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 June 30, 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 August 7, 2002, 131,894,766 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. 333-93239-01). 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. 28
Item 2. Management's Discussion and Analysis of Financial Condition 51
and Results of Operations.
Item 3. Quantitative and Qualitative Disclosures about Market Risk. 74
PART II
Item 6. Exhibits and Reports on Form 8-K. 78
81
Signatures page
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
CEO Chief Executive Officer
CFO Chief Financial Officer
ChevronTexaco ChevronTexaco Corp., its subsidiaries and affiliates
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
E-Oaktree E-Oaktree, LLC, a subsidiary of the Company of whom 98% of its membership
interests were acquired by us from affiliates of Williams in July 2002
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
Evangeline Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively,
an equity investment of EPOLP
FASB Financial Accounting Standards Board
FTC U.S. Federal Trade Commission
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
IPO Refers to our initial public offering in July 1998
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
Mapletree Mapletree, LLC, a subsidiary of the Company of whom 98% of its membership
interests were acquired by us from affiliates of Williams in July 2002
MBA Mont Belvieu Associates, see "MBA acquisition" below
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
Mid-America Mid-America Pipeline Company, LLC
MMcf/d Million cubic feet 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
Moody's Moody's Investors Service
MTBE Methyl tertiary butyl ether
Nemo Nemo Gathering Company, LLC, an equity investment of EPOLP
Neptune Neptune Pipeline Company, LLC, an equity investment of EPOLP
NGL or NGLs Natural gas liquid(s)
NYSE New York Stock Exchange
Ocean Breeze Ocean Breeze Pipeline Company, LLC, an equity investment of EPOLP (merged
into Neptune during fourth quarter of 2001)
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
Seminole Seminole Pipeline Company
SFAS Statement of Financial Accounting Standards issued by the FASB
Shell Shell Oil Company, its subsidiaries and affiliates
S and P Standard and Poor's Rating Services
Starfish Starfish Pipeline Company LLC, an equity investment of EPOLP
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
Williams The Williams Companies, Inc. and subsidiaries
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)
June 30,
2002 December 31,
ASSETS (unaudited) 2001
-------------------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of $5,034 at
June 30, 2002 and $5,752 at December 31, 2001) $ 7,929 $ 137,823
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $21,098 at June 30, 2002 and $20,642 at December 31, 2001 284,021 256,927
Accounts receivable - affiliates 1,740 4,375
Inventories 153,280 69,443
Prepaid and other current assets 34,089 50,207
-------------------------------------
Total current assets 481,059 518,775
Property, Plant and Equipment, Net 1,570,571 1,306,790
Investments in and Advances to Unconsolidated Affiliates 403,070 398,201
Intangible assets, net of accumulated amortization of $18,235 at
June 30, 2002 and $13,084 at December 31, 2001 249,222 202,226
Goodwill 81,543
Other Assets 6,911 5,201
-------------------------------------
Total $2,792,376 $2,431,193
=====================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $70,716 $54,269
Accounts payable - affiliates 21,233 29,885
Accrued gas payables 303,983 233,536
Accrued expenses 12,961 22,460
Accrued interest 24,676 24,302
Other current liabilities 70,672 44,764
-------------------------------------
Total current liabilities 504,241 409,216
Long-Term Debt 1,223,552 855,278
Other Long-Term Liabilities 7,919 8,061
Minority Interest 10,818 11,716
Commitments and Contingencies
Partners' Equity
Common Units (112,954,266 Units outstanding at June 30, 2002
and 102,721,830 at December 31, 2001) 589,504 651,872
Subordinated Units (32,114,804 Units outstanding at June 30, 2002
and 42,819,740 December 31, 2001) 165,818 193,107
Special Units (29,000,000 Units outstanding at June 30, 2002
and December 31, 2001) 296,634 296,634
Treasury Units, at cost (799,700 Common Units
outstanding at June 30, 2002 and 327,200 at December 31, 2001) (16,736) (6,222)
General Partner 10,626 11,531
-------------------------------------
Total Partners' Equity 1,045,846 1,146,922
-------------------------------------
Total $2,792,376 $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)
Three Months Ended Six Months Ended
June 30, June 30,
-----------------------------------------------------------
2002 2001 2002 2001
-----------------------------------------------------------
REVENUES
Revenues from consolidated operations $786,257 $959,397 $1,448,311 $1,795,712
Equity income in unconsolidated affiliates 7,068 9,050 16,295 11,061
-----------------------------------------------------------
Total 793,325 968,447 1,464,606 1,806,773
-----------------------------------------------------------
COST AND EXPENSES
Operating costs and expenses 745,621 851,639 1,410,044 1,629,380
Selling, general and administrative 7,740 7,737 15,702 13,905
-----------------------------------------------------------
Total 753,361 859,376 1,425,746 1,643,285
-----------------------------------------------------------
OPERATING INCOME 39,964 109,071 38,860 163,488
OTHER INCOME (EXPENSE)
Interest expense (19,032) (16,331) (37,545) (23,318)
Interest income from unconsolidated affiliates 62 7 92 31
Dividend income from unconsolidated affiliates 1,242 2,196 1,632
Interest income - other 241 1,479 1,575 5,477
Other, net 46 (251) (31) (531)
-----------------------------------------------------------
Other income (expense) (17,441) (15,096) (33,713) (16,709)
-----------------------------------------------------------
INCOME BEFORE MINORITY INTEREST 22,523 93,975 5,147 146,779
MINORITY INTEREST (203) (944) (30) (1,478)
-----------------------------------------------------------
NET INCOME $ 22,320 $ 93,031 $ 5,117 $ 145,301
===========================================================
ALLOCATION OF NET INCOME TO:
Limited partners $ 19,672 $ 91,643 $ 1,223 $ 142,931
===========================================================
General partner $ 2,648 $ 1,388 $ 3,894 $ 2,370
===========================================================
BASIC EARNINGS PER UNIT
Income before minority interest $ 0.14 $ 0.68 $ 0.01 $ 1.07
===========================================================
Net income per Common and Subordinated unit $ 0.14 $ 0.68 $ 0.01 $ 1.06
===========================================================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 0.11 $ 0.55 $ 0.01 $ 0.86
===========================================================
Net income per Common, Subordinated
and Special unit $ 0.11 $ 0.54 $ 0.01 $ 0.85
===========================================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 2
Enterprise Products Partners L.P.
Statements of Consolidated Cash Flows
(Dollars in thousands)
(Unaudited)
Six Months Ended
June 30,
----------------------------------
2002 2001
----------------------------------
OPERATING ACTIVITIES
Net income $ 5,117 $145,301
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 35,349 23,234
Equity in income of unconsolidated affiliates (16,295) (11,061)
Distributions received from unconsolidated affiliates 29,113 13,212
Leases paid by EPCO 4,534 5,267
Minority interest 30 1,478
Loss (gain) on sale of assets 12 (387)
Changes in fair market value of financial instruments (see Note 13) 19,702 (55,880)
Net effect of changes in operating accounts (32,379) (30,569)
----------------------------------
Operating activities cash flows 45,183 90,595
----------------------------------
INVESTING ACTIVITIES
Capital expenditures (26,755) (57,090)
Proceeds from sale of assets 12 563
Business acquisitions, net of cash received (394,775) (225,665)
Investments in and advances to unconsolidated affiliates (10,137) (115,282)
----------------------------------
Investing activities cash flows (431,655) (397,474)
----------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 538,000 449,716
Long-term debt repayments (170,000)
Debt issuance costs (418) (3,125)
Cash dividends paid to partners (99,010) (76,112)
Cash dividends paid to minority interest by Operating Partnership (1,014) (783)
Cash contributions from EPCO to minority interest 86 53
Treasury Units purchased (11,066)
Increase in restricted cash 718 (7,321)
----------------------------------
Financing activities cash flows 257,296 362,428
----------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (129,176) 55,549
CASH AND CASH EQUIVALENTS, JANUARY 1 132,071 60,409
----------------------------------
CASH AND CASH EQUIVALENTS, JUNE 30 $ 2,895 $115,958
==================================
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 June 30, 2002 and consolidated results of operations and cash flows for the
three and six months ended June 30, 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., which are included elsewhere in this combined report on Form
10-Q. We own 98.9899% of the Operating Partnership and act as guarantor of certain debt obligations of the
Operating Partnership. Our General Partner, Enterprise Products GP, LLC, owns the remaining 1.0101% of the
Operating Partnership. Essentially all of our assets, liabilities, revenues and expenses are recorded at the
Operating Partnership level in our consolidated financial statements.
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 three and six months ended June 30, 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, the General Partner approved a two-for-one split for each class of our partnership
Units. The partnership Unit split was accomplished by distributing one additional partnership Unit for each
partnership Unit outstanding to holders of record on April 30, 2002. The Units were distributed on May 15,
2002. All references to number of Units or earnings per Unit contained in this document reflect the Unit split,
unless otherwise indicated.
2. BUSINESS ACQUISITIONS
Acquisition of Diamond-Koch propylene fractionation business in February 2002
In February 2002, we purchased 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. These assets are part of
our Mont Belvieu propylene fractionation operations, which is part of the Fractionation segment. The purchase
price of $239.0 million was funded by a drawdown on our Multi-Year and 364-Day Credit Facilities (see Note 8).
PAGE 4
Acquisition of Diamond-Koch storage business in January 2002
In January 2002, we purchased 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, these facilities represent the largest underground storage operation of its kind in
the world. The size and location of the business provide it with a competitive position to increase its services
to expanding Gulf Coast petrochemical complexes. These assets are part of our Mont Belvieu storage operations,
which is part of the Pipelines segment. 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 were accounted for under the purchase method of accounting and, accordingly, the
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 3,148 $ 890 4,038
Property, plant and equipment 96,772 120,571 217,343
Investments in unconsolidated affiliates 7,550 7,550
Intangible assets (see Note 7) 53,000 8,127 61,127
Goodwill (see Note 7) 73,686 73,686
Current liabilities (107) (107)
------------------------------------------------------------
Total purchase price $239,043 $129,588 $368,631
============================================================
The fair value estimates were developed by independent appraisers using recognized business valuation
techniques. The allocation of the purchase price is preliminary pending the results of a repermitting process
expected to be complete during the fourth quarter of 2002.
The purchase price paid for the propylene fractionation business resulted in $73.7 million in goodwill. The
goodwill primarily represents the value management has attached to future earnings improvements and to the
strategic location of the 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.
Acadian Gas post-closing adjustments completed in April 2002
In April 2002, we finalized the post-closing purchase price adjustment associated with our April 2001 acquisition
of Acadian Gas. Acadian Gas was acquired from an affiliate of Shell and is involved in the purchase, sale,
transportation and storage of natural gas in Louisiana. As a result, we paid Shell $18.0 million for various
PAGE 5
working capital items, of which the majority were related to natural gas inventories. The Acadian Gas acquisition
was accounted for under the purchase method of accounting and, accordingly, the final purchase price has been
allocated to the assets acquired and liabilities assumed based on their estimated fair values at April 1, 2001 as
follows:
Current assets $ 83,123
Investments in unconsolidated affiliates 2,723
Property, plant and equipment 232,187
Current liabilities (72,896)
Other long-term liabilities (1,460)
--------------------
Total purchase price $243,677
====================
Pro forma effect of Diamond-Koch and Acadian Gas business acquisitions
As noted earlier, the Acadian Gas acquisition occurred on April 1, 2001. We acquired Diamond-Koch's storage
business on January 1, 2002 and its propylene fractionation business on February 1, 2002. As a result, our actual
fiscal 2002 Statements of Consolidated Operations reflect the Diamond-Koch propylene fractionation business and
the Diamond-Koch storage business from their respective acquisition dates through June 2002 and the results of
Acadian Gas. For the first six months of fiscal 2001, our Statements of Consolidated Operations reflect only three
months of Acadian Gas.
The following table presents unaudited pro forma financial information incorporating the historical
(pre-acquisition) financial results of the propylene fractionation and storage assets we acquired from
Diamond-Koch and those of Acadian Gas that we acquired from Shell. This information is helpful in gauging the
possible impact that these acquisitions might have had on our results of operations had they been completed on
January 1, 2001 as opposed to the actual dates that these acquisitions occurred. The pro forma information is
based upon data currently available to and certain estimates and assumptions made 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.
Three Months Six Months Ended
Ended June 30, June 30,
-----------------------------
2001 2002 2001
-------------------------------------------------------
Revenues $1,043,671 $1,482,040 $2,195,472
Income before extraordinary item
and minority interest $ 90,424 $ 5,085 $ 147,174
Net income $ 89,517 $ 5,055 $ 145,692
Allocation of net income to
Limited partners $ 88,128 $ 1,161 $ 143,322
General Partner $ 1,389 $ 3,894 $ 2,370
Units used in earnings per Unit calculations
Basic 135,334 145,404 135,334
Diluted 168,334 174,404 168,334
Income per Unit before minority interest
Basic $ 0.66 $ 0.01 $ 1.07
Diluted $ 0.53 $ 0.01 $ 0.86
Net income per Unit
Basic $ 0.65 $ 0.01 $ 1.06
Diluted $ 0.52 $ 0.01 $ 0.85
PAGE 6
Minor acquisitions initiated during the second quarter of 2002
We initiated the purchase of an additional interest in our Mont Belvieu NGL fractionation from ChevronTexaco and
the acquisition of a gas processing plant and NGL fractionator in Louisiana from Western Resources during the
second quarter of 2002. Due to the immaterial nature and incomplete status of these two transactions, our
discussion of each minor purchase is limited to the following:
Acquisition of ChevronTexaco's interest in our Mont Belvieu NGL fractionator. In April 2002, we executed an
agreement with an affiliate of ChevronTexaco to purchase their 12.5% undivided ownership interest in our Mont
Belvieu, Texas NGL fractionator. The purchase price was approximately $8.0 million. The Mont Belvieu facility has a
gross NGL fractionation capacity of 210 MBPD of which 26.2 MBPD was ChevronTexaco's net share. ChevronTexaco was
required to sell their 12.5% interest in a consent order by the FTC as a condition of approving the merger
between Chevron and Texaco. The effective date of the purchase was June 1, 2002.
The other joint owners of the facility (affiliates of Duke Energy Field Services and Burlington Resources Inc.)
have the option to acquire their pro rata share of the ChevronTexaco interest. These preferential purchase rights
expire on September 30, 2002. If the other joint owners fully exercise their option to acquire their share of the
interest, our ownership interest would increase to approximately 71.4% from 62.5% currently. Should the joint
owners decline to exercise their options, we would own 75.0% of the facility. If the other joint owners acquire
any portion of their share of the ChevronTexaco interest, our purchase price will be reduced accordingly. We
expect to complete this transaction during the third quarter of 2002.
Acquisition of gas processing and NGL fractionator assets from Western Gas Resources, Inc. In June 2002, we
executed an agreement to acquire a natural gas processing plant, NGL fractionator and supporting assets
(including contracts) from Western Gas Resources, Inc. for $32.5 million plus certain post-closing purchase price
adjustments. The "Toca Western" facilities are located in St. Bernard Parish, Louisiana near our existing Toca
natural gas processing plant. The gas processing facility has a capacity of 160 MMcf/d and the NGL fractionator
can fractionate up to 14.2 MBPD of NGLs.
This purchase is subject to a preferential purchase right by the other joint owners of our Yscloskey gas
processing facility that expires on September 24, 2002. We are one of the largest owners in the Yscloskey plant
with a 28.2% ownership interest. Should any of the other owners exercise their respective right to acquire their
pro rata interest in the Toca Western facilities, it would reduce the ownership interest we ultimately acquire
and the purchase price we pay. Because of the preferential rights, we expect to close this transaction during the
third quarter of 2002.
3. INVENTORIES
Our inventories are as follows at the dates indicated:
June 30, December 31,
2002 2001
-----------------------------------
Regular trade inventory $70,340 $35,894
Forward-sales inventory 45,960 33,549
Peak Season inventory 20,959
Other 16,021
-----------------------------------
Inventory $153,280 $69,443
===================================
A description of each inventory is as follows:
o Our regular trade (or "working") inventory is comprised of inventories of natural gas, NGLs and
petrochemicals that are available for immediate sale. This inventory is valued at the lower of average
cost or market, with "market" being determined by spot-market related prices.
PAGE 7
o The forward-sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of
forward sales contracts and is valued at the lower of average cost or market, with "market" being
defined as the weighted-average of the sales prices of the forward sales contracts.
o The peak season inventory is comprised of segregated NGL volumes that are expected to be sold outside of
the current summer-winter season and is valued at the lower of average cost or market, with "market"
being determined by spot-market related prices. These volumes are generally expected to be sold within
the next twelve months, but may be held for longer periods depending on market conditions.
o Other inventories generally consist of segregated NGL volumes set aside for possible short-term use as
fuel on an equivalent MMBtu basis. This inventory is carried at the lower of average cost or market,
with "market" being determined by spot-market related prices. The volumes associated with this inventory
are anticipated to be used and/or sold within the next twelve months.
Due to fluctuating market conditions in the NGL, natural gas and petrochemical industry, we occasionally
recognize lower of average cost or market adjustments when the cost of our inventories exceed their net realizable
value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized
and affect our segment operating results in the following manner:
o NGL inventory write downs are recorded as a cost of the Processing segment's merchant activities;
o Natural gas inventory write downs are recorded as a cost of the Pipeline segment's Acadian Gas
operations; and
o Petrochemical inventory write downs are recorded as a cost of the Fractionation segment's propylene
fractionation business.
For the second quarter of 2002, we recognized an adjustment of $4.5 million to write down NGL inventories to
their net realizable value. For the second quarter of 2001, we recorded $25.8 million of such write downs:$19.4
million against NGL inventories, $4.9 million against natural gas inventories and $1.5 million against
petrochemical inventories.
For the first six months of 2002, we recognized $4.6 million in NGL inventory write downs. For the same six month
period in 2001, we recorded $27.8 million in lower of average cost or market write downs. The 2001 adjustments
were $21.4 million against NGL inventories, $4.9 million against natural gas inventories and $1.5 million against
petrochemical inventories. To the extent our commodity hedging strategies address inventory-related risks and are
successful, these inventory value adjustments are mitigated (or in some cases, reversed). See Note 13 for a
description of our commodity hedging activities.
4. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation are as follows at the dates indicated:
Estimated
Useful Life June 30, December 31,
in Years 2002 2001
---------------------------------------------------
Plants and pipelines 5-35 $1,626,739 $1,398,843
Underground and other storage facilities 5-35 241,806 127,900
Transportation equipment 3-35 3,952 3,736
Land 20,014 15,517
Construction in progress 44,003 98,844
-------------------------------------
Total 1,936,514 1,644,840
Less accumulated depreciation 365,943 338,050
-------------------------------------
Property, plant and equipment, net $1,570,571 $1,306,790
=====================================
Property, plant and equipment is recorded at cost and is depreciated using the straight-line method over the
asset's estimated useful life. Maintenance, repairs and minor renewals are charged to operations as incurred. The
PAGE 8
cost of assets retired or sold, together with the related accumulated depreciation, is removed from the accounts,
and any gain or loss on disposition is included in income.
