate was $2.50 per Common Unit. We anticipate that operating cash flows will be
sufficient in 2002 to increase the rate to at least $2.68 per Common Unit (on a pre-split basis). On February 27, 2002, we
announced an increase in the quarterly distribution from $0.625 per Common Unit to $0.67 per Common Unit on a pre-split basis. Based
on the number of distribution-bearing Units projected to be outstanding during 2002, we project that this goal will translate into
cash distributions increasing by approximately $46 million over the amounts paid to partners and the minority interest during 2001.
Capital spending. At March 31, 2002, we had $5.9 million in outstanding purchase commitments attributable to capital
projects. Of this amount, $5.8 million is related to the construction of assets that will be recorded as property, plant and
equipment and $0.1 million is associated with capital projects of our unconsolidated affiliates which will be recorded as additional
investments.
During the first quarter of 2002, our capital expenditures were $17.1 million. For the remainder of 2002, we expect our capital
spending to approximate $46.5 million of which $21.1 million is forecasted for our Pipelines segment. Our unconsolidated affiliates
forecast a combined $31.1 million in capital expenditures during the remainder of 2002 of which we expect our share to be
approximately $10.2 million, the majority of which relate to expansion projects on our Gulf of Mexico natural gas pipeline systems.
These outlays will be recorded as additional investments in unconsolidated affiliates.
PAGE 51
Our debt obligations
Our debt consisted of the following at:
March 31, December 31,
2002 2001
---------------------------------------
Borrowings under:
Senior Notes A, 8.25% fixed rate, due March 2005 $350,000 $350,000
MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
Senior Notes B, 7.50% fixed rate, due February 2011 450,000 450,000
Multi-Year Credit Facility, due November 2005 230,000
364-Day Credit Facility, due November 2002 (a) 83,000
Other short-term borrowing due April 2002 50,000
---------------------------------------
Total principal amount 1,217,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,955 1,653
Less unamortized discount on:
$350 Million Senior Notes (108) (117)
$450 Million Senior Notes (251) (258)
Less current maturities of debt (50,000) -
---------------------------------------
Long-term debt $1,168,596 $855,278
=======================================
(a) Under the terms of this facility, the Operating Partnership has the option to convert this facility into a term loan due
November 15, 2003. Management intends to refinance this obligation with a similar obligation at maturity.
At March 31, 2002, we had a total of $75 million of standby letters of credit capacity under our Multi-Year Credit Facility of which
$18.6 million was outstanding.
Enterprise Products Partners L.P. acts as guarantor of certain debt obligations of the Operating Partnership. This parent-subsidiary
guaranty provision exists under our Senior Notes, MBFC Loan, Multi-Year and 364-Day Credit Facility.
In April 2002, we increased the amount that we can borrow under the Multi-Year Credit Facility by $20 million and the 364-Day Credit
Facility by $80 million, up to an amount not exceeding $500 million in the aggregate for both facilities. At March 31, 2002, we had
borrowed $313 million under these two facilities; the majority of which was related to the acquisition of Diamond-Koch's propylene
fractionation business in February 2002 (see Note 2). In anticipation of the increased borrowing limits under the Multi-Year and
364-Day Credit Facilities, we borrowed $50 million under a short-term supplemental credit facility that was repaid in late April 2002
with proceeds from the increased availability under the Multi-Year and 364-Day Credit Facility.
The indentures under which the Senior Notes and the MBFC Loan were issued contain various restrictive covenants. We were in
compliance with these covenants at March 31, 2001.
In April 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were amended to allow for increased financial
flexibility. The significant changes are as follows (capitalized terms used herein are defined within the credit agreements):
o We were granted increased flexibility under our Consolidated Indebtedness to Consolidated EBITDA ratio for the rolling-four
quarter period which ends on September 30, 2002. The maximum ratio allowed by our lenders was temporarily raised to 4.5 to
1.0 from 4.0 to 1.0. This modification was required as a result of the hedging losses we incurred during the first quarter
of 2002.
o In addition, we are allowed to exclude from the calculation of Consolidated EBITDA up to $50 million in losses resulting
from hedging NGLs that utilized natural gas-based financial instruments entered into on or prior to April 24, 2002. This
PAGE 52
exclusion applies to our quarterly Consolidated EBITDA calculations in which the financial impact of such specific
instruments were recorded (ending with the calculation for the third quarter of 2003 due to the rolling-four quarter nature
of the calculation).
We were in compliance with the covenants of our revolving credit agreements at March 31, 2002.
Summary of contractual obligations and material commercial commitments
The following table summarizes our contractual obligations and material purchase and other commitments for the period shown (as of
March 31, 2002):
Contractual Obligation 2003 2006
or Material Commercial through through After
Commitment Total 2002 2005 2007 2007
- ---------------------------------------------------------------------------------------------------------------
Contractual Obligation (expressed in
terms of millions of dollars payable
per period:)
Debt obligations $1,217.0 $50.0 $663.0 $504.0
Operating leases $17.3 $4.0 $10.1 $0.6 $2.6
Capital spending commitments:
Property, plant and equipment $5.8 $5.8
Investments in unconsolidated
affiliates $0.1 $0.1
Other commitments (expressed in terms
of millions of dollars potentially
payable per period):
Letters of Credit under Multi-Year
Credit Facility $18.6 $18.6
Other Material Contractual Obligations
(Purchase commitments expressed
in terms of minimum volumes
under contract per period:)
NGLs (MBbls) 27,345 8,064 18,941 340
Natural gas (BBtus) 138,605 10,294 39,716 25,595 63,000
Debt obligations reflects amounts due under our Senior Notes A and B, the MBFC Loan and our revolving credit facilities. Of the $83
million outstanding under the 364-Day Credit Facility, management is evaluating its refinancing alternatives regarding amounts due in
November 2002 under the 364-Day Credit Facility. Management intends to refinance this obligation with a similar obligation at
maturity.
We lease certain equipment and processing facilities under noncancelable and cancelable operating leases. The amounts shown in the
table above represent minimum future rental payments due on such leases with terms in excess of one year. The amounts shown reflect
additional operating lease commitments arising from the Diamond-Koch acquisitions in January and February 2002.
Our letters of credit increased from $2.4 million at December 31, 2001 to $18.6 million at March 31, 2002 due to letter of credit
requirements associated with our purchase of hydrocarbon imports.
PAGE 53
Recent accounting developments
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other
Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for business combinations initiated after June
30, 2001 and also applies to all business combinations accounted for by the purchase method that are completed after June 30, 2001.
