FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended June 30, 1999
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number: 1-14323
Enterprise Products Partners L.P.
(Exact name of Registrant as specified in its charter)
Delaware 76-0568219
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2727 North Loop West
Houston, Texas
77008-1037
(Address of principal executive offices) (Zip code)
(713) 880-6500
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes _X_ No ___
The registrant had 45,552,915 Common Units outstanding as of August 9,
1999.
Enterprise Products Partners L.P. and Subsidiaries
TABLE OF CONTENTS
Page
No.
Part I. Financial Information
Item 1. Financial Statements
Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets, June 30, 1999 and December 31, 1998 1
Statements of Consolidated Operations
for the Three and Six Months ended June 30, 1999 and 1998 2
Statements of Consolidated Cash Flows
for the Three and Six Months ended June 30, 1999 and 1998 3
Notes to Unaudited Consolidated Financial Statements 4-8
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 9-20
Item 3. Quantitative and Qualitative Disclosures about Market Risk 21
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 22-24
Signature Page 25
PART 1. FINANCIAL INFORMATION.
Item 1. FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Amounts in thousands)
June 30,
December 31, 1999
ASSETS 1998 (Unaudited)
-------------------------------------
Current Assets
Cash and cash equivalents $ 24,103 $ 3,959
Accounts receivable - trade 57,288 57,644
Accounts receivable - affiliates 15,546 21,764
Inventories 17,574 55,526
Current maturities of participation in notes receivable from
unconsolidated affiliates 14,737 14,737
Prepaid and other current assets 8,445 7,475
-------------------------------------
Total current assets 137,693 161,105
Property, Plant and Equipment, Net 499,793 492,788
Investments in and Advances to Unconsolidated Affiliates 91,121 132,005
Participation in Notes Receivable from Unconsolidated Affiliates 11,760 4,391
Other Assets 670 236
=====================================
Total $741,037 $790,525
=====================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $ 36,586 $ 36,422
Accrued gas payables 27,183 50,047
Accrued expenses 7,540 5,591
Other current liabilities 11,462 7,819
-------------------------------------
Total current liabilities 82,771 99,879
Long-Term Debt 90,000 145,000
Minority Interest 5,730 5,548
Commitments and Contingencies
Partners' Equity
Common Units 433,082 410,958
Subordinated Units 123,829 123,693
General Partner 5,625 5,447
-------------------------------------
Total Partners' Equity 562,536 540,098
=====================================
Total $741,037 $790,525
=====================================
See Notes to Unaudited Consolidated Financial Statements
1
PART 1. FINANCIAL INFORMATION (continued)
Item 1. FINANCIAL STATEMENTS (continued)
Enterprise Products Partners L.P.
Statement of Consolidated Operations
(Unaudited)
(Amounts in thousands, except per Unit amounts)
Three Months Ended Six Months Ended
June 30, June 30,
1998 1999 1998 1999
--------------------------------------------------------------------------
REVENUES $207,566 $174,599 $398,083 $321,913
COST AND EXPENSES
Operating costs and expenses 186,784 153,283 368,231 287,095
Selling, general and administrative 5,857 3,000 11,611 6,000
--------------------------------------------------------------------------
Total 192,641 156,283 379,842 293,095
--------------------------------------------------------------------------
OPERATING INCOME 14,925 18,316 18,241 28,818
--------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense (4,070) (1,913) (10,804) (3,959)
Equity income in unconsolidated affiliates 3,831 2,880 6,653 4,443
Interest income from unconsolidated affiliates - 292 - 689
Interest income - other 285 148 560 432
Other, net 428 (373) 430 (512)
--------------------------------------------------------------------------
Other income (expense) 474 1,034 (3,161) 1,093
--------------------------------------------------------------------------
INCOME BEFORE MINORITY INTEREST 15,399 19,350 15,080 29,911
MINORITY INTEREST (154) (196) (151) (302)
==========================================================================
NET INCOME $ 15,245 $ 19,154 $ 14,929 $ 29,609
==========================================================================
ALLOCATION OF NET INCOME TO:
Limited partners $ 15,093 $ 18,962 $ 14,780 $ 29,313
General partner $ 152 $ 192 $ 149 $ 296
==========================================================================
NET INCOME PER UNIT $ 0.27 $ 0.28 $ 0.27 $ 0.44
==========================================================================
WEIGHTED-AVERAGE NUMBER OF UNITS
OUTSTANDING 54,963 66,696 54,963 66,725
==========================================================================
See Notes to Unaudited Consolidated Financial Statements
2
PART 1. FINANCIAL INFORMATION (continued)
Item 1. FINANCIAL STATEMENTS (continued)
Enterprise Products Partners L.P.
Statements of Consolidated Cash Flows
(Unaudited)
(Dollars in Thousands)
Six Months Ended
June 30,
1998 1999
-----------------------------
OPERATING ACTIVITIES
Net income $14,929 $29,609
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 9,403 9,790
Equity in income of unconsolidated affiliates (6,653) (4,443)
Leases paid by EPCO - 5,278
Minority interest 151 302
(Gain) loss on sale of assets (252) 124
Net effect of changes in operating accounts (36,667) (26,417)
-----------------------------
Operating activities cash flows (19,089) 14,243
-----------------------------
INVESTING ACTIVITIES
Capital expenditures (7,388) (2,513)
Proceeds from sale of assets 3,704 7
Collection of notes receivable from unconsolidated affiliates - 7,369
Unconsolidated affiliates:
Investments in and advances to (14,471) (40,432)
Distributions received 4,891 3,991
-----------------------------
Investing activities cash flows (13,264) (31,578)
-----------------------------
FINANCING ACTIVITIES
Long-term debt borrowings - 85,000
Long-term debt repayments (12,174) (30,000)
Net decrease in restricted cash (1,212) -
Cash dividends paid to partners - (52,718)
Cash dividends paid to minority interest - (538)
Units acquired by consolidated trusts - (4,607)
Cash contributions from EPCO to minority interest - 54
-----------------------------
Financing activities cash flows (13,386) (2,809)
-----------------------------
CASH CONTRIBUTIONS FROM (TO) EPCO 35,974 -
NET CHANGE IN CASH AND CASH EQUIVALENTS (9,765) (20,144)
CASH AND CASH EQUIVALENTS, JANUARY 1 18,941 24,103
=============================
CASH AND CASH EQUIVALENTS , JUNE 30 $ 9,176 $ 3,959
=============================
See Notes to Unaudited Consolidated Financial Statements
3
Enterprise Products Partners L.P.
Notes to Consolidated Financial Statements
(Unaudited)
1. GENERAL
In the opinion of Enterprise Products Partners L.P. (the "Company"), the
accompanying unaudited consolidated financial statements include all adjustments
consisting of normal recurring accruals necessary for a fair presentation of the
Company's consolidated financial position as of June 30, 1999 and its
consolidated results of operations and cash flows for the three and six month
periods ended June 30, 1999 and 1998. Although the Company believes the
disclosures in these financial statements are adequate to make the information
presented not misleading, certain information and footnote disclosures normally
included in annual financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted pursuant to the
rules and regulations of the Securities and Exchange Commission. These unaudited
financial statements should be read in conjunction with the financial statements
and notes thereto included in the Company's Annual Report on Form 10-K for the
year ended December 31, 1998 ("Form 10-K").
The results of operations for the three and six months ended June 30, 1999 are
not necessarily indicative of the results to be expected for the full year.
Dollar amounts presented in the tabulations within the notes to the consolidated
financial statements are stated in thousands of dollars, unless otherwise
indicated.
2. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES
At June 30, 1999, the Company's significant unconsolidated affiliates accounted
for by the equity method included the following:
Belvieu Environmental Fuels ("BEF") - a 33-1/3% economic interest in a
Methyl Tertiary Butyl Ether ("MTBE") production facility.
Mont Belvieu Associates ("MBA") - a 49% economic interest in an entity
which owns a 50% interest in a NGL fractionation facility. See Note 7 for
subsequent event.
Entell NGL Services, LLC ("Entell") - a 50% economic interest in a NGL
transportation and distribution system located in Louisiana and southeast
Texas.
Baton Rouge Fractionators LLC ("BRF") - a 27.5% economic interest in a NGL
fractionation facility which is scheduled to begin production during the
third quarter of 1999.
EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a
50% aggregate economic interest in a refrigerated NGL marine terminal
loading facility which is under construction and scheduled to become fully
operational in the fourth quarter of 1999.
Wilprise Pipeline Company, LLC ("Wilprise") - a 33-1/3% economic interest
in a NGL pipeline system that is scheduled to become fully operational in
the third quarter of 1999 in conjunction with the startup of the BRF NGL
fractionation facility.
