FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 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 November 15,
1999.
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Enterprise Products Partners L.P. and Subsidiaries
TABLE OF CONTENTS
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Page
No.
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Part I. Financial Information
Item 1. Consolidated Financial Statements
Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets, September 30, 1999 and December 31, 1998 1
Statements of Consolidated Operations
for the Three and Nine Months ended September 30, 1999 and 1998 2
Statements of Consolidated Cash Flows
for the Nine Months ended September 30, 1999 and 1998 3
Notes to Unaudited Consolidated Financial Statements 4-12
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 13-27
Item 3. Quantitative and Qualitative Disclosures about Market Risk 27-28
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K 29-32
Signature Page 33
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PART 1. FINANCIAL INFORMATION.
Item 1. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Amounts in thousands)
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September 30,
December 31, 1999
ASSETS 1998 (Unaudited)
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Current Assets
Cash and cash equivalents $ 24,103 $ 21,647
Accounts receivable - trade 57,288 187,615
Accounts receivable - affiliates 15,546 50,562
Inventories 17,574 102,992
Current maturities of participation in notes receivable from
unconsolidated affiliates 14,737 9,778
Prepaid and other current assets 8,445 11,283
-------------------------------------
Total current assets 137,693 383,877
Property, Plant and Equipment, Net 499,793 772,157
Investments in and Advances to Unconsolidated Affiliates 91,121 235,864
Participation in Notes Receivable from Unconsolidated Affiliates 11,760
Intangible assets, net of amortization of $702 79,187
Other Assets 670 1,515
=====================================
Total $ 741,037 $ 1,472,600
=====================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of long-term debt $ 175,000
Accounts payable - trade $ 36,586 139,851
Accrued gas payables 27,183 143,397
Accrued expenses 7,540 13,071
Other current liabilities 11,462 15,017
-------------------------------------
Total current liabilities 82,771 486,336
Long-Term Debt 90,000 215,000
Other Long-Term Liabilities 539
Minority Interest 5,730 7,801
Commitments and Contingencies
Partners' Equity
Common Units (45,552,915 Units outstanding at December 31, 1998 and
September 30, 1999) 433,082 417,651
Subordinated Units (21,409,870 Units outstanding at December 31, 1998 and 123,829 126,496
September 30, 1999)
Special Units (14,500,000 Units outstanding at September 30, 1999) 215,828
Units acquired by Trust, at cost (267,200 Units outstanding at September 30, 1999) (4,727)
General Partner 5,625 7,676
-------------------------------------
Total Partners' Equity 562,536 762,924
=====================================
Total $ 741,037 $ 1,472,600
=====================================
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See Notes to Unaudited Consolidated Financial Statements
1
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Enterprise Products Partners L.P.
Statements of Consolidated Operations
(Unaudited, Amounts in thousands, except per Unit amounts)
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Three Months Ended Nine Months Ended
September 30, September 30,
1998 1999 1998 1999
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REVENUES
Revenues from consolidated operations $ 164,620 $ 441,880 $ 562,703 $ 763,793
Equity income in unconsolidated affiliates 4,171 3,148 10,824 7,591
--------------------------------------------------------------------
Total 168,791 445,028 573,527 771,384
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COST AND EXPENSES
Operating costs and expenses 153,197 401,155 521,428 688,250
Selling, general and administrative 3,751 3,200 15,362 9,200
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Total 156,948 404,355 536,790 697,450
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OPERATING INCOME 11,843 40,673 36,737 73,934
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OTHER INCOME (EXPENSE)
Interest expense (2,500) (4,036) (13,304) (7,995)
Interest income from unconsolidated affiliates 340 407 340 1,096
Interest income - other 85 682 645 1,114
Other, net 34 (1,010) 464 (1,522)
--------------------------------------------------------------------
Other income (expense) (2,041) (3,957) (11,855) (7,307)
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INCOME BEFORE EXTRAORDINARY ITEM
AND MINORITY INTEREST 9,802 36,716 24,882 66,627
Extraordinary charge on early extinguishment of debt (27,176) (27,176)
--------------------------------------------------------------------
INCOME (LOSS) BEFORE MINORITY INTEREST (17,374) 36,716 (2,294) 66,627
MINORITY INTEREST 174 (370) 23 (672)
====================================================================
NET INCOME (LOSS) $ (17,200) $ 36,346 $ (2,271) $ 65,955
====================================================================
ALLOCATION OF NET INCOME (LOSS) TO:
Limited partners $ (17,028) $ 35,983 $ (2,248) $ 65,295
====================================================================
General partner $ (172) $ 363 $ (23) $ 660
====================================================================
Number of Units Used in Computing
Basic Earnings per Common Unit 63,441 66,696 57,830 66,715
====================================================================
BASIC EARNINGS PER COMMON UNIT
Income before extraordinary item and
minority interest per common unit $ 0.15 $ 0.54 $ 0.43 $ 0.99
====================================================================
Net income (loss) per common unit $ (0.27) $ 0.54 $ (0.04) $ 0.98
====================================================================
Number of Units Used in Computing
Diluted Earnings per Common Unit 63,441 76,310 57,830 69,955
====================================================================
DILUTED EARNINGS PER COMMON UNIT
Income before extraordinary item and
minority interest per common unit $ 0.15 $ 0.48 $ 0.43 $ 0.94
====================================================================
Net income (loss) per common unit $ (0.27) $ 0.47 $ (0.04) $ 0.93
====================================================================
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
2
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Enterprise Products Partners L.P
Statements of Consolidated Cash Flows
(Unaudited, Dollars in Thousands)
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Nine Months Ended
September 30,
1998 1999
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OPERATING ACTIVITIES
Net income (loss) ($2,271) $65,955
Adjustments to reconcile net income (loss) to cash flows provided by
(used for) operating activities:
Extraordinary item - early extinguishment of debt 27,176
Depreciation and amortization 14,796 17,280
Equity in income of unconsolidated affiliates (10,824) (7,591)
Leases paid by EPCO 3,327 7,918
Minority interest (23) 672
(Gain) loss on sale of assets (274) 122
Net effect of changes in operating accounts (75,824) (34,246)
-----------------------------
Operating activities cash flows (43,917) 50,110
-----------------------------
INVESTING ACTIVITIES
Capital expenditures (7,159) (10,603)
Proceeds from sale of assets 1,890 8
Acquisitions (208,095)
Participation in notes receivable from unconsolidated affiliates:
Purchase of notes receivable (33,724)
Collection of notes receivable 3,542 16,719
Unconsolidated affiliates:
Investments in and advances to (19,988) (58,460)
Distributions received 6,601 4,607
-----------------------------
Investing activities cash flows (48,838) (255,824)
-----------------------------
FINANCING ACTIVITIES
Net proceeds from sale of common units 243,309
Long-term debt borrowings 75,000 350,000
Long-term debt repayments (256,493) (59,923)
Net decrease in restricted cash 4,522
Cash dividends paid to partners (81,321)
Cash dividends paid to minority interest (830)
Units acquired by consolidated trusts (4,727)
Cash contributions from EPCO to minority interest 59
-----------------------------
Financing activities cash flows 66,338 203,258
-----------------------------
CASH CONTRIBUTIONS FROM EPCO 18,468
NET CHANGE IN CASH AND CASH EQUIVALENTS (7,949) (2,456)
CASH AND CASH EQUIVALENTS, JANUARY 1 18,941 24,103
=============================
CASH AND CASH EQUIVALENTS, SEPTEMBER 30 $ 10,992 $ 21,647
=============================
</TABLE>
See Notes to Unaudited Consolidated Financial Statements
3
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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 September 30, 1999, consolidated
results of operations for the three and nine month periods ended September 30,
1999 and 1998, and its consolidated cash flows for the nine month periods ended
September 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 nine month periods ended September
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 September 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 located in
southeast Texas.
Baton Rouge Fractionators LLC ("BRF") - a 31.25% economic interest in
a natural gas liquid ("NGL") fractionation facility located in
southeastern Louisiana.
Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% economic
interest in a propylene concentration unit located in southeastern
Louisiana which is under construction and scheduled to become
operational in the third quarter of 2000.
EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively,
"EPIK") - a 50% aggregate economic interest in a refrigerated NGL
marine terminal loading facility located in southeast Texas.
Wilprise Pipeline Company, LLC ("Wilprise") - a 33-1/3% economic
interest in a NGL pipeline system located in southeastern Louisiana.
Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33-1/3%
economic interest in a NGL pipeline system located in Louisiana,
Mississippi, and Alabama. In connection with the Tejas Natural Gas
Liquids, LLC ("TNGL") acquisition (discussed in Note 3) the Company
acquired an additional 16-2/3% interest bringing the total investment
in Tri-States to the current 33-1/3%.
Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.7% economic interest
in a NGL pipeline system located in south Louisiana. The Company's
interest in Belle Rose was acquired in connection with the TNGL
acquisition which is discussed in Note 3.
4
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K/D/S Promix LLC ("Promix") - a 33-1/3% economic interest in a NGL
fractionation facility and related storage facilities located in south
Louisiana. The Company's interest in Promix was acquired in connection
with the TNGL acquisition which is discussed in Note 3.
The Company's investments in and advances to unconsolidated affiliates also
includes Venice Energy Services Company, LLC ("VESCO") and Dixie Pipeline
Company ("Dixie"). The VESCO investment consists of a 13.1% economic interest in
a LLC owning a natural gas processing plant, fractionation facilities, storage,
and gas gathering pipelines in Louisiana. The Dixie investment consists of an
11.5% interest in a corporation owning a 1,300-mile propane pipeline and the
associated facilities extending from Mont Belvieu, Texas to North Carolina.
These investments are accounted for using the cost method in accordance with
generally accepted accounting principles.
Effective July 1, 1999, a subsidiary of Enterprise Products Operating L.P. (the
"Operating Partnership") acquired the remaining 51% economic interest of Mont
Belvieu Associates ("MBA") from Kinder Morgan Energy Partners L.P. ("Kinder
Morgan") and Enterprise Products Company ("EPCO") (see Note 3 for a general
discussion regarding this acquisition). As a consequence, the results of
operations since July 1, 1999 are included in consolidated operations. The 49%
economic interest in income of MBA held by the Company prior to the acquisition
was recorded as equity income.