There are also transition provisions that apply to business combinations completed before July 1, 2001, that were accounted for by
the purchase method. SFAS No. 142 was effective for our fiscal year that began January 1, 2002 for all goodwill and other intangible
assets recognized in our consolidated balance sheet at that date, regardless of when those assets were initially recognized. We
adopted SFAS No. 141 and SFAS No. 142 on January 1, 2002.
At December 31, 2001, our intangible assets were comprised of the values associated with the Shell natural gas processing agreement
and the goodwill related to the 1999 MBA acquisition. In accordance with the new standard, we reclassified the goodwill to a
separate line item on our consolidated balance sheet apart from the Shell contract. Based upon our initial interpretation of the
standard, the Shell natural gas processing agreement will continue to be amortized over its 20-year contract term; however,
amortization of the MBA acquisition goodwill will cease due to its indefinite life. Our goodwill will be subject to periodic
impairment testing in accordance with SFAS No. 142. For additional information regarding our intangible assets and goodwill
including additions to both classes of assets as a result of the Diamond-Koch acquisitions, see Note 6 in our Notes to Unaudited
Consolidated Financial Statements.
Within six months of our adoption of SFAS No. 142 (by June 30, 2002), we will have completed a transitional impairment review to
identify if there is an impairment to the December 31, 2001 recorded goodwill or intangible assets of indefinite life using a fair
value methodology. Professionals in the business valuation industry will be consulted to validate the assumptions used in such
methodologies. Any impairment loss resulting from the transitional impairment test will be recorded as a cumulative effect of a
change in accounting principle for the quarter ended June 30, 2002. Subsequent impairment losses will be reflected in operating
income in the Statements of Consolidated Operations. We are continuing to evaluate the complex provisions of SFAS No. 142 and will
fully adopt the standard during 2002 within the prescribed time periods.
In addition to SFAS No. 141 and No. 142, the FASB also issued SFAS No. 143, "Accounting for Asset Retirement Obligations", in June
2001. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement
obligation and the associated asset retirement cost. This statement is effective for our fiscal year beginning January 1, 2003. We
are continuing to evaluate the provisions of this statement. In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets". This statement addresses financial accounting and reporting for the impairment and/or
disposal of long-lived assets. We adopted this statement effective January 1, 2002 and determined that it did not have any
significant effect on our financial statements as of that date.
Uncertainties regarding our investment in BEF
We have a 33.3% ownership interest in BEF, which owns a facility currently producing MTBE. MTBE has come under increasing scrutiny
by various governmental agencies and environmental groups over the last few years because of allegations that MTBE contaminates water
supplies, causes health problems and has not been as beneficial in reducing air pollution as originally contemplated in clean air
programs. Certain states, primarily California, have moved to ban or reduce MTBE use due to these concerns. In addition, the U.S.
Senate, in April 2002, passed an energy bill that includes a total ban on the use of MTBE, effective in four years. The Senate bill
now goes to a conference committee with the U.S. House of Representatives for resolution. The U.S. House of Representatives energy
bill, which passed in August 2001, contains no such ban. We can give no assurance as to whether the federal government or
individual states will ultimately adopt legislation banning the use of MTBE.
In April 2002, a jury in California found three energy companies liable for polluting Lake Tahoe's drinking water with MTBE. While
this decision sets no legal precedent, this was the first time that a jury has defined gasoline containing MTBE to be a "defective
product". This decision is expected to be appealed. Although this development has no direct impact on BEF since our customer uses
PAGE 54
the MTBE we produce in its northeastern U.S. operations, it does contribute to the overall challenging outlook regarding the
long-term viability of domestic MTBE production.
In light of these developments, we and the other two partners of BEF are actively compiling a contingency plan for the BEF facility
should MTBE be banned. We are currently leaning towards a possible conversion of the facility from MTBE production to alkylate
production. We believe that if MTBE usage is banned or significantly curtailed, the motor gasoline industry would need a substitute
additive to maintain octane levels in gasoline and that alkylate would be an attractive substitute. At present, we estimate that our
share of the cost to convert the facility can range from $10 million to $30 million depending on the type of alkylate process chosen
and level of alkylate production desired by the partnership.
Conversion of Subordinated Units into Common Units
As a result of the Company satisfying certain financial tests, 5,352,468 (or 25%) of EPCO's Subordinated Units converted into Common
Units on May 1, 2002. Should the financial criteria continue to be satisfied through the first quarter of 2003, an additional 25%
of the Subordinated Units would undergo an early conversion into Common Units on May 1, 2003. The remaining 50% of Subordinated
Units would convert on August 1, 2003 should the balance of the conversion requirements be met. Subordinated Units have no voting
rights until converted into Common Units. The conversion(s) will have no impact upon our earnings per unit since the Subordinated
Units are already included in both the basic and fully diluted calculations.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are exposed to financial market risks, including changes in commodity prices in our natural gas and NGL businesses and in interest
rates with respect to a portion of our debt obligations. We may use financial instruments (i.e., futures, forwards, swaps, options,
and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated
transactions, primarily in our Processing segment. As a matter of policy, we do not use financial instruments for speculative (or
trading) purposes.
For additional information regarding our financial instruments, see Note 12 of the Company's Notes to Unaudited Consolidated
Financial Statements.
Commodity financial instruments
Our Processing and Octane Enhancement segments are directly exposed to commodity price risk through their respective business
operations. The prices of natural gas, NGLs and MTBE are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with our
Processing segment, we may enter into swaps, forwards, commodity futures, options and other commodity financial instruments with
similar characteristics that are permitted by contract or business custom to be settled in cash or with another financial
instrument. The primary purpose of these risk management activities (or hedging strategies) is to hedge exposure to price risks
associated with natural gas, NGL inventories, firm commitments and certain anticipated transactions. We do not hedge our exposure
to the MTBE markets. Also, in our Pipelines segment, we may utilize a limited number of commodity financial instruments to manage
the price Acadian Gas charges certain of its customers for natural gas.
We have adopted a commercial policy to manage our exposure to the risks of its natural gas and NGL businesses. The objective of this
policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined
as remaining within the position limits established by the General Partner. Under this policy, we enter into risk management
transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term
(less than one month) and long-term basis, generally not to exceed 24 months. The General Partner oversees our hedging strategies
associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy
(including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and
ensuring compliance with the policy.