Additions and improvements to and major renewals of existing assets are capitalized and depreciated using the
straight-line method over the estimated useful life of the new equipment or modifications. These expenditures
result in a long-term benefit to the Company. We generally classify improvements and major renewals of existing
assets as sustaining capital expenditures and all other capital spending (on existing and new assets) as
expansion capital expenditures.
Depreciation expense for the three months ended June 30, 2002 and 2001 was $13.8 million and $11.0 million,
respectively. For the six months ended June 30, 2002 and 2001, it was $27.9 million and $20.3 million,
respectively.
5. 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 14.
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 considered an integral part of our Mont Belvieu III propylene fractionation
operations. These investments are classified as part of our Fractionation operating segment.
PAGE 9
The following table shows the aggregate amount of investments in and advances to (and our ownership percentages
in) unconsolidated affiliates at June 30, 2002 and December 31, 2001:
Ownership June 30, December 31,
Percentage 2002 2001
--------------------------------------------------------
Accounted for on equity basis:
Fractionation:
BRF 32.25% $28,687 $29,417
BRPC 30.00% 18,197 18,841
Promix 33.33% 43,513 45,071
La Porte 50.00% 5,814
OTC 50.00% 1,818
Pipeline:
EPIK 50.00% 14,375 14,280
Wilprise 37.35% 8,663 8,834
Tri-States 33.33% 26,448 26,734
Belle Rose 41.67% 11,211 11,624
Dixie 19.88% 37,284 37,558
Starfish 50.00% 23,777 25,352
Neptune 25.67% 77,226 76,880
Nemo 33.92% 12,211 12,189
Evangeline 49.50% 2,657 2,578
Octane Enhancement:
BEF 33.33% 58,189 55,843
Accounted for on cost basis:
Processing:
VESCO 13.10% 33,000 33,000
----------------------------------------
Total $403,070 $398,201
========================================
PAGE 10
The following table shows equity in income (loss) of unconsolidated affiliates for the three and six months ended
June 30, 2002 and 2001:
Three Months Ended Six Months Ended
June 30, June 30,
Ownership --------------------------------------------------------------------
Percentage 2002 2001 2002 2001
-------------------------------------------------------------------------------------
Fractionation:
BRF 32.25% $ 743 $ 42 $ 1,292 $ 60
BRPC 30.00% 278 252 527 404
Promix 33.33% 996 1,396 2,039 1,789
La Porte 50.00% (173) (265)
OTC 50.00% 128 18
Pipelines:
EPIK 50.00% (54) (172) 1,629 (1,094)
Wilprise 37.35% 320 85 467 (137)
Tri-States 33.33% 365 135 834 100
Belle Rose 41.67% 40 29 114 (60)
Dixie 19.88% (156) 69 561 960
Starfish 50.00% 973 1,022 1,785 1,973
Ocean Breeze 25.67% 12 14
Neptune 25.67% 682 1,095 1,460 1,789
Nemo 33.92% 44 1 22 10
Evangeline 49.50% 5 (149) (71) (149)
Octane Enhancement:
BEF 33.33% 2,877 5,233 5,883 5,402
--------------------------------------------------------------------
Total $7,068 $9,050 $16,295 $11,061
====================================================================
Our initial investment in Promix, La Porte, Dixie, Neptune and Nemo exceeded our share of the historical cost of
the underlying net assets of such entities ("excess cost"). The excess cost of these investments is reflected in
our investments in and advances to unconsolidated affiliates for these entities. The excess cost amounts related
to Promix, La Porte and Nemo are attributable to the tangible plant and pipeline assets of each entity, the
excess cost of which is amortized against equity earnings from these entities in a manner similar to
depreciation. The excess cost of Dixie includes amounts attributable to both goodwill and tangible pipeline
assets, with that portion assigned to the pipeline assets being amortized in a manner similar to depreciation. The
goodwill inherent in Dixie's excess cost is subject to periodic impairment testing and is not amortized. The
following table summarizes our excess cost information:
PAGE 11
Amortization
Unamortized balance at Charged to
Initial --------------------------- Equity Earnings
Excess June 30, December 31, during Amortization
Cost 2002 2001 2002 Period
---------------------------------------------------------------------------------------
Fractionation segment:
Promix $7,955 $6,794 $7,083 $199 20 years
La Porte 873 855 n/a 18 35 years
Pipelines segment:
Dixie
Attributable to pipeline assets 28,448 26,480 26,887 406 35 years
Goodwill 9,246 8,827 8,827 n/a n/a
Neptune 12,768 12,221 12,404 182 35 years
Nemo 727 708 718 10 35 years
The following tables 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 Three Months Ended
-------------------------------------------------------------------------------------------------
June 30, 2002 June 30, 2001
----------------------------------------------- ------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
----------------------------------------------- ------------------------------------------------
Fractionation:
BRF $ 5,750 $ 2,295 $ 2,305 $ 3,802 $ 265 $ 294
BRPC 3,150 923 930 3,400 793 842
Promix 10,819 3,274 3,285 12,340 4,447 4,487
La Porte (301) (306)
OTC 1,421 302 258
Pipeline:
EPIK 1,577 (117) (109) 792 (375) (348)
Wilprise 1,033 855 857 494 224 227
Tri-States 3,680 1,088 1,097 2,321 388 403
Belle Rose 433 95 96 407 13 21
Dixie 6,270 (1,853) (1,191) 8,799 2,001 1,124
Starfish 6,714 2,169 1,943 7,051 2,571 2,299
Ocean Breeze 53 39 39
Neptune 6,926 2,046 2,338 9,362 5,223 5,195
Nemo 887 114 118 (27) 2
Evangeline 35,551 1,030 9 47,609 1,010 (144)
Octane Enhancement:
BEF 58,132 8,570 8,628 76,054 15,509 15,700
----------------------------------------------- ------------------------------------------------
Total $142,343 $20,490 $20,258 $172,484 $32,081 $30,141
=============================================== ================================================
PAGE 12
Summarized Income Statement Data for the Six Months Ended
-------------------------------------------------------------------------------------------------
June 30, 2002 June 30, 2001
----------------------------------------------- ------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
----------------------------------------------- ------------------------------------------------
Fractionation:
BRF $ 10,355 $ 3,960 $ 4,007 $ 7,825 $ 300 $ 350
BRPC 6,102 1,742 1,758 6,833 1,232 1,347
Promix 20,683 6,683 6,713 21,343 5,888 5,964
La Porte (535) (541)
OTC 1,792 109 37
Pipeline:
EPIK 9,849 3,237 3,257 1,967 (1,782) (1,725)
Wilprise 1,804 1,248 1,251 893 (378) (367)
Tri-States 6,780 2,490 2,503 3,953 262 299
Belle Rose 941 271 273 554 (205) (192)
Dixie 21,398 5,552 3,331 24,036 8,301 4,829
Starfish 13,143 4,105 3,569 13,467 4,390 3,916
Ocean Breeze 87 87 65
Neptune 14,629 5,561 5,645 16,747 8,648 8,581
Nemo 1,282 40 48 (42) 36
Evangeline 61,060 1,880 (170) 47,609 1,010 (144)
Octane Enhancement:
BEF 106,061 17,548 17,648 113,918 15,922 16,207
----------------------------------------------- ------------------------------------------------
Total $275,879 $53,891 $49,329 $259,232 $43,633 $39,166
=============================================== ================================================
6. 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-interests 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.
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 SFAS No. 141, we
reclassified the MBA goodwill to a separate line item on our consolidated balance sheet apart from the Shell
contract. Based upon SFAS No. 142, the value of the Shell natural gas processing agreement will continue to be
amortized over its remaining contract term of approximately 18 years; however, amortization of the MBA goodwill
will cease. The MBA goodwill will be subject to periodic impairment testing in accordance with SFAS No. 142 due
to its indefinite life. 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 7.
In accordance with the transition provisions of SFAS No. 142, we have completed an impairment review of
the December 31, 2001 MBA goodwill balance. Professionals in the business valuation industry were consulted
regarding the assumptions and techniques used in our analysis. As a result of this review, no impairment loss was
indicated. Any subsequent impairment losses stemming from future goodwill impairment studies will be reflected as
a component of operating income in the Statements of Consolidated Operations.
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
PAGE 13
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 evaluating 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.
In April 2002, the FASB issued SFAS No. 145, "Rescission of SFAS Statements No. 4, 44, and 64, Amendment of SFAS
No. 13, and Technical Corrections." The purpose of this statement is to update, clarify and simplify existing
accounting standards. We adopted this statement effective April 30, 2002 and determined that it did not have any
significant impact on our financial statements as of that date.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities."
This standard requires companies to recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to exit or disposal plan. Examples of costs covered by the
standard include lease termination costs and certain employee severance costs that are associated with a
restructuring, discontinued operation, plant closing, or other exit or disposal activity. Previous accounting
guidance was provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 replaces
Issue 94-3. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December
31, 2002. This statement is effective for our fiscal year beginning January 1, 2003. We are evaluating the
provisions of this statement.
7. INTANGIBLE ASSETS AND GOODWILL
Intangible assets
Our recorded intangible assets are comprised of the estimated values assigned to contract rights we own arising
from agreements with customers. According to SFAS No. 141, a contract-based intangible asset 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 of
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.
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.
At June 30, 2002, our intangible assets consisted of the Shell natural gas processing agreement that we acquired
as part of the TNGL acquisition in August 1999 and certain propylene fractionation and storage contracts we
acquired in connection with the 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 remaining contract term
(currently $11.1 million annually from 2002 through 2019). At June 30, 2002, the unamortized value of the Shell
contract was $188.8 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
PAGE 14
historically low customer contract turnover rates within these operations. At June 30, 2002, the unamortized value
of these contracts was $60.4 million.
Goodwill
At June 30, 2002, the value of goodwill was $81.5 million. Our goodwill is attributable to the excess of the
purchase price over the fair value of assets acquired and is comprised of the following (values as of June 30,
2002):
o $73.7 million associated with the purchase of propylene fractionation assets from Diamond-Koch in
February 2002; and,
o $7.8 million related to the July 1999 purchase of Kinder Morgan's ownership interest in MBA which in
turn owned an interest in our Mont Belvieu NGL fractionation facility.
Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill amounts are no longer amortized. Instead, we
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 amounts are classified as part of the Fractionation segment
since they are related to assets recorded 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 unaudited pro forma impact on earnings of discontinuing amortization of the MBA
goodwill (for the three and six months ended June 30, 2001).
Three Months Six Months
Ended June 30, Ended June 30,
---------------------------------------------
2001 2001
---------------------------------------------
Reported net income $93,031 $145,301
Discontinue goodwill amortization 111 222
Adjust minority interest expense (1) (2)
---------------------------------------------
Adjusted net income $93,141 $145,521
=============================================
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 15
8. DEBT OBLIGATIONS
Our debt consisted of the following at:
June 30, 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) 138,000
---------------------------------------
Total principal amount 1,222,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,895 1,653
Less unamortized discount on:
Senior Notes A (99) (117)
Senior Notes B (244) (258)
Less current maturities of debt - -
---------------------------------------
Long-term debt $1,223,552 $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 or
before maturity.
The above table does not reflect the $1.26 billion in debt we incurred on July 31, 2002 in connection with the
Mapletree and E-Oaktree acquisitions (see Note 15 for information regarding this subsequent event).
At June 30, 2002, we had a total of $75 million of standby letters of credit capacity under our Multi-Year Credit
Facility of which $9.4 million was outstanding.
Enterprise Products Partners L.P. acts as guarantor of certain of the Operating Partnership's 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 June 30, 2002, we had borrowed a total of $368 million under these two facilities.
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 June 30, 2002.
On April 24, 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were amended to allow for
the commodity hedging losses we incurred during the first four months of 2002. As defined within the second
amendment to each of these loan agreements, the changes included allowing us 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 earnings impact of such specific instruments were recognized. This
provision allows for $45.1 million to be added back to Consolidated EBITDA for the first quarter of 2002 and $4.9
million to be added back for the second quarter of 2002. Due to the rolling four-quarter nature of the
Consolidated EBITDA calculation, this provision will affect our financial covenants through the first quarter of
2003. In addition, the second amendment temporarily raised the maximum ratio allowed under the Consolidated
Indebtedness to Consolidated EBITDA ratio for the rolling-four quarter period ending September 30, 2002 (this
provision was superseded by the third amendment to these loan agreements executed on July 31, 2002, see Note 15
for information regarding this subsequent event).
PAGE 16
We were in compliance with the covenants of our Multi-Year and 364-Day revolving credit agreements at June 30,
2002.
9. CAPITAL STRUCTURE
Conversion of EPCO Subordinated Units to Common Units
As a result of the Company satisfying certain financial tests, 10,704,936 (or 25%) of EPCO's Subordinated Units
converted to 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 to 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 to 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 EPU calculations.
Conversion of Shell Special Units to Common Units
In accordance with existing agreements with Shell, 19.0 million of Shell's non-distribution bearing Special Units
converted to distribution-bearing Common Units on August 1, 2002. The remaining 10.0 million Special Units will
convert to Common Units on a one-for-one basis in August 2003. These conversions have a dilutive impact on basic
EPU.
Treasury Units
During the first quarter of 1999, the Operating Partnership established the EPOLP 1999 Grantor Trust (the
"Trust") to fund 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 June 30, 2002, the Trust held 427,200 Common Units that are
classified as Treasury Units. The Trust purchased 100,000 Common Units during the first six months of 2002 at a
cost of $2.4 million.
Beginning in July 2000 and later modified in September 2001, the General Partner authorized the Company
(specifically, "Enterprise Products Partners L.P." in this context) and the Trust to repurchase up to 2.0 million
of our publicly-held Common Units (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 original 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 Units.
In April 2002, management modified the Buy-Back Program to treat Common Units repurchased by the Company as
Treasury Units. For accounting purposes, Units repurchased by the Company will be held in treasury to fund future
obligations under EPCO's long-term incentive plan (i.e, used for the same intent as that contemplated for the
Common Units repurchased by the Trust). The Company purchased 424,459 Common Units during the first six months of
2002 at a cost of $9.3 million. At June 30, 2002, 677,900 Common Units could be repurchased under the Buy-Back
Program.
During the second quarter of 2002, 51,959 Common Units were reissued from the Company's Treasury Units at their
weighted-average cost of $1.2 million to fulfill our obligations under certain employee Unit option agreements of
EPCO.
Comprehensive Income
We report comprehensive income or loss in our Statements of Consolidated Partners' Equity and Comprehensive
Income. For the six months ended June 30, 2001, the cumulative transition adjustment resulting from the adoption
PAGE 17
of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted, was
the only item of other comprehensive income for us. There were no differences between net income and comprehensive
income for the same period in 2002. The following table summarizes the activity in other comprehensive income for
the six months ended June 30, 2001.
Comprehensive Income
for the six months ended June 30, 2001
Net Income $145,301
Less: Accumulated Other Comprehensive Loss (9,711)
---------------
Comprehensive Income $135,590
===============
10. 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 the three and six months ended June 30, 2002 and 2001.
PAGE 18
Three Months Ended Six Months Ended
---------------------------------- -------------------------------
June 30, June 30,
---------------------------------- -------------------------------
2002 2001 2002 2001
---------------------------------- -------------------------------
Income before minority interest $22,523 $93,975 $ 5,147 $146,779
General partner interest (2,648) (1,388) (3,894) (2,370)
---------------------------------- -------------------------------
Income before minority interest 19,875 92,587 1,253 144,409
available to Limited Partners
Minority interest (203) (944) (30) (1,478)
---------------------------------- -------------------------------
Net income available to Limited Partners $19,672 $91,643 $ 1,223 $142,931
================================== ===============================
BASIC EARNINGS PER UNIT
Numerator
Income before minority interest
Available to Limited Partners $19,875 $92,587 $ 1,253 $144,409
================================== ===============================
Net income available
To Limited Partners $19,672 $91,643 $ 1,223 $142,931
================================== ===============================
Denominator
Common Units outstanding 109,640 92,514 106,192 92,514
Subordinated Units outstanding 35,644 42,820 39,212 42,820
---------------------------------- -------------------------------
Total 145,284 135,334 145,404 135,334
================================== ===============================
Basic Earnings per Unit
Income before minority interest
Available to Limited Partners $ 0.14 $ 0.68 $ 0.01 $ 1.07
================================== ===============================
Net income available
To Limited Partners $ 0.14 $ 0.68 $ 0.01 $ 1.06
================================== ===============================
DILUTED EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $19,875 $92,587 $ 1,253 $144,409
================================== ===============================
Net income available
to Limited Partners $19,672 $91,643 $ 1,223 $142,931
================================== ===============================
Denominator
Common Units outstanding 109,640 92,514 106,192 92,514
Subordinated Units outstanding 35,644 42,820 39,212 42,820
Special Units outstanding 29,000 33,000 29,000 33,000
---------------------------------- -------------------------------
Total 174,284 168,334 174,404 168,334
================================== ===============================
Diluted Earnings per Unit
Income before minority interest
available to Limited Partners $ 0.11 $ 0.55 $ 0.01 $ 0.86
================================== ===============================
Net income available
to Limited Partners $ 0.11 $ 0.54 $ 0.01 $ 0.85
================================== ===============================
PAGE 19
11. 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 $0.225 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 $0.3125 per Common and
Subordinated Unit. The distribution paid on May 10, 2002 (based on first quarter 2002 results) was $0.335 per
Common and Subordinated Unit. As a result of these distributions, the General Partner received $3.9 million in
incentive distributions.
The distribution rate declared by the General Partner for the second quarter of 2002 was $0.335 per Common Unit
to Unitholders of record on July 31, 2002. This distribution was paid on August 12, 2002.
12. SUPPLEMENTAL CASH FLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Six Months Ended
June 30,
----------------------------------
2002 2001
----------------------------------
(Increase) decrease in:
Accounts and notes receivable $(24,455) $ 96,860
Inventories (78,843) 522
Prepaid and other current assets 9,599 (10,831)
Other assets (3,436) (129)
Increase (decrease) in:
Accounts payable 7,795 (55,755)
Accrued gas payable 70,447 (78,008)
Accrued expenses (9,499) (11,232)
Accrued interest 374 14,546
Other current liabilities (4,219) 13,271
Other liabilities (142) 187
----------------------------------
Net effect of changes in operating accounts $(32,379) $(30,569)
==================================
During the first six months of 2002, we completed $394.8 million in business acquisitions of which the purchase
price allocations of each affected various balance sheet accounts. See Note 2 for information regarding the
allocation of the purchase price for these acquisitions.
The $32.5 million purchase price obligation of the Toca Western facilities will not be paid until September
2002. This amount was accrued as additional property, plant and equipment with the offsetting payable amount
recorded under other current liabilities (see Note 2).
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 six months ended June 30, 2002, we recognized a
net $19.7 million in non-cash changes related to decreases in the fair value of these financial instruments,
primarily in our commodity financial instruments portfolio. For the six months ended June 30, 2001, we recognized
a net $55.9 million in non-cash mark-to-market income from our financial instruments portfolio.