In conjunction with the acquisition of TNGL from Tejas Energy, LLC ("Tejas
Energy") effective August 1, 1999, the Company currently owns 100% of the
economic interest in Entell NGL Services, LLC ("Entell") (see Note 3 for a
general discussion regarding the TNGL acquisition). As a result, Entell is now a
wholly-owned subsidiary of the Operating Partnership. The Operating
Partnership's 50% economic interest in the income of Entell prior to the
acquisition has been recorded as equity income.
Investments in and advances to unconsolidated affiliates at:
December 31, September 30,
1998 1999
-----------------------------------
BEF $ 50,079 $ 56,493
MBA 12,551
BRF 17,896 34,656
BRPC 8,400
EPIK 5,667 12,974
Wilprise 4,873 8,063
Tri-States 55 28,324
Promix 29,590
Dixie 20,000
VESCO 25,000
Belle Rose 12,364
===================================
Total $ 91,121 $ 235,864
===================================
5
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Equity in income of unconsolidated affiliates for the:
Three Months ended Nine Months ended
September 30, September 30,
1998 1999 1998 1999
------------------------------------------------------------------
BEF $ 3,355 $ 2,519 $ 6,609 $ 4,756
MBA 862 72 4,305 1,256
BRF (258) (544)
BRPC 4 4
EPIK (46) 59 (90) 236
Entell 258 1,389
Wilprise (130) (130)
Tri-States 472 472
Belle Rose 245 245
Promix (93) (93)
==================================================================
Total $ 4,171 $ 3,148 $ 10,824 $ 7,591
==================================================================
3. ACQUISITIONS
Acquisition of Tejas Natural Gas Liquids, LLC
Effective August 1, 1999, the Company acquired TNGL from a subsidiary of Tejas
Energy, an affiliate of Shell Oil Company ("Shell"). TNGL engages in natural gas
processing and NGL fractionation, transportation, storage and marketing in
Louisiana and Mississippi. TNGL's assets include a 20-year natural gas
processing agreement with Shell for the rights to process its current and future
natural gas production from the state and federal waters of the Gulf of Mexico
and varying interests in eleven natural gas processing plants (including one
under construction) with a combined gross capacity of 11.0 billion cubic feet
per day (Bcfd) and a net capacity of 3.1 Bcfd; four NGL fractionation facilities
with a combined gross capacity of 281,000 barrels per day (BPD) and net capacity
of 131,500 BPD; four NGL storage facilities with approximately 29.5 million
barrels of gross capacity and 8.8 million barrels of net capacity; and over
2,100 miles of NGL pipelines (including an 11.5% interest in Dixie Pipeline).
As discussed in Note 5, the TNGL acquisition was purchased with a combination of
$166 million in cash and 14.5 million issuance of non-distribution bearing
convertible Special Units. The $166 million cash portion of the purchase price
was funded with borrowings under the Company's new $350 million bank credit
facility led by The Chase Manhattan Bank. The Special Units were valued within a
range provided by an independent investment banker using both present value and
Black Scholes Model methodologies. The consideration for the acquisition was
determined by arms-length negotiation among the parties.
The acquisition was accounted for under the purchase method of accounting and,
accordingly, the purchase price has been allocated to the assets acquired and
liabilities assumed based on their estimated fair value at August 1, 1999 as
follows:
Current Assets $127.5
Investments 97.7
Property, net 225.8
Intangible asset 71.1
Liabilities (145.7)
==========
Total purchase price $ 376.3
==========
6
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The $71.1 million intangible asset is associated with the 20-year natural gas
processing agreement with Shell ("Shell Contract") and is being amortized over a
period of 20 years, approximating the life of the agreement. For the quarter
ending September 30, 1999, approximately $0.6 million of such amortization was
charged to expense. The assets, liabilities and results of operations of TNGL
are included with those of the Company as of August 1, 1999. Historical
information for periods prior to August 1, 1999 do not reflect any impact
associated with the TNGL acquisition.
As described in Note 5, Tejas Energy has the opportunity to earn an additional
6.0 million non-distribution bearing, convertible special Contingency Units over
the next two years upon the achievement of certain gas production thresholds
under the Shell Contract. If such special Contingency Units are issued, the
purchase price will be adjusted accordingly.
Acquisition of Kinder Morgan and EPCO interest in Mont Belvieu Fractionation
Facility
Effective July 1, 1999, the Company acquired Kinder Morgan Energy Partners
L.P.'s ("Kinder Morgan") 25% indirect ownership interest and EPCO's 0.5%
indirect ownership interest in a 210,000 BPD NGL fractionation facility located
in Mont Belvieu, Texas for approximately $41 million in cash and the assumption
of approximately $ 4 million of debt. The $41 million in cash was funded with
borrowings under the Company's new $350 million bank credit facility led by The
Chase Manhattan Bank.
The acquisition was accounted for under the purchase method of accounting and,
accordingly, the purchase price has been allocated to the assets purchased and
liabilities assumed based on their estimated fair value at July 1, 1999 as
follows:
Property, net $36.3
Intangible asset 8.7
Liabilities (3.8)
==========
Total purchase price $ 41.2
==========
The intangible asset represents the excess cost of purchase price over the fair
market value of the assets acquired and is being amortized over 20 years. For
the quarter ending September 30, 1999, approximately $0.1 million of such
amortization was charged to expense.
Prior to this transaction, the Company held a 25% indirect and a 12.5% direct
ownership interest in the fractionation facility. The indirect ownership
interests of the Company, Kinder Morgan and EPCO were held through MBA. Prior to
the acquisition, the 12.5% direct ownership interest and the 49% equity
ownership of MBA were held by Enterprise Products Texas Operating L.P.
("EPTexas"). Upon completion of the transaction, EPTexas held 100% of MBA and,
as a result, MBA was merged into EPTexas. The net assets and results of
operations of MBA are included with those of EPTexas beginning with the July 1,
1999 acquisition date. Historical information for periods prior to July 1, 1999
does not reflect any impact associated with the acquisition of the Mont Belvieu
Fractionation Facility. The Company's equity in the earnings of MBA prior to
July 1, 1999 is included in equity in income of unconsolidated affiliates.
Pro Forma Financial Information
The balances included in the consolidated balance sheets related to the current
year acquisitions are based upon preliminary information and are subject to
change as additional information is obtained. Material changes in the
preliminary allocations are not anticipated by management.
The following pro forma information gives effect to the acquisition of TNGL and
MBA as if the business combination had occurred at the beginning of each period
presented. The pro forma adjustments which have been made are based on the
preliminary allocation of the purchase price to assets acquired and liabilities
7
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assumed. This pro forma information should be read in conjunction with the
accompanying interim Consolidated Financial Statements, Management's Discussion
and Analysis of Financial Condition and Results of Operations. This pro forma
information is not necessarily indicative of the financial results which would
have occurred had the acquisition taken place on the dates indicated, nor is it
necessarily indicative of future financial results.
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Three Months Ended Nine Months Ended
(Amounts in millions) September 30, September 30,
1998 1999 1998 1999
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Unaudited Pro Forma Financial Information
Revenues $ 282.6 $ 505.7 $ 1,043.9 $ 1,153.7
Income before extraordinary items 0.6 40.8 29.0 78.0
Net Income (26.6) 40.8 1.9 78.0
Earnings per Unit:
Basic $ (0.40) $ 0.61 $ 0.03 $ 1.17
Diluted $ (0.33) $ 0.50 $ 0.02 $ 0.96
</TABLE>
4. LONG-TERM DEBT
Existing Bank Credit facility. In July 1998, the Operating Partnership entered
into a $200.0 million bank credit facility ("Bank Revolver A") 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 September 30, 1999, the Company has
borrowed $175.0 million under the bank credit facility which is due in July
2000. Management is currently exploring options to convert this short-term debt
into long-term debt.
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 in July 2000 and all amounts borrowed thereunder
shall be due and payable at that time. There must be no amount outstanding under
the working capital facility for at least 15 consecutive days during each fiscal
year.
As amended on July 28, 1999, the existing 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 $250.0 million,
(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/or 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 (excluding certain affiliates of EPCO or Shell Oil
Company); (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 ("Bank Revolver B") that includes a
8
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$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 were used to
finance the acquisition of TNGL and the MBA ownership interests. Future uses of
the remaining credit line include the purchase of the Lou-Tex pipeline (see Note
10).
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 in July 2001 and all
amounts borrowed thereunder shall be due and payable at that time. 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 $250.0 million, (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/or 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 (excluding certain affiliates of EPCO and Shell Oil
Company); (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.
Long-term debt consisted of the following:
September 30,
December 31, 1999
1998 (Unaudited)
-------------------------------------
Bank Revolver A $90,000 $175,000
Bank Revolver B 215,000
-------------------------------------
Total 90,000 390,000
Less current maturities of long-term debt (175,000)
=====================================
Long-term debt $90,000 $215,000
=====================================
5. CAPITAL STRUCTURE
At September 30, 1999, the Company had 33,552,915 Common Units and 21,409,870
Subordinated Units outstanding held by EPCO (the Company's ultimate parent),
12,000,000 Common Units outstanding held by third parties, and 14,500,000
non-distribution bearing, convertible Special Units held by Tejas Energy. During
the first quarter of 1999, the Company established a revocable grantor trust
(the "Trust") to fund future liabilities of a long-term incentive plan. At
September 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.
9
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On August 1, 1999, in exchange for its NGL business (see Note 3), Tejas Energy
received 14.5 million non-distribution bearing, convertible Special Units in the
Company and $166 million in cash. The 14.5 million non-distribution bearing,
convertible Special Units received by Tejas Energy represent an approximate
17.6% equity ownership in the Company. These convertible Special Units do not
accrue distributions and are not entitled to cash distributions until their
conversion into Common Units, which occurs automatically with respect to 1.0
million Units on August 1, 2000 (or the day following the record date for
determining units entitled to receive distributions in the second quarter of
2000), 5.0 million Units on August 1, 2001 and 8.5 million Units on August 1,
2002.
Tejas Energy has the opportunity to earn an additional 6 million
non-distribution bearing, convertible Contingency Units over the next two years
based on certain performance criteria. Shell will earn 3 million convertible
Contingency Units if at any point during calendar year 2000 (or extensions
thereto due to force majeure events), gas production by Shell from its offshore
Gulf of Mexico producing properties and leases is 950 million cubic feet per day
for 180 not-necessarily-consecutive days or 375 billion cubic feet on a
cumulative basis. Shell will earn another 3 million convertible Contingency
Units if at any point during calendar year 2001 (or extensions thereto due to
force majuere events) such gas production is 900 million cubic feet per day for
180 not-necessarily-consecutive days or 350 billion cubic feet on a cumulative
basis. If either or both of the preceding performance tests is not met but
Shell's Offshore Gulf of Mexico gas production reaches 725 billion cubic feet on
a cumulative basis in calendar years 2000 and 2001 (or extensions thereto due to
force majuere events), Shell would still earn 6 million non-distribution
bearing, convertible Contingency Units. If all of the Contingency Units are
earned, 1 million Contingency Units would convert into Common Units on August 1,
2002 and 5 million Contingency Units would convert into Common Units on August
1, 2003. The Contingency Units do not accrue distributions and are not entitled
to cash distributions until conversion into Common Units. Tejas Energy's
ownership interest in the Company would then increase to approximately 23.2%.