PAGE 55
Our commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of SFAS No. 133
because of ineffectiveness. A hedge is normally regarded as effective if, among other things, at inception and throughout the term
of the financial instrument, we could expect changes in the fair value of the hedged item to be almost fully offset by the changes in
the fair value of the financial instrument. When financial instruments do not qualify as effective hedges under the guidelines of
SFAS No. 133, changes in the fair value of these positions are recorded on the balance sheet and in earnings through mark-to-market
accounting. The use of mark-to-market accounting for these ineffective instruments results in a degree of non-cash earnings
volatility that is dependent upon changes in the underlying commodity prices. Although our financial instruments may from time to
time be regarded as ineffective hedges under SFAS No. 133, we continue to view these instruments as hedges (i.e., "economic hedges")
inasmuch as this was the intent when such contracts were executed. This characterization is consistent with the actual economic
performance of these contracts to date and we expect our economic hedges to continue to mitigate (or offset) commodity price risk in
the future. The specific accounting for these contracts, however, is consistent with the requirements of SFAS No. 133.
We assess the risk of our commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis
performed on this portfolio measures the potential income or loss (e.g., the change in fair value of the portfolio) based upon a
hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the dates
noted within the following table. In general, we derive the quoted market prices used in the model from those actively quoted on
commodity exchanges (ex. NYMEX) for instruments of similar duration. In those rare instances where prices are not actively quoted,
we employ regression analysis techniques possessing strong correlation factors.
The sensitivity analysis model takes into account the following primary factors and assumptions:
o the current quoted market price of natural gas;
o the current quoted market price of NGLs;
o changes in the composition of commodities hedged (i.e., the mix between natural gas and related NGLs);
o fluctuations in the overall volume of commodities hedged (for both natural gas and related NGL hedges outstanding);
o market interest rates, which are used in determining the present value; and
o a liquid market for such financial instruments.
An increase in fair value of the commodity financial instruments (based upon the factors and assumptions noted above) approximates
the income that would be recognized if all of the commodity financial instruments were settled at the dates noted within the table.
Conversely, a decrease in fair value of the commodity financial instruments would result in the recording of a loss.
The sensitivity analysis model does not include the impact that the same hypothetical price movement would have on the hedged
commodity positions to which they relate. Therefore, the impact on the fair value of the commodity financial instruments of a change
in commodity prices would be offset by a corresponding gain or loss on the hedged commodity positions, assuming:
o the commodity financial instruments function effectively as hedges of the underlying risk;
o the commodity financial instruments are not closed out in advance of their expected term; and
o as applicable, anticipated underlying transactions settle as expected.
We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some
financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on
the specific exposure. When this occurs, we may enter into a new commodity financial instrument to reestablish the economic hedge to
which the closed instrument relates.
PAGE 56
The following table shows the impact of hypothetical price movements on our commodity financial instrument portfolio at the dates
indicated:
Sensitivity Analysis for Commodity Financial Instruments Portfolio
Estimates of Fair Value ("FV") and Earnings Impact ("EI")
due to selected changes in quoted market prices at dates selected
At At At
Resulting December 31, March 31, May 2,
Scenario classification 2001 2002 2002
- --------------------------------------------------- --------------------------------------------------------------------
(in millions of dollars)
--------------------------------------------------------------------
FV assuming no change in quoted market prices Asset(Liability) $ 5.6 $ (20.8) $ (19.6)
FV assuming 10% increase in quoted market prices Asset(Liability) $ (0.3) $ (30.7) $ (19.8)
EI assuming 10% increase in quoted market prices Income (Loss) $ (5.9) $ (9.9) $ (0.2)
FV assuming 10% decrease in quoted market prices Asset(Liability) $ 11.4 $ (10.9) $ (19.5)
EI assuming 10% decrease in quoted market prices Income (Loss) $ 5.8 $ 9.9 $ 0.1
As the table shows, the value of our portfolio declined from a $5.6 million asset at the end of 2001 to a $20.8 million payable at
March 31, 2002. The negative change in value is primarily due to an increase in natural gas prices that occurred at the end of the
first quarter of 2002. The vast majority of our hedging transactions over the last year and a half have been based on the
historical relationship between natural gas and NGL prices. This type of hedging strategy utilized the forward sale of natural gas
at a fixed-price with the expected margin on the settlement of the position offsetting or mitigating changes in the anticipated
margins on NGL merchant activities and the value of our equity NGL production. This strategy was successful during periods of
falling natural gas prices (as was the case during most of 2001) and we chose to continue this strategy going into 2002 believing
that the fundamentals of the natural gas business indicated additional moderation in prices. Unfortunately, the price of natural gas
became unstable and rapidly increased as supply concerns influenced the market in March 2002. As the market price of natural gas
increased, our fixed positions became less and less profitable until we were finally left in a payable position (i.e., in a loss
position on these instruments). At March 31, 2002, we recognized a loss from these activities for the first quarter of 2002 of
$45.1 million of which $16.4 million was already realized. The $45.1 million loss is treated as an increase in operating costs and
expenses in the Statements of Consolidated Operations.
Due to the inherent uncertainty that was controlling the markets, management decided that it was prudent for the Company to exit this
strategy completely and did so by late April 2002. By the time that these positions were effectively closed out in late April, the
March 31, 2002 market value of $20.8 million payable increased to $26.1 million payable. We forecast that the latter will be paid to
counterparties as follows during 2002: $15.5 million in the second quarter, $10.1 million in the third quarter and $0.5 million in
the fourth quarter. The value of the portfolio at May 2, 2002 was $19.6 million payable. A movement in market prices at this date
has very little impact on the value of the portfolio because most of the portfolio has been effectively closed as noted above.
As a result of the loss recognized in the first quarter of 2002, management has elected to take a more traditional approach to
hedging activities for the foreseeable future. We anticipate that the hedging strategies used by our natural gas processing and
related NGL merchant activities (over the short-term) will be limited to those deemed prudent in managing the cost of natural gas
consumed as a feedstock in these operations. A variety of factors influence whether or not our hedging strategies are successful.
Interest rate swaps
Our interest rate exposure results from variable-rate borrowings from commercial banks and fixed-rate borrowings pursuant to the
Company's Senior Notes and MBFC Loan. We manage a portion of our exposure to changes in interest rates by utilizing interest rate
swaps. The objective of holding interest rate swaps is to manage debt service costs by converting a portion of fixed-rate debt into
PAGE 57
variable-rate debt or a portion of variable-rate debt into fixed-rate debt. An interest rate swap, in general, requires one party to
pay a fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount.
The General Partner oversees the strategies associated with financial risks and approves instruments that are appropriate for our
requirements. At March 31, 2002, we had one interest rate swap outstanding having a notional amount of $54 million extending
through March 2010 . Under this agreement, we exchanged a fixed-rate of 8.70% for a market-based variable-rate. If it elects to
do so, the counterparty may terminate this swap in March 2003.