PAGE 20
Cash and cash equivalents at June 30, 2002, per the Statements of Consolidated Cash Flows, excludes $5.0 million
of restricted cash. This restricted cash represents 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.
Of the $9.3 million spent by the Company for Treasury Units during the first six months of 2002, $0.7 million
will not result in cash settlements until July 2002.
13. 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 we charge certain of our customers for natural gas.
We have adopted a financial commodity and commercial policy to manage our exposure to the risks of our natural
gas and NGL businesses. The objective of these policies 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 these policies, 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 policies (including authorized products, instruments and markets) and
establishes specific guidelines and procedures for implementing and ensuring compliance with the policies.
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.
We recognized a loss of $50.9 million in the first six months of 2002 from our commodity hedging activities, of
which $45.1 million was attributable to the first quarter of 2002. These losses are treated as an increase in
operating costs and expenses in our Statements of Consolidated Operations. Of this amount, $31.9 million has been
realized (e.g., paid out to counterparties). The remaining $19.0 million represents the negative change in value
PAGE 21
of the open positions between December 31, 2001 and June 30, 2002 (based on market prices at those dates). The
market value of our open positions at June 30, 2002 was $11.1 million payable (a loss).
For the first six months of 2001, we recognized income of $70.3 million from these activities of which $5.6
million was recorded in the first quarter and $64.7 million in the second quarter. Of the $70.3 million recorded
for the first six months of 2001, $52.4 million was attributable to the market value of open positions at June
30, 2001.
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 June 30, 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 $0.8 million during the first six months of 2002 from our interest rate swaps that is
treated as a reduction of interest expense ($0.7 million recorded in the second quarter of 2002). The fair value
of the interest rate swap at June 30, 2002 was a receivable of $3.1 million. We recognized income of $5.5 million
during the first six months 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 in the first quarter of 2001.
14. 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: Pipelines, Fractionation, 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. Pipelines consists of both liquids and natural gas pipeline systems,
storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization,
and polymer grade propylene fractionation 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.
Gross operating margin by segment includes intersegment and intrasegment revenues (offset by corresponding
intersegment and intrasegment expenses within the segments), which are generally based on transactions made at
market-related rates. Our intersegment and intrasegment activities include, but are not limited to, the following
types of transactions:
PAGE 22
o NGL fractionation revenues from separating our NGL raw-make inventories into distinct NGL products using
our fractionation plants for our merchant activities group (an intersegment revenue of Fractionation
offset by an intersegment expense of Processing);
o liquids pipeline revenues from transporting our merchant volumes from the gas processing plants on our
pipelines to our NGL fractionation facilities (an intersegment revenue of Pipelines offset by an
intersegment expense of Processing); and,
o the sale of our NGL equity production extracted by our gas processing plants to our merchant activities
group (an intrasegment revenue of Processing offset by an intrasegment expense of Processing).
Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries, after
elimination of all material intercompany (both intersegment and intrasegment) accounts and 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 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. See Note 15 regarding an
expansion of our business activities into certain regions of the central and western United States.
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.
PAGE 23
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------------------------------------
2002 2001 2002 2001
---------------------------------------------------------------------
Total segment gross operating margin $66,938 $131,255 $93,351 $204,148
Depreciation and amortization (16,962) (11,793) (34,199) (21,822)
Retained lease expense, net (2,273) (2,660) (4,578) (5,320)
(Gain) loss on sale of assets 1 6 (12) 387
Selling, general and administrative (7,740) (7,737) (15,702) (13,905)
---------------------------------------------------------------------
Consolidated operating income 39,964 109,071 38,860 163,488
Interest expense (19,032) (16,331) (37,545) (23,318)
Interest income from unconsolidated affiliates 62 7 92 31
Dividend income from unconsolidated affiliates 1,242 2,196 1,632
Interest income-other 241 1,479 1,575 5,477
Other, net 46 (251) (31) (531)
---------------------------------------------------------------------
Consolidated income before minority interest $22,523 $ 93,975 $ 5,147 $146,779
=====================================================================
PAGE 24
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:
Three months ended June 30, 2002 $169,345 $138,589 $477,941 $382 $786,257
Three months ended June 30, 2001 86,566 178,958 693,242 631 959,397
Six months ended June 30, 2002 278,767 237,670 930,975 899 1,448,311
Six months ended June 30, 2001 176,245 186,145 1,432,011 1,311 1,795,712
Intersegment and intrasegment
revenues:
Three months ended June 30, 2002 56,103 25,578 140,969 102 $(222,752)
Three months ended June 30, 2001 44,133 24,631 131,657 96 (200,517)
Six months ended June 30, 2002 89,500 50,088 267,229 202 (407,019)
Six months ended June 30, 2001 85,785 45,410 241,966 191 (373,352)
Equity income in
unconsolidated affiliates:
Three months ended June 30, 2002 1,973 2,219 $2,876 7,068
Three months ended June 30, 2001 1,692 2,125 5,233 9,050
Six months ended June 30, 2002 3,612 6,801 5,882 16,295
Six months ended June 30, 2001 2,253 3,406 5,402 11,061
Total revenues:
Three months ended June 30, 2002 227,421 166,386 618,910 2,876 484 (222,752) 793,325
Three months ended June 30, 2001 132,391 205,714 824,899 5,233 727 (200,517) 968,447
Six months ended June 30, 2002 371,879 294,559 1,198,204 5,882 1,101 (407,019) 1,464,606
Six months ended June 30, 2001 264,283 234,961 1,673,977 5,402 1,502 (373,352) 1,806,773
Total gross operating margin
by segment:
Three months ended June 30, 2002 33,853 32,190 (1,182) 2,876 (799) 66,938
Three months ended June 30, 2001 32,803 24,696 68,112 5,233 411 131,255
Six months ended June 30, 2002 58,230 64,858 (34,558) 5,882 (1,061) 93,351
Six months ended June 30, 2001 58,471 42,819 96,510 5,402 946 204,148
Segment assets:
At June 30, 2002 470,249 918,052 129,028 9,239 44,003 1,570,571
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 June 30, 2002 98,029 213,852 33,000 58,189 403,070
At December 31, 2001 93,329 216,029 33,000 55,843 398,201
Intangible Assets:
At June 30, 2002 52,369 8,011 188,842 249,222
At December 31, 2001 7,857 194,369 202,226
Goodwill:
At June 30, 2002 81,543 81,543
Total revenues for the second quarter of 2002 were lower than those of the second quarter of 2001 primarily due
to a decline in NGL product prices between the two periods. The same can be said for the difference between the
first six months of 2002 compared to the same period in 2001. Total gross operating margin for the second quarter
of 2002 decreased $64.3 million from the second quarter of 2001 primarily due to the 2001 period including $64.7
million of commodity hedging income in the Processing segment that was not repeated in the 2002 period. For the
PAGE 25
first six months of 2002, gross operating margin decreased $110.8 million compared to the first six months of
2001. The year-to-date decline in gross operating margin is primarily due to the 2002 period including $50.9
million in commodity hedging losses versus the 2001 period including $70.3 million in commodity hedging income
(together accounting for $121.2 million of the year-to-date difference in gross operating margin). The $121.2
million difference in commodity hedging results is primarily reflected in the Processing segment.
Since January 1, 2002, segment assets have increased $263.8 million. The increase is primarily due to the
Diamond-Koch acquisitions completed during the first quarter of 2002 and the Toca Western acquisition in June
2002 (see Note 2). Intangible assets increased $47.0 million since January 1, 2002 primarily the result of the
contract-based intangible assets we acquired from Diamond-Koch (see Note 7). Goodwill was $81.5 million at June
30, 2002 due to the goodwill we added as a result of the Diamond-Koch acquisition and the reclassification of the
goodwill associated with the 1999 MBA acquisition (see Note 7).
15. SUBSEQUENT EVENTS
Purchase of Interests in Mapletree and E-Oaktree
On August 1, 2002, we announced the purchase of equity interests in affiliates of Williams, which in turn, own
controlling interests in Mid-America Pipeline Company, LLC (formerly Mid-America Pipeline Company) and Seminole
Pipeline Company. The purchase price of the acquisition was approximately $1.2 billion (subject to certain
post-closing purchase price adjustments). The effective date of the acquisition was July 31, 2002.
The acquisitions include a 98% ownership interest in Mapletree, LLC ("Mapletree"), owner of a 100% interest in
Mid-America Pipeline Company, LLC and certain propane terminals and storage facilities. The Mid-America pipeline
is a major NGL pipeline system consisting of three NGL pipelines, with 7,226 miles of pipeline, and average
transportation volumes of approximately 850 MBPD. Mid-America's 2,548-mile Rocky Mountain system transports mixed
NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to Hobbs, Texas. Its 2,740-mile Conway North
segment links the large NGL hub at Conway, Kansas to the upper Midwest; its 1,938 mile Conway South system connects
the Conway hub with Kansas refineries and transports mixed NGLs from Conway, Kansas to Hobbs, Texas.
We also acquired a 98% ownership interest in E-Oaktree, LLC, owner of an 80% equity interest in Seminole Pipeline
Company. The Seminole pipeline consists of a 1,281-mile NGL pipeline, with an average transportation volume of
approximately 260 MBPD. This pipeline transports mixed NGLs and NGL products from Hobbs, Texas and the Permian
Basin to Mont Belvieu, Texas.
The post-closing purchase price adjustments of the Mapletree and E-Oaktree acquisitions are expected to be
completed during the fourth quarter of 2002. These acquisitions do not require any material governmental approvals.
These acquisitions were funded by a $1.2 billion senior unsecured 364-day term loan entered into by the Operating
Partnership on July 31, 2002. The lenders under this facility are Wachovia Bank, National Association; Lehman
Brothers Bank, FSB; Lehman Commercial Paper Inc. and Royal Bank of Canada. As defined within the credit agreement,
the loan will generally bear interest at either (i) the greater of (a) the Prime Rate or (b) the Federal Funds
Effective Rate plus one-half percent or (ii) a Eurodollar rate, with any rate in effect being increased by an
appropriate applicable margin. The credit agreement contains various affirmative and negative covenants
applicable to the Operating Partnership similar to those required under our Multi-Year and 364-Day Credit
Facility agreements. The $1.2 billion term loan is guaranteed by Enterprise Products Partners L.P. through an
unsecured guarantee. The loan will be repaid as follows:$150 million due on December 31, 2002, $450 million on
March 31, 2003 and $600 million on July 30, 2003.
On August 1, 2002, Seminole Pipeline Company had $60 million in senior unsecured notes due in December 2005. The
principal amount of these notes amortize by $15 million each December 1 through 2005. In accordance with GAAP,
this debt will be consolidated on our balance sheet because of our 98% controlling interest in E-Oaktree, LLC,
which owns 80% of Seminole Pipeline Company.
PAGE 26
Third Amendment to our Multi-Year and 364-Day Credit Facilities
On July 31, 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were further amended to allow
for increased financial flexibility in light of the Mapletree and E-Oaktree acquisitions. As defined within the
third amendment to each of these loan agreements, the maximum ratio of Consolidated Indebtedness to Consolidated
EBITDA allowed by our lenders was increased as follows from that noted in the second amendment issued in April
2002:
Changes made to the
Consolidated Indebtedness to Consolidated EBITDA Ratio
- ---------------------------------------------------------------------------
Maximum Ratio Allowed
------------------------------------------
Calculation made for Old provisions New provisions
the rolling four-quarter under 2nd under 3rd
period ending Amendment Amendment
- ---------------------------------------------------------------------------
September 30, 2002 4.50 to 1.0 6.00 to 1.0
December 31, 2002 4.00 to 1.0 5.25 to 1.0
March 31, 2003 4.00 to 1.0 5.25 to 1.0
June 30, 2003 4.00 to 1.0 4.50 to 1.0
September 30, 2003 and 4.00 to 1.0 4.00 to 1.0
for each rolling-four
quarter period thereafter
In addition, the negative covenant on Indebtedness (as defined within the Multi-Year and 364-Day credit
agreements) was amended to permit the Seminole Pipeline Company indebtedness assumed in connection with the
acquisition of E-Oaktree.
PAGE 27
PART I. FINANCIAL INFORMATION.
Item 1B. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Operating L.P.
Consolidated Balance Sheets
(Dollars in thousands)
June 30,
2002 December 31,
ASSETS (unaudited) 2001
---------------------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of $5,034 at
June 30, 2002 and $5,752 at December 31, 2001) $7,788 $137,823
Accounts and notes receivable - trade, net of allowance for doubtful
accounts of $21,098 at June 30, 2002 and $20,642 at
December 31, 2001 284,021 256,927
Accounts receivable - affiliates 11,503 4,405
Inventories 153,280 69,443
Prepaid and other current assets 34,089 50,207
---------------------------------------
Total current assets 490,681 518,805
Property, Plant and Equipment, Net 1,570,571 1,306,790
Investments in and Advances to Unconsolidated Affiliates 403,070 398,201
Intangible assets, net of accumulated amortization of $18,235 at
June 30, 2002 and $13,084 at December 31, 2001 249,222 202,226
Goodwill 81,543
Other Assets 6,911 5,201
---------------------------------------
Total $2,801,998 $2,431,223
=======================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $ 70,716 $54,269
Accounts payable - affiliate 21,233 33,691
Accrued gas payables 303,983 233,536
Accrued expenses 12,961 22,233
Accrued interest 24,676 24,302
Other current liabilities 70,024 44,767
---------------------------------------
Total current liabilities 503,593 412,798
Long-Term Debt 1,223,552 855,278
Other Long-Term Liabilities 7,919 8,061
Minority Interest 2,331 1,468
Commitments and Contingencies
Partners' Equity
Limited Partner 1,062,422 1,148,124
General Partner 10,841 11,716
Parent's Units acquired by Trust (8,660) (6,222)
---------------------------------------
Total Partners' Equity 1,064,603 1,153,618
---------------------------------------
Total $2,801,998 $2,431,223
=======================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 28
Enterprise Products Operating L.P.
Statements of Consolidated Operations
(Dollars in thousands)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------------------------------------
2002 2001 2002 2001
---------------------------------------------------------------------
REVENUES
Revenues from consolidated operations $786,257 $959,397 $1,448,311 $1,795,712
Equity income in unconsolidated affiliates 7,068 9,050 16,295 11,061
---------------------------------------------------------------------
Total 793,325 968,447 1,464,606 1,806,773
---------------------------------------------------------------------
COST AND EXPENSES
Operating costs and expenses 745,621 851,639 1,410,044 1,629,380
Selling, general and administrative 7,815 8,418 15,601 14,586
---------------------------------------------------------------------
Total 753,436 860,057 1,425,645 1,643,966
---------------------------------------------------------------------
OPERATING INCOME 39,889 108,390 38,961 162,807
OTHER INCOME (EXPENSE)
Interest expense (19,032) (16,331) (37,545) (23,318)
Interest income from unconsolidated affiliates 62 3 92 15
Dividend income from unconsolidated affiliates 1,242 2,196 1,632
Interest income - other 384 1,626 1,820 5,771
Other, net (65) (251) (142) (531)
---------------------------------------------------------------------
Other income (expense) (17,409) (14,953) (33,579) (16,431)
---------------------------------------------------------------------
INCOME BEFORE MINORITY INTEREST 22,480 93,437 5,382 146,376
MINORITY INTEREST (33) (44) (86) (67)
---------------------------------------------------------------------
NET INCOME $ 22,447 $ 93,393 $ 5,296 $ 146,309
=====================================================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 29
Enterprise Products Operating L.P.
Statements of Consolidated Cash Flows
(Dollars in thousands)
(Unaudited)
Six Months Ended
June 30,
---------------------------------
2002 2001
---------------------------------
OPERATING ACTIVITIES
Net income $ 5,296 $146,309
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 35,349 23,234
Equity in income of unconsolidated affiliates (16,295) (11,061)
Distributions received from unconsolidated affiliates 29,113 13,212
Leases paid by EPCO 4,579 5,320
Minority interest 86 67
Loss (gain) on sale of assets 12 (387)
Changes in fair market value of financial instruments (see Note 11) 19,702 (55,880)
Net effect of changes in operating accounts (45,691) (30,611)
---------------------------------
Operating activities cash flows 32,151 90,203
---------------------------------
INVESTING ACTIVITIES
Capital expenditures (26,755) (57,090)
Proceeds from sale of assets 12 563
Business acquisitions, net of cash acquired (394,775) (225,665)
Investments in and advances to unconsolidated affiliates (10,137) (115,282)
---------------------------------
Investing activities cash flows (431,655) (397,474)
---------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 538,000 449,716
Long-term debt repayments (170,000)
Debt issuance costs (418) (3,125)
Cash distributions to partners (96,490) (77,494)
Cash distributions to minority interest (45)
Cash contribution from General Partner 39
Cash contributions from minority interest 777 110
Parent's Units acquired by consolidated Trust (2,439)
Increase in restricted cash 718 (7,321)
---------------------------------
Financing activities cash flows 270,187 361,841
---------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (129,317) 54,570
CASH AND CASH EQUIVALENTS, DECEMBER 31 132,071 58,446
---------------------------------
CASH AND CASH EQUIVALENTS, JUNE 30 $ 2,754 $113,016
=================================
See Notes to Unaudited Consolidated Financial Statements
PAGE 30
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 June 30, 2002 and consolidated results of operations and cash flows for
the three and six months ended June 30, 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. References to "Limited Partner" shall mean the consolidated financial
statements of our parent, Enterprise Products Partners L.P., which are included elsewhere in this combined report
on Form 10-Q.
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 three and six months ended June 30, 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 purchased 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. These assets are part of
our Mont Belvieu propylene fractionation operations, which is part of the Fractionation segment. The purchase
price of $239.0 million was funded by a drawdown on our Multi-Year and 364-Day Credit Facilities (see Note 8).
Acquisition of Diamond-Koch storage business in January 2002
In January 2002, we purchased 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, these facilities represent the largest underground storage operation of its kind in
the world. The size and location of the business provide it with a competitive position to increase its services
PAGE 31
to expanding Gulf Coast petrochemical complexes. These assets are part of our Mont Belvieu storage operations,
which is part of the Pipelines segment. 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 were accounted for under the purchase method of accounting and, accordingly, the
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 3,148 $ 890 4,038
Property, plant and equipment 96,772 120,571 217,343
Investments in unconsolidated affiliates 7,550 7,550
Intangible assets (see Note 7) 53,000 8,127 61,127
Goodwill (see Note 7) 73,686 73,686
Current liabilities (107) (107)
------------------------------------------------------------
Total purchase price $239,043 $129,588 $368,631
============================================================
The fair value estimates were developed by independent appraisers using recognized business valuation
techniques. The allocation of the purchase price is preliminary pending the results of a repermitting process
expected to be complete during the fourth quarter of 2002.
The purchase price paid for the propylene fractionation business resulted in $73.7 million in goodwill. The
goodwill primarily represents the value management has attached to future earnings improvements and to the
strategic location of the 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.