Under the rules of the New York Stock Exchange, conversion of the Special Units
into Common Units requires approval of the Company's Unitholders. The General
Partner has agreed to call a special meeting of the Unitholders for the purpose
of soliciting such approval. EPC Partners II, Inc. ("EPC II"), which owns in
excess of 81% of the outstanding Common Units, has agreed to vote its Units in
favor of such approval, which will satisfy the approval requirement.
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 was paid on August 11, 1999 to Common Unitholders of
record on July 30, 1999. The third quarter 1999 distribution of $.45 per Unit
was declared on October 15, 1999 and was paid on November 10, 1999 to all
Unitholders of record at the close of business on October 29, 1999.
10
<PAGE>
7. SUPPLEMENTAL CASH FLOW DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows:
Nine Months Ended
September 30,
1998 1999
--------------------------------
(Increase) decrease in:
Accounts receivable $ 19,879 $ (48,448)
Inventories (41,985) (64,992)
Prepaid and other current assets (550) (4,647)
Other assets (494) (1,757)
Increase (decrease) in:
Accounts payable - trade (27,255) 43,944
Accrued gas payable (8,437) 61,474
Accrued expenses (4,503) 1,236
Other current liabilities (12,479) (21,595)
Other liabilities 539
================================
Net effect of changes in operating accounts $ (75,824) $ (34,246)
================================
8. 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.
9. CONCENTRATION OF CREDIT RISK
A substantial portion of the Company's revenues are derived from natural gas
processing and the fractionation, isomerization, propylene production,
marketing, storage and transportation of NGLs to various companies in the NGL
industry, primarily located in the United States. Although this concentration
could affect the Company's overall exposure to credit risk since these customers
might be affected by similar economic or other conditions, management believes
the Company is exposed to minimal credit risk, since the majority of its
business is conducted with major companies within the industry and much of the
business is conducted with companies with whom the Company has joint operations.
The Company generally does not require collateral for its accounts receivable.
11
<PAGE>
The Company is subject to a number of risks inherent in the industry in which it
operates, primarily fluctuating gas and liquids prices and gas supply. The
Company's financial condition and results of operations will depend
significantly on the prices received for NGLs and the price paid for gas
consumed in the NGL extraction process. These prices are subject to fluctuations
in response to changes in supply, market uncertainty and a variety of additional
factors that are beyond the control of the Company. In addition, the Company
must continually connect new wells through third-party gathering systems which
serve the gas plants in order to maintain or increase throughput levels to
offset natural declines in dedicated volumes. The number of wells drilled by
third parties 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 the Company's control.
10. SUBSEQUENT EVENT
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, 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. The acquisition of the Lou-Tex
pipeline is the first step in the Company's development of a $210 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 purchase of the pipeline asset from Concha is
expected to be completed in the fourth quarter of 1999. The development of the
expanded Lou-Tex gas liquids pipeline system is expected to be completed in the
second half of 2000.
12
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.
For the Interim Periods ended September 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. As a result of the
recent Tejas Natural Gas Liquids, LLC ("TNGL") acquisition described below, the
Company is also engaged in natural gas processing in Louisiana and Mississippi.
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) processes natural gas; (ii) 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; (iii) converts normal butane to isobutane through the process of
isomerization; (iv) produces MTBE from isobutane and methanol; and (v)
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 NGL processing operations are concentrated in the Texas,
Louisiana, and Mississippi Gulf Coast area. A large portion is 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 we operate 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 80,000 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 62.5% economic interest (see Recent
Acquisitions 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
13
<PAGE>
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.
As a result of the Tejas Natural Gas Liquids, LLC ("TNGL") acquisition, the
Company acquired, effective August 1, 1999, a 20-year natural gas processing
agreement with Shell Oil Company ("Shell") for the rights to process its current
and future natural gas production from the state and federal waters of the Gulf
of Mexico and varying interests in 11 natural gas processing plants (including
one under construction) with a combined gross capacity of 11.0 billion cubic
feet per day ("Bcfd") and net capacity of 3.1 Bcfd; four NGL fractionation
facilities with a combined gross capacity of 281,000 BPD and net capacity of
131,500 BPD; four NGL storage facilities with approximately 29.5 million barrels
of gross capacity and 8.8 million barrels of net capacity; and over 2,100 miles
of NGL pipelines (including a 11.5% interest in Dixie Pipeline).
Recent Acquisitions
Tejas Natural Gas Liquids, LLC. As noted above, effective August 1, 1999,
the Company acquired TNGL from Tejas Energy, LLC ("Tejas Energy"), an affiliate
of Shell, in exchange for 14.5 million non-distribution bearing, convertible
special partner units of the Company and a cash payment of $166 million. The
Company has also agreed to issue up to 6.0 million non-distribution bearing,
convertible special units to Tejas Energy in the future if the volumes of
natural gas that the Company processes for Shell and its affiliates reach
certain agreed upon levels in 2000 and 2001. The businesses acquired from Tejas
Energy include natural gas processing and NGL fractionation, transportation and
storage in Louisiana and Mississippi and its NGL supply and marketing business.
As described in General above, the assets acquired include varying interests in
11 natural gas processing plants, four NGL fractionation facilities, four NGL
storage facilities and over 2,100 miles of NGL pipelines.
The Company's major customer related to the TNGL assets is Shell. Under the
terms of a 20-year processing agreement with Shell, the Company has the right to
process substantially all of Shell's current and future natural gas production
from the Gulf of Mexico. This includes natural gas production from the
developments currently referred to as deepwater.
Natural gas processing plants are generally located near the production
area. When produced at the wellhead, natural gas generally must be processed to
separate the merchantable, pipeline quality natural gas (principally methane),
from NGLs and other impurities. Wet or rich natural gas normally must be
processed to render the natural gas acceptable for transport in the nation's
pipeline system and to meet specifications required by local natural gas
distribution companies. After being extracted in the field, mixed NGLs,
sometimes referred to as "y-grade" or "raw make" are typically transported to a
central facility for fractionation and subsequent sale.
Mont Belvieu NGL Fractionation facility. Effective July 1, 1999, a
subsidiary of the Operating Partnership acquired an additional 25% interest in
the Mont Belvieu NGL fractionation facility from Kinder Morgan for a purchase
price of approximately $41 million in cash and the assumption of $4 million in
debt. An additional 0.5% interest in the same facility was purchased from EPCO
for a cash purchase price of $0.9 million. These acquisitions increased our
effective economic interest in the Mont Belvieu NGL fractionation facility from
37.0% to 62.5%.
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.
14
<PAGE>
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.
Effective July 1, 1999, the Company's ownership interest in the Mont
Belvieu NGL fractionation facility increased to an effective 62.5% from 37.0%.
Since the acquisition, the Company's 62.5% interest in the results of operations
of the fractionation facility have been included in consolidated operations.
Prior to the acquisition, the Company's 12.5% direct economic interest was
included in consolidated operations, and its effective 24.5% economic interest
was recorded as equity income.
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.
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
15
<PAGE>
must provide service to any shipper who requests transportation services at
rates regulated by the Federal Energy Regulatory Commission ("FERC"). The
Company's intrastate common carrier pipelines are regulated by the State of
Louisiana. The profitability of this business unit is primarily dependent on
pipeline throughput volumes.
Gas Processing
As a result of the TNGL acquisition, the Company is now engaged in natural
gas processing in Louisiana and Mississippi via ownership interests in eleven
plants. The profitability of the natural gas processing plants is primarily
dependent on the volume of NGLs extracted from the natural gas streams and the
pricing of NGLs and natural gas in the marketplace.
Unconsolidated Affiliates
At September 30, 1999, the Company's significant unconsolidated affiliates
accounted for using the equity method were BEF, BRF, BRPC, EPIK, Wilprise,
Tri-States, Belle Rose, and Promix. BEF owns the MTBE production facility
operated by the Company at its Mont Belvieu complex. BRF owns a NGL
fractionation facility in southeastern Louisiana that began operations in the
third quarter of 1999. BRPC is a newly-formed joint venture (August 1999)
between the Operating Partnership and Exxon Chemical Company ("Exxon") which
owns a propylene concentration unit under construction in southeastern
Louisiana. The Company holds a 30% economic interest in BRPC. Management
anticipates that operations will commence at this plant in the third quarter of
2000. 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. Wilprise owns a NGL pipeline in Louisiana which started operations in the
third quarter of 1999 in conjunction with the start-up of the BRF fractionator.
Tri-States owns a NGL pipeline in Louisiana, Mississippi, and Alabama which
became operational in March 1999. Effective with the TNGL acquisition, the
Company acquired an equity interest in Belle Rose and Promix. Belle Rose owns a
NGL pipeline system in south Louisiana. The Company owns 41.7% of Belle Rose.
Promix owns a NGL fractionation and related storage facilities in south
Louisiana. The Company holds a 33-1/3% interest in Promix. In connection with
the TNGL acquisition, the Company acquired an additional 16-2/3% of Tri-States
bringing the total ownership interest to the current 33-1/3%.
As of September 30, 1999, the Company had two investments accounted for
using the cost method. These were VESCO and Dixie. VESCO owns a natural gas
processing plant, fractionation and storage facilities, and a gas gathering
pipeline system in Louisiana. The Company holds a 13.1% economic interest in
VESCO. The Dixie investment consists of an 11.5% interest in a corporation
owning a 1,300 mile propane pipeline and the associated facilities extending
from Mont Belvieu, Texas to North Carolina.
Results of Operations
Historically, the Company has had only one reportable segment: NGL
Operations. The operating margin of this segment has been reported on under five
distinct business units: NGL Fractionation, Isomerization, Propylene
Fractionation, Pipeline, and Storage and Other Plants. With the acquisition of
TNGL, management has opted to add a sixth business unit: TNGL Operations. In
addition, with the growth of the Company's equity method investments, Equity in
income of unconsolidated affiliates has been included in operating margin in
order to provide a more comprehensive view of the Company's results of
operations. For the future, due to the growing complexity of the Company's
operations with the acquisition of TNGL late in the third quarter of 1999,
management is currently studying alternative reporting methods such as reporting
results of operations using multiple segments.