We recognized income of $0.1 million during the first quarter of 2002 from our interest rate swaps that is treated as a reduction of
interest expense in our Statements of Consolidated Operations. The fair value of the interest rate swap at March 31, 2002 was a
receivable of $2.4 million. This fair value would decrease to $2.3 million if quoted market interest rates were to increase by 10%.
PART II. OTHER INFORMATION.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibit.
2.1 Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated as of September 22,
2000. (Exhibit 10.1 to the Company's Form 8-K filed on September 26, 2000).
2.2 Purchase and Sale Agreement dated as of January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and
Enterprise Products Texas Operating L.P. (Exhibit 10.1 to the Company's Form 8-K filed February 8, 2002).
2.3 Purchase and Sale Agreement dated as of January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and
Diamond-Koch III, L.P. as Sellers, and Enterprise Products Operating L.P., as Buyer. (Exhibit 10.2 to the Company's Form
8-K filed February 8, 2002).
3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. (Exhibit 3.2 to the
Company's Registration Statement of 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 the Company's 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 the Company's Form 10-Q filed August 11, 2000).
4.1 Form of Common Unit certificate. (Exhibit 4.1 to the Company's 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).
PAGE 58
4.3 Contribution Agreement by and among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise Products Partners L.P.,
Enterprise Products Operating L.P., Enterprise Products Company, Enterprise Products GP, LLC and EPC Partners II, Inc.
dated September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "B" to the Schedule
13 D 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 13 D 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 the Company's 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 (the "Senior Notes A").
(Exhibit 4.2 on the Company's Form 8-K filed March 10, 2000).
4.7 $250 million Multi-Year Revolving Credit Agreement (the "Multi-Year Credit Facility") 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
the Company's Form 8-K filed January 25, 2001).
4.8 $150 Million 364-Day Revolving Credit Agreement (the "364-Day Credit Facility") among Enterprise Products Operating L.P. and
First Union National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan Bank, as
syndication agent and the Several Banks from time to time parties thereto dated November 17, 2000. (Exhibit 4.3 on the
Company's Form 8-K filed January 25, 2001).
4.9 Guaranty Agreement (relating to the Multi-Year Credit Facility) by Enterprise Products Partners L.P. in favor of First Union
National Bank, as administrative agent dated November 17, 2000. (Exhibit 4.4 on the Company's Form 8-K filed January 25,
2001).
4.10 Guaranty Agreement (relating to the 364-Day Credit Facility) by Enterprise Products Partners L.P. in favor of First Union
National Bank, as administrative agent dated November 17, 2000. (Exhibit 4.5 on the Company's Form 8-K filed January 25,
2001).
4.11 Form of Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011 (the "Senior Notes B").
(Exhibit 4.1 to the Company's Form 8-K filed January 25, 2001).
4.12 First Amendment to Multi-Year Credit Facility dated April 19, 2001. (Exhibit 4.12 to the Company's Form 10-Q filed May 14,
2001).
4.13 First Amendment to 364-Day Credit Facility dated November 6, 2001, effective as of November 16, 2001. (Exhibit 4.13 to the
Company's Form 10-K filed March 21, 2002).
4.14* Second Amendment to Multi-Year Credit Facility dated April 24, 2002.
4.15* Second Amendment to 364-Day Credit Facility dated April 24, 2002.
* An asterisk indicates that an exhibit is filed in conjunction with this report. All other documents are incorporated by
reference as indicated in their descriptions.
No material contracts were entered into during the first quarter of 2002.
PAGE 59
(b) Reports on Form 8-K.
On February 8, 2002, we filed a Form 8-K describing the acquisition of Diamond-Koch's propylene fractionation and NGL and
petrochemical storage businesses located in Mont Belvieu, Texas.
On February 28, 2002, we filed a Form 8-K notifying our investors that the General Partner had approved a two-for-one split of the
Company's Units on May 15, 2002 (to unitholders of record on April 30, 2002). In addition, we stated that the distribution rate for
the first quarter of 2002 was increased from $0.625 per Common Unit to $0.67 per Common Unit.
PAGE 60
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this
report to be signed on their behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on May 14,
2002.
Enterprise Products Partners L.P.
(A Delaware Limited Partnership)
Enterprise Products Operating L.P.
(A Delaware Limited Partnership)
By: Enterprise Products GP, LLC
as General Partner for both registrants
/s/ Michael J. Knesek
---------------------------------------------------------------
Vice President, Controller and
Date: May 14, 2002 Principal Accounting Officer
SECOND AMENDMENT AND SUPPLEMENT
TO CREDIT AGREEMENT
(Multi-Year Revolving Credit Facility)
THIS SECOND AMENDMENT AND SUPPLEMENT TO CREDIT AGREEMENT (this "Second Amendment") is made and
entered into as of the 24th day of April, 2002 (the "Second Amendment Effective Date"), among ENTERPRISE
PRODUCTS OPERATING L.P., a Delaware limited partnership ("Borrower"); WACHOVIA BANK, NATIONAL ASSOCIATION
(formerly known as First Union National Bank), as administrative agent (in such capacity, the "Administrative
Agent") for each of the lenders (the "Lenders") that is a signatory or which becomes a signatory to
the hereinafter defined Credit Agreement; and the Lenders party hereto.
R E C I T A L S:
A. On November 17, 2000, the Borrower, the Lenders and the Administrative Agent entered into a certain
Credit Agreement (as amended by First Amendment to Credit Agreement dated April 19, 2001, the "Credit
Agreement") whereby, upon the terms and conditions therein stated, the Lenders agreed to make certain Loans
(as defined in the Credit Agreement) and extend certain credit to the Borrower.
B. Pursuant to Section 2.01(b) of the Credit Agreement (i) the Borrower has, as of the Second Amendment
Effective Date, added Royal Bank of Canada as an additional Lender under the Credit Agreement (the "Additional
Lender"), and (ii) certain of the existing Lenders have, as of the Second Amendment Effective Date, increased
their respective Commitments (as defined in the Credit Agreement), thereby increasing the total Commitments of
the Lenders by an aggregate amount equal to $20,000,000 making the aggregate amount of the Lenders' Commitments
$270,000,000.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained, the Borrower,
the Lenders party hereto and the Administrative Agent hereby agree as follows:
1. Certain Definitions.
1.1 Terms Defined Above. As used in this Second Amendment, the terms "Additional Lender",
..."Administrative Agent", "Borrower", "Credit Agreement", "Second Amendment" and "Second Amendment Effective Date",
shall have the meanings indicated above.
1.2 Terms Defined in Agreement. Unless otherwise defined herein, all terms beginning with a capital
letter which are defined in the Credit Agreement shall have the same meanings herein as therein unless the
context hereof otherwise requires.