The Company's investments in and advances to unconsolidated affiliates also
includes Tri-States NGL Pipeline, LLC ("Tri-States"). The Tri-States investment
consists of a 16-2/3% economic interest in a NGL pipeline system which became
operational on March 26, 1999. This investment is accounted for using the cost
method in accordance with generally accepted accounting principles.
4
Other joint ventures included various entities in the formation stage at June
30, 1999.
Investments in and advances to unconsolidated affiliates at:
December 31, June 30,
1998 1999
---------------------------------
BEF................................................ $ 50,079 $ 51,712
MBA................................................ 12,551 14,373
BRF................................................ 17,896 28,148
EPIK............................................... 5,667 11,773
Wilprise........................................... 4,873 7,540
Entell............................................. - 773
Tri-States......................................... 55 14,794
Other.............................................. - 2,892
=================================
Total.............................................. $ 91,121 $ 132,005
=================================
Equity in income of unconsolidated affiliates for the:
Three Months ended Six Months ended
June 30, June 30,
1998 1999 1998 1999
------------------------------------------------------------------
BEF............................ $2,381 $1,936 $3,254 $2,237
MBA............................ 1,494 424 3,443 1,184
BRF............................ - (143) - (286)
EPIK........................... (44) (220) (44) 177
Entell......................... - 883 - 1,131
==================================================================
Total.......................... $3,831 $2,880 $6,653 $4,443
==================================================================
3. SUPPLEMENTAL CASH FLOW DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Six Months Ended
June 30,
1998 1999
---------------------------------
(Increase) decrease in:
Accounts receivable............................... $ 4,805 $ (6,574)
Inventories....................................... (19,015) (37,952)
Prepaid and other current assets.................. 425 970
Other assets...................................... (906) -
Increase (decrease) in:
Accounts payable - trade.......................... (34,203) (164)
Accrued gas payable............................... 23,699 22,864
Accrued expenses.................................. (4,849) (1,949)
Other current liabilities......................... (6,623) (3,612)
=================================
Net effect of changes in operating accounts $ (36,667) $(26,417)
=================================
5
4. RECENTLY ISSUED ACCOUNTING STANDARDS
On June 6, 1999, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS) No. 137, "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date of
FASB Statement No. 133-an amendment of FASB Statement No. 133" which effectively
delays and amends the application of SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" for one year, to fiscal years beginning
after June 15, 2000. Management is currently studying both SFAS No. 137 and SFAS
No. 133 for possible impact on the consolidated financial statements.
On April 3, 1998, the American Institute of Certified Public Accountants issued
Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up
Activities." For years beginning after December 15, 1998, SOP 98-5 generally
requires that all start-up costs of a business activity be charged to expense as
incurred and any start-up costs previously deferred should be written off as a
cumulative effect of a change in accounting principle. Adoption of SOP 98-5
during 1999 did not have a material impact on the consolidated financial
statements except for a $4.5 million noncash write-off that occurred on January
1, 1999 of the unamortized balance of deferred start-up costs of BEF, in which
the Company owns a 33-1/3% interest. This write-off caused a $1.5 million
reduction in the equity in income of unconsolidated affiliates for 1999 and a
corresponding reduction in the Company's investment in unconsolidated
affiliates.
5. CAPITAL STRUCTURE
At June 30, 1999, the Company had 33,552,915 Common Units outstanding held by
Enterprise Products Company (the Company's ultimate parent or "EPCO") and
12,000,000 Common Units outstanding held by third parties. During the first
quarter of 1999, the Company established a revocable grantor trust (the "Trust")
to fund future liabilities of a Long-Term Incentive Plan (the "Plan").
Provisions of the Plan were not finalized as of August 9, 1999. At June 30,
1999, the Trust had purchased a total of 267,200 Common Units (the "Trust
Units") which are accounted for in a manner similar to treasury stock under the
cost method of accounting. The Trust Units are considered outstanding and will
receive distributions; however, they are excluded from the calculation of net
income per Unit in accordance with generally accepted accounting principles.
6. DISTRIBUTIONS
On January 12, 1999, the Company declared a quarterly distribution of $.45 per
Unit for the fourth quarter of 1998, which was paid on February 11, 1999 to all
Unitholders of record on January 29, 1999. The Company declared its distribution
for the first quarter of 1999 on April 16, 1999 in the amount of $.45 per Common
Unit. The first quarter 1999 distribution was paid on May 12, 1999 to Common
Unitholders of record on April 30, 1999. The Company declared a $.45 per Common
Unit distribution for the second quarter of 1999 on July 16, 1999. The second
quarter 1999 distribution will be paid on August 11, 1999 to Common Unitholders
of record on July 30, 1999.
7. SUBSEQUENT EVENTS
Acquisition of Tejas Assets
On April 20, 1999, the Company and Tejas Energy, LLC ("Tejas"), an affiliate of
Shell Oil Company ("Shell"), announced that they had agreed to general terms for
a business combination encompassing the Company and a substantial portion of
Tejas' natural gas liquids ("NGL") business. The agreed upon terms contemplate
Tejas contributing certain NGL assets to the Company for which Tejas would
receive an equity interest in the Company and other consideration. The
completion of this transaction would form a business combination comprising a
fully integrated Gulf Coast NGL processing, fractionation, storage, and
transportation business. It would also establish an alliance between the Company
and Shell whereby the Company would have the rights to process Shell's current
and future Gulf of Mexico natural gas production and market the NGLs recovered.
Any transaction resulting from the agreed upon terms would be subject to the
Company and Tejas successfully executing a definitive agreement; satisfactorily
completing their respective due diligence reviews; receiving requisite
regulatory approvals and receiving approvals from each company's board of
directors. The parties anticipate the closing of this transaction in August
1999.
6
Purchase of Lou-Tex Pipeline
On July 27, 1999, the Company announced the execution of a letter of intent to
acquire a Louisiana and Texas pipeline asset from Concha Chemical Pipeline
Company ("Concha"), an affiliate of Shell Oil Company, for an undisclosed amount
of cash. The pipeline being acquired, referred to as the Lou-Tex pipeline, is
263 miles of 10" pipeline from Sorrento, Louisiana to Mont Belvieu, Texas. The
Lou-Tex pipeline is currently dedicated to the transportation of chemical grade
propylene from Sorrento to the Mont Belvieu area. Enterprise plans to convert a
portion of the Lou-Tex pipeline into batch service. In batch service, the
pipeline will be able to transport refinery and chemical grade propylene, mixed
NGLs and NGL products: ethane, propane, normal butane, isobutane and natural
gasoline. In conjunction with the plans to convert the pipeline to batch
service, the capacity of the Lou-Tex pipeline will be increased to approximately
75,000 barrels per day. The acquisition of the Lou-Tex pipeline and its
conversion into batch service is the first step in the Company's development of
a $245 million, 160,000 barrel per day gas liquids pipeline system. This larger
system will link growing supplies of NGLs produced in Louisiana and Mississippi
with the principal NGL markets on the United States Gulf Coast. The completion
of the Lou-Tex transaction is subject to the successful negotiation of
definitive agreements, approval of those agreements by the respective
managements and regulatory approvals. This transaction is expected to be
completed by the end of the third quarter of 1999. Conversion of the Lou-Tex
system to batch service with 75,000 barrels per day of capacity is expected in
the second half of 2000.
The Company will acquire the Lou-Tex pipeline asset through its affiliate,
Entell NGL Services, LLC ("Entell"). Entell, formed in early 1999, is a 50/50
joint venture between the Company and Tejas Natural Gas Liquids, LLC, an
affiliate of Shell Oil Company. Upon completion of the previously announced NGL
alliance between Shell Oil Company and the Company, Entell will be a
wholly-owned subsidiary of the Company.
Acquisition of Kinder Morgan interest in Fractionation facility
On July 28, 1999, the Company announced that it had agreed to general terms and
conditions for the Company to purchase Kinder Morgan Energy Partners L.P.'s 25%
indirect ownership interest in a 210,000 barrel per day NGL fractionating
facility located in Mont Belvieu, Texas for $41 million in cash and
approximately $4 million in debt assumption. In conjunction with this
transaction, the Company will acquire EPCO's 1% interest in MBA for an
undisclosed amount of cash. Upon completion of these transactions, the Company's
ownership interest in the Mont Belvieu fractionation facility will increase from
37.0% to 62.5%. This fractionator is located in the Company's Mont Belvieu
processing complex. The Company serves as the operator of the facility. The
parties anticipate closing this transaction in August 1999.