16
<PAGE>
The Company's operating margins by business unit for the three and nine
month periods ended September 30, 1998 and 1999 were as follows:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1999 1998 1999
---------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Margin:
NGL Fractionation $ 1,274 $ 1,369 $ 2,812 $ 2,901
Isomerization 2,267 17,731 15,729 35,727
Propylene Fractionation 3,538 5,374 8,004 16,813
Pipeline 3,221 2,553 10,268 6,268
TNGL Operations 13,648 13,648
Storage and Other Plants 1,123 51 4,462 185
Equity in Income of Unconsolidated Affiliates 4,171 3,148 7,591 10,824
=========================================================
Total $ 15,594 $ 43,874 $ 52,099 $ 83,133
=========================================================
</TABLE>
The Company's plant production data (in thousands of barrels per day or
"MBPD") for the three and nine month periods ended September 30, 1998 and 1999
were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1999 1998 1999
----------------------------------------------
Plant Production Data :
TNGL Equity NGL Production 63 63
NGL Fractionation 180 149 197 155
Isomerization 65 77 65 73
MTBE 14 12 13 13
Propylene Fractionation 26 26 26 27
The Company's equity in income of unconsolidated affiliates (in thousands)
for the three and nine month periods ended September 30, 1998 and 1999 were as
follows:
Three Months ended Nine Months ended
September 30, September 30,
1998 1999 1998 1999
---------------------------------------------------------------
BEF $ 3,355 $ 2,519 $ 6,609 $ 4,756
MBA 862 72 4,305 1,256
BRF (258) (544)
BRPC 4 4
EPIK (46) 59 (90) 236
Entell 258 1,389
Wilprise (130) (130)
Tri-States 472 472
Belle Rose 245 245
Promix (93) (93)
===============================================================
Total $ 4,171 $ 3,148 $ 10,824 $ 7,591
===============================================================
Three Months Ended September 30, 1999 Compared with Three Months Ended September
30, 1998
17
<PAGE>
Revenues; Costs and Expenses
The Company's revenues increased to $445.0 million in 1999 compared to
$168.8 million in 1998. The Company's costs and expenses increased to $404.4
million in 1999 compared to $156.9 million in 1998. Operating margin increased
to $43.9 million in 1999 compared to $15.6 million in 1998. The primary reasons
for the increase in operating margins are an improvement in the isomerization
business and the addition of the operating results of the TNGL assets.
NGL Fractionation. Operating margin from NGL fractionation, which reflects
earnings from the Company's Mont Belvieu NGL fractionation assets, was $1.4
million for the third quarter of 1999 compared to $1.3 million for the third
quarter of 1998. For the quarter, NGL fractionation volumes at Mont Belvieu
averaged 149 MBPD compared to 180 MBPD for the same period in 1998. The slight
increase in operating margin for the quarter was principally due to the
Company's acquisition of an additional ownership interest in the fractionation
from Kinder Morgan and EPCO, offset by lower volumes fractionated. The lower
fractionation rates are attributable to the short-term diversion of customer
volumes to competitors. The Company fully expects that the diverted volumes will
be recovered.
Isomerization. The Company's margin in isomerization was $17.7 million for
the third quarter of 1999 versus $2.3 million for the third quarter of 1998.
Plant production volumes for the third quarter of 1999 averaged 77 MBPD as
compared to 65 MBPD for the same period in 1998. The margin improvement was
attributable to the increase in plant production volumes, a stronger price
environment for normal butane and isobutane during the third quarter of 1999
which benefited the merchant portion of this business and non-recurring
inventory write-downs which impaired margins in the third quarter of 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 $17.0 million as compared to $2.3 million in 1998.
Isobutane volumes from tolling and merchant activities for the third
quarter of 1999 averaged 98 MBPD as compared to 107 MBPD for the same period in
1998. Average daily toll processing volumes were 58 MBPD in 1999 and 1998.
Isobutane volumes related to merchant activities were 40 MBPD in 1999 and 49
MBPD in 1998. Isobutane merchant volumes decreased in the third quarter of 1999
compared to third quarter of 1998 due to lower margins on isobutane sales
relative to normal butane sales. The average spread between isobutane and normal
butane decreased from a positive 2.3 cents per gallon ("CPG") in the third
quarter of 1998 to a negative 1.2 CPG in the third quarter of 1999.
Propylene Fractionation. The Company's operating margin from propylene
fractionation for the third quarter of 1999 increased to $5.4 million from $3.5
million for the third quarter of 1998. Propylene fractionation for both periods
averaged 26 MBPD. The earnings improvement was primarily attributable to the
Company's actions in the merchant portion of the business to match the volume,
timing and price of feedstock purchases with sales of the product. Polymer grade
propylene prices for the third quarter of 1999 were significantly stronger at
15.7 cents per pound ("CPP") versus 13.7 CPP in the third quarter of 1998. The
increase in propylene prices in general for 1999 is attributable to higher crude
oil prices and increased global propylene demand.
Pipeline. Operating margin from pipeline operations for the third quarter
of 1999 was $2.6 million as compared to $3.2 million for the third quarter of
1998. The decrease in operating margin is primarily attributable to lower butane
import volume in the third quarter of 1999 as compared to 1998. The lower
volumes led to a $0.3 million decrease in the operating margin in 1999 versus
1998. A strengthening of normal butane prices worldwide has led to a decrease in
the availability of import volumes coming to the U.S. Gulf Coast. Throughput for
the third quarter of 1999 averaged 192 MBPD as compared to 193 MBPD for the same
period in 1998.
TNGL Operations. The operating margin from the assets acquired from TNGL in
the third quarter 1999 was $13.6 million. Since the effective date of the TNGL
acquisition was August 1, 1999, the operating margin included in the Company's
results of operations was for the months of August and September. Gas Processing
produced an operating margin of approximately $9.2 million. NGL fractionation
generated an operating margin of $4.1 million. The Pipelines and Other assets
produced an operating margin of $0.3 million.
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<PAGE>
Gas Processing is comprised of interests in eleven natural gas processing
plants (one of which is under construction) with 11 billion cubic feet per day
("Bcfd") of gross capacity and 3.1 Bcfd of net capacity to the Company's
interest anchored by a 20-year natural gas processing agreement with Shell (the
"Shell Agreement"). The Company is operator of four of these facilities. Its
major customer is Shell. Under the terms of a 20-year processing agreement with
Shell, the Company has the right to process substantially all of Shell's current
and future natural gas production from the Gulf of Mexico. This includes natural
gas production from the developments currently referred to as deepwater. Also
included in Gas Processing is the Tebone NGL fractionation facility. This
fractionation facility is an integral part of the Tebone and North Terrebone Gas
Processing facility. The Tebone NGL fractionation facility was built to receive
raw make from the North Terrebone Gas Processing facility and has a rated
capacity of 30 MBPD. During the months of August and September, the Gas
Processing facilities produced NGLs at a rate of 63 MBPD with the Tebone
fractionator operating at 29 MBPD.
NGL fractionation business is comprised of the Norco NGL fractionation
facility located in Louisiana. This facility is wholly owned by the Company and
has a capacity of 60 MBPD. During the months of August and September, the Norco
NGL fractionation plants operated a rate of 47 MBPD.
Pipeline and Other TNGL assets is primarily composed of varying ownership
interests in NGL and NGL product pipelines and storage assets located in
southern Louisiana.
Selling, General and Administrative Expenses
Selling, general and administrative expenses decreased $0.6 million to $3.2
million in 1999 from $3.8 million in 1998. The 1998 charges included $0.8
million in one-time expenses related to the initial public offering in July
1998. This amount was offset by a $0.2 million increase in the monthly charge
from EPCO. On July 7, 1999, the Audit and Conflicts Committee of Enterprise
Products GP, LLC (the "general partner") authorized an increase in the
administrative services fee to $1.1 million per month in accordance with the
EPCO Agreement from the initial rate of $1.0 million per month. The increased
fees were effective August 1, 1999.
Interest Expense
Interest expense for the second quarter was $4.0 million in 1999 and $2.5
million in 1998. This increase is principally due to the increased level of
average debt outstanding during the third quarter of 1999 attributable to the
borrowings associated with the TNGL and Mont Belvieu fractionation facility
acquisitions. Of the total debt outstanding at September 30, 1999 of $390
million, approximately $208 million is directly related to these two acquisition
transactions.
Equity Income in Unconsolidated Affiliates
Equity income in unconsolidated affiliates was $3.1 million in 1999
compared to $4.2 million in 1998. Equity income from BEF decreased from $3.4
million in the third quarter of 1998 to $2.5 million in the comparable period
for 1999. The decrease of $0.9 million is primarily attributable to downtime
associated with maintenance activities in July 1999. As a result of the
acquisition of the remaining MBA ownership interests in the Mont Belvieu
fractionator on July 1, 1999 and subsequent consolidation of operating results,
equity income from MBA ceased effective on that date. The third quarter 1998
equity income amount includes $0.9 million from MBA. EPIK showed a slight
increase over the third quarter of 1998 with $0.1 million in equity income
versus a loss of $0.1 million in the prior period. Wilprise showed a slight loss
during the quarter of $0.1 million with the BRF fractionation facility
evidencing a loss as well of $0.3 million. Both the Wilprise pipeline and the
BRF fractionation facility started operations in the third quarter of 1999.
The Company acquired equity interests in other entities as a result of the
TNGL acquisition. Among these entities were Belle Rose (equity income of $0.2
million) and Promix (equity loss of $0.1 million). With the acquisition of an
additional 16-2/3% in Tri-States, the Company obtained an equity interest of
33-1/3%. This investment contributed $0.5 million in equity income.
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Nine Months Ended September 30, 1999 Compared with Nine Months Ended September
30, 1998
Revenues; Costs and Expenses
The Company's revenues increased by 35% to $771.4 million in 1999 compared
to $573.5 million in 1998. The Company's costs and expenses decreased by 32% to
$688.3 million in 1999 compared to $521.4 million in 1998. Operating margin
increased by 60% to $83.1 million in 1999 compared to $52.1 million in 1998. The
primary reasons for the increase in operating margins are an improvement in the
isomerization and propylene fractionation business areas and the addition of the
operating results of the TNGL assets.