PAGE 1
2. Amendments to Credit Agreement.
2.1 Defined Terms. The following terms defined in Section 1.02 of the Credit
Agreement are hereby amended as follows:
(a) The term "Agreement" is hereby amended to mean the Credit Agreement, as amended and supplemented by this
Second Amendment and as the same may from time to time be further amended or supplemented.
(b) The term "Commitment" is hereby amended in its entirety to read as follows:
"Commitment" means, with respect to each Lender, the
commitment of such Lender to make Revolving Loans and to acquire participations in
Letters of Credit and Swingline Loans hereunder, expressed as an amount representing
the maximum aggregate amount of such Lender's Revolving Credit Exposure hereunder,
as such commitment may be (a) reduced from time to time pursuant to Section 2.09 and
(b) reduced or increased from time to time pursuant to Section 2.01 or assignments
by or to such Lender pursuant to Section 9.04. The amount of each Lender's
Commitment as of the Second Amendment Effective Date is set forth on Schedule 2.01
to the Second Amendment, or in the Assignment and Acceptance pursuant to which such
Lender shall have assumed its Commitment, as applicable. The aggregate amount of
the Lenders' Commitments as of the Second Amendment Effective Date is $270,000,000.
(c) The term "Consolidated EBITDA" is hereby amended in its entirety to read as follows:
"Consolidated EBITDA" means for any period, the sum of (a) the consolidated
net income of the Borrower and its consolidated Subsidiaries (excluding Project Finance
Subsidiaries) for such period plus, to the extent deducted in determining consolidated net
income for such period, the aggregate amount of (i) Consolidated Interest Expense, (ii) income
tax expense and (iii) depreciation and amortization expense plus (b) the amount of cash
dividends actually received during such period by the Borrower or a Subsidiary (other than a
Project Finance Subsidiary) from a Project Finance Subsidiary plus (c) the amount of all
payments during such period on leases of the type referred to in clause (d) of the definition
herein of Indebtedness and the amount of all payments during such period under other
off-balance sheet loans and financings of the type referred to in such clause (d);
provided, however, for any four fiscal quarter period in which a fiscal quarter of
fiscal year 2002 is included, up to $50,000,000 in losses resulting from hedging natural gas
PAGE 2
liquids utilizing natural gas financial instruments entered into on or prior to the Second
Amendment Effective Date, shall be excluded from the calculation of Consolidated EBITDA for
such four fiscal quarter period.
(d) The term "Lenders" is hereby amended in its entirety to read as follows:
"Lenders" means the Persons listed on Schedule 2.01 to the Second
Amendment and any other Person that shall have become a party hereto pursuant to an Assignment
and Acceptance or pursuant to Section 2.01(b), other than any such Person that ceases to be a
party hereto pursuant to an Assignment and Acceptance or pursuant to Section 2.01(c). Unless
the context otherwise requires, the term "Lenders" includes the Swingline Lender.
2.2 Additional Defined Term. Section 1.02 of the Credit Agreement is hereby further amended and
supplemented by adding the following new definition, which reads in its entirety as follows:
"Second Amendment" shall mean that certain Second Amendment and
Supplement to Credit Agreement dated as of April 24, 2002, among the Borrower, the Lenders
party thereto and the Administrative Agent."
2.3 Schedule 2.01 - Commitments. Schedule 2.01 attached to the Credit Agreement is hereby replaced
and superseded by Schedule 2.01 attached to this Second Amendment. From and after the Second Amendment Effective
Date, each Lender's Commitment shall be as set forth on Schedule 2.01 attached hereto.
2.4 Ratio of Consolidated Indebtedness to Consolidated EBITDA. Section 6.07(b) of the Credit
Agreement is hereby amended in its entirety to read as follows:
"(b) Ratio of Consolidated Indebtedness to Consolidated EBITDA. The
Borrower shall not permit its ratio of Consolidated Indebtedness to Consolidated EBITDA for the four full fiscal
quarters most recently ended to exceed 4.00 to 1.0 as of the last day of any fiscal quarter of the Borrower;
provided, however, for the four fiscal quarter period ending September 30, 2002, the Borrower's
ratio of Consolidated Indebtedness to Consolidated EBITDA shall not exceed 4.50 to 1.0 as of September 30, 2002.
For purposes of calculating such ratio, the Project Finance Subsidiaries shall be disregarded. For purposes of
this Section 6.07(b), if during any period of four fiscal quarters the Borrower or any Subsidiary acquires any
Person (or any interest in any Person) or all or substantially all of the assets of any Person, the EBITDA
attributable to such assets or an amount equal to the percentage of ownership of the Borrower in such Person
times the EBITDA of such Person, for such period determined on a pro forma basis (which determination, in each
case, shall be subject to approval of the Administrative Agent, not to be unreasonably withheld) may be included
as Consolidated EBITDA for such period; provided that during the portion of such period that
follows such acquisition, the computation in respect of the EBITDA of such Person or such assets, as the case may
be, shall be made on the basis of actual (rather than pro forma) results."
PAGE 3
3. Conditions Precedent. In addition to all other applicable conditions precedent contained in the
Credit Agreement, the obligation of the Lenders party hereto (including the Additional Lender) and the
Administrative Agent to enter into this Second Amendment shall be conditioned upon the following conditions
precedent:
(a) The Administrative Agent shall have received a copy of this Second Amendment, duly completed and
executed by the Borrower;
(b) To the extent requested by the Additional Lender or by the Lenders party hereto whose Commitment will
increase as of the Second Amendment Effective Date, duly executed Notes payable to the order of such Lender
reflecting such Lender's Commitment; and
(c) The Administrative Agent shall have received such other information, documents or instruments as it or
its counsel may reasonably request.
4. Representations and Warranties. The Borrower represents and warrants that:
(a) there exists no Default or Event of Default, or any condition or act which constitutes, or with notice
or lapse of time or both would constitute, an Event of Default under the Credit Agreement, as hereby amended and
supplemented;
(b) the Borrower has performed and complied with all covenants, agreements and conditions contained in the
Credit Agreement, as hereby amended and supplemented, required to be performed or complied with by it; and
(c) the representations and warranties of the Borrower contained in the Credit Agreement, as hereby amended
and supplemented, were true and correct when made, and are true and correct in all material respects at and as of
the time of delivery of this Second Amendment.
5. Extent of Amendments. Except as expressly herein set forth, all of the terms, conditions,
defined terms, covenants, representations, warranties and all other provisions of the Credit Agreement are herein
ratified and confirmed and shall remain in full force and effect.