Acadian Gas post-closing adjustments completed in April 2002
In April 2002, we finalized the post-closing purchase price adjustment associated with our April 2001 acquisition
of Acadian Gas. Acadian Gas was acquired from an affiliate of Shell and is involved in the purchase, sale,
transportation and storage of natural gas in Louisiana. As a result, we paid Shell $18.0 million for various
working capital items, of which the majority were related to natural gas inventories. The Acadian Gas acquisition
was accounted for under the purchase method of accounting and, accordingly, the final purchase price has been
allocated to the assets acquired and liabilities assumed based on their estimated fair values at April 1, 2001 as
follows:
PAGE 32
Current assets $83,123
Investments in unconsolidated affiliates 2,723
Property, plant and equipment 232,187
Current liabilities (72,896)
Other long-term liabilities (1,460)
--------------------
Total purchase price $243,677
====================
Pro forma effect of Diamond-Koch and Acadian Gas business acquisitions
As noted earlier, the Acadian Gas acquisition occurred on April 1, 2001. We acquired Diamond-Koch's storage
business on January 1, 2002 and its propylene fractionation business on February 1, 2002. As a result, our actual
fiscal 2002 Statements of Consolidated Operations reflect the Diamond-Koch propylene fractionation business and
the Diamond-Koch storage business for their respective acquisition dates through June 2002 and the results of
Acadian Gas. For the first six months of fiscal 2001, our Statements of Consolidated Operations reflect only three
months of Acadian Gas.
The following table presents unaudited pro forma financial information incorporating the historical
(pre-acquisition) financial results of the propylene fractionation and storage assets we acquired from
Diamond-Koch and those of Acadian Gas that we acquired from Shell. This information is helpful in gauging the
possible impact that these acquisitions might have had on our results of operations had they been completed on
January 1, 2001 as opposed to the actual dates that these acquisitions occurred. The pro forma information is
based upon data currently available to and certain estimates and assumptions made 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.
Three Months Six Months Ended
Ended June 30, June 30,
------------------------------
2001 2002 2001
--------------------------------------------------------
Revenues $1,043,671 $1,482,040 $2,195,472
Income before extraordinary item
and minority interest $ 89,886 $ 5,291 $ 146,771
Net income $ 89,842 $ 5,204 $ 146,704
Minor acquisitions initiated during the second quarter of 2002
We initiated the purchase of an additional interest in our Mont Belvieu NGL fractionation from ChevronTexaco and
the acquisition of a gas processing plant and NGL fractionator in Louisiana from Western Resources during the
second quarter of 2002. Due to the immaterial nature and incomplete status of these two transactions, our
discussion of each minor purchase is limited to the following:
Acquisition of ChevronTexaco's interest in our Mont Belvieu NGL fractionator. In April 2002, we executed an
agreement with an affiliate of ChevronTexaco to purchase their 12.5% undivided ownership interest in our Mont
Belvieu, Texas NGL fractionator. The purchase price was approximately $8.0 million. The Mont Belvieu facility has a
gross NGL fractionation capacity of 210 MBPD of which 26.2 MBPD was ChevronTexaco's net share. ChevronTexaco was
required to sell their 12.5% interest in a consent order by the FTC as a condition of approving the merger
between Chevron and Texaco. The effective date of the purchase was June 1, 2002.
The other joint owners of the facility (affiliates of Duke Energy Field Services and Burlington Resources Inc.)
have the option to acquire their pro rata share of the ChevronTexaco interest. These preferential purchase rights
expire on September 30, 2002. If the other joint owners fully exercise their option to acquire their share of the
interest, our ownership interest would increase to approximately 71.4% from 62.5% currently. Should the joint
owners decline to exercise their options, we would own 75.0% of the facility. If the other joint owners acquire
PAGE 33
any portion of their share of the ChevronTexaco interest, our purchase price will be reduced accordingly. We
expect to complete this transaction during the third quarter of 2002.
Acquisition of gas processing and NGL fractionator assets from Western Gas Resources, Inc. In June 2002, we
executed an agreement to acquire a natural gas processing plant, NGL fractionator and supporting assets
(including contracts) from Western Gas Resources, Inc. for $32.5 million plus certain post-closing purchase price
adjustments. The "Toca Western" facilities are located in St. Bernard Parish, Louisiana near our existing Toca
natural gas processing plant. The gas processing facility has a capacity of 160 MMcf/d and the NGL fractionator
can fractionate up to 14.2 MBPD of NGLs.
This purchase is subject to a preferential purchase right by the other joint owners of our Yscloskey gas
processing facility that expires on September 24, 2002. We are one of the largest owners in the Yscloskey plant
with a 28.2% ownership interest. Should any of the other owners exercise their respective right to acquire their
pro rata interest in the Toca Western facilities, it would reduce the ownership interest we ultimately acquire
and the purchase price we pay. Because of the preferential rights, we expect to close this transaction during the
third quarter of 2002.
3. INVENTORIES
Our inventories are as follows at the dates indicated:
June 30, December 31,
2002 2001
-----------------------------------
Regular trade inventory $ 70,340 $35,894
Forward-sales inventory 45,960 33,549
Peak Season inventory 20,959
Other 16,021
-----------------------------------
Inventory $153,280 $69,443
===================================
A description of each inventory is as follows:
o Our regular trade (or "working"), inventory is comprised of inventories of natural gas, NGLs and
petrochemicals that are available for immediate sale. This inventory is valued at the lower of average
cost or market, with "market" being determined by spot-market related prices.
o The forward-sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of
forward sales contracts and is valued at the lower of average cost or market, with "market" being
defined as the weighted-average of the sales prices of the forward sales contracts.
o The peak season inventory is comprised of segregated NGL volumes that are expected to be sold outside of
the current summer-winter season and is valued at the lower of average cost or market, with "market"
being determined by spot-market related prices. These volumes are generally expected to be sold within
the next twelve months, but may be held for longer periods depending on market conditions.
o Other inventories generally consist of segregated NGL volumes set aside for possible short-term use as
fuel on an equivalent MMBtu basis. This inventory is carried at the lower of average cost or market,
with "market" being determined by spot-market related prices. The volumes associated with this inventory
are anticipated to be used and/or sold within the next twelve months.
Due to fluctuating market conditions in the NGL, natural gas and petrochemical industry, we occasionally
recognize lower of average cost or market adjustments when the cost of our inventories exceed their net realizable
value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized
and affect our segment operating results in the following manner:
o NGL inventory write downs are recorded as a cost of the Processing segment's merchant activities;
o Natural gas inventory write downs are recorded as a cost of the Pipeline segment's Acadian Gas
operations; and
PAGE 34
o Petrochemical inventory write downs are recorded as a cost of the Fractionation segment's propylene
fractionation business.
For the second quarter of 2002, we recognized an adjustment of $4.5 million to write down NGL inventories to
their net realizable value. For the second quarter of 2001, we recorded $25.8 million of such write downs:$19.4
million against NGL inventories, $4.9 million against natural gas inventories and $1.5 million against
petrochemical inventories.
For the first six months of 2002, we recognized $4.6 million in NGL inventory write downs. For the same six month
period in 2001, we recorded $27.8 million in lower of average cost or market write downs. The 2001 adjustments
were $21.4 million against NGL inventories, $4.9 million against natural gas inventories and $1.5 million against
petrochemical inventories. To the extent our commodity hedging strategies address inventory-related risks and are
successful, these inventory value adjustments are mitigated (or in some cases, reversed). See Note 11 for a
description of our commodity hedging activities.
4. PROPERTY, PLANT AND EQUIPMENT
Our property, plant and equipment and accumulated depreciation are as follows:
Estimated
Useful Life June 30, December 31,
in Years 2002 2001
---------------------------------------------------
Plants and pipelines 5-35 $1,626,739 $1,398,843
Underground and other storage facilities 5-35 241,806 127,900
Transportation equipment 3-35 3,952 3,736
Land 20,014 15,517
Construction in progress 44,003 98,844
-------------------------------------
Total 1,936,514 1,644,840
Less accumulated depreciation 365,943 338,050
-------------------------------------
Property, plant and equipment, net $1,570,571 $1,306,790
=====================================
Property, plant and equipment is recorded at cost and is depreciated using the straight-line method over the
asset's estimated useful life. Maintenance, repairs and minor renewals are charged to operations as incurred. The
cost of assets retired or sold, together with the related accumulated depreciation, is removed from the accounts,
and any gain or loss on disposition is included in income.
Additions and improvements to and major renewals of existing assets are capitalized and depreciated using the
straight-line method over the estimated useful life of the new equipment or modifications. These expenditures
result in a long-term benefit to the Company. We generally classify improvements and major renewals of existing
assets as sustaining capital expenditures and all other capital spending (on existing and new assets) as
expansion capital expenditures.
Depreciation expense for the three months ended June 30, 2002 and 2001 was $13.8 million and $11.0 million,
respectively. For the six months ended June 30, 2002 and 2001, it was $27.9 million and $20.3 million,
respectively.
5. 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 12.
PAGE 35
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 considered 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 the aggregate amount of investments in and advances to (and our ownership percentages
in) unconsolidated affiliates at June 30, 2002 and December 31, 2001:
Ownership June 30, December 31,
Percentage 2002 2001
--------------------------------------------------------
Accounted for on equity basis:
Fractionation:
BRF 32.25% $ 28,687 $ 29,417
BRPC 30.00% 18,197 18,841
Promix 33.33% 43,513 45,071
La Porte 50.00% 5,814
OTC 50.00% 1,818
Pipeline:
EPIK 50.00% 14,375 14,280
Wilprise 37.35% 8,663 8,834
Tri-States 33.33% 26,448 26,734
Belle Rose 41.67% 11,211 11,624
Dixie 19.88% 37,284 37,558
Starfish 50.00% 23,777 25,352
Neptune 25.67% 77,226 76,880
Nemo 33.92% 12,211 12,189
Evangeline 49.50% 2,657 2,578
Octane Enhancement:
BEF 33.33% 58,189 55,843
Accounted for on cost basis:
Processing:
VESCO 13.10% 33,000 33,000
----------------------------------------
Total $403,070 $398,201
========================================
PAGE 36
The following table shows equity in income (loss) of unconsolidated affiliates for the three and six months ended
June 30, 2002 and 2001:
Three Months Ended Six Months Ended
June 30, June 30,
Ownership -----------------------------------------------------------
Percentage 2002 2001 2002 2001
-------------------------------------------------------------------------------------
Fractionation:
BRF 32.25% $743 $ 42 $ 1,292 $ 60
BRPC 30.00% 278 252 527 404
Promix 33.33% 996 1,396 2,039 1,789
La Porte 50.00% (173) (265)
OTC 50.00% 128 18
Pipelines:
EPIK 50.00% (54) (172) 1,629 (1,094)
Wilprise 37.35% 320 85 467 (137)
Tri-States 33.33% 365 135 834 100
Belle Rose 41.67% 40 29 114 (60)
Dixie 19.88% (156) 69 561 960
Starfish 50.00% 973 1,022 1,785 1,973
Ocean Breeze 25.67% - 12 - 14
Neptune 25.67% 682 1,095 1,460 1,789
Nemo 33.92% 44 1 22 10
Evangeline 49.50% 5 (149) (71) (149)
Octane Enhancement:
BEF 33.33% 2,877 5,233 5,883 5,402
--------------------------------------------------------------------
Total $7,068 $9,050 $16,295 $11,061
====================================================================
Our initial investment in Promix, La Porte, Dixie, Neptune and Nemo exceeded our share of the historical cost of
the underlying net assets of such entities ("excess cost"). The excess cost of these investments is reflected in
our investments in and advances to unconsolidated affiliates for these entities. The excess cost amounts related
to Promix, La Porte and Nemo are attributable to the tangible plant and pipeline assets of each entity, the
excess cost of which is amortized against equity earnings from these entities in a manner similar to
depreciation. The excess cost of Dixie includes amounts attributable to both goodwill and tangible pipeline
assets, with that portion assigned to the pipeline assets being amortized in a manner similar to depreciation. The
goodwill inherent in Dixie's excess cost is subject to periodic impairment testing and is not amortized. The
following table summarizes our excess cost information:
PAGE 37
Amortization
Unamortized balance at Charged to
Initial -------------------------------- Equity Earnings
Excess June 30, December 31, during Amortization
Cost 2002 2001 2002 Period
---------------------------------------------------------------------------------------
Fractionation segment:
Promix $7,955 $6,794 $7,083 $199 20 years
La Porte 873 855 n/a 18 35 years
Pipelines segment:
Dixie
Attributable to pipeline assets 28,448 26,480 26,887 406 35 years
Goodwill 9,246 8,827 8,827 n/a n/a
Neptune 12,768 12,221 12,404 182 35 years
Nemo 727 708 718 10 35 years
The following tables 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 Three Months Ended
-------------------------------------------------------------------------------------------------
June 30, 2002 June 30, 2001
----------------------------------------------- ------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
----------------------------------------------- ------------------------------------------------
Fractionation:
BRF $ 5,750 $ 2,295 $ 2,305 $ 3,802 $ 265 $ 294
BRPC 3,150 923 930 3,400 793 842
Promix 10,819 3,274 3,285 12,340 4,447 4,487
La Porte (301) (306)
OTC 1,421 302 258
Pipeline:
EPIK 1,577 (117) (109) 792 (375) (348)
Wilprise 1,033 855 857 494 224 227
Tri-States 3,680 1,088 1,097 2,321 388 403
Belle Rose 433 95 96 407 13 21
Dixie 6,270 (1,853) (1,191) 8,799 2,001 1,124
Starfish 6,714 2,169 1,943 7,051 2,571 2,299
Ocean Breeze 53 39 39
Neptune 6,926 2,046 2,338 9,362 5,223 5,195
Nemo 887 114 118 (27) 2
Evangeline 35,551 1,030 9 47,609 1,010 (144)
Octane Enhancement:
BEF 58,132 8,570 8,628 76,054 15,509 15,700
----------------------------------------------- ------------------------------------------------
Total $142,343 $20,490 $20,258 $172,484 $32,081 $30,141
=============================================== ================================================
PAGE 38
Summarized Income Statement Data for the Six Months Ended
-------------------------------------------------------------------------------------------------
June 30, 2002 June 30, 2001
----------------------------------------------- ------------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
----------------------------------------------- ------------------------------------------------
Fractionation:
BRF $ 10,355 $ 3,960 $ 4,007 $ 7,825 $ 300 $ 350
BRPC 6,102 1,742 1,758 6,833 1,232 1,347
Promix 20,683 6,683 6,713 21,343 5,888 5,964
La Porte - (535) (541)
OTC 1,792 109 37
Pipeline:
EPIK 9,849 3,237 3,257 1,967 (1,782) (1,725)
Wilprise 1,804 1,248 1,251 893 (378) (367)
Tri-States 6,780 2,490 2,503 3,953 262 299
Belle Rose 941 271 273 554 (205) (192)
Dixie 21,398 5,552 3,331 24,036 8,301 4,829
Starfish 13,143 4,105 3,569 13,467 4,390 3,916
Ocean Breeze - - - 87 87 65
Neptune 14,629 5,561 5,645 16,747 8,648 8,581
Nemo 1,282 40 48 (42) 36
Evangeline 61,060 1,880 (170) 47,609 1,010 (144)
Octane Enhancement:
BEF 106,061 17,548 17,648 113,918 15,922 16,207
----------------------------------------------- ------------------------------------------------
Total $275,879 $53,891 $49,329 $259,232 $43,633 $39,166
=============================================== ================================================
6. 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-interests 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.
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 SFAS No. 141, we
reclassified the MBA goodwill to a separate line item on our consolidated balance sheet apart from the Shell
contract. Based upon SFAS No. 142, the value of the Shell natural gas processing agreement will continue to be
amortized over its remaining contract term of approximately 18 years; however, amortization of the MBA goodwill
will cease. The MBA goodwill will be subject to periodic impairment testing in accordance with SFAS No. 142 due
to its indefinite life. 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 7.
In accordance with the transition provisions of SFAS No. 142, we have completed an impairment review of
the December 31, 2001 MBA goodwill balance. Professionals in the business valuation industry were consulted
regarding the assumptions and techniques used in our analysis. As a result of this review, no impairment loss was
indicated. Any subsequent impairment losses stemming from future goodwill impairment studies will be reflected as
a component of operating income in the Statements of Consolidated Operations.
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
PAGE 39
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 evaluating 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.
In April 2002, the FASB issued SFAS No. 145, "Rescission of SFAS Statements No. 4, 44, and 64, Amendment of SFAS
No. 13, and Technical Corrections." The purpose of this statement is to update, clarify and simplify existing
accounting standards. We adopted this statement effective April 30, 2002 and determined that it did not have any
significant impact on our financial statements as of that date.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities."
This standard requires companies to recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to exit or disposal plan. Examples of costs covered by the
standard include lease termination costs and certain employee severance costs that are associated with a
restructuring, discontinued operation, plant closing, or other exit or disposal activity. Previous accounting
guidance was provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). "SFAS No. 146 replaces
Issue 94-3. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December
31, 2002. This statement is effective for our fiscal year beginning January 1, 2003. We are evaluating the
provisions of this statement.
7. INTANGIBLE ASSETS AND GOODWILL
Intangible assets
Our recorded intangible assets are comprised of the estimated values assigned to contract rights we own arising
from agreements with customers. According to SFAS No. 141, a contract-based intangible asset 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 of
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.
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.
At June 30, 2002, our intangible assets consisted of the Shell natural gas processing agreement that we acquired
as part of the TNGL acquisition in August 1999 and certain propylene fractionation and storage contracts we
acquired in connection with the 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 remaining contract term
(currently $11.1 million annually from 2002 through 2019). At June 30, 2002, the unamortized value of the Shell
contract was $188.8 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
PAGE 40
historically low customer contract turnover rates within these operations. At June 30, 2002, the unamortized value
of these contracts was $60.4 million.
Goodwill
At June 30, 2002, the value of goodwill was $81.5 million. Our goodwill is attributable to the excess of the
purchase price over the fair value of assets acquired and is comprised of the following (values as of June 30,
2002):
o $73.7 million associated with the purchase of propylene fractionation assets from Diamond-Koch in
February 2002; and,
o $7.8 million related to the July 1999 purchase of Kinder Morgan's ownership interest in MBA which in
turn owned an interest in our Mont Belvieu NGL fractionation facility.
Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill amounts are no longer amortized. Instead, we
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 amounts are classified as part of the Fractionation segment
since they are related to assets recorded 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 unaudited pro forma impact on earnings of discontinuing amortization of the MBA
goodwill (for the three and six months ended June 30, 2001).
Three Months Six Months
Ended June 30, Ended June 30,
2001 2001
---------------------------------------------
Reported net income $93,393 $146,309
Discontinue goodwill amortization 111 222
---------------------------------------------
Adjusted net income $93,504 $146,531
=============================================
PAGE 41
8. DEBT OBLIGATIONS
Our debt consisted of the following at:
June 30, 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) 138,000
---------------------------------------
Total principal amount 1,222,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,895 1,653
Less unamortized discount on:
Senior Notes A (99) (117)
Senior Notes B (244) (258)
Less current maturities of debt - -
---------------------------------------
Long-term debt $1,223,552 $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 or
before maturity.