NGL Fractionation. The Company's operating margin for NGL fractionation was
$2.9 million for 1999 versus $2.8 million for 1998. Average daily fractionation
volumes decreased from 197 MBPD in 1998 to 155 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 in early 1999, 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.
Isomerization. The Company's operating margin for isomerization increased
to $35.8 million in 1999 compared to $15.7 million in 1998. The operating margin
for 1999 included a $2.0 million benefit from the amortization of the deferred
gain associated with the sale and leaseback of one of the Company's
isomerization units. The margin improvement is primarily attributable to a
stronger price environment for normal butane and isobutane during 1999 which
benefited the merchant portion of this business and non-recurring inventory
write-downs which impaired margins in 1998. Excluding this benefit, the
operating margin for 1999 would have been $33.8 million as compared to $15.7
million in 1998. Isobutane volumes from tolling and merchant activities for 1999
averaged 100 MBPD as compared to 102 MBPD for the same period in 1998. Average
daily toll processing volumes were 57 MBPD in 1999, or 73% of total volumes
produced, compared to 56 MBPD in 1998, or 86% of total volumes produced.
Isobutane volumes related to merchant activities were 43 MBPD in 1999 and 45
MBPD in 1998.
Propylene Fractionation. The Company's operating margin increased to $16.8
million in 1999 from $8.0 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 $6.3
million in 1999 compared to $10.3 million in 1998. Throughput for 1999 averaged
184 MBPD as compared to 198 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 approximately $2.8 million of the decrease.
TNGL Operations. The operating margin from the assets acquired from TNGL in
the third quarter 1999 was $13.6 million. Since the effective date of the TNGL
acquisition was August 1, 1999, the operating margin included in the Company's
results of operations was for the months of August and September. Gas Processing
produced an operating margin of approximately $9.2 million. NGL fractionation
generated an operating margin of $4.1 million. The Pipelines and Other assets
produced an operating margin of $0.3 million.
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Gas Processing is comprised of interests in eleven natural gas processing
plants (one of which is under construction) with 11 billion cubic feet per day
("Bcfd") of gross capacity and 3.1 Bcfd of net capacity to the Company's
interest anchored by a 20-year natural gas processing agreement with Shell (the
"Shell Agreement"). The Company is operator of four of these facilities. Its
major customer is Shell. Under the terms of a 20-year processing agreement with
Shell, the Company has the right to process substantially all of Shell's current
and future natural gas production from the Gulf of Mexico. This includes natural
gas production from the developments currently referred to as deepwater. Also
included in Gas Processing is the Tebone NGL fractionation facility. This
fractionation facility is an integral part of the Tebone and North Terrebone Gas
Processing facility. The Tebone NGL fractionation facility was built to receive
raw make from the North Terrebone Gas Processing facility and has a rated
capacity of 30 MBPD. During the months of August and September, the Gas
Processing facilities produced NGLs at a rate of 63 MBPD with the Tebone
fractionator operating at 29 MBPD.
NGL fractionation business is comprised of the Norco NGL fractionation
facility located in Louisiana. This facility is wholly owned by the Company and
has a capacity of 60 MBPD. During the months of August and September, the Norco
NGL fractionation plants operated a rate of 47 MBPD.
Pipeline and Other TNGL assets is primarily composed of varying ownership
interests in NGL and NGL product pipelines and storage assets located in
southern Louisiana.
Selling, General and Administrative Expenses
Selling, general and administrative expenses decreased $6.2 million to $9.2
million in 1999 from $15.4 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 $1.0 million per month.
On July 7, 1999, the Audit and Conflicts Committee of the general partner
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 $8.0 million in 1999 and $13.3 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. The decrease was muted, however, due
to a substantial increase in the average debt outstanding in the third quarter
of 1999 due to the borrowings associated with the TNGL and Mont Belvieu
fractionation facility acquisitions.
Equity Income in Unconsolidated Affiliates
Equity income in unconsolidated affiliates was $7.6 million in 1999
compared to $10.8 million in 1998. Equity income from BEF decreased from $6.6
million in 1998 to $4.8 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 to $1.3 million in 1999 from $4.3
million in 1998 due to decreased throughput caused by ethane rejection and
downtime associated with preventative maintenance activities. In addition, as a
result of the acquisition of the remaining MBA ownership interests in the Mont
Belvieu fractionator on July 1, 1999 and subsequent consolidation of operating
results, equity income from MBA ceased effective on that date. The 1998 results
for MBA are for a nine-month period whereas the 1999 results reflect a six-month
period. The third quarter results of operations are now consolidated and
included in NGL Fractionation. EPIK showed a slight increase over the 1998 with
$0.2 million in equity income versus a loss of $0.1 million in the prior period.
The 1998 results for EPIK reflected its first quarter in existence whereas the
1999 results are for nine months. Wilprise showed a slight loss of $0.1 million
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with the BRF fractionation facility generating a loss of $0.5 million. Both the
Wilprise pipeline and the BRF fractionation facility started operations in the
third quarter of 1999. Equity income from Entell was $1.4 million through July
31, 1999. Effective August 1, 1999, as a result of the TNGL acquisition, the
results of operations for Entell are now included in consolidated pipeline
revenues. Consolidation of operating results is necessary under generally
accepted accounting principles since the combined interests of the Company now
equal 100% (prior to August 1, 1999, the Company held a 50% interest with TNGL
holding the remaining 50%).
The Company acquired equity interests in other entities as a result of the
TNGL acquisition. Among these entities were Belle Rose (equity income of $0.2
million) and Promix (equity loss of $0.1 million). With the acquisition of an
additional 16-2/3% in Tri-States, the Company obtained an equity interest of
33-1/3%. This investment contributed $0.5 million in equity income.
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. Capital expenditures for future expansion
activities and asset acquisitions are expected to be funded with cash flows from
operating activities and borrowings under the revolving bank credit facilities.
Cash flows from operating activities were a $50.1 million inflow for the
first nine months of 1999 compared to a $43.9 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. Net
income increased significantly as a result of improved overall margins and the
TNGL acquisition. Depreciation and amortization increased by $2.5 million in
1999 primarily as a result of additional capital expenditures and the TNGL and
Mont Belvieu fractionator acquisitions (the "acquisitions") in the third quarter
of 1999. Amortization expense increased by $0.7 million due to the amortization
of the excess cost recorded in connection with acquisitions. The excess cost
associated with the acquisitions will be amortized over a 20-year period at
approximately $0.4 million per month. The net effect of changes in operating
accounts from year to year is generally the result of timing of NGL sales and
purchases near the end of the period.
Cash outflows for investing activities were $255.8 million in 1999 and
$48.8 million for the comparable period of 1998. Cash outflows included capital
expenditures of $10.6 million for 1999 and $7.2 million for 1998. Included in
the capital expenditures amounts are maintenance capital expenditures of $1.7
million for 1999 and $5.6 million for 1998. Investing cash outflows in 1999 also
included $58.4 million in advances to and investments in unconsolidated
affiliates versus $20.0 million for the comparable period of 1998. The $38.4
million increase stems primarily from contributions made to the Wilprise,
Tri-States, BRF, and BRPC joint ventures located in Louisiana. Also, the Company
received $16.7 million in payments on notes receivable from the BEF and MBA
notes purchased during 1998 with the proceeds of the Company's IPO. In
conjunction with the acquisition of the MBA interest in the Mont Belvieu
fractionation facility, $5.8 million was received during the third quarter 1999
from MBA for the balance of the Company's note receivable. The $9.8 million
outstanding balance of notes receivable from unconsolidated affiliates relates
to the participation in the BEF note. This balance will be collected in equal
installments of approximately $3.3 million each at the end of November 1999,
February 2000 and May 2000.
Cash outflows for investing activities also include the cash payments
related to the acquisitions. Per the terms of the TNGL acquisition, $166.0
million was paid to Tejas Energy in September 1999. Likewise, $42.1 million was
paid to Kinder Morgan and EPCO to purchase their collective 51% interest in MBA.
As described in Note 10 of the notes to the consolidated financial statements,
the Company expects to complete a third significant acquisition in the fourth
quarter of 1999 - the purchase of a pipeline from Concha Chemical Pipeline
Company ("Concha"), an affiliate of Shell, for approximately $100 million in
cash. The purchase of the Lou-Tex pipeline is the first step in the Company's
development of a $210 million, 160,000 barrel per day gas liquids pipeline
system. The completion of the Lou-Tex transaction is subject to the successful
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negotiation of definitive agreements, approval of those agreements by the
respective managements and regulatory approvals. The development of the expanded
Lou-Tex gas liquids pipeline system is expected to be completed in the second
half of 2000.
Cash flows from financing activities were a $203.3 million inflow in 1999
versus a $66.3 million inflow 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. The 1998 period reflects the transactions that occurred in the IPO in
July 1998. The 1999 period includes $215 million in long-term debt borrowings
associated with the TNGL and Mont Belvieu fractionation facility acquisition.
Cash flows from financing activities for 1999 also reflected the net purchase of
$4.7 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 $8.6
million (including $6.2 million for the BRPC propylene concentrator). 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 $24.3 million will be spent in 1999 on capital
projects that will be recorded as property, plant, and equipment (including
$10.9 million for the Lou-Tex pipeline and $5.6 million for the construction of
gas plants acquired from TNGL). The Company expects to finance these
expenditures out of operating cash flows and borrowings under its bank credit
facilities. As of September 30, 1999, the Company had $13.2 million in
outstanding purchase commitments attributable to its capital projects. Of this
amount, $4.7 million is associated with significant capital projects which will
be recorded as additional investments in unconsolidated affiliates for
accounting purposes.
Distributions from Unconsolidated Affiliates
Distributions to the Company from MBA were $1.9 million in 1999 and $4.7
million in 1998. The level of distributions is lower in 1999 versus 1998 due to
lower fractionation margins and the acquisition of the MBA interest in the Mont
Belvieu fractionation facility on July 1, 1999. Distributions from BEF in 1999
were $0.3 million versus $1.9 million in 1998. Distributions from BEF are down
from 1998 levels due to downtime associated with maintenance activities.
Distributions from EPIK in 1999 were $1.6 million. EPIK was formed in the second
quarter of 1998 and had no distributions until the third quarter of 1998.
Bank Credit Facility
Existing Bank Credit facility. In July 1998, the Operating Partnership
entered into a $200.0 million bank credit facility ("Bank Revolver A") 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 September 30, 1999, the
Company has borrowed $175.0 million under the bank credit facility which is due
in July 2000. Management is currently exploring options to convert this
short-term debt into long-term debt.