6. Counterparts. This Second Amendment may be executed in two or more counterparts, and it shall
not be necessary that the signatures of all parties hereto be contained on any one counterpart hereof; each
counterpart shall be deemed an original, but all of which together shall constitute one and same instrument.
7. References. On and after the Second Amendment Effective Date, the terms "Agreement", "hereof",
"herein", "hereunder", and terms of like import when used in the Credit Agreement shall, except where the context
otherwise requires, refer to the Credit Agreement, as amended and supplemented by this Second Amendment.
THIS SECOND AMENDMENT, THE CREDIT AGREEMENT, AS AMENDED HEREBY, THE NOTES AND THE OTHER LOAN
DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
PAGE 4
CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES .
THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
This Second Amendment shall benefit and bind the parties hereto, as well as their respective assigns,
successors, heirs and legal representatives.
[Signatures Begin on Next Page]
PAGE 5
EXECUTED as of the Second Amendment Effective Date.
BORROWER:
ENTERPRISE PRODUCTS OPERATING L.P.
By: Enterprise Products GP, LLC , General Partner
By: /s/ W. Randall Fowler
Name: W. Randall Fowler
Title: Vice President and Treasurer
LENDERS AND AGENTS:
WACHOVIA BANK, NATIONAL ASSOCIATION (formerly known as First
Union National Bank), Individually and as Administrative
Agent
By: /s/ Russell Clingman
Name: Russell Clingman
Title: Director
JPMORGAN CHASE BANK, successor-in-interest to The Chase
Manhattan Bank, Individually and as Syndication Agent
By: _____________________________________________________
Name: _____________________________________________________
Title: _____________________________________________________
BANK ONE, NA (Main Office - Chicago),
Individually and as Documentation Agent
By: /s/ Dianne L. Russell
Name: Dianne L. Russell
Title: Director
THE BANK OF NOVA SCOTIA
By: /s/ A. S. Norsworthy
Name: A.S. Norsworthy
Title: Senior Manager
MIZUHO CORPORATE BANK, Ltd., Individually and as Managing
Agent
By: /s/ Jacques Azagury
Name: Jacques Azagury
Title: Senior Vice President and Manager
NATIONAL AUSTRALIA BANK LIMITED, A.C.N. 004044937,
Individually and as Managing Agent
By: _____________________________________________________
Name: _____________________________________________________
Title: _____________________________________________________
FLEET NATIONAL BANK, Individually and as Managing Agent
By: /s/ Christopher c. Holmgren
Name: Christopher C. Holmgren
Title: Managing Director
WESTDEUTSCHE LANDESBANK
GIRONZENTRALE, NEW YORK BRANCH, Individually and as Co-Agent
By: _____________________________________________________
Name: _____________________________________________________
Title: _____________________________________________________
TORONTO DOMINION (TEXAS), INC., Individually and As Managing
Agent
By: /s/ Debbie A. Greene
Name: Debbie A. Greene
Title: Vice President
GUARANTY BANK
By: /s/ Jim R. Hamilton
Name: James R. Hamilton
Title: Senior Vice President
HIBERNIA NATIONAL BANK
By: /s/ Nancy G. Moragas
Name: Nancy G. Moragas
Title: Vice President
ROYAL BANK OF CANADA
By: /s/ Tom J. Oberaigner
Name: Tom J. Oberaigner
Title: Senior Manager
BANK OF TOKYO-MITSUBISHI, LTD., HOUSTON AGENCY, Individually
and as Co-Agent
By: /s/ K. Glasscock
Name: K. Glasscock
Title: VP and Manager
SUNTRUST BANK, Individually and as Co-Agent
By: /s/ David J. Edge
Name: David J. Edge
Title: Director
CITIBANK, N.A.
By: /s/ Douglas A. Whiddon
Name: Douglas A. Whiddon
Title: Attorney-In-Fact
Houston:845511_4.DOC
-1-
ACKNOWLEDGMENT AND RATIFICATION OF GUARANTOR
The undersigned ("Guarantor") hereby expressly (i) acknowledges the terms of the foregoing Second
Amendment and Supplement to Credit Agreement; (ii) ratifies and affirms its obligations under its Guaranty
Agreement dated as of November 17, 2000, in favor of the Administrative Agent; (iii) acknowledges, renews and
extends its continued liability under said Guaranty Agreement and Guarantor hereby agrees that its Guaranty
Agreement remains in full force and effect; and (iv) guarantees to the Administrative Agent the prompt payment
when due of all amounts owing or to be owing by it under its Guaranty Agreement pursuant to the terms and
conditions thereof, as modified hereby.
The foregoing acknowledgment and ratification of the undersigned Guarantor shall be evidenced by signing
the spaces provided below, to be effective as of Second Amendment Effective Date.
ENTERPRISE PRODUCTS PARTNERS L.P., a Delaware limited
partnership
By: Enterprise Products GP, LLC, General Partner
By: /w/ W. Randall Fowler
Name: W. Randall Fowler
Title: Vice President and Treasurer
-1-
SCHEDULE 2.01
COMMITMENTS
Lender Commitment
Wachovia Bank, National Association $ 25,000,000
JPMorgan Chase Bank $ 23,125,000
Bank One, NA (Main Office - Chicago) $ 23,125,000
National Australia Bank Limited $ 21,250,000
Toronto Dominion (Texas), Inc. $ 21,250,000
Fleet National Bank $ 21,250,000
Mizuho Corporate Bank, Ltd. $ 21,250,000
Royal Bank of Canada $ 20,000,000
Bank of Tokyo - Mitsubishi, Ltd., $ 15,625,000
Houston Agency
SunTrust Bank $ 15,625,000
Westdeutsche Landesbank Girozentrale, $ 15,625,000
New York Branch
Guaranty Bank $ 12,500,000
Citibank NA $ 12,500,000
The Bank of Nova Scotia $ 12,500,000
Hibernia National Bank $ 9,375,000
TOTAL $270,000,000
TO CREDIT AGREEMENT
(364-Day Credit Facility)
THIS SECOND AMENDMENT AND SUPPLEMENT TO CREDIT AGREEMENT (this "Second Amendment") is made and
entered into as of the 24th day of April, 2002 (the "Second Amendment Effective Date"), among ENTERPRISE
PRODUCTS OPERATING L.P., a Delaware limited partnership ("Borrower"); WACHOVIA BANK, NATIONAL ASSOCIATION
(formerly known as First Union National Bank), as administrative agent (in such capacity, the "Administrative
Agent") for each of the lenders (the "Lenders") that is a signatory or which becomes a signatory to
the hereinafter defined Credit Agreement; and the Lenders party hereto.