The above table does not reflect the $1.26 billion in debt we incurred on July 31, 2002 in connection with the
Mapletree and E-Oaktree acquisitions (see Note 13 for information regarding this subsequent event).
At June 30, 2002, we had a total of $75 million of standby letters of credit capacity under our Multi-Year Credit
Facility of which $9.4 million was outstanding.
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 June 30, 2002, we had borrowed a total of $368 million under these two facilities.
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 June 30, 2002.
On April 24, 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were amended to allow for
the commodity hedging losses we incurred during the first four months of 2002. As defined within the second
amendment to each of these loan agreements, the changes included allowing us 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 earnings impact of such specific instruments were recognized. This
provision allows for $45.1 million to be added back to Consolidated EBITDA for the first quarter of 2002 and $4.9
million to be added back for the second quarter of 2002. Due to the rolling four-quarter nature of the
Consolidated EBITDA calculation, this provision will affect our financial covenants through the first quarter of
2003. In addition, the second amendment temporarily raised the maximum ratio allowed under the Consolidated
Indebtedness to Consolidated EBITDA ratio for the rolling-four quarter period ending September 30, 2002 (this
provision was superseded by the third amendment to these loan agreements executed on July 31, 2002, see Note 13
for information regarding this subsequent event).
PAGE 42
We were in compliance with the covenants of our Multi-Year and 364-Day revolving credit agreements at June 30,
2002.
9. 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 June 30, 2002, the Trust held 427,200 Common Units. The Trust purchased 100,000 Common Units
during the first six months of 2002 at a cost of $2.4 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 2.0 million Common Units. The Common Unit purchases made during the first six months of 2002 were under this
program. At June 30, 2002, 677,900 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.
The Unit totals noted above reflect a two-for-one split of our Parent's Units that occurred in May 2002.
10. SUPPLEMENTAL CASHFLOWS DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Six Months Ended
June 30,
-------------------------------------
2002 2001
-------------------------------------
(Increase) decrease in:
Accounts and notes receivable $(34,188) $ 96,064
Inventories (78,843) 522
Prepaid and other current assets 9,599 (10,843)
Other assets (3,436) (118)
Increase (decrease) in:
Accounts payable 3,989 (55,682)
Accrued gas payable 70,447 (78,008)
Accrued expenses (9,272) (10,550)
Accrued interest 374 14,546
Other current liabilities (4,219) 13,271
Other liabilities (142) 187
-------------------------------------
Net effect of changes in operating accounts $(45,691) $(30,611)
=====================================
During the first six months of 2002, we completed $394.8 million in business acquisitions of which the purchase
price allocations of each affected various balance sheet accounts. See Note 2 for information regarding the
allocation of the purchase price for these acquisitions.
The $32.5 million purchase price obligation of the Toca Western facilities will not be paid until September
2002. This amount was accrued as additional property, plant and equipment with the offsetting payable amount
recorded under other current liabilities.
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 six months ended June 30, 2002, we recognized a
net $19.7 million in non-cash changes related to decreases in the fair value of these financial instruments,
PAGE 43
primarily in our commodity financial instruments portfolio. For the six months ended June 30, 2001, we recognized
a net $55.9 million in non-cash mark-to-market income from our financial instruments portfolio.
Cash and cash equivalents at June 30, 2002, per the Statements of Consolidated Cash Flows, excludes $5.0 million
of restricted cash. This restricted cash represents 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.
11. 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 financial commodity and commercial policy to manage our exposure to the risks of our natural
gas and NGL businesses. The objective of these policies 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 these policies, 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 policies (including authorized products, instruments and markets) and
establishes specific guidelines and procedures for implementing and ensuring compliance with the policies.
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.
We recognized a loss of $50.9 million in the first six months of 2002 from our commodity hedging activities, of
which $45.1 million was attributable to the first quarter of 2002. These losses are treated as an increase in
operating costs and expenses in our Statements of Consolidated Operations. Of this amount, $31.9 million has been
PAGE 44
realized (e.g., paid out to counterparties). The remaining $19.0 million represents the negative change in value
of the open positions between December 31, 2001 and June 30, 2002 (based on market prices at those dates). The
market value of our open positions at June 30, 2002 was $11.1 million payable (a loss).
For the first six months of 2001, we recognized income of $70.3 million from these activities of which $5.6
million was recorded in the first quarter and $64.7 million in the second quarter. Of the $70.3 million recorded
for the first six months of 2001, $52.4 million was attributable to the market value of open positions at June
30, 2001.
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 June 30, 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 $0.8 million during the first six months of 2002 from our interest rate swaps that is
treated as a reduction of interest expense ($0.7 million recorded in the second quarter of 2002). The fair value
of the interest rate swap at June 30, 2002 was a receivable of $3.1 million. We recognized income of $5.5 million
during the first six months 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 in the first quarter of 2001.
12. 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: Pipelines, Fractionation, 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. Pipelines consists of both liquids and natural gas pipeline systems, storage and
import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization, and polymer
grade propylene fractionation 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.
Gross operating margin by segment includes intersegment and intrasegment revenues (offset by corresponding
intersegment and intrasegment expenses within the segments), which are generally based on transactions made at
PAGE 45
market-related rates. Our intersegment and intrasegment activities include, but are not limited to, the following
types of transactions:
o NGL fractionation revenues from separating our NGL raw-make inventories into distinct NGL products using
our fractionation plants for our merchant activities group (an intersegment revenue of Fractionation
offset by an intersegment expense of Processing);
o liquids pipeline revenues from transporting our merchant volumes from the gas processing plants on our
pipelines to our NGL fractionation facilities (an intersegment revenue of Pipelines offset by an
intersegment expense of Processing); and,
o the sale of our NGL equity production extracted by our gas processing plants to our merchant activities
group (an intrasegment revenue of Processing offset by an intrasegment expense of Processing).
Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries, after
elimination of all material intercompany (both intersegment and intrasegment) accounts and 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 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. See Note 13 regarding an
expansion of our business activities into certain regions of the central and western United States.
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.
PAGE 46
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------------------------------------
2002 2001 2002 2001
---------------------------------------------------------------------
Total segment gross operating margin $66,938 $131,255 $93,351 $204,148
Depreciation and amortization (16,962) (11,793) (34,199) (21,822)
Retained lease expense, net (2,273) (2,660) (4,578) (5,320)
(Gain) loss on sale of assets 1 6 (12) 387
Selling, general and administrative (7,815) (8,418) (15,601) (14,586)
---------------------------------------------------------------------
Consolidated operating income 39,889 108,390 38,961 162,807
Interest expense (19,032) (16,331) (37,545) (23,318)
Interest income from unconsolidated affiliate 62 3 92 15
Dividend income from unconsolidated affiliates 1,242 2,196 1,632
Interest income - other 384 1,626 1,820 5,771
Other, net (65) (251) (142) (531)
---------------------------------------------------------------------
Consolidated income before minority interest $22,480 $ 93,437 $ 5,382 $146,376
=====================================================================
PAGE 47
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:
Three months ended June 30, 2002 $169,345 $138,589 $477,941 $382 $786,257
Three months ended June 30, 2001 86,566 178,958 693,242 631 959,397
Six months ended June 30, 2002 278,767 237,670 930,975 899 1,448,311
Six months ended June 30, 2001 176,245 186,145 1,432,011 1,311 1,795,712
Intersegment and intrasegment
Revenues:
Three months ended June 30, 2002 56,103 25,578 140,969 102 $(222,752)
Three months ended June 30, 2001 44,133 24,631 131,657 96 (200,517)
Six months ended June 30, 2002 89,500 50,088 267,229 202 (407,019)
Six months ended June 30, 2001 85,785 45,410 241,966 191 (373,352)
Equity income in
unconsolidated affiliates:
Three months ended June 30, 2002 1,973 2,219 $2,876 7,068
Three months ended June 30, 2001 1,692 2,125 5,233 9,050
Six months ended June 30, 2002 3,612 6,801 5,882 16,295
Six months ended June 30, 2001 2,253 3,406 5,402 11,061
Total revenues:
Three months ended June 30, 2002 227,421 166,386 618,910 2,876 484 (222,752) 793,325
Three months ended June 30, 2001 132,391 205,714 824,899 5,233 727 (200,517) 968,447
Six months ended June 30, 2002 371,879 294,559 1,198,204 5,882 1,101 (407,019) 1,464,606
Six months ended June 30, 2001 264,283 234,961 1,673,977 5,402 1,502 (373,352) 1,806,773
Total gross operating margin
by segment:
Three months ended June 30, 2002 33,853 32,190 (1,182) 2,876 (799) 66,938
Three months ended June 30, 2001 32,803 24,696 68,112 5,233 411 131,255
Six months ended June 30, 2002 58,230 64,858 (34,558) 5,882 (1,061) 93,351
Six months ended June 30, 2001 58,471 42,819 96,510 5,402 946 204,148
Segment assets:
At June 30, 2002 470,249 918,052 129,028 9,239 44,003 1,570,571
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 June 30, 2002 98,029 213,852 33,000 58,189 403,070
At December 31, 2001 93,329 216,029 33,000 55,843 398,201
Intangible Assets:
At June 30, 2002 52,369 8,011 188,842 249,222
At December 31, 2001 7,857 194,369 202,226
Goodwill:
At June 30, 2002 81,543 81,543
Total revenues for the second quarter of 2002 were lower than those of the second quarter of 2001 primarily due
to a decline in NGL product prices between the two periods. The same can be said for the difference between the
first six months of 2002 compared to the same period in 2001. Total gross operating margin for the second quarter
of 2002 decreased $64.3 million from the second quarter of 2001 primarily due to the 2001 period including $64.7
PAGE 48
million of commodity hedging income in the Processing segment that was not repeated in the 2002 period. For the
first six months of 2002, gross operating margin decreased $110.8 million compared to the first six months of
2001. The year-to-date decline in gross operating margin is primarily due to the 2002 period including $50.9
million in commodity hedging losses versus the 2001 period including $70.3 million in commodity hedging income
(together accounting for $121.2 million of the year-to-date difference in gross operating margin). The $121.2
million difference in commodity hedging results is primarily reflected in the Processing segment.
Since January 1, 2002, segment assets have increased $263.8 million. The increase is primarily due to the
Diamond-Koch acquisitions completed during the first quarter of 2002 and the Toca Western acquisition in June
2002 (see Note 2). Intangible assets increased $47.0 million since January 1, 2002 primarily the result of the
contract-based intangible assets we acquired from Diamond-Koch (see Note 7). Goodwill was $81.5 million at June
30, 2002 due to the goodwill we added as a result of the Diamond-Koch acquisition and the reclassification of the
goodwill associated with the 1999 MBA acquisition (see Note 7).
13. SUBSEQUENT EVENTS
Purchase of Interests in Mapletree and E-Oaktree
On August 1, 2002, we announced the purchase of equity interests in affiliates of Williams, which in turn, own
controlling interests in Mid-America Pipeline Company, LLC (formerly Mid-America Pipeline Company) and Seminole
Pipeline Company. The purchase price of the acquisition was approximately $1.2 billion (subject to certain
post-closing purchase price adjustments). The effective date of the acquisition was July 31, 2002.
The acquisitions include a 98% ownership interest in Mapletree, LLC ("Mapletree"), owner of a 100% interest in
Mid-America Pipeline Company, LLC and certain propane terminals and storage facilities. The Mid-America pipeline
is a major NGL pipeline system consisting of three NGL pipelines, with 7,226 miles of pipeline, and average
transportation volumes of approximately 850 MBPD. Mid-America's 2,548-mile Rocky Mountain system transports mixed
NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to Hobbs, Texas. Its 2,740-mile Conway North segment
links the large NGL hub at Conway, Kansas to the upper Midwest; its 1,938 mile Conway South system connects the Conway
hub with Kansas refineries and transports mixed NGLs from Conway, Kansas to Hobbs, Texas.
We also acquired a 98% ownership interest in E-Oaktree, LLC, owner of an 80% equity interest in Seminole Pipeline
Company. The Seminole pipeline consists of a 1,281-mile NGL pipeline, with an average transportation volume of
approximately 260 MBPD. This pipeline transports mixed NGLs and NGL products from Hobbs, Texas and the Permian
Basin to Mont Belvieu, Texas.
The post-closing purchase price adjustments of the Mapletree and E-Oaktree acquisitions are expected to be
completed during the fourth quarter of 2002. These acquisitions do not require any material governmental approvals.
These acquisitions were funded by a $1.2 billion senior unsecured 364-day term loan entered into by the Operating
Partnership on July 31, 2002. The lenders under this facility are Wachovia Bank, National Association; Lehman
Brothers Bank, FSB; Lehman Commercial Paper Inc. and Royal Bank of Canada. As defined within the credit agreement,
the loan will generally bear interest at either (i) the greater of (a) the Prime Rate or (b) the Federal Funds
Effective Rate plus one-half percent or (ii) a Eurodollar rate, with any rate in effect being increased by an
appropriate applicable margin. The credit agreement contains various affirmative and negative covenants
applicable to the Operating Partnership similar to those required under our Multi-Year and 364-Day Credit
Facility agreements. The $1.2 billion term loan is guaranteed by Enterprise Products Partners L.P. through an
unsecured guarantee. The loan will be repaid as follows:$150 million due on December 31, 2002, $450 million on
March 31, 2003 and $600 million on July 30, 2003.
On August 1, 2002, Seminole Pipeline Company had $60 million in senior unsecured notes due in December 2005. The
principal amount of these notes amortize by $15 million each December 1 through 2005. In accordance with GAAP,
this debt will be consolidated on our balance sheet because of our 98% controlling interest in E-Oaktree, LLC,
which owns 80% of Seminole Pipeline Company.
PAGE 49
Third Amendment to our Multi-Year and 364-Day Credit Facilities
On July 31, 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were further amended to allow
for increased financial flexibility in light of the Mapletree and E-Oaktree acquisitions. As defined within the
third amendment to each of these loan agreements, the maximum ratio of Consolidated Indebtedness to Consolidated
EBITDA allowed by our lenders was increased as follows from that noted in the second amendment issued in April
2002:
Changes made to the
Consolidated Indebtedness to Consolidated EBITDA Ratio
- ---------------------------------------------------------------------------
Maximum Ratio Allowed
------------------------------------------
Calculation made for Old provisions New provisions
the rolling four-quarter under 2nd under 3rd
period ending Amendment Amendment
- ---------------------------------------------------------------------------
September 30, 2002 4.50 to 1.0 6.00 to 1.0
December 31, 2002 4.00 to 1.0 5.25 to 1.0
March 31, 2003 4.00 to 1.0 5.25 to 1.0
June 30, 2003 4.00 to 1.0 4.50 to 1.0
September 30, 2003 and 4.00 to 1.0 4.00 to 1.0
for each rolling-four
quarter period thereafter
In addition, the negative covenant on Indebtedness (as defined within the Multi-Year and 364-Day credit
agreements) was amended to permit the Seminole Pipeline Company indebtedness assumed in connection with the
acquisition of E-Oaktree.
PAGE 50
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
For the interim periods ended June 30, 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.
CEO and CFO certification of our SEC filings
Certification required under SEC Order No. 4-460.On June 28, 2002, the SEC requested that the CEO and CFO
of 947 publicly-traded companies (with fiscal 2001 revenues in excess of $1.2 billion) file sworn written
statements that their most recent reports filed with the SEC are materially truthful and complete or explain why
such a statement would be incorrect. Enterprise Products Partners L.P. was included on this list. On August 9,
2002, we forwarded to the SEC sworn written statements by O.S. Andras (the CEO of our General Partner) and
Michael A. Creel (the CFO of our General Partner) attesting that, to the best of their knowledge, all of our SEC
filings made since January 1, 2002 (and through August 9, 2002) have been materially truthful and complete. These
filings include our fiscal 2001 Form 10-K, our first quarter of 2002 Form 10-Q and our reports on Form 8-K filed
during that period. In addition to the actual sworn statements forwarded to the SEC, we electronically filed
these documents on Form 8-K under Item 9 on August 12, 2002. Once the actual sworn statements have been scanned
and electronically processed, the SEC will post them and the date of receipt on their website for public viewing.
The SEC's website is www.sec.gov. In addition, we are required to post these certifications on our
website, www.eprod.com.
Certifications required under Section 906 of the Sarbanes-Oxley Act of 2002. On July 30, 2002, George W.
Bush, President of the United States, signed into law the Sarbanes-Oxley Act of 2002 (the "Act"). Section 906 of
the Act requires that each periodic report containing financial statements filed by a registrant with the SEC
pursuant to Section 13(a) and 15(d) of the Securites Exchange Act of 1934 (the "1934 Act") on or after July 20,
2002 must be accompanied by a written statement by the issuer's CEO and CFO. That statement must certify that such
report fully complies with the requirements of Sections 13(a) and 15(d) of the 1934 Act and that information
contained in the periodic report fairly presents, in all material respects, the financial condition and results
of operations of the registrant. This certification is in addition to those documents required under SEC Order
No. 4-460.
The Sarbanes-Oxley certification begins with this report on Form 10-Q for both of our registrants: Enterprise
Products Partners L.P. and Enterprise Products Operating L.P. On August 13, 2002, we filed with the SEC, as
correspondence accompanying this report on Form 10-Q, the required certifications by Mr. Andras and Mr. Creel.
PAGE 51
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 in the central and western United States and
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 purity 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;
o storage of NGL and petrochemical products; and,
o sale of NGL and petrochemical products we produce and/or purchase for resale on a merchant basis.
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.
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.
PAGE 52
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, 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.
Recent acquisitions and other investments
Purchase of Interests in Mapletree and E-Oaktree. On August 1, 2002, we announced the purchase of equity
interests in affiliates of Williams, which in turn, own controlling interests in Mid-America Pipeline Company,
LLC ("Mid-America") and Seminole Pipeline Company ("Seminole"). The purchase price of the acquisition was
approximately $1.2 billion (subject to certain post-closing purchase price adjustments). The effective date of the
acquisition was July 31, 2002.
The acquisitions include a 98% ownership interest in Mapletree, LLC ("Mapletree"), owner of a 100% interest in
Mid-America Pipeline Company, LLC and certain propane terminals and storage facilities. The Mid-America pipeline
is a major NGL pipeline system consisting of three NGL pipelines, with 7,226 miles of pipeline, and average
transportation volumes of approximately 850 MBPD. Mid-America's 2,548-mile Rocky Mountain system transports mixed
NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to Hobbs, Texas. Its 2,740-mile Conway North segment
links the large NGL hub at Conway, Kansas to the upper Midwest; its 1,938 mile Conway South system connects the Conway
hub with Kansas refineries and transports mixed NGLs from Conway, Kansas to Hobbs, Texas.
We also acquired a 98% ownership interest in E-Oaktree, LLC, owner of an 80% equity interest in Seminole Pipeline
Company. The Seminole pipeline consists of a 1,281-mile NGL pipeline, with an average transportation volume of
approximately 260 MBPD. This pipeline transports mixed NGLs and NGL products from Hobbs, Texas and the Permian
Basin to Mont Belvieu, Texas.