New Bank Credit facility
Also on July 28, 1999, Enterprise Products Operating L.P. (the "Operating
Partnership") entered into a $350.0 million bank credit facility that includes a
$50.0 million working capital facility and a $300.0 million revolving term loan
facility. The $300.0 million revolving term loan facility includes a sublimit of
$10.0 million for letters of credit. The proceeds of this loan will be used
principally for the acquisition of the Tejas assets, the Lou-Tex pipeline, and
Kinder Morgan's interest in the fractionation facility.
Borrowings under the bank credit facility will bear interest at either the
bank's prime rate or the Eurodollar rate plus the applicable margin as defined
in the facility. The bank credit facility will expire after two years and all
amounts borrowed thereunder shall be due and payable on such date. There must be
no amount outstanding under the working capital facility for at least 15
consecutive days during each fiscal year.
The credit agreement relating to the new facility contains a prohibition on
distributions on, or purchases or redemptions of Units if any event of default
is continuing. In addition, the bank credit facility contains various
affirmative and negative covenants applicable to the ability of the Company to,
among other things, (i) incur certain additional indebtedness, (ii) grant
certain liens, (iii) sell assets in excess of certain limitations, (iv) make
investments, (v) engage in transactions with affiliates and (vi) enter into a
merger, consolidation, or sale of assets. The bank credit facility requires that
the Operating Partnership satisfy the following financial covenants at the end
of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined
in the bank credit facility) of at least $250,000,000, (ii) maintain a ratio of
EBITDA (as defined in the bank credit facility) to Consolidated Interest Expense
(as defined in the bank credit facility) for the previous 12-month period of at
least 3.5 to 1.0 and (iii) maintain a ratio of Total Indebtedness (as defined in
the bank credit facility) to EBITDA of no more than 3.0 to 1.0.
7
A "Change of Control" constitutes an Event of Default under the bank credit
facility. A Change of Control includes any of the following events: (i) Dan L.
Duncan (and certain affiliates) cease to own (a) at least 51% (on a fully
converted, fully diluted basis) of the economic interest in the capital stock of
EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to
elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own,
through a wholly owned subsidiary, at least 65% of the outstanding membership
interest in the General Partner and at least a majority of the outstanding
Common Units; (iii) any person or group beneficially owns more than 20% of the
outstanding Common Units; (iv) the General Partner ceases to be the general
partner of the Company or the Operating Partnership; or (v) the Company ceases
to be the sole limited partner of the Operating Partnership.
8
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
For the Interim Periods ended June 30, 1999 and 1998
The following discussion and analysis should be read in conjunction with
the unaudited consolidated financial statements and notes thereto of Enterprise
Products Partners L.P. ("Enterprise" or the "Company") included elsewhere
herein.
The Company
The Company is a leading integrated North American provider of processing
and transportation services to domestic and foreign producers of natural gas
liquids ("NGLs") and other liquid hydrocarbons and domestic and foreign
consumers of NGLs and liquid hydrocarbon products. The Company manages a fully
integrated and diversified portfolio of midstream energy assets and is engaged
in NGL processing and transportation through direct and indirect ownership and
operation of NGL fractionators. It also manages NGL processing facilities,
storage facilities, pipelines, and rail transportation facilities, and methyl
tertiary butyl ether ("MTBE") and propylene production and transportation
facilities in which it has a direct and indirect ownership.
The Company is a publicly traded master limited partnership (NYSE, symbol
"EPD") that conducts substantially all of its business through Enterprise
Products Operating L.P. (the "Operating Partnership"), the Operating
Partnership's subsidiaries, and a number of joint ventures with industry
partners. The Company was formed in April 1998 to acquire, own, and operate all
of the NGL processing and distribution assets of Enterprise Products Company
("EPCO").
The principal executive office of the Company is located at 2727 North Loop
West, Houston, Texas, 77008-1038, and the telephone number of that office is
713-880-6500. References to, or descriptions of, assets and operations of the
Company in this quarterly report include the assets and operations of the
Operating Partnership and its subsidiaries as well as the predecessors of the
Company.
General
The Company (i) fractionates for a processing fee mixed NGLs produced as
by-products of oil and natural gas production into their component products:
ethane, propane, isobutane, normal butane and natural gasoline; (ii) converts
normal butane to isobutane through the process of isomerization; (iii) produces
MTBE from isobutane and methanol; and (iv) transports NGL products to end users
by pipeline and railcar. The Company also separates high purity propylene from
refinery-sourced propane/propylene mix and transports high purity propylene to
plastics manufacturers by pipeline. Products processed by the Company generally
are used as feedstocks in petrochemical manufacturing, in the production of
motor gasoline and as fuel for residential and commercial heating.
The Company's processing operations are concentrated in Mont Belvieu,
Texas, which is the hub of the domestic NGL industry and is adjacent to the
largest concentration of refineries and petrochemical plants in the United
States. The facilities operated by the Company at Mont Belvieu include: (i) one
of the largest NGL fractionation facilities in the United States with an average
production capacity of 210,000 barrels per day; (ii) the largest butane
isomerization complex in the United States with an average isobutane production
capacity of 116,000 barrels per day; (iii) one of the largest MTBE production
facilities in the United States with an average production capacity of 14,800
barrels per day; and (iv) two propylene fractionation units with an average
combined production capacity of 31,000 barrels per day. The Company owns all of
the assets at its Mont Belvieu facility except for the NGL fractionation
facility, in which it owns an effective 37.0% economic interest (see NGL
Fractionation below); one of the propylene fractionation units, in which it owns
a 54.6% interest and controls the remaining interest through a long-term lease;
the MTBE production facility, in which it owns a 33-1/3% interest; and one of
its three isomerization units and one deisobutanizer which are held under
long-term leases with purchase options. The Company also owns and operates
approximately 35 million barrels of storage capacity at Mont Belvieu and
elsewhere that are an integral part of its processing operations, a network of
approximately 500 miles of pipelines along the Gulf Coast and a NGL
fractionation facility in Petal, Mississippi with an average production capacity
of 7,000 barrels per day. The Company also leases and operates one of only two
commercial NGL import/export terminals on the Gulf Coast.
9
Industry Environment
Because certain NGL products compete with other refined petroleum products
in the fuel and petrochemical feedstock markets, NGL product prices are set by
or in competition with refined petroleum products. Increased production and
importation of NGLs and NGL products in the United States may decrease NGL
product prices in relation to refined petroleum alternatives and thereby
increase consumption of NGL products as NGL products are substituted for other
more expensive refined petroleum products. Conversely, a decrease in the
production and importation of NGLs and NGL products could increase NGL product
prices in relation to refined petroleum product prices and thereby decrease
consumption of NGLs. However, because of the relationship of crude oil and
natural gas production to NGL production, the Company believes any imbalance in
the prices of NGLs and NGL products and alternative products would be temporary.
Historically, when the price of crude oil is a multiple of ten or more to
the price of natural gas (i.e., crude oil $20 per barrel and natural gas $2 per
thousand cubic feet ("MCF")), NGL pricing has been strong due to increased use
in manufacturing petrochemicals. In 1998, the industry experienced an annualized
multiple of approximately six (i.e., crude oil $12 per barrel and natural gas $2
per MCF), which caused petrochemical manufacturing demand to change from
reliance on NGLs to a preference for crude oil derivatives. This change resulted
in the lowering of both the production and pricing of NGLs. In the NGL industry,
revenues and cost of goods sold can fluctuate significantly up or down based on
current NGL prices. However, operating margins will generally remain constant
except for the effect of inventory price adjustments or increased operating
expenses.
NGL Fractionation
The profitability of this business unit depends on the volume of mixed NGLs
that the Company processes for its toll customers and the level of toll
processing fees charged to its customers. The most significant variable cost of
fractionation is the cost of energy required to operate the units and to heat
the mixed NGLs to effect separation of the NGL products. The Company is able to
reduce its energy costs by capturing excess heat and re-using it in its
operations. Additionally, the Company's NGL fractionation processing contracts
typically contain escalation provisions for cost increases resulting from
increased variable costs, including energy costs. The Company's interest in the
operations of its NGL fractionation facilities at Mont Belvieu consists of a
directly-owned 12.5% undivided interest and a 49.0% economic interest in MBA,
which in turn owns a 50.0% undivided interest in such facilities. The Company's
12.5% interest is recorded as part of revenues and expenses, and its effective
24.5% economic interest is recorded as an equity investment in an unconsolidated
subsidiary.