R E C I T A L S:
A. On November 17, 2000, the Borrower, the Lenders and the Administrative Agent entered into a certain
Credit Agreement (as amended and supplemented by First Amendment and Supplement to Credit Agreement dated
November 6, 2001, effective as of November 16, 2001, the "Credit Agreement") whereby, upon the terms and
conditions therein stated, the Lenders agreed to make certain Loans (as defined in the Credit Agreement) and
extend certain credit to the Borrower.
B. Pursuant to Section 2.01(b) of the Credit Agreement (i) the Borrower has, as of the Second Amendment
Effective Date, added Royal Bank of Canada as an additional Lender under the Credit Agreement (the "Additional
Lender"), and (ii) certain of the existing Lenders have, as of the Second Amendment Effective Date, increased
their respective Commitments (as defined in the Credit Agreement), thereby increasing the total Commitments of
the Lenders by an aggregate amount equal to $80,000,000 making the aggregate amount of the Lenders' Commitments
$230,000,000.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained, the Borrower,
the Lenders party hereto and the Administrative Agent hereby agree as follows:
1. Certain Definitions.
1.1 Terms Defined Above. As used in this Second Amendment, the terms "Additional Lender",
"Administrative Agent", "Borrower", "Credit Agreement", "Second Amendment" and "Second Amendment Effective Date",
shall have the meanings indicated above.
1.2 Terms Defined in Agreement. Unless otherwise defined herein, all terms beginning with a capital
letter which are defined in the Credit Agreement shall have the same meanings herein as therein unless the
context hereof otherwise requires.
2. Amendments to Credit Agreement.
2.1 Defined Terms. The following terms defined in Section 1.02 of the Credit
Agreement are hereby amended as follows:
PAGE 1
(a) The term "Agreement" is hereby amended to mean the Credit Agreement, as amended and supplemented by this
Second Amendment and as the same may from time to time be further amended or supplemented.
(b) The term "Commitment" is hereby amended in its entirety to read as follows:
"Commitment" means, with respect to each Lender, the
commitment of such Lender to make Loans hereunder, expressed as an amount
representing the maximum aggregate amount of such Lender's Exposure hereunder, as
such commitment may be (a) reduced from time to time pursuant to Section 2.09 and
(b) reduced or increased from time to time pursuant to Section 2.01 or assignments
by or to such Lender pursuant to Section 9.04. The amount of each Lender's
Commitment as of the Second Amendment Effective Date is set forth on Schedule 2.01
to the Second Amendment, or in the Assignment and Acceptance pursuant to which such
Lender shall have assumed its Commitment, as applicable. The aggregate amount of
the Lenders' Commitments as of the Second Amendment Effective Date is $230,000,000.
(c) The term "Consolidated EBITDA" is hereby amended in its entirety to read as follows:
"Consolidated EBITDA" means for any period, the sum of (a) the
consolidated net income of the Borrower and its consolidated Subsidiaries (excluding
Project Finance Subsidiaries) for such period plus, to the extent deducted in
determining consolidated net income for such period, the aggregate amount of (i)
Consolidated Interest Expense, (ii) income tax expense and (iii) depreciation and
amortization expense plus (b) the amount of cash dividends actually received during
such period by the Borrower or a Subsidiary (other than a Project Finance Subsidiary)
from a Project Finance Subsidiary plus (c) the amount of all payments during such
period on leases of the type referred to in clause (d) of the definition herein of
Indebtedness and the amount of all payments during such period under other off-balance
sheet loans and financings of the type referred to in such clause (d);
provided, however, for any four fiscal quarter period in which a fiscal
quarter of fiscal year 2002 is included, up to $50,000,000 in losses resulting from
hedging natural gas liquids utilizing natural gas financial instruments entered into
on or prior to the Second Amendment Effective Date shall be excluded from the
calculation of Consolidated EBITDA for such four fiscal quarter period.
PAGE 2
(d) The term "Lenders" is hereby amended in its entirety to read as follows:
"Lenders" means the Persons listed on Schedule 2.01 to the
Second Amendment and any other Person that shall have become a party hereto pursuant
to an Assignment and Acceptance or pursuant to Section 2.01(b), other than any such
Person that ceases to be a party hereto pursuant to an Assignment and Acceptance or
pursuant to Section 2.01(c).
2.2 Additional Defined Term. Section 1.02 of the Credit Agreement is hereby further amended and
supplemented by adding the following new definition, which reads in its entirety as follows:
"Second Amendment" shall mean that certain Second Amendment and
Supplement to Credit Agreement dated as of April 24, 2002, among the Borrower, the Lenders
party thereto and the Administrative Agent.
2.3 Schedule 2.01 - Commitments. Schedule 2.01 attached to the Credit Agreement is hereby replaced
and superseded by Schedule 2.01 attached to this Second Amendment. From and after the Second Amendment Effective
Date, each Lender's Commitment shall be as set forth on Schedule 2.01 attached hereto.
2.4 Ratio of Consolidated Indebtedness to Consolidated EBITDA. Section 6.07(b) of the Credit
Agreement is hereby amended in its entirety to read as follows:
"(b) Ratio of Consolidated Indebtedness to Consolidated EBITDA. The
Borrower shall not permit its ratio of Consolidated Indebtedness to Consolidated EBITDA for the four full fiscal
quarters most recently ended to exceed 4.00 to 1.0 as of the last day of any fiscal quarter of the Borrower;
provided, however, for the four fiscal quarter period ending September 30, 2002, the Borrower's
ratio of Consolidated Indebtedness to Consolidated EBITDA shall not exceed 4.50 to 1.0 as of September 30, 2002.
For purposes of calculating such ratio, the Project Finance Subsidiaries shall be disregarded. For purposes of
this Section 6.07(b), if during any period of four fiscal quarters the Borrower or any Subsidiary acquires any
Person (or any interest in any Person) or all or substantially all of the assets of any Person, the EBITDA
attributable to such assets or an amount equal to the percentage of ownership of the Borrower in such Person
times the EBITDA of such Person, for such period determined on a pro forma basis (which determination, in each
case, shall be subject to approval of the Administrative Agent, not to be unreasonably withheld) may be included
as Consolidated EBITDA for such period; provided that during the portion of such period that
follows such acquisition, the computation in respect of the EBITDA of such Person or such assets, as the case may
be, shall be made on the basis of actual (rather than pro forma) results."