PAGE 53
These pipelines connect our Mont Belvieu and Gulf Coast NGL businesses with all of the major natural gas and NGL
supply basins in North America, giving us the ability to provide integrated midstream energy services to the two
fastest growing natural gas basins in the United States - the deepwater Gulf of Mexico and the Rocky Mountain
Overthrust.
In order to fund this transaction, the Operating Partnership entered into a $1.2 billion senior unsecured 364-day
credit facility. Our plans for permanent financing of this acquisition include the issuance of equity, including
partnership equity for institutional investors, and debt in amounts which are consistent with our objective of
maintaining our financial flexibility and investment grade balance sheet.
The post-closing purchase price adjustments of the Mapletree and E-Oaktree acquisitions are expected to be
completed during the fourth quarter of 2002. These acquisitions do not require any material governmental approvals.
Acquisition of Diamond-Koch's Mont Belvieu storage and propylene fractionation assets. 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
$239.0 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.
Acquisition of ChevronTexaco's interest in our Mont Belvieu NGL fractionator. In April 2002, we executed an
agreement with an affiliate of ChevronTexaco to purchase their 12.5% undivided ownership interest in our Mont
Belvieu, Texas NGL fractionator. The purchase price was approximately $8.0 million. The Mont Belvieu facility has a
gross NGL fractionation capacity of 210 MBPD of which 26.2 MBPD was ChevronTexaco's net share. ChevronTexaco was
required to sell their 12.5% interest in a consent order by the FTC as a condition of approving the merger
between Chevron and Texaco. The effective date of the purchase was June 1, 2002.
The other joint owners of the facility (affiliates of Duke Energy Field Services and Burlington Resources Inc.)
have the option to acquire their pro rata share of the ChevronTexaco interest. These preferential purchase rights
expire on September 30, 2002. If the other joint owners fully exercise their option to acquire their share of the
interest, our ownership interest would increase to approximately 71.4% from 62.5% currently. Should the joint
owners decline to exercise their options, we would own 75.0% of the facility. If the other joint owners acquire
any portion of their share of the ChevronTexaco interest, our purchase price will be reduced accordingly. We
expect to complete this transaction during the third quarter of 2002.
Acquisition of gas processing and NGL fractionator assets from Western Gas Resources, Inc. In June 2002,
we executed an agreement to acquire a natural gas processing plant, NGL fractionator and supporting assets
(including contracts) from Western Gas Resources, Inc. for $32.5 million plus certain post-closing purchase price
adjustments. The "Toca Western" facilities are located in St. Bernard Parish, Louisiana near our existing Toca
natural gas processing plant. The gas processing facility has a capacity of 160 MMcf/d and the NGL fractionator
can fractionate up to 14.2 MBPD of NGLs.
This purchase is subject to a preferential purchase right which expires on September 24, 2002 by the other joint
owners of our Yscloskey gas processing facility. We are one of the largest owners in the Yscloskey plant with a
28.2% ownership interest. Should any of the other owners exercise their respective right to acquire their pro rata
interest in the Toca Western facilities, it would reduce the ownership interest we ultimately acquire and the
purchase price we pay. Because of the preferential rights, we expect to close this transaction during the third
quarter of 2002.
PAGE 54
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 June 30, 2002 and December 31, 2001, the net book value of
our property, plant and equipment was $1.6 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 of 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 June 30, 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 remaining 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 remaining life of the
agreement. Such a change would increase the annual amortization charge at that time. At June 30, 2002, the
unamortized value of the Shell contract was $188.8 million.
PAGE 55
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 June 30, 2002, the unamortized value of these contracts was $60.4 million.
o Goodwill. At June 30, 2002, the value of goodwill was $81.5 million. Our goodwill is attributable
to the excess of the purchase price over the fair value of assets acquired and is comprised of the
following (values as of June 30, 2002):
o $73.7 million associated with the purchase of propylene fractionation assets from Diamond-Koch in
February 2002; and,
o $7.8 million related to the July 1999 purchase of Kinder Morgan's ownership interest in MBA which in
turn owned an interest in our Mont Belvieu NGL fractionation facility.
Since our adoption of SFAS No. 142 on January 1, 2002, our goodwill amounts are no longer
amortized. Instead, goodwill is tested at a reporting unit level annually, and more frequently, if
certain circumstances indicate it is more likely than not that the fair value of goodwill is below its
carrying amount. 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. Currently, all of our goodwill is
recorded as part of the Fractionation operating segment (based on the assets to which the goodwill
relates).
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.
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);
PAGE 56
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 and Toca Western NGL fractionation
facilities);
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 and Toca Western NGL fractionation facilities. 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 was $21.1 million at
June 30, 2002 and $20.6 million at December 31, 2001.
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 six months ending June 30, 2002, we recognized losses from our commodity hedging activities of
$50.9 million. Of this loss, $19.0 million is attributable to the negative change in market value of the
commodity hedging portfolio since December 31, 2001 using the mark-to-market method of accounting for
our financial instruments. 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.
PAGE 57
Additional information regarding our financial statements and 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
Form 10-Q.
Our results of operations
Revenues, costs and expenses and operating income. The following table shows our consolidated revenues,
costs and expenses, and operating income for the three and six month periods ended June 30, 2002 and 2001
(dollars in thousands):
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------------------------------
2002 2001 2002 2001
---------------------------------------------------------------
Revenues $793,325 $968,447 $1,464,606 $1,806,773
Costs and expenses 753,361 859,376 1,425,746 1,643,285
Operating income 39,964 109,071 38,860 163,488
Revenues for the three months ended June 30, 2002 declined $175.1 million when compared to the same three-month
period in 2001. Revenues for the six months ended June 30, 2002 declined $342.2 million when compared to the same
six-month period in 2001. The quarterly and year-to-date decline is primarily due to lower NGL prices which
affected revenues from our gas processing business and related merchant activities. This was partially offset by
the addition of revenue from businesses we have acquired since June 30, 2001.
Costs and expenses for the three months ended June 30, 2002 decreased $106.0 million when compared to those
recorded for the three months ended June 30, 2001. Costs and expenses for the six months ended June 30, 2002
declined $217.5 million when compared to the same period in 2001. The decrease in quarterly and year-to-date costs
and expenses is primarily due to lower NGL and natural gas prices (which affected energy-related expenses at our
facilities and cost of sales in our merchant activities). This was partially offset by expenses from acquired
businesses and a negative change in our commodity hedging results.
Operating income declined $69.1 million quarter-to-quarter and $124.6 million year-to-year primarily the result
of the items discussed in the previous two paragraphs, particularly that of the negative change in commodity
hedging results. For the three months ended June 30, 2002, we recognized a loss from the commodity hedging
activities of our gas processing business of $5.8 million versus income of $64.7 million in the second quarter of
2001 (a $70.5 million negative change between periods). For the six months ended June 30, 2002, we recognized a
loss of $50.9 million from these hedging activities as compared to income of $70.3 million during the same period
in 2001 (a $121.2 million negative change between periods).
PAGE 58
The following table illustrates selected average quarterly prices for natural gas, crude oil, selected NGL
products and polymer grade propylene since 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) $7.05 $28.77 $0.49 $0.63 $0.70 $0.74 $0.23
Second quarter $4.65 $27.86 $0.37 $0.50 $0.56 $0.66 $0.19
Third quarter $2.90 $26.64 $0.27 $0.41 $0.49 $0.49 $0.16
Fourth quarter $2.43 $21.04 $0.21 $0.34 $0.40 $0.39 $0.18
Fiscal 2002:
First quarter $2.34 $21.41 $0.22 $0.30 $0.38 $0.44 $0.16
Second quarter $3.38 $26.26 $0.26 $0.40 $0.48 $0.51 $0.20
- ----------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL and polymer grade propylene prices represent an average of selected 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
Gross operating margin. Our management evaluates segment performance based on 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 have five reportable operating segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other.
Pipelines consists of liquids and natural gas pipeline systems, storage and import/export terminal services.
Fractionation primarily includes NGL fractionation, isomerization and propylene fractionation. 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.
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.
PAGE 59
Our gross operating margin amounts by segment (in thousands of dollars) along with a reconciliation to
consolidated operating income were as follows for the periods indicated:
Three Months Ended Six Months Ended
June 30, June 30,
---------------------------------------------------------------------
2002 2001 2002 2001
---------------------------------------------------------------------
Gross operating margin by segment:
Pipelines $32,190 $ 24,696 $64,858 $ 42,819
Fractionation 33,853 32,803 58,230 58,471
Processing (1,182) 68,112 (34,558) 96,510
Octane enhancement 2,876 5,233 5,882 5,402
Other (799) 411 (1,061) 946
---------------------------------------------------------------------
Gross operating margin total 66,938 131,255 93,351 204,148
Depreciation and amortization 16,962 11,793 34,199 21,822
Retained lease expense, net 2,273 2,660 4,578 5,320
Loss (gain) on sale of assets (1) (6) 12 (387)
Selling, general and administrative expenses 7,740 7,737 15,702 13,905
---------------------------------------------------------------------
Consolidated operating income $39,964 $109,071 $38,860 $163,488
=====================================================================
Our significant plant production and other volumetric data were as follows for the periods indicated:
Three Months Ended Six Months Ended
June 30, June 30,
-------------------------------------------------------------------
2002 2001 2002 2001
--------------------------------------------------------------------
MBPD, Net
---------
Major NGL and petrochemical pipelines 499 519 518 430
Equity NGL production 74 63 78 54
NGL fractionation 237 202 226 184
Isomerization 86 94 80 82
Propylene fractionation 58 29 55 30
Octane enhancement 6 5 5 4
BBtu/d, net
-----------
Natural gas pipelines 1,300 1,295 1,262 1,263
The following discussions highlight the significant quarterly and year-to-date comparisons in gross operating
margin and volumes by operating segment.
Pipelines
Our Pipelines segment consists of natural gas, NGL and petrochemical liquids transportation and distribution
pipelines. Our natural gas pipeline systems provide for the gathering, transmission and storage of natural gas
from both onshore and offshore Louisiana developments. Our liquids pipelines transport mixed NGLs and hydrocarbons
to NGL fractionation plants and distribute NGL and petrochemical products to petrochemical plants, refineries and
propane markets.
Three months ended June 30, 2002 and 2001. Our Pipelines segment posted a near record quarterly gross
operating margin of $32.2 million for the second quarter of 2002 compared to $24.7 million for the second quarter
of 2001. Net pipeline volumes for the second quarter of 2002 were 841 MBPD compared to 860 MBPD for the same
quarter during 2001. These volumes are on an energy equivalent basis where 3.8 MMBtus of natural gas is
equivalent to one barrel of NGLs. Of the $7.5 million increase in margin quarter-to-quarter, $6.3 million of the
increase is attributable to storage assets we acquired from Diamond-Koch in January 2002. Other factors in the
quarter-to-quarter difference are as follows:
PAGE 60
o Margin from our Acadian Gas operations improved $3.4 million quarter-to-quarter primarily due to natural
gas inventory value write downs recorded during the second quarter of 2001 that did not recur in the
2002 period.
o Our Louisiana Pipeline System posted a $2.4 million increase in margin primarily due to a rise in
liquids throughput rates attributable to higher NGL extraction and downstream processing rates between
the two quarters.
o Margin from our Houston Ship Channel NGL import facility and associated HSC pipeline decreased a
combined $2.8 million quarter-to-quarter primarily due to a decline in mixed butane import activity.
o Margin from the Lou-Tex Propylene pipeline declined $1.5 million quarter-to-quarter primarily due to
lower pipeline throughput rates during the 2002 period attributable to a decrease in petrochemical
production flowing through this system.
o Our Lou-Tex NGL pipeline system posted a $0.4 million decrease in margin quarter-to-quarter primarily
due to downtime and expense associated with repairs and maintenance during the second quarter of 2002.
o Margin from our Gulf of Mexico natural gas pipelines decreased $0.4 million quarter-to-quarter primarily
due to mechanical problems at certain Gulf of Mexico production platforms. These platforms recommenced
production in May 2002.
Six months ended June 30, 2002 and 2001. From a year-to-date perspective, our Pipelines segment recognized
$64.9 million in gross operating margin for the first six months of 2002 compared to $42.8 million during the
same period in 2001. Net pipeline volumes (on an energy equivalent basis) were 850 MBPD during the 2002 period
versus 762 MBPD during the 2001 period. As in the quarter-to-quarter discussion above, the largest factor in the
difference in margin between the two periods is the margin contribution from the storage assets we acquired from
Diamond-Koch. For the first six months of 2002, these acquired assets added $8.2 million to the gross operating
margin of this segment. Other significant year-to-date differences are as follows:
o The 2002 period includes six months of Acadian Gas margins whereas the 2001 period includes only three
months (we acquired Acadian Gas on April 1, 2002). The additional quarter's worth of margin in the 2002
period accounts for $4.2 million of the overall increase in segment margin. This amount is in addition
to the $3.4 million benefit noted above for Acadian Gas in the quarter-to-quarter analysis.
o Margin from the Louisiana Pipeline System for the 2002 period increased $5.5 million over the 2001
period primarily due to higher liquids throughput rates. Liquids transport volumes increased to 182
MBPD during the first six months of 2002 compared to 119 MBPD during the first six months of 2001. The
lower throughput rates during the 2001 period were primarily due to decreased NGL extraction rates at
gas processing plants during the first half of 2001 caused by high natural gas prices.
o Equity earnings from EPIK's export terminal increased $2.7 million period-to-period due to a strong
export market during the first quarter of 2002. Unusually high domestic prices for propane-related
products in the first half of 2001 decreased export opportunities. Product prices during the first
quarter of 2002 presented EPIK with a more favorable export environment relative to the first quarter
of 2001.
o Margin from our Lou-Tex NGL pipeline system increased $1.9 million period-to-period primarily due to a
13 MBPD increase in transportation volumes.
o Margin from the Lou-Tex Propylene pipeline decreased $2.6 million period-to-period primarily due to
lower pipeline throughput rates and higher operating costs. The reduction in volumes is generally
attributable to a decline in petrochemical production by shippers.
o Margin from our Houston Ship Channel NGL import facility decreased $1.7 million period-to-period
primarily due to a decline in mixed butane imports.
o Margin from our Gulf of Mexico natural gas pipelines decreased $0.5 million period-to-period due
to mechanical problems at certain Gulf of Mexico production platforms, as mentioned previously.
Fractionation
Our Fractionation segment includes eight NGL fractionators, an isomerization complex and four propylene
fractionation facilities. NGL fractionators separate mixed NGL streams into discrete NGL products: ethane,
propane, isobutane, normal butane and natural gasoline. Our isomerization unit converts normal butane into mixed
butane, which is subsequently fractionated into normal butane, isobutane and high purity isobutane. In general,
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our propylene fractionation plants separate refinery grade propylene (a mixture of propane and propylene) into
either polymer grade propylene or chemical grade propylene along with by-products of propane and mixed butane.
Three months ended June 30, 2002 and 2001. On a quarterly basis, gross operating margin was $33.9 million
for the three months ended June 30, 2002 compared to $32.8 million for the same period in 2001. NGL fractionation
margin decreased $1.7 million for the second quarter of 2002 when compared to the second quarter of 2001. NGL
fractionation net volumes improved to 237 MBPD during the 2002 period versus 202 MBPD during the 2001 period. The
decrease in NGL fractionation margin is primarily due to lower tolling revenues at our Mont Belvieu NGL
fractionator due to competition at this industry hub, lower in-kind fees at our Norco plant (caused by lower NGL
prices in 2002 relative to 2001), partially offset by increased margins from our Tebone and Venice NGL
fractionation facilities due to increased volumes.
Our isomerization business posted a $5.1 million decrease in margin for the second quarter of 2002 when compared
to the second quarter of 2001. Isomerization volumes were 86 MBPD during the 2002 period versus 94 MBPD during the
2001 period. The decrease in margin is primarily due to lower isomerization revenues. Certain of our isomerization
fees are indexed to historical natural gas prices which were lower during the second quarter of 2002 relative to
the second quarter of 2001.
For the second quarter of 2002, gross operating margin from propylene fractionation was $7.3 million higher than
the second quarter of 2001. The second quarter of 2002 includes $7.5 million in margin from the propylene
fractionation business we acquired from Diamond-Koch in February 2002. Net volumes at our propylene fractionation
facilities increased to 58 MBPD for the second quarter of 2002 compared to 29 MBPD for the second quarter of
2001. Of the 28 MBPD increase in 2002 volumes, 26 MBPD is attributable to operations acquired from Diamond-Koch.
Six months ended June 30, 2002 and 2001. From a year-to-date perspective, Fractionation gross operating
margin was $58.2 million for the first six months of 2002 versus $58.5 million for the first six months of 2001.
NGL fractionation margin decreased $2.8 million during the 2002 period when compared to the 2001 period. NGL
fractionation net volumes improved to 226 MBPD during the first six months of 2002 versus 184 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 for the 2002
period is primarily due to the following:
o certain non-routine maintenance charges at our Mont Belvieu facility in the first quarter of 2002;
o a decrease in tolling revenues at our Mont Belvieu facility due to competition at this industry hub
(which offset a 12 MBPD increase in fractionation volumes);
o lower in-kind fee revenue at our Norco plant (caused by lower NGL prices in 2002 relative to 2001);
o partially offset by increased margins at other facilities due to higher processing volumes.
Our isomerization business posted a $9.9 million decrease in margin for the first six months of 2002 when
compared to the first six months of 2001. Isomerization volumes decreased to 80 MBPD during the 2002 period versus
82 MBPD during the 2001 period. The decrease in margin is primarily due to lower isomerization revenues. As
discussed earlier, certain of our isomerization tolling fees are indexed to historical natural gas prices and
were positively impacted when the price of natural gas was at historically high levels during 2001, particularly
during the first quarter of 2001.
For the first six months of 2002, gross operating margin from propylene fractionation was $11.6 million higher
than the same period in 2001. The first six months of 2002 includes $10.4 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 energy-related costs at our other Mont Belvieu propylene fractionation facilities
attributable to lower natural gas prices between periods. Net volumes at our propylene fractionation facilities
increased to 55 MBPD for the first six months of 2002 compared to 30 MBPD for the first six months of 2001. Of the
25 MBPD increase in 2002 volumes, 24 MBPD is attributable to operations acquired from Diamond-Koch.
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Processing
This segment is comprised of our natural gas processing business and related merchant activities. At the core of
our natural gas processing business are twelve gas plants located primarily in south Louisiana. Our net share of
the NGL production from these gas plants (i.e., "our equity NGL production"), in addition to the NGLs we purchase
on a merchant basis and a portion of the production from our isomerization facilities, support the merchant
activities included in this operating segment.