On July 28, 1999, the Company announced that it had agreed to general terms
and conditions for the purchase of Kinder Morgan Energy Partners L.P.'s 50%
economic interest in MBA for $41 million in cash and approximately $4 million in
debt assumption. In conjunction with this transaction, the Company will acquire
EPCO's 1% interest in MBA for an undisclosed amount of cash. Upon completion of
this transaction, the Company's ownership interest in the Mont Belvieu
fractionation facility will increase from 37.0% to 62.5%. The parties anticipate
closing this transaction in August 1999.
Isomerization
The profitability of this business unit depends on the volume of normal
butane that the Company isomerizes (i.e., converts) into isobutane for its toll
processing customers, the level of toll processing fees charged to its
customers, and the margins generated from selling isobutane to merchant
customers. The Company's toll processing customers pay the Company a fee for
isomerizing their normal butane into isobutane. In addition, the Company sells
isobutane that it obtains by isomerizing normal butane into isobutane,
fractionating mixed butane into isobutane and normal butane, or purchasing
isobutane in the spot market. The Company determines the optimal sources for
isobutane to meet sales obligations based on current and expected market prices
for isobutane and normal butane, volumes of mixed butane held in inventory, and
estimated costs of isomerization and mixed butane fractionation.
10
The Company purchases most of its imported mixed butanes between the months
of February and October. During these months, the Company is able to purchase
imported mixed butanes at prices that are often at a discount to posted market
prices. Because of its storage capacity, the Company is able to store these
imports until the summer months when the spread between isobutane and normal
butane typically widens or until winter months when the prices of isobutane and
normal butane typically rise. As a result, inventory investment is generally at
its highest level at the end of the third quarter of the year. Should this
spread not materialize, or in the event absolute prices decline, margins
generated from selling isobutane to merchant customers may be negatively
affected.
Propylene Fractionation
The profitability of this business unit depends on the volumes of
refinery-sourced propane/propylene mix that the Company processes for its toll
customers, the level of toll processing fees charged to its customers and the
margins associated with buying refinery-sourced propane/propylene mix and
selling high purity propylene to meet sales contracts with non-tolling
customers.
Pipelines
The Company operates both interstate and intrastate NGL product and
propylene pipelines. The Company's interstate pipelines are common carriers and
must provide service to any shipper who requests transportation services at
rates regulated by the Federal Energy Regulatory Commission ("FERC"). One of the
Company's intrastate pipelines is a common carrier regulated by the State of
Louisiana. The profitability of this business unit is primarily dependent on
pipeline throughput volumes.
Unconsolidated Affiliates
At June 30, 1999, the Company's significant unconsolidated affiliates were
BEF, MBA, EPIK, BRF, Tri-States, Wilprise, and Entell. BEF owns the MTBE
production facility operated by the Company at its Mont Belvieu complex. MBA
owns a 50% interest in a NGL fractionation facility at the Company's Mont
Belvieu complex. EPIK owns a refrigerated NGL marine terminal loading facility
located on the Houston ship channel. An expansion of EPIK's NGL marine terminal
loading facility is under way and is scheduled for completion in the fourth
quarter of 1999. BRF owns a NGL fractionation facility in Louisiana. This
facility is expected to begin operations in August 1999. Tri-States owns a NGL
pipeline in Louisiana, Mississippi, and Alabama which became operational in
March 1999. Wilprise owns a NGL pipeline in Louisiana. Management anticipates
that the Wilprise pipeline will become fully operational in the third quarter of
1999 in conjunction with the startup of the BRF fractionation facility.
Results of Operations
The Company's operating margins by business unit for the three and six
month periods ended June 30, 1998 and 1999 were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
1998 1999 1998 1999
----------------------------------------------------------
Operating Margin:
NGL Fractionation......................... $ 697 $ 726 $ 1,544 $ 1,532
Isomerization............................. 10,808 12,359 13,462 17,996
Propylene Fractionation................... 2,454 6,354 4,466 11,440
Pipeline ................................. 3,772 1,621 7,047 3,715
Storage and Other Plants.................. 3,051 256 3,339 135
==========================================================
Total $20,782 $21,316 $29,858 $34,818
==========================================================
11
The Company's plant production data (in thousands of barrels per day) for
the three and six month periods ended June 30, 1998 and 1999 were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
1998 1999 1998 1999
----------------------------------------------------------
Plant Production Data:
NGL Fractionation 205 166 206 158
Isomerization 67 74 65 71
MTBE 14 15 12 13
Propylene Fractionation 27 31 26 27
The Company's equity in income of unconsolidated affiliates (in thousands)
for the three and six month periods ended June 30, 1998 and 1999 were as
follows:
Three Months ended Six Months ended
June 30, June 30,
1998 1999 1998 1999
------------------------------------------------------------------
BEF $2,381 $1,936 $3,254 $2,237
MBA 1,494 424 3,443 1,184
BRF - (143) - (286)
EPIK (44) (220) (44) 177
Entell - 883 - 1,131
==================================================================
Total $3,831 $2,880 $6,653 $4,443
==================================================================
Three Months Ended June 30, 1999 Compared with Three Months Ended June 30, 1998
Revenues; Costs and Expenses
The Company's revenues decreased by 16% to $174.6 million in 1999 compared
to $207.6 million in 1998. The Company's costs and expenses decreased by 18% to
$153.3 million in 1999 compared to $186.8 million in 1998. Revenues and cost of
goods sold for the second quarter of 1998 were $32.4 million higher than in the
second quarter of 1999 due to higher than normal sales of normal butane and
contained propylene inventories. Excess inventory volumes of these commodities
were sold in anticipation of forecasted declines in NGL prices. In the NGL
industry, revenues and costs and expenses can fluctuate significantly based on
the level of NGL prices without necessarily affecting margin. Operating margin
increased by 2% to $21.3 million in 1999 compared to $20.8 million in 1998.
NGL Fractionation.. The Company's operating margin for NGL fractionation
was $0.7 million for both 1999 and 1998. Excluding the positive effect of $0.5
million in overhead expenses and support facility cost reimbursements from joint
venture partners in 1999, the Company's NGL fractionation operating margin
decreased 71% to $0.2 million in 1999 from $0.7 million in 1998. Average daily
fractionation volumes decreased from 205 MBPD ("thousands of barrels per day")
in 1998 to 166 MBPD in 1999. The lower fractionation rates are attributable to
decreased volumes from joint owners and third party customers stemming partly
from reduced drilling activity (and thus natural gas production) in the
producing regions brought on by a decrease in oil and gas prices and the
short-term diversion of customer volumes to a competitor. The Company fully
expects that the diverted volumes will be recovered in the next six to twelve
months.
Isomerization. The Company's operating margin for isomerization increased
15% to $12.4 million in 1999 compared to $10.8 million in 1998. Isobutane
volumes from tolling and merchant activities for the second quarter of 1999
averaged 107 MBPD as compared to 106 MBPD for the same period in 1998. The
operating margin for 1999 included a $0.7 million benefit from the amortization
of the deferred gain associated with the sale and leaseback of one of the
Company's isomerization units. Excluding this benefit, the operating margin for
1999 would have been $11.7 million as compared to $10.8 million in 1998.
12
Average daily toll processing volumes were 58 MBPD in 1999 compared to 56
MBPD in 1998. Isobutane volumes related to merchant activities were 49 MBPD in
1999 and 1998. Isobutane volumes were slightly higher in the second quarter of
1999 compared to second quarter of 1998 due to increased export volumes and
higher isobutane prices.
Propylene Fractionation. The Company's operating margin increased 156% to
$6.4 million in 1999 from $2.5 million in 1998. Propylene production during the
second quarter averaged 31 MBPD in 1999 as compared to 27 MBPD in 1998. The
earnings improvement was primarily attributable to the Company's actions to
maximize earnings while minimizing price risk in the merchant portion of this
business by matching the volume, timing and price of feedstock purchases with
sales of the product. Earnings also benefited from an increase in production
volumes associated with spot business caused by increased demand for polymer
grade propylene.
Pipeline. The Company's operating margin from pipeline operations was $1.6
million in 1999 compared to $3.8 million in 1998. The decrease in Pipeline
margin for the quarter was primarily attributable to the Company's contribution
of certain wholly-owned pipeline assets, in the first quarter of 1999, and its
export loading facility, in June 1998, to joint ventures in which the Company
owns a 50% interest. As a result, the earnings from these assets since the time
of their contribution are included in equity income from unconsolidated
affiliates as prescribed by the equity method of accounting rather than in
earnings from consolidated Pipeline operations. This change in accounting
treatment accounts for approximately $1.9 million of the decrease. Throughput
for the second quarter of 1999 averaged 189 MBPD as compared to 220 MBPD for the
same period in 1998.