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 in July 2000 and all amounts
borrowed thereunder shall be due and payable at that time. There must be no
amount outstanding under the working capital facility for at least 15
consecutive days during each fiscal year.
As amended on July 28, 1999, the existing 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 $250.0 million,
(ii) maintain a ratio of EBITDA (as defined in the bank credit facility) to
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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/or 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 (excluding certain affiliates of EPCO or Shell Oil
Company); (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 ("Bank Revolver B") 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 were
used to finance the acquisition of TNGL and the MBA ownership interests. Future
uses of the remaining credit line include the purchase of the Lou-Tex pipeline
(see Note 10).
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 in July 2001 and all
amounts borrowed thereunder shall be due and payable at that time. 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 $250.0 million, (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/or 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 (excluding certain affiliates of EPCO and Shell Oil
Company); (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.
MTBE Production
The Company owns a 33-1/3% economic interest in the BEF partnership that
owns the MTBE production facility located within the Compan'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.
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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; however, due to increasing concerns about the
viability of alternative fuels, the California legislature on October 10, 1999
passed the Sher Bill (SB 989) stating that MTBE should be banned as soon as
feasible rather than by the end of 2002.
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 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 forecasted cost to
the Company of this conversion would be in the $20 million to $25 million range
with the Company's share being $6.7 million to $8.3 million. 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.
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. As
of October 31, 1999 work is approximately 99% complete in all areas.
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As of September 30, 1999, EPCO had spent approximately $326,500 in
connection with Year 2000 compliance and has estimated the future costs to
approximate $12,000. 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. These amounts are current cost estimates and actual future
costs could potentially be higher or lower than the estimates.
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 September 30, 1999, the Company had incurred expenditures of approximately
$1,026,000 in connection with finalizing its Year 2000 compliance project
(principally the SCADA system). The Company does not expect any additional
material expenditures. This approximate 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.
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
certain information concerning Year 2000 compliance status from a group of
critical suppliers and vendors. This information has assisted the Company in
determining the extent to which it may be vulnerable to the failure of third
parties 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. Final completion of the plan and testing of
replacement or modified systems is anticipated by November 30, 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 be handled
safely and so that a return to normal operations can be commenced as soon as is
practicable.
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.
26
<PAGE>
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.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Historically, the Company has been 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 could, but generally
did 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 was generally not affected by foreign currency
fluctuations. Through the third quarter of 1999, the Company did not use any
material derivative financial instruments for speculative purposes. At September
30, 1999, the Company had no material derivative instruments in place to cover
any potential interest rate, foreign currency or other financial instrument
risk.
At September 30, 1999, the Company had $21.6 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 September 30, 1999, was $103.0 million. Inventories are carried
at the lower of cost or market. A 10% adverse change in commodity prices would
result in an approximate $10.3 million decrease in the fair value of the
Company's inventory, based on a sensitivity analysis at September 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 $2.1 million effect on the amount of interest expense for the year
based upon amounts outstanding at September 30, 1999.
Beginning with the fourth quarter of 1999, the Company adopted a commercial
policy to manage exposures to the risks generated by the NGL business. The
objective of the policy is to assist the Company in achieving its profitability
goals while maintaining a portfolio of conservative risk, defined as remaining
27
<PAGE>
within the position limits established by the Board of Directors of the general
partner. The Company will enter into risk management transactions to manage
price risk, basis risk, physical risk or other risks related to energy
commodities on both a short-term (less than 30 days) and long-term basis, not to
exceed 18 months. The general partner has established a Risk Committee (the
"committee") that will oversee overall strategies associated with physical and
financial risks. The committee will approve specific commercial policies of the
Company subject to this policy, including authorized products, instruments and
markets. The committee is also charged with establishing specific guidelines and
procedures for implementing the policy and ensuring compliance with the policy.
This policy will affect transactions beginning with the fourth quarter of 1999.
28
<PAGE>
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).
*3.4 Second Amended and Restated Agreement of Limited Partnership of
Enterprise Products Partners L.P. dated September 17, 1999. (The
Company incorporates by reference the above document included in the
Schedule 13D filed September 27, 1999 by Tejas Energy LLC ; filed as
Exhibit 99.7 on Form 8-K dated October 4, 1999).
*3.5 First Amended and Restated Limited Liability Company Agreement of
Enterprise Products GP, LLC dated September 17, 1999. (Exhibit 99.8 on
Form 8-K/A-1 filed October 27, 1999).
*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 $200 million 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).
*4.3 First Amendment to $200 million Credit Agreement dated July 28, 1999
among Enterprise Products Operating L.P. and the several banks
thereto. (Exhibit 99.9 on Form 8-K/A-1 filed October 27, 1999).
*4.4 $350 million Credit Agreement among Enterprise Products Operating
L.P., BankBoston, N.A., Societe Generale, Southwest Agency and First
Union National Bank, as Co-Arrangers, The Chase Manhattan Bank, as
Co-Arranger and as Administrative Agent, The First National Bank of
Chicago, as Co-Arranger and as Documentation Agent, The Bank of Nova
Scotia, as Co-Arranger and Syndication Agent, and the Several Banks
from Time to Time parties hereto with First Union Capital Markets
acting as Managing Agent and Chase Securities Inc. acting as Lead
Arranger and Book Manager dated July 28, 1999 (Exhibit 99.10 on Form
8-K/A-1 filed October 27, 1999).
*4.5 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 in
the Schedule 13D filed September 27, 1999 by Tejas Energy LLC ; filed
as Exhibit 99.5 on Form 8-K dated October 4, 1999).
29
<PAGE>
*10.1Articles 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).
*10.2Form 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).
*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).
30
<PAGE>
*10.12 Amendment to Propylene Facility and Pipeline Sales Agreement between
HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1,
1993 (Exhibit 10.12 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.13 Amendment to Propylene Facility and Pipeline Agreement between
HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1,
1995 (Exhibit 10.13 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
10.14Fourth Amendment to Conveyance of Gas Processing Rights between Tejas
Natural Gas Liquids, LLC and Shell Oil Company, Shell Exploration &
Production Company, Shell Offshore Inc., Shell Deepwater Development
Inc., Shell Land & Energy Company and Shell Frontier Oil & Gas Inc.
dated August 1, 1999.
*99.1Contribution Agreement between Tejas Energy LLC, Tejas Midstream
Enterprises, LLC, Enterprise Products Partners L.P., Enterprise
Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999.
(The Company incorporates by reference the above document included in
the Schedule 13D filed September 27, 1999 by Tejas Energy LLC ; filed
as Exhibit 99.4 on Form 8-K dated October 4, 1999).
*99.2Registration 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 in the Schedule
13D filed September 27, 1999 by Tejas Energy LLC ; filed as Exhibit
99.6 on Form 8-K dated October 4, 1999).
27.1 Financial Data Schedule
* Asterisk indicates exhibits incorporated by reference as indicated
(b) Reports on Form 8-K
Three reports on Form 8-K were filed during the third quarter of 1999
associated with the Tejas acquisition.
On September 20, 1999 a Form 8-K was filed whereby the Company
announced it had completed its acquisition of TNGL, from Tejas Energy, an
affiliate of Shell. In exchange for its NGL business, Tejas Energy received
14.5 million convertible special partnership units in the Company and $166
million in cash. Tejas Energy has the opportunity to earn an additional 6.0
million convertible contingency units over the next two years. As part of
the transaction, the Company has entered into a long-term gas processing
agreement with Shell for its Gulf of Mexico production. TNGL's NGL
businesses include natural gas processing and NGL fractionation,
transportation, storage and marketing. All of TNGL's assets in Louisiana
and Mississippi are included under the terms of the transaction. This
acquisition by the Company forms a fully integrated Gulf Coast NGL
processing, fractionation, storage, transportation and marketing business.
On October 4, 1999, a Form 8-K was filed whereby the Company
summarized the Unitholder Rights Agreement and other material agreements
associated with the TNGL acquisition. This filing incorporated by reference
certain material documents associated with the acquisition.
31
<PAGE>
On October 27, 1999, a Form 8-K/A-1 was filed whereby the Company
disclosed certain historical financial information of TNGL for the years
ended 1996, 1997, and 1998. In addition, this filing contained other
documentation relating to the TNGL acquisition.
32
<PAGE>
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: November 15, 1999 By: /s/ Gary L. Miller
Executive Vice President
Chief Financial Officer and Treasurer
33
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
COMBINED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0001061219
<NAME> ENTERPRISE PRODUCTS PARTNERS L.P.