Three months ended June 30, 2002 and 2001. Gross operating margin was a loss of $1.2 million for the second
quarter of 2002 versus income of $68.1 million for the second quarter of 2001. Our equity NGL production for the
second quarter of 2002 increased 11 MBPD over the same period in 2001 primarily due to improved gas processing
economics quarter-to-quarter, which were generally the result of lower natural gas prices. The change in margin
between the two quarters can generally be attributed to the following:
o We recorded a loss of $5.8 million from our commodity hedging activities during the second quarter of
2002 compared to income of $64.7 million during the second quarter of 2001. This accounted for $70.5
million of the negative change in margin. For further information regarding our commodity hedging losses,
see "Impact of commodity hedging activities on our results of operations" in this Processing
section.
o Results for the second quarter of 2001 reflected exceptionally strong demand for isobutane from refiners
which did not reoccur during the second quarter of 2002. During the second quarter of 2001, gasoline
refiners purchased unusually high levels of isobutane in anticipation of concerns regarding reformulated
gasoline production during the summer of 2001. These supply concerns did not reappear during 2002 which
affected both prices and sales volumes.
o Lastly, the decline in commodity hedging results and isobutane demand was offset by a favorable decrease
in NGL inventory valuation adjustments between the two quarters.
Six months ended June 30, 2002 and 2001. Gross operating margin was a loss of $34.6 million for the first
six months of 2002 compared to income of $96.5 million for the first six months of 2001. Our equity NGL production
averaged 78 MBPD during the 2002 period versus 54 MBPD during the 2001 period. Equity NGL production during the
2001 period reflected reduced NGL extraction rates at our gas plants resulting from abnormally high natural gas
prices (which negatively affected operating costs), particularly during the first quarter of 2001. Of the $131.1
million decrease in margin between periods, the significant differences are as follows:
o We recorded a loss of $50.9 million from our commodity hedging activities during the first six months of
2002, of which $45.1 million of the loss was recognized during the first quarter of 2002. This compares
to $70.3 million of income from such activities during the first six months of 2001. This change in
results accounts for $121.2 million of the decrease in margin. For further information regarding our
commodity hedging losses, see "Impact of commodity hedging activities on our results of
operations"in this section.
o Prior year margin benefited from unusually strong propane demand in the first quarter of 2001 for
heating and isobutane in the second quarter of 2001 for refining. The higher prices caused by the
extraordinary demand for these products during the 2001 periods did not recur during the 2002 period.
o Lastly, the decline in commodity hedging results and propane and isobutane demand was offset by a
favorable decrease in NGL inventory valuation adjustments between the two quarters and improved
processing margins. Processing economics improved period to period as a result of lower natural gas
prices during the 2002 period relative to the 2001 period which in turn resulted in higher equity NGL
production rates during 2002.
Impact of commodity hedging activities on our results of operations. In order to manage the risks
associated with our Processing segment, we may enter into commodity financial instruments to hedge our exposure
to price risks associated with natural gas, NGL production and inventories, firm commitments and certain
anticipated transactions. We have employed various hedging strategies to mitigate the effects of fluctuating
commodity prices (primarily NGL and natural gas prices) on margins from our Processing segment.
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
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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. Throughout 2001, this strategy proved very successful for us (as the price of natural gas declined
relative to our fixed positions) and was responsible for most of the $101.3 million in income we recorded from
commodity hedging activities.
As a result of the success of this strategy, 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 gas processing
margins. A number of factors influenced this rapid increase in natural gas prices. These factors included industry
concerns that current drilling activity was not sufficient to support the production levels needed to satisfy the
increase in demand resulting from the U.S. economic recovery. In addition, the industry was concerned about the
potential need for natural gas to replace nuclear power in some areas of the U.S. as nuclear power facilities
were taken offline for critical maintenance work. As a result, we recognized a loss on these hedging activities
of $45.1 million during the first quarter of 2002.
Due to the inherent uncertainty that was controlling the markets, management decided that it was prudent for the
Company to exit this hedging strategy, and we did so by late April 2002. By the time the positions were generally
closed out, the value of the portfolio had declined by an additional $5.7 million; thus, the total loss from this
strategy during fiscal 2002 was $50.8 million. The $5.8 million loss we recorded during the second quarter of 2002
is primarily due to this additional decline. Of the $50.8 million in losses from this strategy recorded during
2002, $7.6 million was related to mark-to-market income from these instruments that we recognized
in the fourth quarter of 2001. The remaining $43.2 million represents our cash exposure from these losses of which
$31.9 million has been paid to counterparties through June 30, 2002. The balance of the cash payments will be made
over the remainder of 2002.
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
Our Octane Enhancement segment consists of a 33.33% equity investment in BEF, which owns a facility which
currently produces motor gasoline additives to enhance octane.
Three months ended June 30, 2002 and 2001. Our second quarter of 2002 equity earnings from BEF decreased
$2.4 million when compared to the second quarter of 2001. The decrease is primarily due to lower MTBE prices
quarter-to-quarter. MTBE prices were very strong during the second quarter of 2001 due to exceptional demand for
reformulated gasoline by refiners in anticipation of supply problems in the summer of 2001.
Six months ended June 30, 2002 and 2001. Equity earnings from our BEF investment improved to $5.9 million
for the first six months of 2002 from $5.4 million for the first six months of 2001. The improvement is primarily
due to a 24% increase in MTBE production during the 2002 period due to less maintenance downtime offset by the
impact of lower overall MTBE prices period-to-period which affected margins.
Other matters
Selling, general and administrative expenses. Selling, general and administrative expenses for the first
six months of 2002 increased $1.8 million when compared to the first six months of 2001. This increase is
primarily due to the additional staff and resources acquired as a result of business acquisitions.
Interest expense. Interest expense increased between the second quarters of 2002 and 2001 and the
year-to-date periods primarily due to additional borrowings we made in conjunction with the Diamond-Koch
acquisitions and investments in inventories. Also, the first quarter of 2001 includes a $9.3 million benefit
related to our interest rate swaps which did not reoccur in 2002.
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General outlook for the remainder of 2002
Processing
We anticipate that our equity NGL production rates will approximate 65 MBPD for the third quarter and rise to
around 70 MBPD during the fourth quarter. The mechanical problems at certain customer Gulf of Mexico production
platforms that curtailed natural gas flows during the March through May timeframe have been fixed and production
from these areas is expected to be at normal levels for the remainder of the year. We also anticipate that
production from Shell's Princess field will begin late in the third quarter (these volumes will be processed at
our Venice gas plant). From a processing economics perspective, natural gas prices are expected to remain
moderate to strong over the remainder of the year, which will negatively affect processing margins given
anticipated NGL prices. We expect that as gas prices rise over the coming months, some regional gas plants will
be forced into ethane rejection mode. This will negatively impact downstream volumes available for fractionation.
If gas prices decline and NGL prices strengthen, processing economics would improve and may lead to full NGL
extraction rates at our facilities. At full NGL extraction rates, we expect that our equity NGL production rate
would approximate 90 MBPD to 95 MBPD. Our current outlook for processing economics is based on quarterly
weighted-average NGL prices ranging from approximately 39 CPG to 44 CPG and quarterly natural gas prices
averaging from approximately $3.30 per MMBtu to $3.60 per MMBtu.
Pipelines
The indirect acquisition of interests in the Mid-America and Seminole NGL pipeline systems on July 31, 2002 was a
significant transaction for us. It was a transforming event because it extends our platform of assets beyond the
Gulf Coast and gives us a strong business position in the Midwest and linkage to Canadian NGL production. These
pipelines integrate our Mont Belvieu and Gulf Coast NGL business with all of the major natural gas and NGL supply
basins in North America. We will now provide integrated midstream energy services to the two fastest growing
natural gas basins in the United States - the deepwater Gulf of Mexico and the Rocky Mountain Overthrust.
We know these assets very well. Our parent, EPCO, was a charter partner in the formation and development of the
Seminole Pipeline in 1981 and one of the Seminole lines terminates at our Mont Belvieu complex. In addition,
several key members of our management team, who were formerly with MAPCO Inc., had commercial responsibilities
for the Mid-America and Seminole pipeline systems for many years. We anticipate that these pipeline businesses
will substantially increase our fee-based cash flows and offer excellent growth prospects for the future. We are
truly excited about the acquisition of these premier midstream energy assets.
We are diligently working to integrate these assets into our system. For the third and fourth quarters of 2002,
the existing business plan forecasts throughput volumes to be near capacity. We believe that these volume
expectations are reasonable. Based upon historical information available to us, we believe that these investments
will generate approximately $154 million of EBITDA (representing our pro-rata share of such cash flows) on
an annualized twelve-month basis, which does not include the effect of any cost-saving synergies that may develop
over time as we integrate these assets into our system.
As for our Gulf Coast liquids pipelines, we expect that ethane rejection at gas processing facilities in the
region will negatively affect the throughput rates on certain of our pipelines during the third quarter. We
expect that rates will improve during the fourth quarter as gas processing economics improve resulting in an
increase in NGL volumes for transport to fractionation facilities. Also, we expect volumes on the Dixie propane
pipeline system to increase in the fourth quarter as seasonal heating requirements in the southeastern U.S.
increase throughput on the system.
Our storage operations should continue to benefit as NGL production continues and slow petrochemical and other
downstream demand for feedstocks keeps inventory levels higher than normal. Import volumes at our Houston Ship
Channel import dock are expected to be near historical averages for the remainder of the year. EPIK's export
business should see a rise in throughput rates over the same period as export opportunities increase. EPIK
usually experiences an increase in exports of propane during the winter months.
PAGE 65
We anticipate that our Gulf of Mexico and Acadian Gas natural gas pipeline businesses will be stable for the
remainder of the year with normal margins. Throughput on our propylene pipelines for the remainder of the year
should be consistent with that of the first half of the year.
Fractionation
We expect that NGL volumes available for fractionation will decline 10% to 15% from levels seen earlier this year
as the impact of ethane rejection at regional gas plants begins to affect our facilities. Margins from our Mont
Belvieu NGL fractionation complex will continue to be under pressure due to the intense competition at this
industry hub caused by excess fractionation capacity in the region (given the current demand picture for NGLs
from petrochemical companies). Margins from in-kind NGL fractionation fees (such as those at Norco) should be
consistent with the prior year given our expectations for NGL prices.
Our isomerization units should operate at 90% to 95% of the production rates seen during the first half of the
year. The operating rates of these facilities are in part linked to gasoline refinery demand which will
experience a seasonal decline in the third and fourth quarters. Our propylene fractionation units should operate
at rates similar to those seen in the first six months of 2002 on the assumption that demand for petrochemicals
should remain constant for the remainder of the year.
Octane Enhancement
BEF should experience a seasonal decline in margins during the third and fourth quarters as the summer driving
season ends and refiners reduce their demand for MTBE (which will negatively affect the price we receive for our
MTBE production). If our assumptions regarding the future price of natural gas are realized, our margins may also
be under pressure due to an increase in feedstock costs, particularly that of methanol.
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 partnership equity securities in this discussion pertain to Units issued by
Enterprise Products Partners L.P. References to public debt pertain to those obligations issued by Enterprise
Products Operating L.P. and guaranteed by Enterprise Products Partners 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 and sustaining capital
expenditures 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 partnership equity and public debt. Our quarterly cash distributions to partners are expected to be
funded primarily by current period operating cash flows or to a lesser extent, temporary borrowings under bank
credit facilities or a combination thereof. 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,
PAGE 66
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 partnership equity or public debt (separately or in
combination). As of June 30, 2002, total borrowing capacity under our revolving bank credit facilities was $500
million of which $132 million was available. On February 23, 2001, we filed a $500 million universal shelf
registration (the "February 2001 Shelf") covering the issuance of an unspecified amount of partnership equity or
debt securities or a combination thereof. Our plans for permanent financing of the approximately $1.2 billion
Mapletree and E-Oaktree acquisitions include the issuance of equity, including partnership equity for
institutional investors, and debt in amounts which are consistent with our objective of maintaining our financial
flexibility and investment grade balance sheet. For additional information regarding our debt, see the section
below labeled "Our debt obligations".
We have the ability, under certain conditions during the Subordination Period, to issue an unlimited number of
Common Units to finance acquisitions and capital improvements. The Subordination Period generally extends until
the first day of any quarter beginning after June 30, 2003 when certain financial tests have been satisfied. We
have the ability to issue an unlimited number of Common Units for this type of expenditure if Adjusted Operating
Surplus (as defined within our partnership agreement) for the previous four fiscal quarter period prior to the
expenditure, on a pro forma basis, would have increased as a result of such expenditure (i.e., would have been
accretive on a pro forma basis for each of the previous four fiscal quarters).
For those acquisitions and other transactions that do not qualify under the aforementioned pro forma "accretive"
test, we have 54,550,000 Units available (and unreserved) for general partnership purposes during the
Subordination Period. After the Subordination Period expires, we may prudently issue an unlimited number of Units
for general partnership purposes that do not meet the pro forma "accretive" test.
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.
Credit ratings. Our current investment grade credit ratings of Baa2 by Moody's and BBB by S and P highlight our
underlying financial strength. We maintain regular communications with these rating agencies which independently
judge our credit worthiness based on a variety of quantitative and qualitative factors.
On August 2, 2002, Moody's and S and P changed their ratings outlook regarding our debt securities from "stable" to
"negative". The ratings agencies did not take any action to downgrade our ratings; they remain at Baa2 by Moody's
and BBB by S and P. Their negative outlook on the future of our ratings reflects the execution risk they see
associated with our permanent financing plan for the Mapletree and E-Oaktree acquisitions, which includes the
issuance of traditional retail partnership equity, institutional partnership equity and long-term debt
aggregating about $1.2 billion over the remainder of 2002 and first quarter of 2003. On a positive note, the
ratings agencies noted that as a result of the acquisition, our cash flows should be more stable due to the
increase in fee-based revenues. They also commented that the acquired entities should result in the
diversification of our current NGL businesses and enhance our overall business profile.
The change in ratings outlook (as opposed to an actual change in ratings) does not translate into any material
financial impact on our liquidity. Management is committed to achieving its goals of permanent financing for the
Mapletree and E-Oaktree acquisitions and will actively pursue the appropriate mix and timing of offerings of
partnership equity and issuance of public debt that will maintain our investment grade balance sheet. We strongly
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
PAGE 67
Unit split was accomplished by distributing one additional partnership Unit for each partnership Unit outstanding
to holders of record on April 30, 2002. The Units were distributed on May 15, 2002. All references to number of
Units or earnings per Unit contained in this document relate to the post-split Units, except if indicated
otherwise.
Consolidated cash flows for six months ended June 30, 2002 compared to six months ended June 30, 2001
Operating cash flows. Cash flow from operating activities was an inflow of $45.2 million for the first six
months of 2002 compared to $90.6 million during the same period in 2001. Excluding changes in operating accounts
which are generally the result of timing of sales and purchases near the end of each period, adjusted cash flow
from operating activities would be an inflow of $77.6 million in 2002 versus $121.2 million during 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 or
have an interest in. The $43.6 million decrease in adjusted cash flows between the two year-to-date periods is
primarily due to:
o net hedging losses in 2002 versus net hedging income in 2001; offset by
o increased distributions from our unconsolidated affiliates and
o an increase in operating earnings due to acquisitions.
As noted under the Processing segment discussion under "Our results of operations" section, we recorded
$50.9 million in net commodity hedging losses during the first six months of 2002 compared to $70.4 million of
income during the first six months of 2001. Of the recorded hedging loss for the 2002 period, we have realized
(i.e., paid out to counterparties) $31.9 million of this loss. The difference of $19.0 million between the
recorded loss and the realized loss represents the non-cash change in market value of the overall portfolio
between December 31, 2001 and June 30, 2002. At June 30, 2002, the market value of the commodity financial
instruments that were outstanding was a payable of $11.1 million, which we expect to pay to counterparties over
the remainder of the 2002.
We discontinued the hedging strategy underlying the $50.9 million in losses in April 2002. This strategy had
helped create basically all of the $70.3 million in income from commodity hedging activities we recorded during
the first six months of 2001, of which $17.9 million had been received from counterparties through June 30, 2001.
Our current hedging strategies are limited in scope and duration. These strategies primarily cover the price risk
associated with certain NGL inventories and fuel costs. We do not expect any material impact on our liquidity from
the settlement of these commodity financial instruments, which settle primarily in the fourth quarter of 2002 and
first quarter of 2003. The market value of these instruments at June 30, 2002 was a net payable of $0.3 million,
(which is included in the $11.1 million payable market value of the overall portfolio mentioned previously). From
a cash flow sensitivity standpoint, if the commodity prices underlying these instruments were to increase by 10%
from the levels they were at on June 30, 2002, the amount we would have to pay counterparties would increase to
$0.8 million from $0.3 million. Likewise, if the underlying prices decreased by 10%, we would receive cash of $0.1
million from counterparties as opposed to paying $0.3 million. These amounts do not reflect the degree to which
the cash flows of the hedged transaction would be oppositely affected by the change in prices.
Investing cash flows. During the first six months of 2002, we used $431.7 million in cash to finance
investing activities compared to $397.5 million spent during the first six months of 2001. The 2001 period
includes $113 million paid to acquire equity interests in several Gulf of Mexico natural gas pipelines from El
Paso (our Neptune, Starfish and Nemo equity investments) and $225.7 million paid to acquire Shell's Acadian Gas
natural gas pipeline system. The 2002 period reflects $394.8 million in business acquisitions including $368.7
million paid to acquire Diamond-Koch's propylene fractionation and NGL and petrochemical storage businesses and
$18.0 million paid to Shell representing the final purchase price adjustment relating to the Acadian Gas
acquisition.
Financing cash flows. Our financing activities generated $257.3 million in cash inflows during the first
six months of 2002 compared to $362.4 million during the first six months of 2001. The 2002 period includes $368
million in borrowings under our revolving credit facilities while the 2001 period reflects $449.7 million in
proceeds from the issuance of the Senior Notes B. Cash distributions paid to our partners increased
period-to-period primarily due to increases in both the declared quarterly distribution rate and the number of
Units entitled to receive distributions.
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On a forward-looking basis, the conversion of Shell's non-distribution bearing Special Units to
distribution-bearing Common Units will increase distributions paid to partners beginning with the third quarter
of 2002 distribution paid in November 2002. See "Conversion of Shell Special Units to Common Units" on
page 74 for additional information regarding this issue.
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 positioned
to continue to grow through acquisitions that will expand its platform of assets and through internal growth
projects.
For fiscal 2002, we have invested or are committed to invest $1.6 billion in business acquisitions and internal
growth projects including $1.2 billion for the interests in Mapletree and E-Oaktree we purchased from affiliates
of Williams in July 2002;$239.0 million for the Mont Belvieu propylene fractionation assets we purchased from
Diamond-Koch in February 2002; and $129.6 million for the Mont Belvieu NGL and petrochemical storage assets we
purchased from Diamond-Koch in January 2002. Our goal is to invest at least $400 million annually in such
opportunities to the extent that we believe such investments will be accretive to our limited partners.
The funds needed to achieve this goal can be attained through a combination of operating cash flows, public and
private debt and/or partnership equity. Of the $1.6 billion in business acquisitions and internal growth projects
we have completed thus far in 2002, we have borrowed approximately $1.5 billion of the funds required. This will
translate into additional debt service costs during 2002.