Selling, General and Administrative Expenses
Selling, general and administrative expenses decreased $2.9 million to $3.0
million in 1999 from $5.9 million in 1998. This decrease was primarily due to
the adoption of the EPCO Agreement in July 1998 in conjunction with the
Company's initial public offering ("IPO") which fixed reimbursable selling,
general, and administrative expenses at an initial amount of $1.0 million per
month.
Interest Expense
Interest expense for the second quarter was $1.9 million in 1999 and $4.1
million in 1998. This decrease was principally due to the reduced level of
average debt outstanding during the first quarter of 1999 attributable to the
retirement of debt in July 1998 using proceeds from the Company's IPO.
Equity Income in Unconsolidated Affiliates
Equity income in unconsolidated affiliates was $2.9 million in 1999
compared to $3.8 million in 1998. Equity income from BEF decreased 21% from $2.4
million in 1998 to $1.9 million in 1999. Equity income from BEF in 1999 was
affected by contractual spot sales of MTBE in April 1999 and May 1999 . Equity
income from MBA decreased 73% to $0.4 million in 1999 from $1.5 million in 1998
due to decreased throughput from joint owners and third party customers. Among
the Company's new projects, equity income from Entell was $0.9 million with EPIK
showing a loss of $0.2 million. Equity income from EPIK is seasonal based on
export needs which are at a peak during the September to February time period.
BRF, which is still in the development stage, showed a slight loss of $0.1
million.
13
Six Months Ended June 30, 1999 Compared with Six Months Ended June 30, 1998
Revenues; Costs and Expenses
The Company's revenues decreased by 19% to $321.9 million in 1999 compared
to $398.1 million in 1998. The Company's costs and expenses decreased by 22% to
$287.1 million in 1999 compared to $368.2 million in 1998. Both revenues and
cost of goods sold decreased from 1998 to 1999 due to merchant activities
associated with reductions of excess inventories in 1998 and declines in average
NGL prices. Operating margin increased by 16% to $34.8 million in 1999 compared
to $29.9 million in 1998.
NGL Fractionation. The Company's operating margin for NGL fractionation was
$1.5 million for both 1999 and 1998. Excluding the positive effect of $1.1
million in overhead expenses and support facility cost reimbursements from joint
venture partners in 1999, the Company's NGL fractionation operating margin
decreased 73% to $0.4 million in 1999 from $1.5 million in 1998. Average daily
fractionation volumes decreased from 201 MBPD in 1998 to 180 MBPD in 1999.
Fractionation volumes are lower in 1999 as compared to 1998 due primarily to
ethane rejection, downtime associated with preventative maintenance activities,
lower natural gas production caused by depressed oil and gas prices, and the
short-term diversion of customer volumes to a competitor. During the first
quarter of 1999, natural gas prices remained higher than the energy unit
equivalent of ethane; therefore, upstream natural gas processing plants rejected
ethane which reduced the volumes delivered to Company facilities for
fractionation services. The Company took advantage of the reduced demand for its
fractionation services during the first quarter of 1999 to perform certain
preventative maintenance procedures on one of its fractionation facilities that
are generally required every two to three years. During the second quarter of
1999, volumes were reduced due to the short-term diversion of customer volumes
to a competitor. Management expects that these volumes will be fully recovered
in the next six to twelve months.
Isomerization. The Company's operating margin for isomerization increased
33% to $18.0 million in 1999 compared to $13.5 million in 1998. Isobutane
volumes from tolling and merchant activities for 1999 averaged 101 MBPD as
compared to 99 MBPD for the same period in 1998. The operating margin for 1999
included a $1.3 million benefit from the amortization of the deferred gain
associated with the sale and leaseback of one of the Company's isomerization
units. Excluding this benefit, the operating margin for 1999 would have been
$16.7 million as compared to $13.5 million in 1998.
Average daily toll processing volumes were 57 MBPD in 1999, or 80% of total
volumes produced, compared to 55 MBPD in 1998, or 85% of total volumes produced.
Isobutane volumes related to merchant activities were 44 MBPD in 1999 and 1998.
Isobutane volumes are higher in 1999 compared to 1998 due to increased export
volumes and higher isobutane prices.
Propylene Fractionation. The Company's operating margin increased 153% to
$11.4 million in 1999 from $4.5 million in 1998. Propylene production averaged
27 MBPD in 1999 as compared to 26 MBPD in 1998. The earnings improvement was
primarily attributable to the Company's actions to minimize risk in the merchant
portion of this business by matching the volume, timing and price of feedstock
purchases with sales of end products. The operating margin also benefited from
an increase in production volumes associated with spot business caused by
increased demand for polymer grade propylene.
Pipeline. The Company's operating margin from pipeline operations was $3.7
million in 1999 compared to $7.0 million in 1998. Throughput for 1999 averaged
180 MBPD as compared to 201 MBPD for the same period in 1998. The decrease in
throughput was primarily attributable to a decrease in import volumes. The
decrease in Pipeline margin is principally related to the Company's contribution
of certain wholly-owned pipeline assets, in the first quarter of 1999, and its
export loading facility, in June 1998 to joint ventures in which the Company
owns a 50% interest. As a result, the earnings from these assets since the time
of their contribution are included in equity income from unconsolidated
affiliates as prescribed by the equity method of accounting rather than in
earnings from consolidated pipeline operations. This change in accounting
treatment accounts for $2.8 million of the decrease.
14
Selling, General and Administrative Expenses
Selling, general and administrative expenses decreased $5.6 million to $6.0
million in 1999 from $11.6 million in 1998. This decrease was primarily due to
the adoption of the EPCO Agreement in July 1998 in conjunction with the
Company's initial public offering ("IPO") which fixed reimbursable selling,
general, and administrative expenses at $1.0 million per month.
On July 7, 1999, the Audit and Conflicts Committee of Enterprise Products
GP, LLC (the general partner of the Company) authorized an increase in the
administrative services fee to $1.1 million per month in accordance with the
EPCO Agreement. The increased fees are effective August 1, 1999.
Interest Expense
Interest expense was $4.0 million in 1999 and $10.8 million in 1998. This
decrease was principally due to the reduced level of average debt outstanding
during the first quarter of 1999 attributable to the retirement of debt in July
1998 using proceeds from the Company's IPO.
Equity Income in Unconsolidated Affiliates
Equity income in unconsolidated affiliates was $4.4 million in 1999
compared to $26.7 million in 1998. Equity income from BEF decreased 33% from
$3.3 million in 1998 to $2.2 million in 1999. Equity income from BEF for both
periods was affected by required annual maintenance on the Company's MTBE
facility that generally takes the unit out of production for approximately three
weeks. Equity income from BEF during 1999 also includes a $1.5 million non-cash
charge for the cumulative effect of a change in accounting principal related to
the write-off of deferred start-up costs as prescribed by generally accepted
accounting principles. Equity income from MBA decreased 65% to $1.2 million in
1999 from $3.4 million in 1998 due primarily to decreased throughput caused by
ethane rejection and downtime associated with preventative maintenance
activities. Among the Company's new projects, equity income from EPIK was $0.2
million and Entell was $1.1 million. BRF, which is still in the development
stage, showed a slight loss of $0.3 million.
Financial Condition and Liquidity
General
The Company's primary cash requirements, in addition to normal operating
expenses, are debt service, maintenance capital expenditures, expansion capital
expenditures, and quarterly distributions to the partners. The Company expects
to fund future cash distributions and maintenance capital expenditures with cash
flows from operating activities. Expansion capital expenditures for current
projects are expected to be funded with working capital and borrowings under the
revolving bank credit facility described below while capital expenditures for
future expansion activities are expected to be funded with cash flows from
operating activities and borrowings under the revolving bank credit facility.
Cash flows from operating activities were a $14.2 million inflow for the
first six months of 1999 compared to a $19.1 million outflow for the comparable
period of 1998. Cash flows from operating activities primarily reflect the
effects of net income, depreciation and amortization, extraordinary items,
equity income of unconsolidated affiliates and changes in working capital.
Depreciation and amortization increased by $0.4 million in 1999 as a result of
additional capital expenditures. The net effect of changes in operating accounts
from year to year is generally the result of timing of NGL sales and purchases
near the end of the period.
15
Cash outflows from investing activities were $31.6 million in 1999 and
$13.3 million for the comparable period of 1998. Cash outflows included capital
expenditures of $2.5 million for 1999 and $7.4 million for 1998. Included in the
capital expenditures amounts are maintenance capital expenditures of $0.7
million for 1999 and $3.5 million for 1998. Investing cash outflows in 1999 also
included $40.4 million in advances to and investments in unconsolidated
affiliates versus $14.5 million for the comparable period of 1998. The $25.9
million increase stems primarily from contributions made to the Wilprise,
Tri-States, and BRF joint ventures located in Louisiana. Also, the Company
received $7.4 million in payments on notes receivable from the BEF and MBA notes
purchased during 1998 with the proceeds of the Company's IPO.