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 21647
<SECURITIES> 0
<RECEIVABLES> 238177
<ALLOWANCES> 0
<INVENTORY> 102992
<CURRENT-ASSETS> 383877
<PP&E> 1027423
<DEPRECIATION> 255266
<TOTAL-ASSETS> 1472600
<CURRENT-LIABILITIES> 486336
<BONDS> 215000
0
0
<COMMON> 0
<OTHER-SE> 762924
<TOTAL-LIABILITY-AND-EQUITY> 1472600
<SALES> 763793
<TOTAL-REVENUES> 771384
<CGS> 688250
<TOTAL-COSTS> 688250
<OTHER-EXPENSES> 9200
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7995
<INCOME-PRETAX> 65939
<INCOME-TAX> 0
<INCOME-CONTINUING> 65955
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 65955
<EPS-BASIC> 0.98
<EPS-DILUTED> 0.93
</TABLE>
FOURTH AMENDMENT TO CONVEYANCE
OF GAS PROCESSING RIGHTS
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
<S> <C>
RECITALS.................................................................................................1
1. DEFINITIONS.....................................................................................2
2. TERM............................................................................................6
2.1 Primary and Successive Terms...........................................................6
2.2 Termination of Agreement...............................................................6
2.3 Survival Provision.....................................................................6
2.3.1 Post Termination: Continuation as to Committed Leases........................6
2.3.2 Post Termination: Proposals for New Volumes...................................6
2.4 Early Termination of Entire Agreement Due To Unprofitable Processing...................7
2.4.1 Right to Terminate............................................................7
2.4.2 Obligation to Continue Processing. ...........................................7
3. ASSIGNMENT OF GAS PROCESSING RIGHTS.............................................................7
3.1 Grant of Processing Rights.............................................................7
3.2 Attachment of Gas Processing Rights....................................................8
3.3 Producers Nondisturbance Covenant; Prior Reservations or Contracts.....................8
3.4 Processor's Right to Consume PTR.......................................................9
3.5 Title to Raw Make, Products, Processor's Retrograde and PTR............................9
3.6 Limitations on Upstream Processing.....................................................9
3.6.1 Producer's Operational Requirements...........................................9
3.6.2 Processor's Exclusive Rights..................................................9
3.7 NGL Banks.....................................................................9
4. PROCESSOR'S OBLIGATION TO PROCESS AND
REDELIVER; LIMITATIONS.........................................................................10
4.1 Processor's Obligation to Process and Redeliver Residue Gas...........................10
4.2 Temporary Cessation of Processing.....................................................10
4.3 Refused Volumes.......................................................................10
4.3.1 Insufficient Capacity; Option to Refuse Volumes..............................10
4.3.2 Option to Reacquire Refused Volumes..........................................10
4.4 Excludable Gas........................................................................11
4.4.1 Option to Exclude Certain Gas................................................11
4.4.2 Terms of Continued Processing Pending Third Party Contract...................11
4.4.3 Option to Reacquire Excludable Gas. .........................................11
4.5 Unprofitable Plant....................................................................11
4.5.1 Right to Close Unprofitable Plant. ..........................................11
4.5.2 Terms of Continued Processing. ..............................................12
4.6 Suspension in Case of Dangerous Condition.............................................12
i
<PAGE>
5. SPECIFICATIONS FOR GAS AND SLUG LIQUIDS........................................................12
5.1 Quality Specifications................................................................12
5.2 Testing...............................................................................12
5.3 Off-Spec Deliveries...................................................................13
5.4 Notification of Non-Conformity; Rejection of Delivery.................................13
5.5 Acceptance of Nonconforming Product...................................................13
5.6 Processor's Limited Commitment to Accept Non-Conforming Product.......................13
5.7 Specifications for Residue Gas Redelivered by Processor...............................13
5.8 Off Spec Pipeline.....................................................................14
6. CONSIDERATION..................................................................................14
6.1 Payment ..............................................................................14
6.2 Consideration Basis...................................................................14
6.3 Consideration Timing...........................................................................14
6.4 Consideration Basis Updates...........................................................14
6.5 Processor Provided PTR.........................................................................14
7. PTR AND PTR TRANSPORTATION.....................................................................15
8. ROYALTY........................................................................................15
8.1 Responsibility for Royalty Payments...................................................15
8.2 Delivery of Royalty Taken In Kind.....................................................16
8.3 Compliance with Federal Acts..........................................................16
9. METERING, ANALYSIS, AND ALLOCATION.............................................................16
9.1 Gas Metering, Analysis and Reports....................................................16
9.2 Liquids Metering and Analysis. .......................................................17
9.3 Meter Failure.........................................................................17
10. INDEMNITY......................................................................................17
11. CURTAILMENT....................................................................................17
11.1 Mutual Agreement Not to Curtail or Withhold. ........................................18
11.2 Limited Right to Interrupt Performance for Maintenance, etc.. ........................18
12. FORCE MAJEURE..................................................................................18
12.1 Performance Excused...................................................................18
12.2 Force Majeure Defined.................................................................18
13. AUDIT RIGHTS...................................................................................19
14. NOTIFICATIONS..................................................................................19
14.1 Annual Information....................................................................19
14.2 Notice of Material Changes to Annual Information....................................19
14.3 Notice of Proposed Transfers of Dedicated Leases......................................19
14.4 Notice of Pending Transportation Agreements...........................................19
14.5 Notice of Scheduled Plant Downtime....................................................20
ii
<PAGE>
15. CONFIDENTIALITY................................................................................20
15.1 General...............................................................................20
15.2 Annual Information....................................................................20
16. DISPUTE RESOLUTION.............................................................................20
16.1 Arbitration...........................................................................20
16.2 Initiation of Procedures..............................................................21
16.3 Negotiation Between Executives........................................................21
16.4 Binding Arbitration...................................................................21
17. TRANSFER AND ASSIGNMENT........................................................................22
17.1 Successors and Assigns................................................................22
17.2 Processor's Rights Under Leases.......................................................22
17.3 Affiliates of Producer Parties........................................................22
17.4 Excepted Leases.......................................................................23
18. MISCELLANEOUS.........................................................................22
18.1 Title and Captions....................................................................23
18.2 Pronouns and Plurals..................................................................23
18.3 Separability..........................................................................23
18.4 Successors............................................................................23
18.5 Further Actions.......................................................................23
18.6 Notices...............................................................................23
18.7 Amendment only in Writing.............................................................24
18.8 Right of Ingress and Egress...........................................................24
18.9 No Special Damages....................................................................24
18.10 Applicable Law........................................................................24
18.11 Entire Agreement......................................................................24
18.12 Counterparts..........................................................................24
EXHIBIT A............................................................Dedicated Leases as of August 1, 1999
EXHIBIT B................. ................................................................Excluded Leases
EXHIBIT C................................................................Consideration Bases (Inside FERC)
EXHIBIT D..................................................................Consideration Bases (Gas Daily)
EXHIBIT E.................. ............................................................Upstream Pipelines
EXHIBIT F.............................................................................Letter of Attornment
</TABLE>
iii
<PAGE>
FOURTH AMENDMENT TO CONVEYANCE
OF GAS PROCESSING RIGHTS
THIS FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS (this
"Agreement") dated as of August 1, 1999 is made by and between Tejas Natural Gas
Liquids, LLC ("Processor"), a Delaware limited liability company, on the one
hand, and Shell Oil Company ("SOC"), Shell Exploration & Production Company
("SEPCO"), Shell Offshore Inc. ("SOI"), Shell Deepwater Development Inc.
("SDDI"), Shell Deepwater Production Inc. ("SDPI"), Shell Consolidated Energy
Resources Inc. ("SCERI"), Shell Land & Energy Company ("SLEC"), and Shell
Frontier Oil & Gas Inc. ("SFOGI")", all Delaware corporations, on the other, the
latter eight parties and their respective Affiliates (as defined below),
successors and assigns being collectively referred to as "Producer" or
"Producers".
RECITALS
A. Effective January 1, 1982, SOI and SOC executed that certain Conveyance
of Gas Processing Rights (the "Original Conveyance"), which granted to SOC the
right to process SOI's gas sold pursuant to certain identified gas sale
contracts.
B. Effective January 1, 1984, SOC assigned its rights under the Original
Conveyance to Shell Western E&P Inc. ("SWEPI").
C. Effective January 1, 1992, the Original Conveyance was amended (the
"First Amendment") to provide for a different method of calculating the annual
compensation to be paid to SOI by SWEPI and to provide that a list of mineral
leases, rather than gas sales contracts, to which the Original Conveyance
applied, would be updated annually.
D. Effective September 1, 1997, the First Amendment was amended ("Second
Amendment") solely with respect to certain mineral leases, the production from
which was dedicated for Processing at the Venice Plant of Venice Energy Services
Company, L.L.C., to confirm SWEPI's ownership of the Gas Processing Rights for
those mineral leases.
E. Effective January 1, 1998, the Second Amendment was amended in its
entirety (the "Third Amendment") to (1) recognize and confirm SWEPI's ownership
of the Producers' Gas Processing Rights associated with the Equity Gas
attributable to the leases listed on Exhibit A to such Third Amendment,
including the right to Process Equity Gas, and receive the benefits therefrom,
with respect to such leases; (2) confirm that the transfer of such rights to
SWEPI was and is binding on Producers as SOI's successors and assigns, and their
respective Affiliates, notwithstanding non-compliance by Producer or SWEPI with
respect to any provision concerning annual notification requirements of the
First Amendment; (3) provide that SWEPI shall be conveyed without further act,
the Gas Processing Rights for Equity Gas from any Lease upon the earlier of that
point in time (x) when Gas production from such Lease is committed to be
transported in an Upstream Pipeline, (y) when such Lease (or unitized portion
thereof) begins Gas production to an Upstream Pipeline, or (z) when SWEPI
requires a written dedication of Gas Processing Rights for a Lease in connection
with SWEPI's efforts to provide Processing capacity for Gas production from
1
<PAGE>
such Lease, regardless of whether Exhibit A is thereafter amended to include
Leases; and (4) to make such other changes to the Conveyance as specified in the
Third Amendment.
F. Effective January 12, 1998, SWEPI assigned to Tejas Holdings, LLC all of
its rights under the Third Amendment and Tejas Holdings, LLC subsequently
assigned all of such rights to Tejas Natural Gas Liquids, LLC.
G. The parties desire to further amend the Third Amendment to clarify their
respective rights and obligations thereunder and to restate the Conveyance in
its entirety.
NOW THEREFORE, in consideration of the mutual agreements, covenants and
conditions herein contained, the Parties hereby agree as follows:
1. DEFINITIONS.
1.1 "Affiliate" means, with respect to any relevant Person, any other
Person that directly or indirectly controls, is controlled by, or is under
common control with, such relevant Person in question. As used herein, the term
"control" (including its derivatives and similar terms) means owning, directly
or indirectly, the power (1) to vote ten percent or more of the voting stock of
any such relevant Person and (2) to direct or cause the direction of the
management and policies of any such relevant Person.
1.2 "Annual Information" has the meaning given it in Section 14.
1.3 "BTU" or "British Thermal Unit" means the quantity of heat required to
raise the temperature of one pound of pure water from 58.5 degrees to 59.5
degrees on the Fahrenheit temperature scale at a constant pressure of 14.73
psia. The term "MMBTU" shall mean 1,000,000 BTU's.
1.4 "Commitment Date" has the meaning given it in Section 3.2.
1.5 "Consideration Basis" has the meaning given it in Section 6.2.
1.6 "Conveyance" means the Original Conveyance described in Recital A, as
amended to date and by this Agreement and as hereafter amended from time to
time.
1.7 "Cubic foot of Gas" shall mean the volume of Gas contained in one cubic
foot of space at a standard pressure base of 14.73 pounds per square inch
absolute, and at a standard temperature base of 60 degrees F. Whenever the
conditions of pressure and temperature differ from the above standard,
conversion of the volume from these conditions to the above stated standard
conditions shall be made in accordance with the Ideal Gas Laws, corrected for
deviation due to supercompressibility by the methods set forth in ANSI/API 2530,
as revised or amended from time to time, and further detailed in American
Petroleum Institute Manual of Petroleum Measurement Standards (API MPMS) Chapter
14, Section 2, American Gas Association (AGA) Report Number 3, "Compressibility
Factors of Natural Gas and Other Related Hydrocarbons," as revised or amended
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from time to time. The terms "MCF" and "MMCF" shall mean, respectively, 1,000
Cubic Feet of Gas and 1,000,000 Cubic Feet of Gas.