The $1.2 billion we borrowed to effect the Mapletree and E-Oaktree acquisitions was in the form of a 364-day term
loan. The loan will be repaid as follows:$150 million due on December 31, 2002, $450 million on March 31, 2003
and $600 million on July 30, 2003. As noted earlier, our plans for permanent financing of this acquisition include
the issuance of equity, including partnership equity for institutional investors, and debt in amounts which are
consistent with our objective of maintaining our financial flexibility and investment grade balance sheet.
Distributions. Another stated goal of management is to increase the distribution rate to our investors by
at least 10% annually. For the fourth quarter of 2001, the declared annual rate was $1.25 per Common Unit (on a
post-split basis). In the first quarter of 2002, the declared annual rate was raised to $1.34 per Common Unit. Our
goal is to raise the declared annual rate to at least $1.375 per Common Unit by the end of fiscal 2002. Based on
the number of distribution-bearing Units projected to be outstanding during 2002 (not including the effect of any
potential equity offerings), we project that this goal would translate into cash distributions to partners
increasing by approximately $46 million over the amounts paid during 2001. The number of distribution-Units
projected to be outstanding during 2002 includes the conversion of 19.0 million non-distribution bearing Special
Units owned by Shell into an equal amount of distribution-bearing Common Units.
Our distribution rate is supported by prospective and historical cumulative cash flow since our IPO in July
1998. From our IPO through August 2002, we generated $849.6 million in cash that was available for distribution to
Unitholders, of which $573.3 million was paid to Unitholders (including the second quarter of 2002 distribution
paid on August 12, 2002). Our policy has been to retain and reinvest the difference of $276.3 million (the
"excess cash flow") into projects that we anticipate will be accretive in terms of cash flow to our Unitholders
over time. This policy has helped us to maintain a strong financial presence in the markets we serve by
minimizing debt and using the excess cash flow to expand the partnership through internal growth and acquisitions.
We believe that all cash distributions will be paid out of operating cash flows over the long-term; however, from
time to time, we may temporarily borrow under our bank credit facilities for the purpose of paying distributions
until the full cash flow impact of our operations are realized.
PAGE 69
Capital spending. At June 30, 2002, we had $6.8 million in outstanding purchase commitments attributable to
capital projects. Of this amount, $5.1 million is related to the construction of assets that will be recorded as
property, plant and equipment and $1.7 million is associated with capital projects of our unconsolidated
affiliates which will be recorded as additional investments.
During the first six months of 2002, our capital expenditures were $26.8 million. For the remainder of 2002, we
expect our capital spending to approximate $8.1 million of which $5.7 million is forecasted for our Pipelines
segment. Our unconsolidated affiliates forecast a combined $13.9 million in capital expenditures during the
remainder of 2002 of which we expect our share to be approximately $4.8 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.
Our debt obligations
Our debt consisted of the following at:
June 30, 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) 138,000
---------------------------------------
Total principal amount 1,222,000 854,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 1,895 1,653
Less unamortized discount on:
Senior Notes A (99) (117)
Senior Notes B (244) (258)
Less current maturities of debt - -
---------------------------------------
Long-term debt $1,223,552 $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 or
before maturity.
Debt associated with Mapletree and E-Oaktree acquisitions. The above table does not reflect the $1.2
billion senior unsecured 364-day term loan entered into by the Operating Partnership to fund the acquisition of
indirect interests in the Mid-America and Seminole pipelines from affiliates of Williams on July 31, 2002. The
lenders under this facility are Wachovia Bank, National Association; Lehman Brothers Bank, FSB; Lehman Commercial
Paper Inc. and Royal Bank of Canada. As defined within the credit agreement, the loan will generally bear interest
at either (i) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus one-half percent or
(ii) a Eurodollar rate, with any rate in effect being increased by an appropriate applicable margin. The credit
agreement contains various affirmative and negative covenants applicable to the Operating Partnership similar to
those required under our Multi-Year and 364-Day Credit Facility agreements (as defined within the second and
third amendments to these revolving credit facilities, see "Covenants" below). The $1.2 billion term loan
is guaranteed by Enterprise Products Partners L.P. through an unsecured guarantee. The loan will be repaid as
follows:$150 million due on December 31, 2002, $450 million on March 31, 2003 and $600 million on July 30, 2003.
On August 1, 2002, Seminole Pipeline Company had $60 million in senior unsecured notes due in December 2005. The
principal amount of these notes amortize by $15 million each December 1 through 2005. In accordance with GAAP,
this debt will be consolidated on our balance sheet because of our 98% controlling interest in E-Oaktree, LLC,
which owns 80% of Seminole Pipeline Company.
PAGE 70
Letters of credit. At June 30, 2002, we had a total of $75 million of standby letters of credit capacity
under our Multi-Year Credit Facility of which $9.4 million was outstanding.
Parent-subsidiary guarantees. Enterprise Products Partners L.P. also acts as guarantor of the Operating
Partnership's other debt obligations. This parent-subsidiary guaranty provision exists under our Senior Notes,
MBFC Loan, Multi-Year and 364-Day Credit Facility. The consolidated financial statements of both the Company and
Operating Partnership are included as part of this report on Form 10-Q.
Increased borrowing limits under revolving credit facilities. 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 June 30, 2002, we had
borrowed a total of $368 million under these two facilities.
Covenants. 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 June 30, 2002.
On April 24, 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were amended to allow for
the commodity hedging losses we incurred during the first four months of 2002. As defined within the second
amendment to each of these loan agreements, the changes included allowing us 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 earnings impact of such specific instruments were recognized. This
provision allows for $45.1 million to be added back to Consolidated EBITDA for the first quarter of 2002 and $4.9
million to be added back for the second quarter of 2002. Due to the rolling four-quarter nature of the
Consolidated EBITDA calculation, this provision will affect our financial covenants through the first quarter of
2003. In addition, the second amendment temporarily raised the maximum ratio allowed under the Consolidated
Indebtedness to Consolidated EBITDA ratio for the rolling-four quarter period ending September 30, 2002 (this
provision was superseded by the third amendment to these loan agreements as noted in the following paragraph).
On July 31, 2002, certain covenants of our Multi-Year and 364-Day Credit Facilities were further amended to allow
for increased financial flexibility in light of the Mapletree and E-Oaktree acquisitions. As defined within the
third amendment to each of these loan agreements, the maximum ratio of Consolidated Indebtedness to Consolidated
EBITDA allowed by our lenders was increased as follows from that noted in the second amendment issued in April
2002:
Changes made to the
Consolidated Indebtedness to Consolidated EBITDA Ratio
- ---------------------------------------------------------------------------
Maximum Ratio Allowed
------------------------------------------
Calculation made for Old provisions New provisions
the rolling four-quarter under 2nd under 3rd
period ending Amendment Amendment
- ---------------------------------------------------------------------------
September 30, 2002 4.50 to 1.0 6.00 to 1.0
December 31, 2002 4.00 to 1.0 5.25 to 1.0
March 31, 2003 4.00 to 1.0 5.25 to 1.0
June 30, 2003 4.00 to 1.0 4.50 to 1.0
September 30, 2003 and 4.00 to 1.0 4.00 to 1.0
for each rolling-four
quarter period thereafter
In addition, the negative covenant on Indebtedness (as defined within the Multi-Year and 364-Day credit
agreements) was amended to permit the Seminole Pipeline Company indebtedness assumed in connection with the
acquisition of E-Oaktree.
We were in compliance with the covenants of our Multi-Year and 364-Day revolving credit agreements at June 30,
2002.
PAGE 71
Summary of contractual obligations and material commercial commitments
The following table summarizes our contractual obligations and material purchase and other commitments for the
periods shown. The values shown in the table are as of June 30, 2002 with the exception that long-term debt
includes those obligations incurred or assumed on August 1, 2002 in connection with the Mapletree and E-Oaktree
acquisitions.
Contractual Obligation 2004 2006
or Material Commercial through through After
Commitment Total 2002 2003 2005 2007 2007
- ----------------------------------------------------------------------------------------------------------------------------
Contractual Obligation (expressed in
terms of millions of dollars payable
per period:)
Long-term debt $2,482.0 $165.0 $1,203.0 $ 610.0 $504.0
Operating leases $ 16.0 $ 2.7 $ 5.1 $ 5.0 $0.6 $ 2.6
Capital spending commitments:
Property, plant and equipment $ 5.1 $ 5.1
Investments in unconsolidated
affiliates $ 1.7 $ 1.7
Other commitments (expressed in terms
of millions of dollars potentially
payable per period):
Letters of Credit under Multi-Year
Credit Facility $ 9.4 $ 9.4
Other Material Contractual Obligations
(Purchase commitments expressed
in terms of minimum volumes
under contract per period:)
NGLs (MBbls) 26,810 6,415 10,371 9,684 340
Natural gas (BBtus) 135,174 6,863 13,725 25,991 25,595 63,000
Long-term debt. Long-term debt reflects amounts due under our Senior Notes A and B, the MBFC Loan and our
two revolving credit facilities. Of the $138 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 or before maturity.
As noted previously, we have included the aggregate $1.26 billion increase in debt associated with the Mapletree
and E-Oaktree acquisitions which occurred on July 31, 2002. The debt associated with these acquisitions consists
of (a) the $1.2 billion 364-Day term loan we incurred to pay affiliates of Williams for these businesses plus (b)
the $60 million in debt principal outstanding on Seminole's balance sheet at acquisition date. The $1.2 billion
364-Day term loan will be repaid as follows:$150 million due on December 31, 2002, $450 million on March 31, 2003
and $600 million on July 30, 2003. For additional information regarding these new debt obligations, see "Our
debt obligations" beginning on page 70 and "Acquisitions" beginning on page 69.
Operating leases. 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.
PAGE 72
Letters of Credit under our Multi-Year Credit Facility. Our letters of credit increased from $2.4 million
at December 31, 2001 to $9.4 million at June 30, 2002 primarily due to letter of credit requirements associated
with our purchase of hydrocarbon imports. As of August 7, 2002, our letters of credit were $2.2 million.
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-interests 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.
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 SFAS No. 141, we
reclassified the MBA goodwill to a separate line item on our consolidated balance sheet apart from the Shell
contract. Based upon our interpretation of SFAS No. 142, the value of the Shell natural gas processing agreement
will continue to be amortized over its remaining contract term of approximately 18 years; however, amortization
of the MBA goodwill will cease. The MBA goodwill will be subject to periodic impairment testing in accordance
with SFAS No. 142 due to its indefinite life. 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 accordance with the transition provisions of SFAS No. 142, we have completed an impairment review of
the December 31, 2001 MBA goodwill balance using a fair value methodology. Professionals in the business valuation
industry were consulted regarding the assumptions and techniques used in our analysis. As a result of this
review, no impairment loss was indicated. Any subsequent impairment losses stemming from future goodwill
impairment studies will be reflected as a component of operating income in the Statements of Consolidated
Operations.
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 evaluating 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.
In April 2002, the FASB issued SFAS No. 145, "Rescission of SFAS Statements No. 4, 44, and 64, Amendment of SFAS
No. 13, and Technical Corrections." The purpose of this statement is to update, clarify and simplify existing
accounting standards. We adopted this statement effective April 30, 2002 and determined that it did not have any
significant impact on our financial statements as of that date.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities."
This standard requires companies to recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to exit or disposal plan. Examples of costs covered by the
standard include lease termination costs and certain employee severance costs that are associated with a
restructuring, discontinued operation, plant closing, or other exit or disposal activity. Previous accounting
guidance was provided by EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). "SFAS No. 146 replaces
Issue 94-3. SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after December
31, 2002. This statement is effective for our fiscal year beginning January 1, 2003. We are evaluating the
provisions of this statement.
PAGE 73
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 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 toward 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. We are currently undergoing a more rigorous and detailed engineering
study that is expected to be completed during the third quarter of 2002, at which time a more definitive
conversion cost estimate will be available. The cost to convert the facility will depend on the type of alkylate
process chosen and level of alkylate production desired by the partnership.
Conversion of EPCO Subordinated Units to Common Units
As a result of the Company satisfying certain financial tests, 10,704,936 (or 25%) of EPCO's Subordinated Units
converted to 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 to 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 to 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.
Conversion of Shell Special Units to Common Units
In accordance with existing agreements with Shell, 19.0 million of Shell's non-distribution bearing Special Units
converted to distribution-bearing Common Units on August 1, 2002. The remaining 10.0 million Special Units will
convert to Common Units on a one-for-one basis in August 2003. These conversions have a dilutive impact on basic
earnings per Unit.
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 13 of the Company's Notes to Unaudited
Consolidated Financial Statements.
PAGE 74
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 financial commodity and commercial policy to manage our exposure to the risks of our natural
gas and NGL businesses. The objective of these policies 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 these policies, 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 policies (including authorized products, instruments and markets) and
establishes specific guidelines and procedures for implementing and ensuring compliance with the policies.
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.
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.
PAGE 75
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.
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
Estimated Portfolio Value in millions of dollars at
Resulting ----------------------------------------------------
Scenario classification 12/31/01 03/31/02 06/30/02 08/01/02
- ----------------------------------------------------------------------------------------------------------------------
FV assuming no change in quoted market prices Asset (Liability) $ 5.6 $(20.8) $(11.1) $(5.5)
FV assuming 10% increase in quoted market prices Asset (Liability) $(0.3) $(30.7) $(11.3) $(5.3)
EI assuming 10% increase in quoted market prices Income (Loss) $(5.9) $ (9.9) $ (0.2) $ 0.2
FV assuming 10% decrease in quoted market prices Asset (Liability) $11.4 $(10.9) $(10.8) $(5.8)
EI assuming 10% decrease in quoted market prices Income (Loss) $ 5.8 $ 9.9 $ 0.3 $(0.3)
As the table shows, the estimated value of our commodity hedging portfolio declined from a $5.6 million asset at
December 31, 2001 to a $20.8 million payable at March 31, 2002. The negative change in value was 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 speculation surrounding potential natural gas shortages began to influence 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). As a result, we
recognized a loss from our commodity hedging activities for the first quarter of 2002 of $45.1 million.
Due to the inherent uncertainty that was controlling the markets, management decided that it was prudent for the
Company to exit this strategy and did so by late April 2002. By the time that these positions were generally
closed out in late April, we had incurred approximately $5.7 million in additional losses; thus, the total
commodity hedging loss for 2002 due to this strategy was approximately $50.8 million.
Of the $50.8 million in losses from this strategy recorded during 2002, $7.6 million is related to mark-to-market
income from these instruments that we recognized in the fourth quarter of 2001. The remaining $43.2 million
PAGE 76
represents our cash exposure from these losses of which $31.9 million has been paid to counterparties through
June 30, 2002. The balance of the cash payments will be made over the remainder of 2002.
The value of the portfolio at June 30, 2002 was $11.1 million payable. A movement in market prices at this date
has minimal impact on the value of the portfolio because most of the portfolio has been generally closed out as
noted above. The change in overall portfolio value primarily reflects the settlement of transactions that
occurred during the second quarter of 2002. The value of the portfolio was $5.5 million payable at August 1,
2002. The change between June 30, 2002 and August 1, 2002 is primarily the result of settlements that occurred
during July 2002.
Our current hedging strategies are limited in scope and duration. These commodity financial instruments primarily
hedge the price risk associated with certain NGL inventories and fuel costs. These instruments are short-term in
nature with settlements extending through March 2003. The market value of these instruments at June 30, 2002 was a
net payable of $0.3 million, (which is included in the $11.1 million payable market value of the overall
portfolio mentioned previously). From a cash flow sensitivity standpoint, if the commodity prices underlying these
instruments were to increase by 10% from the levels they were at on June 30, 2002, the amount we would have to
pay counterparties would increase to $0.8 million from $0.3 million. Likewise, if the underlying prices decreased
by 10%, we would receive cash of $0.1 million from counterparties as opposed to paying $0.3 million. These amounts
do not reflect the degree to which the cash flows of the hedged transaction would be oppositely affected by the
change in prices. 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 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 June 30, 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 the counterparty elects to do so, it may terminate this swap in March 2003.
We recognized income of $0.7 million and $0.8 million for the three and six months ended June 30, 2002,
respectively, that is treated as a reduction of interest expense in our Statements of Consolidated Operations. The
fair value of the interest rate swap at June 30, 2002 was a receivable of $3.1 million. This fair value would
decrease slightly if quoted market interest rates were to increase by 10%.
PAGE 77
Part II, Other Information
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
2.1 Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated as of
September 22, 2000. (Exhibit 10.1 to 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).
2.4 Purchase Agreement dated as of July 31, 2002 by and between E-Birchtree, LLC and E-Cypress, LLC (Exhibit
2.1 to the Company's Form 8-K filed August 12, 2002).
2.5 Purchase Agreement dated as of July 31, 2002 by and between E-Birchtree, LLC and Enterprise Products
Operating L.P. (Exhibit 2.2 to the Company's Form 8-K filed August 12, 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 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).
3.3* Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated
May 15, 2002.
3.4* Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Enterprise Products
Partners L.P. dated August 7, 2002.
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).
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).
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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 and Supplement to Multi-Year Credit Facility dated April 24, 2002.
4.15 Second Amendment and Supplement to 364-Day Credit Facility dated April 24, 2002.
4.16 Third Amendment and Supplement to Multi-Year Credit Facility dated July 31, 2002. (Exhibit 4.1 to the
Company's Form 8-K filed August 12, 2002).
4.17 Third Amendment and Supplement to 364-Day Credit Facility dated July 31, 2002. (Exhibit 4.2 to the
Company's Form 8-K filed August 12, 2002).
4.18 $1.2 billion 364-Day Term Loan Credit Agreement among Enterprise Products Operating L.P.; Wachovia Bank,
National Association, as administrative agent; Lehman Commercial Paper Inc., as co-syndication agent;
and the Royal Bank of Canada, as co-syndication agent and arranger dated July 31, 2002. (Exhibit 4.3 to
the Company's Form 8-K filed August 12, 2002).
4.19 Guaranty Agreement (relating to the $1.2 billion 364-Day Term Loan Credit Agreement) by Enterprise
Products Partners L.P. in favor of Wachovia Bank, National Association, as administrative agent dated
July 31, 2002. (Exhibit 4.4 to the Company's Form 8-K filed August 12, 2002).
PAGE 79
12.1* Computation of ratio of earnings to fixed charges for the six months ended June 30, 2002 and each of the
five years ended December 31, 2001, 2000, 1999, 1998 and 1997 for Enterprise Products Partners L.P.
12.2* Computation of ratio of earnings to fixed charges for the six months ended June 30, 2002 and each of the
five years ended December 31, 2001, 2000, 1999, 1998 and 1997 for Enterprise Products Operating L.P.
* 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 have been entered into during the first six months of 2002.
(b) Reports on Form 8-K.
On April 2, 2002, we filed a Form 8-K that noted a press release declaring our first quarter of 2002 distribution
rate of $0.67 per Common Unit (on a pre-split basis).
PAGE 80
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 August 13, 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
By: /s/ Michael J. Knesek
Name: Michael J. Knesek
Title: Vice President, Controller and Principal Accounting
Officer of the General Partner