Cash flows from financing activities were a $2.8 million outflow in 1999
versus a $13.4 million outflow for the comparable period of 1998. Cash flows
from financing activities are affected primarily by repayments of long-term
debt, borrowings under the long-term debt agreements and distributions to the
partners. Cash flows from financing activities for 1999 also reflected the
purchase of $4.6 million of Common Units by a consolidated trust.
Future Capital Expenditures
The Company currently estimates that its share of remaining expenditures
for significant capital projects in fiscal 1999 will be approximately $14.8
million. These expenditures relate to the construction of joint venture projects
which will be recorded as additional investments in unconsolidated affiliates.
The Company forecasts that an additional $6.7 million will be spent in 1999 on
capital projects that will be recorded as property, plant, and equipment. The
Company expects to finance these expenditures out of operating cash flows and
borrowings under its bank credit facilities. As of June 30, 1999, the Company
had $8.7 million in outstanding purchase commitments attributable to its capital
projects. Of this amount, $6.1 million is associated with significant capital
projects which will be recorded as additional investments in unconsolidated
affiliates for accounting purposes.
Distributions from Unconsolidated Affiliates; Loan Participations
Distributions to the Company from MBA were $1.1 million in 1999 and $1.2
million in 1998. Distributions from BEF in 1999 were $0.3 million versus $1.4
million in 1998. Prior to the first quarter of 1998, BEF was prohibited under
the terms of its bank indebtedness from making distributions to its owners. The
restrictions lapsed during the first quarter of 1998 as a result of BEF having
repaid 50% of the principal on such indebtedness, with the Company receiving its
first distribution from BEF in April 1998. The April 1998 distribution from BEF
included a special one-time disbursement of $1.5 million in debt reserve funds
allowed by its lenders. Distributions from EPIK in 1999 were $1.1 million. EPIK
was formed in the second quarter of 1998 and had no distributions until the
third quarter of 1998.
In connection with the IPO in July 1998, the Company purchased
participation interests in a bank loan to MBA and a bank loan to BEF. The
Company acquired an approximate $7.7 million participation interest in the bank
debt of MBA, which bears interest at a floating rate per annum of LIBOR plus
0.75% and matures on December 31, 2001. The Company is receiving monthly
principal payments, aggregating approximately $1.7 million per year, plus
interest from MBA during the term of the loan. The Company will receive a final
payment of principal and interest of $1.8 million upon maturity. The Company
acquired an approximate $26.1 million participation interest in a bank loan to
BEF, which bears interest at a floating rate per annum at either the bank's
prime rate, CD rate, or the Eurodollar rate plus the applicable margin as
defined in the facility and matures on May 31, 2000. The Company is receiving
quarterly principal payments of approximately $3.3 million plus interest from
BEF during the term of the loan.
Bank Credit Facility
Existing Bank Credit facility. In July 1998, Enterprise Products Operating
L.P. (the "Operating Partnership") entered into a $200.0 million bank credit
facility that includes a $50.0 million working capital facility and a $150.0
million revolving term loan facility. The $150.0 million revolving term loan
facility includes a sublimit of $30.0 million for letters of credit. As of June
30, 1999, the Company has borrowed $145.0 million under the bank credit
facility.
16
The Company's obligations under the bank credit facility are unsecured
general obligations and are non-recourse to the General Partner. Borrowings
under the bank credit facility will bear interest at either the bank's prime
rate or the Eurodollar rate plus the applicable margin as defined in the
facility. The bank credit facility will expire after two years and all amounts
borrowed thereunder shall be due and payable on such date. There must be no
amount outstanding under the working capital facility for at least 15
consecutive days during each fiscal year.
The credit agreement relating to the facility contains a prohibition on
distributions on, or purchases or redemptions of, Units if any event of default
is continuing. In addition, the bank credit facility contains various
affirmative and negative covenants applicable to the ability of the Company to,
among other things, (i) incur certain additional indebtedness, (ii) grant
certain liens, (iii) sell assets in excess of certain limitations, (iv) make
investments, (v) engage in transactions with affiliates and (vi) enter into a
merger, consolidation or sale of assets. The bank credit facility requires that
the Operating Partnership satisfy the following financial covenants at the end
of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined
in the bank credit facility) of at least $257,000,000 plus 75% of the net cash
proceeds from the sale of equity securities of the Company that are contributed
to the Operating Partnership, (ii) maintain a ratio of EBITDA (as defined in the
bank credit facility) to Consolidated Interest Expense (as defined in the bank
credit facility) for the previous 12-month period of at least 3.50 to 1.0 and
(iii) maintain a ratio of Total Indebtedness (as defined in the bank credit
facility) to EBITDA of no more than 2.25 to 1.0.
A "Change of Control" constitutes an Event of Default under the bank credit
facility. A Change of Control includes any of the following events: (i) Dan L.
Duncan (and certain affiliates) cease to own (a) at least 51% (on a fully
converted, fully diluted basis) of the economic interest in the capital stock of
EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to
elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own,
through a wholly owned subsidiary, at least 95% of the outstanding membership
interest in the General Partner and at least 51% of the outstanding Common
Units; (iii) any person or group beneficially owns more than 20% of the
outstanding Common Units; (iv) the General Partner ceases to be the general
partner of the Company or the Operating Partnership; or (v) the Company ceases
to be the sole limited partner of the Operating Partnership.
New Bank Credit facility. On July 28, 1999, the Operating Partnership
entered into a $350.0 million bank credit facility that includes a $50.0 million
working capital facility and a $300.0 million revolving term loan facility. The
$300.0 million revolving term loan facility includes a sublimit of $10.0 million
for letters of credit. The proceeds of this loan will be used principally for
the acquisition of the Tejas assets, the Lou-Tex pipeline, and Kinder Morgan's
interest in the fractionation facility.
Borrowings under the bank credit facility will bear interest at either the
bank's prime rate or the Eurodollar rate plus the applicable margin as defined
in the facility. The bank credit facility will expire after two years and all
amounts borrowed thereunder shall be due and payable on such date. There must be
no amount outstanding under the working capital facility for at least 15
consecutive days during each fiscal year.
The credit agreement relating to the new facility contains a prohibition on
distributions on, or purchases or redemptions of Units if any event of default
is continuing. In addition, the bank credit facility contains various
affirmative and negative covenants applicable to the ability of the Company to,
among other things, (i) incur certain additional indebtedness, (ii) grant
certain liens, (iii) sell assets in excess of certain limitations, (iv) make
investments, (v) engage in transactions with affiliates and (vi) enter into a
merger, consolidation, or sale of assets. The bank credit facility requires that
the Operating Partnership satisfy the following financial covenants at the end
of each fiscal quarter: (i) maintain Consolidated Tangible Net Worth (as defined
in the bank credit facility) of at least $250,000,000, (ii) maintain a ratio of
EBITDA (as defined in the bank credit facility) to Consolidated Interest Expense
(as defined in the bank credit facility) for the previous 12-month period of at
least 3.5 to 1.0 and (iii) maintain a ratio of Total Indebtedness (as defined in
the bank credit facility) to EBITDA of no more than 3.0 to 1.0.
A "Change of Control" constitutes an Event of Default under the bank credit
facility. A Change of Control includes any of the following events: (i) Dan L.
Duncan (and certain affiliates) cease to own (a) at least 51% (on a fully
converted, fully diluted basis) of the economic interest in the capital stock of
EPCO or (b) an aggregate number of shares of capital stock of EPCO sufficient to
elect a majority of the board of directors of EPCO; (ii) EPCO ceases to own,
through a wholly owned subsidiary, at least 65% of the outstanding membership
interest in the General Partner and at least a majority of the outstanding
Common Units; (iii) any person or group beneficially owns more than 20% of the
outstanding Common Units; (iv) the General Partner ceases to be the general
partner of the Company or the Operating Partnership; or (v) the Company ceases
to be the sole limited partner of the Operating Partnership.
17
MTBE Production
The Company owns a 33-1/3% economic interest in the BEF partnership that
owns the MTBE production facility located within the Company's Mont Belvieu
complex. The production of MTBE is driven by oxygenated fuels programs enacted
under the federal Clean Air Act Amendments of 1990 and other legislation. Any
changes to these programs that enable localities to opt out of these programs,
lessen the requirements for oxygenates or favor the use of non-isobutane based
oxygenated fuels reduce the demand for MTBE and could have an adverse effect on
the Company's results of operations.