3. Conditions Precedent. In addition to all other applicable conditions precedent contained in the
Credit Agreement, the obligation of the Lenders party hereto (including the Additional Lender) and the
Administrative Agent to enter into this Second Amendment shall be conditioned upon the following conditions
precedent:
(a) The Administrative Agent shall have received a copy of this Second Amendment, duly completed and
executed by the Borrower;
PAGE 3
(b) To the extent requested by the Additional Lender or by the Lenders party hereto whose Commitment will
increase as of the Second Amendment Effective Date, duly executed Notes payable to the order of such Lender
reflecting such Lender's Commitment; and
(c) The Administrative Agent shall have received such other information, documents or instruments as it or
its counsel may reasonably request.
4. Representations and Warranties. The Borrower represents and warrants that:
(a) there exists no Default or Event of Default, or any condition or act which constitutes, or with notice
or lapse of time or both would constitute, an Event of Default under the Credit Agreement, as hereby amended and
supplemented;
(b) the Borrower has performed and complied with all covenants, agreements and conditions contained in the
Credit Agreement, as hereby amended and supplemented, required to be performed or complied with by it; and
(c) the representations and warranties of the Borrower contained in the Credit Agreement, as hereby amended
and supplemented, were true and correct when made, and are true and correct in all material respects at and as of
the time of delivery of this Second Amendment.
5. Extent of Amendments. Except as expressly herein set forth, all of the terms, conditions,
defined terms, covenants, representations, warranties and all other provisions of the Credit Agreement are herein
ratified and confirmed and shall remain in full force and effect.
6. Counterparts. This Second Amendment may be executed in two or more counterparts, and it shall
not be necessary that the signatures of all parties hereto be contained on any one counterpart hereof; each
counterpart shall be deemed an original, but all of which together shall constitute one and same instrument.
7. References. On and after the Second Amendment Effective Date, the terms "Agreement", "hereof",
"herein", "hereunder", and terms of like import when used in the Credit Agreement shall, except where the context
otherwise requires, refer to the Credit Agreement, as amended and supplemented by this Second Amendment.
PAGE 4
THIS SECOND AMENDMENT, THE CREDIT AGREEMENT, AS AMENDED HEREBY, THE NOTES AND THE OTHER LOAN
DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.
THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
This Second Amendment shall benefit and bind the parties hereto, as well as their respective assigns,
successors, heirs and legal representatives.
[Signatures Begin on Next Page]
EXECUTED as of the Second Amendment Effective Date.
BORROWER:
ENTERPRISE PRODUCTS OPERATING L.P.
By: Enterprise Products GP, LLC , General Partner
By: /s/ W. Randall Fowler
Name: W. Randall Fowler
Title: Vice President and Treasurer
LENDERS AND AGENTS:
WACHOVIA BANK, NATIONAL ASSOCIATION (formerly known as First
Union National Bank), Individually and as Administrative
Agent
By: /s/ Russell Clingman
Name: Russell Clingman
Title: Director
BANK ONE, NA (Main Office - Chicago),
Individually and as Co-Syndication Agent
By: /s/ Dianne L. Russell
Name: Dianne L. Russell
Title: Director
THE BANK OF NOVA SCOTIA, Individually and as Co-Syndication
Agent
By: /s/ A.S. Norsworthy
Name: A.S. Norsworthy
Title: Senior Manager
MIZUHO CORPORATE BANK, Ltd., Individually and as Managing
Agent
By: /s/ Jacques Azagury
Name: Jacques Azagury
Title: Senior vice President and Manager
FLEET NATIONAL BANK, Individually and as Co-Documentation
Agent
By: /s/ Christopher C. Holmgren
Name: Christopher Holmgren
Title: Managing Director
WESTDEUTSCHE LANDESBANK
GIRONZENTRALE, NEW YORK BRANCH, Individually and as
Co-Documentation Agent
By: _____________________________________________________
Name: _____________________________________________________
Title: _____________________________________________________
TORONTO DOMINION (TEXAS), INC.
By: /s/ Debbie A. Greene
Name: Debbie A. Greene
Title: Vice President
GUARANTY BANK
By: /s/ Jim R. Hamilton
Name: James R. Hamilton
Title: Senior Vice President
HIBERNIA NATIONAL BANK
By: /s/ Nancy G. Moragas
Name: Nancy G. Moragas
Title: Vice President
ROYAL BANK OF CANADA
By: /s/ Tom J. Oberaigner
Name: Tom J. Oberaigner
Title: Senior Manger
BANK OF TOKYO-MITSUBISHI, LTD., HOUSTON AGENCY
By: /s/ K. Glasscock
Name: K. Glasscock
Title: VP and Manger
SUNTRUST BANK,
Individually and as Managing Agent
By: /s/ David J. Edge
Name: David J. Edge
Title: Director
CITIBANK, N.A.
By: /s/ Douglas A. Whiddon
Name: Douglas A. Whiddon
Title: Attorney-In-Fact
ACKNOWLEDGMENT AND RATIFICATION OF GUARANTOR
The undersigned ("Guarantor") hereby expressly (i) acknowledges the terms of the foregoing Second
Amendment and Supplement to Credit Agreement; (ii) ratifies and affirms its obligations under its Guaranty
Agreement dated as of November 17, 2000, in favor of the Administrative Agent; (iii) acknowledges, renews and
extends its continued liability under said Guaranty Agreement and Guarantor hereby agrees that its Guaranty
Agreement remains in full force and effect; and (iv) guarantees to the Administrative Agent the prompt payment
when due of all amounts owing or to be owing by it under its Guaranty Agreement pursuant to the terms and
conditions thereof, as modified hereby.
The foregoing acknowledgment and ratification of the undersigned Guarantor shall be evidenced by signing
the spaces provided below, to be effective as of Second Amendment Effective Date.
ENTERPRISE PRODUCTS PARTNERS L.P., a Delaware limited
partnership
By: Enterprise Products GP, LLC, General Partner
By: /s/ W. Randall Fowler
Name: W. Randall Fowler
Title: Vice President and Treasurer
SCHEDULE 2.01
COMMITMENTS
Lender Commitment
Wachovia Bank, National Association $ 27,625,000
Bank One, NA (Main Office - Chicago) $ 25,000,000
Toronto Dominion (Texas), Inc. $ 12,500,000
Fleet National Bank $ 26,750,000
Mizuho Corporate Bank, Ltd. $ 15,000,000
Bank of Tokyo - Mitsubishi, Ltd., $ 10,000,000
Houston Agency
SunTrust Bank $ 23,500,000
Westdeutsche Landesbank Girozentrale, $ 15,000,000
New York Branch
Guaranty Bank $ 7,500,000
Citibank NA $ 16,500,000
The Bank of Nova Scotia $ 25,000,000
Hibernia National Bank $ 5,625,000
Royal Bank of Canada $ 20,000,000
TOTAL $230,000,000