On March 25, 1999, the Governor of California ordered the phase-out of MTBE
in that state by the end of 2002 due to allegations by several public advocacy
and protest groups that MTBE contaminates water supplies, causes health problems
and has not been as beneficial in reducing air pollution as originally
contemplated. The order also seeks to obtain a waiver of the oxygenate
requirement from the federal Environmental Protection Agency ("EPA") in order to
facilitate the phase-out. In addition, legislation to amend the federal Clean
Air Act of 1990 has been introduced in the U.S. House of Representatives to ban
the use of MTBE as a fuel additive within three years. Legislation introduced in
the U.S. Senate would eliminate the Clean Air Act's oxygenate requirement in
order to assist the elimination of MTBE in fuel. No assurance can be given as to
whether this or similar federal legislation ultimately will be adopted or
whether Congress or the EPA might takes steps to override the MTBE ban in
California.
In November 1998, U.S. EPA Administrator Carol M. Browner appointed a Blue
Ribbon Panel (the "Panel") to investigate the air quality benefits and water
quality concerns associated with oxygenates in gasoline, and to provide
independent advice and recommendations on ways to maintain air quality while
protecting water quality. The Panel issued a report on their findings and
recommendations in July 1999. The Panel urged the widespread reduction in the
use of MTBE due to the growing threat to drinking water sources despite that
fact that use of reformulated gasolines have contributed to significant air
quality improvements. The Panel credited reformulated gasoline with "substantial
reductions" in toxic emissions from vehicles and recommended that those
reductions be maintained by the use of cleaner-burning fuels that rely on
additives other than MTBE and improvements in refining processes. The Panel
stated that the problems associated with MTBE can be characterized as a
low-level, widespread problem that had not reached the state of a being a public
health threat. The Panel's recommendations are geared towards confronting the
problems associated with MTBE now rather than letting the issue grow into a
larger and worse problem. The Panel did not call for an outright ban on MTBE but
stated that its use should be curtailed significantly. The Panel also encouraged
a public educational campaign on the potential harm posed by gasoline when it
leaks into ground water from storage tanks or while in use. Based on the Panel's
recommendations, the EPA will ask Congress for a revision of the Clean Air Act
of 1990 that maintains air quality gains and allows for the removal of the
oxygenate demand in gasoline.
In light of these developments, the Company is formulating a contingency
plan for use of the BEF MTBE facility if MTBE were banned or significantly
curtailed. Management is exploring a possible conversion of the BEF facility
from MTBE production to alkylate production. At present the forecast cost of
this conversion would be in the $15 million to $20 million range. Management
anticipates that if MTBE is banned alkylate demand will rise as producers use it
to replace MTBE as an octane enhancer. Alkylate production would be expected to
generate margins comparable to those of MTBE. Greater alkylate production would
be expected to increase isobutane consumption nationwide and result in improved
isomerization margins for the Company.
Year 2000 Readiness Disclosure
Pursuant to the EPCO Agreement, any selling, general and administrative
expenses related to Year 2000 compliance issues are covered by the annual
administrative services fee paid by the Company to EPCO. Consequently, only
those costs incurred in connection with Year 2000 compliance which relate to
operational information systems and hardware will be paid directly by the
Company.
18
Since 1997, EPCO has been assessing the impact of Year 2000 compliance
issues on the software and hardware used by the Company. A team was assembled to
review and document the status of EPCO's and the Company's systems for Year 2000
compliance. The key information systems reviewed include the Company's pipeline
Supervisory Control and Data Acquisition ("SCADA") system, plant, storage, and
other pipeline operating systems. In connection with each of these areas,
consideration was given to hardware, operating systems, applications, data base
management, system interfaces, electronic transmission, and outside vendors.
Work is nearly complete in all areas except for the SCADA system. Management
anticipates that work on all systems (including SCADA) will be complete by
October 1, 1999.
As of June 30, 1999, EPCO had spent approximately $264,500 in connection
with Year 2000 compliance and has estimated the future costs to approximate
$74,000. This cost estimate does not include internal costs of EPCO's previously
existing resources and personnel that might be partially used for Year 2000
compliance or cost of normal system upgrades which also included various Year
2000 compliance features or fixes. Such internal costs have been determined to
be materially insignificant to the total estimated cost of Year 2000 compliance.
At this time, the Company believes its total cost for known or anticipated
remediation of its information systems to make them Year 2000 compliant will not
be material to its financial position or its ability to sustain operations. As
of June 30, 1999, the Company had incurred expenditures aggregating $154,250 in
connection with Year 2000 compliance. The Company expects future spending to
approximate $871,800 (principally for the SCADA system) to complete the project
and become fully compliant with all Year 2000 issues. This estimated cost does
not include the Company's internal costs related to previously existing
resources and personnel that might be partially used for remediation of Year
2000 compliance issues. Such internal costs have been determined to be
materially insignificant to the total estimated cost of Year 2000 compliance.
These amounts are current cost estimates and actual future costs could
potentially be higher or lower than the estimates.
The Company relies on third-party suppliers for certain systems, products
and services, including telecommunications. There can be no assurance that the
systems of other companies on which the Company's systems rely also will timely
be compliant or that any such failure to be compliant by another company would
not have an adverse effect on the Company's systems. The Company has received
some information concerning Year 2000 compliance status from a group of critical
suppliers and vendors, and anticipates receiving additional information in the
near future. This information will assist the Company in determining the extent
to which it may be vulnerable to those third parties' failure to address their
Year 2000 compliance issues. Based on the responses received to date, the
Company believes that its critical suppliers and vendors will be Year 2000
compliant.
Management believes it has a program to address the Year 2000 compliance
issue in a timely manner. Completion of the plan and testing of replacement or
modified systems is anticipated by October 1, 1999. Nevertheless, since it is
not possible to anticipate all possible future outcomes, especially when third
parties are involved, there could be circumstances in which the Company would be
unable to invoice customers or collect payments. The failure to correct a
material Year 2000 compliance problem could result in an interruption in or
failure of certain normal business activities or operations of the Company. Such
failures could have a material adverse effect on the Company. The amount of
potential liability and lost revenue has not been estimated.
The Company and EPCO have developed a contingency plan to address
unavoidable risks associated with Year 2000 compliance issues. Management has
examined the Year 2000 compliance issue and determined that a worst-case
scenario would be a total, unexpected facility shutdown caused by a disruption
of third-party utilities (principally a total electrical power outage).
Enterprise personnel are trained to respond timely and effectively to such
emergencies; however, because of the uncertainty surrounding the Year 2000
problem, the Company will have additional resources available to assist the
operations, maintenance, and various other groups on December 31, 1999 and
January 1, 2000. The Company will have extra operating, maintenance, process
control, computer support, environmental and safety personnel on site and/or on
standby in the event that a Year 2000 problem arises. The Company and EPCO will
have a defined team of trained personnel available for the rollover into January
1, 2000, so that any disruption to Company or EPCO facilities can handled safely
and so that a return to normal operations can be commenced as soon as is
practicable.
19
Accounting Standards
On June 6, 1999, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS) No. 137, "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date of
FASB Statement No. 133-an amendment of FASB Statement No. 133" which effectively
delays and amends the application of SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" for one year, to fiscal years beginning
after June 15, 2000. Management is currently studying both SFAS No. 137 and SFAS
No. 133 for possible impact on the consolidated financial statements.
On April 3, 1998, the American Institute of Certified Public Accountants
issued Statement of Position ("SOP") 98-5, "Reporting on the Costs of Start-Up
Activities." For years beginning after December 15, 1998, SOP 98-5 generally
requires that all start-up costs of a business activity be charged to expense as
incurred and any start-up costs previously deferred should be written off as a
cumulative effect of a change in accounting principle. Adoption of SOP 98-5
during 1999 did not have a material impact on the consolidated financial
statements except for a $4.5 million noncash write-off that occurred on January
1, 1999 of the unamortized balance of deferred start-up costs of BEF, in which
the Company owns a 33-1/3% interest. This write-off caused a $1.5 million
reduction in the equity in income of unconsolidated affiliates for 1999 and a
corresponding reduction in the Company's investment in unconsolidated
affiliates.
Uncertainty of Forward-Looking Statements and Information.
This quarterly report contains various forward-looking statements and
information that are based on the belief of the Company and the General Partner,
as well as assumptions made by and information currently available to the
Company and the General Partner. When used in this document, words such as
"anticipate," "estimate," "project," "expect," "plan," "forecast," "intend,"
"could," and "may," and similar expressions and statements regarding the plans
and objectives of the Company for future operations, are intended to identify
forward-looking statements. Although the Company and the General Partner believe
that the expectations reflected in such forward-looking statements are
reasonable, they can give no assurance that such expectations will prove to be
correct. Such statements are subject to certain risks, uncertainties, and
assumptions. If one or more of these risks or uncertainties materialize, or if
underlying assumptions prove incorrect, actual results may vary materially from
those anticipated, estimated, projected, or expected. Among the key risk factors
that may have a direct bearing on the Company's results of operations and
financial condition are: (a) competitive practices in the industries in which
the Company competes, (b) fluctuations in oil, natural gas, and NGL product
prices and production, (c) operational and systems risks, (d) environmental
liabilities that are not covered by indemnity or insurance, (e) the impact of
current and future laws and governmental regulations (including environmental
regulations) affecting the NGL industry in general, and the Company's operations
in particular, (f) loss of a significant customer, and (g) failure to complete
one or more new projects on time or within budget.
20
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to financial market risks, including changes in
interest rates with respect to its investments in financial instruments and
changes in commodity prices. The Company may, but generally does not, use
derivative financial instruments (i.e., futures, forwards, swaps, options, and
other financial instruments with similar characteristics) or derivative
commodity instruments (i.e., commodity futures, forwards, swaps, or options, and
other commodity instruments with similar characteristics that are permitted by
contract or business custom to be settled in cash or with another financial
instrument) to mitigate either of these risks. The return on the Company's
financial investments is generally not affected by foreign currency
fluctuations. The Company does not use derivative financial instruments for
speculative purposes. At June 30, 1999, the Company had no derivative
instruments in place to cover any potential interest rate, foreign currency or
other financial instrument risk.
At June 30, 1999, the Company had $4.0 million invested in cash and cash
equivalents. All cash equivalent investments other than cash are highly liquid,
have original maturities of less than three months, and are considered to have
insignificant interest rate risk. The Company's inventory of NGLs and NGL
products at June 30, 1999, was $57.6 million. Inventories are carried at the
lower of cost or market. A 10% adverse change in commodity prices would result
in an approximate $5.8 million decrease in the fair value of the Company's
inventory, based on a sensitivity analysis at June 30, 1999. Actual results may
differ materially. All the Company's long-term debt is at variable interest
rates; a 10% change in the base rate selected would have an approximate $0.7
million effect on the amount of interest expense for the year based upon amounts
outstanding at June 30, 1999.
21
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
*3.1 Form of Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L. P. ( Exhibit 3.1 to Registration
Statement on Form S-1,File No. 333-52537, filed on May 13, 1998).
*3.2 Form of Amended and Restated Agreement of Limited Partnership of
Enterprise Products Operating L.P. (Exhibit 3.2 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*3.3 LLC Agreement of Enterprise Products GP (Exhibit 3.3 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*4.1 Form of Common Unit certificate (Exhibit 4.1 to Registration Statement
on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*4.2 Credit Agreement among Enterprise Products Operating L.P., the Several
Banks from Time to Time Parties Hereto, Den Norske Bank ASA, and Bank
of Tokyo-Mitsubishi, Ltd., Houston Agency as Co-Arrangers, The Bank of
Nova Scotia, as Co-Arranger and as Documentation Agent and The Chase
Manhattan Bank as Co-Arranger and as Agent dated as of July 27, 1998
as Amended and Restated as of September 30, 1998. (Exhibit 4.2 on Form
10-K for year ended December 31, 1998, filed March 17, 1999).
*10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline
Partnership, L.P., Chunchula Pipeline Company, LLC, Propylene Pipeline
Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise Products
Texas Operating L.P. dated June 1, 1998 (Exhibit 10.1 to Registration
Statement on Form S-1/A, File No: 333-52537, filed on July 8, 1998).
*10.2 Form of EPCO Agreement between Enterprise Products Partners L.P.,
Enterprise Products Operating L.P., Enterprise Products GP, LLC and
Enterprise Products Company (Exhibit 10.2 to Registration Statement on
Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*10.3Transportation Contract between Enterprise Products Operating L.P.
and Enterprise Transportation Company dated June 1, 1998 (Exhibit 10.3
to Registration Statement on Form S-1/A, File No. 333-52537, filed on
July 8, 1998).
*10.4Venture Participation Agreement between Sun Company, Inc. (R&M),
Liquid Energy Corporation and Enterprise Products Company dated May 1,
1992 (Exhibit 10.4 to Registration Statement on Form S-1, File No.
333-52537, filed on May 13, 1998).
*10.5Partnership Agreement between Sun BEF, Inc., Liquid Energy Fuels
Corporation and Enterprise Products Company dated May 1, 1992 (Exhibit
10.5 to Registration Statement on Form S-1, File No. 333-52537, filed
on May 13, 1998).
22
*10.6Amended and Restated MTBE Off-Take Agreement between Belvieu
Environmental Fuels and Sun Company, Inc. (R&M) dated August 16, 1995
(Exhibit 10.6 to Registration Statement on Form S-1, File No.
333-52537, filed on May 13, 1998).
*10.7Articles of Partnership of Mont Belvieu Associates dated July 17, 1985
(Exhibit 10.7 to Registration Statement on Form S-1, File No.
333-52537, filed on May 13, 1998).
*10.8First Amendment to Articles of Partnership of Mont Belvieu Associates
dated July 15, 1996 (Exhibit 10.8 to Registration Statement on Form
S-1, File No. 333-52537, filed on May 13, 1998).
*10.9Propylene Facility and Pipeline Agreement between Enterprise
Petrochemical Company and Hercules Incorporated dated December 13,
1978 (Exhibit 10.9 to Registration Statement on Form S-1, File No.
333-52537, dated May 13, 1998).
*10.10 Restated Operating Agreement for the Mont Belvieu Fractionation
Facilities Chambers County, Texas between Enterprise Products Company,
Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin
Petroleum Company dated July 17, 1985 (Exhibit 10.10 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 8, 1998).
*10.11 Ratification and Joinder Agreement relating to Mont Belvieu
Associates Facilities between Enterprise Products Company, Texaco
Producing Inc., El Paso Hydrocarbons Company, Champlin Petroleum
Company and Mont Belvieu Associates dated July 17, 1985 (Exhibit 10.11
to Registration Statement on Form S-1/A, File No. 333-52537, filed on
July 8, 1998).
*10.12Amendment to Propylene Facility and Pipeline Sales Agreement between
HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1,
1993 (Exhibit 10.12 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.13Amendment to Propylene Facility and Pipeline Agreement between HIMONT
U.S.A., Inc. and Enterprise Products Company dated January 1, 1995
(Exhibit 10.13 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
27.1 Financial Data Schedule
* Asterisk indicates exhibits incorporated by reference as indicated
23
(b) Reports on Form 8-K
One report on Form 8-K was filed during the second quarter of 1999.
Form 8-K dated April 20, 1999, reporting that the Company announced
the general terms of an agreement to form a major NGL alliance with
Tejas Energy ("Tejas"), an affiliate of Shell Oil Company ("Shell").
Under the terms of the alliance Shell will contribute its ownership
interests in its natural gas processing, NGL fractionation, NGL
storage and NGL transportation assets in Mississippi and Louisiana to
the Company in exchange for an equity interest in the Company and
other consideration. The completion of this transaction would form a
strategic business combination comprising a fully integrated Gulf
Coast NGL processing, fractionation, storage and transportation
business. It also establishes a strategic alliance between the Company
and Shell whereby the Company would have the rights to process Shell's
current and future Gulf of Mexico natural gas production and market
the NGLs recovered.
All of Tejas' NGL assets in Louisiana and Mississippi are included
under the terms of the combination. This includes its varying
interests in 11 natural gas processing plants (including one under
construction) with a combined gross capacity of approximately 11
billion cubic feet per day; four NGL fractionation facilities with a
combined gross capacity of approximately 240,000 barrels per day; NGL
storage facilities with approximately 29 million barrels of gross
capacity; and over 1,800 miles of NGL pipelines (including an interest
in the Dixie Pipeline).
The transaction is subject to the Company and Tejas successfully
executing a definitive agreement; satisfactorily completing their
respective due diligence reviews; receiving requisite regulatory
approvals and receiving approvals from each company's board of
directors. The parties anticipate closing of the transaction to occur
by the end of the third quarter of 1999.
24
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Enterprise Products Partners L.P.
(A Delaware Limited Partnership)
By: Enterprise Products GP, LLC
as General Partner
Date: August 9, 1999 By: /s/ Gary L. Miller
_____________________________________
Executive Vice President
Chief Financial Officer and Treasurer
25