1.8 "Dedicated" means, with respect to a Lease, a Lease owned by a Producer
as of or after the Commitment Date.
1.9 "Equity Gas" means Gas that is produced from a Dedicated Lease and is
owned and marketed by, or on behalf of, Producers. Equity Gas shall also include
any lessor's royalty Gas that is not taken "in-kind" by lessor and which is
marketed by, or on behalf of, Producers. Equity Gas shall exclude the following:
(i) Gas consumed by a Producer in the development and operation of
Dedicated Leases, including, but not limited to, the following
operations: drilling; deepening; reworking of wells; compression; Gas
lift; treating; separation; operationally integrated power generation;
maintenance of facilities; and consumed as fuel in such operations.
(ii) Gas provided by a Producer to another operator or producer in the
general vicinity of such Producer's operations to be used by such
operators or producers for purposes similar to those set forth in (i)
above; provided, however, if Gas furnished by Producer is used for
such purposes, Producer shall keep Processor whole from an economic
standpoint for any volumes that are so used.
(iii)Gas used by a Producer as makeup or non-consent Gas to or for the
benefit of third parties as may be required under joint operating, Gas
balancing or other similar agreements and produced from wells covered
by such agreements or to settle Gas imbalance claims with other
mineral and/or leasehold interest owners.
(iv) Gas used by a Producer to make payment of royalty and/or overriding
royalty in kind if required in the Dedicated Leases or instruments
pursuant to which such royalties and overriding royalties were
created, excluding any overriding royalties held by Affiliates of
Producer.
(v) Gas which is actually used by pipelines for fuel to transport lease
production and/or is otherwise flared, lost or unaccounted for prior
to delivery to a Plant.
(vi) Gas which is precluded from being produced or Processed due to
governmental intervention, regulations, laws or judicial or
administrative orders.
1.10 "Excludable Gas" means any Equity Gas that contains less than or equal
to one GPM of ethane and heavier hydrocarbons as measured at a Field Delivery
Point.
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1.11 "Excluded Lease" means a Lease listed on Exhibit B.
1.12 "Field Delivery Point" means any point at which Gas being transported
in Upstream Pipelines is measured for the purpose of allocating PTR and Products
from a Plant.
1.13 "Gallon" means one U.S. Standard Liquid Gallon of 231 cubic inches,
adjusted to a temperature of 60 degrees F and either the equilibrium pressure of
the product at 60 degrees F or 14.696 psia, whichever is greater.
1.14 "Gas" means all vaporized hydrocarbons and vaporized concomitant
materials whether produced from wells classified as oil wells or gas wells.
1.15 "Gas Processing Rights" has the meaning given it in Section 3.1.
1.16 "Geographical Scope" means that area (i) within the state waters of
Louisiana, Texas, Mississippi, Alabama and Florida, (ii) within the federal
waters of the United States of America in the Gulf of Mexico, including any
portion thereof claimed by Mexico.
1.17 "GPM" means Gallons per MCF of Gas.
1.18"Injected Liquids" means liquid hydrocarbons and liquid concomitant
materials that are delivered into an Upstream Pipeline.
1.19 "Lease" means any oil, Gas, and/or mineral lease or interest therein
owned now or hereafter acquired by Producers or their Affiliates within the
Geographical Scope excluding any lease listed on Exhibit B.
1.20 "New Volumes" has the meaning given it in Section 2.3.2.
1.21 "Off-Spec Deliveries" has the meaning given it in Section 5.3.
1.22 "Person" means any individual or entity, including, without
limitation, any corporation, limited liability company, partnership (general or
limited), joint venture, association, joint stock company, trust, unincorporated
organization or government (including any board, agency, political subdivision
or other body thereof).
1.23 "Plant" means a natural gas processing plant.
1.24 "Plant Delivery Point" means the point where an Upstream Pipeline
interconnects with a Plant.
1.25 "Plant Redelivery Point" means the point at or near the tailgate of a
Plant at which the Residue Gas is redelivered by a Plant into any interstate or
intrastate pipeline connected to that Plant.
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1.26 "Process" or "Processing" means the removal of liquefiable
hydrocarbons and/or impurities from Gas using mechanical separation, extraction,
condensation, compression, absorption, stripping, refrigeration, adiabatic
expansion, and other generally accepted natural gas processing methods.
1.27 "Processor" means Tejas Natural Gas Liquids, LLC and its successors
and assigns.
1.28 "Processor's Retrograde" means (i) liquefiable hydrocarbons that
condense from Equity Gas in the Upstream Pipelines listed in Exhibit E, and (ii)
any liquid hydrocarbons that are collected in the Plant prior to Processing.
Processor's Retrograde shall not include Injected Liquids but shall include any
lessor's royalty share of such liquefiable hydrocarbons in clauses (i) and (ii)
of this definition not taken "in kind" by lessor.
1.29 "Producer" means each of those entities listed in the first paragraph
of this Agreement and their respective Affiliates, successors and assigns (but
as to any such assigns, only to the extent such assigns acquire all or part of a
lessee's interest in a Dedicated Lease).
1.30 "Products" means the individual liquefied hydrocarbons recovered from
Equity Gas and/or Processor's Retrograde by Processing including, but not by way
of limitation, condensate, natural gasoline, butanes, propane, ethane, and/or
any unfractionated mixture thereof including, in each case, such methane as is
liquefied and incidentally recovered.
1.31 "PTR" means plant thermal reduction or the heat content stated in
MMBTU's removed from the Equity Gas and/or Processor's Retrograde as a result of
Processing including those MMBTU's (i) associated with extraction of Products,
(ii) consumed in the operation of a Plant, and (iii) flared, lost or otherwise
unaccounted for in the operation of a Plant.
1.32 "Quality Specifications" has the meaning given it in Section 5.1.
1.33 "Raw Make" means a combined stream of liquefied hydrocarbons and
concomitant materials extracted from Equity Gas by Processing including
Processor's Retrograde if subsequently combined with the other Raw Make.
1.34 "Residue Gas" means the portion of Equity Gas remaining after removal
of PTR during Processing and available for redelivery to a pipeline at the Plant
Redelivery Point.
1.35 "Slug Liquids" means free water, liquid hydrocarbons and other
concomitant materials which are separated from Gas upstream of the Plant
Delivery Point.
1.36 "Transportation Cost" means the cost of transportation of PTR from the
wellhead to the Plant Delivery Point.
1.37 "Termination Date" has the meaning given it in Section 2.2.
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1.38 "Upstream Pipeline" means any pipeline that transports Gas and/or Slug
Liquids between the Field Delivery Points and the Plant Delivery Points.
2. TERM.
2.1 Primary and Successive Terms. The term of this Agreement shall begin on
the date of this Agreement and continue for a primary term of 20 years, unless
sooner terminated under Section 2.2. At the end of the primary term, the term of
this Agreement shall be automatically extended for ten successive two year
terms, unless sooner terminated under Section 2.2.
2.2 Termination of Agreement. The Processor or any Producer shall have the
right, subject to Section 2.3, to terminate this Agreement as to such Producer
at the end of the primary term or at the end of any successive two year term
thereafter ("Termination Date") by giving written notice of termination, in
accordance with Section 18.6, no sooner than 20 nor later than 18 months prior
to the expiration of the then effective primary term or two year successive
term.
2.3 Survival Provision.
2.3.1 Post Termination: Continuation as to Committed Leases.
Notwithstanding termination of this Agreement pursuant to Section 2.2 above (but
not Section 2.4), the Gas Processing Rights held by Processor and all the
provisions of this Agreement shall continue in full force and effect with
respect to each Dedicated Lease until the expiration of such Dedicated Lease.
2.3.2 Post Termination: Proposals for New Volumes. For a period of 20 years
after the Termination Date, as to Leases (other than Dedicated Leases) from
which Gas is discovered to be ultimately produced by Producers ("New Volumes"),
Producers agree to provide Processor with notice of the estimated quantity of
New Volumes and the estimated date on which such New Volumes will be available
for Processing as soon as reasonably practicable. Producers further agree that
they will provide Processor a nonexclusive opportunity to submit a proposal to
Process the New Volumes. If, in the sole discretion of the Producer offering the
New Volumes, the proposal of Processor is not acceptable, then the Producer will
notify Processor of such, without any obligation to disclose terms or conditions
of, or differences between, other proposals. The Producer will then enter into
negotiations with Processor for no more than a 15 day period in an effort to
enter into agreements concerning the New Volumes. If Processor and Producer do
not enter into such mutually agreeable Processing agreements within the 15 day
period, then Producer shall be free to deliver and/or dedicate said New Volumes,
in their sole discretion, and for any purpose, to a third party.
2.4 Early Termination of Entire Agreement Due To Unprofitable Processing.
2.4.1 Right to Terminate. If for any 12 month period, the expenses of
Processor incurred in Processing Equity Gas exceed revenues obtained therefrom,
then Processor may, at its sole option, terminate this Agreement upon delivery
to all Producers of notice to terminate in accordance with Section 18.6. After
delivery of such notice, at the written request of Processor or any Producer,
the Processor and such Producer shall enter into exclusive good faith
negotiations for
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a period of 90 days from delivery of notice of termination to negotiate the
terms and conditions of a mutually agreeable alternative Processing arrangement.
If the Processor and Producer are unable to negotiate and execute the definitive
agreement for such alternative Processing arrangement within the 90-day period,
then any Producer that has not entered into such a definitive agreement shall be
free to negotiate and enter into an agreement with any one or more third parties
for Processing services; provided, however, that the terms agreed to between
such Producer and a potential third party processor for Processing services are,
taken as a whole, more favorable to the Producer than the latest terms for
Processing services previously offered by Processor to Producer during such
90-day period.
2.4.2 Obligation to Continue Processing. Processor shall continue to
process Equity Gas for each Producer until the earlier of (i) 12 months after
the expiration of the 90 day period, or (ii) the effective date of the
Producer's new third party processing agreement with respect to such Gas. In any
such case, if Processor's expenses incurred exceed the revenues obtained through
Processing a Producer's Equity Gas in any given month, such Producer shall
reimburse Processor on a monthly basis the difference between the Processor's
expenses and revenues for such month. Producer shall pay Processor any cash due
no later than 60 days following the end of the month in which the Producer's
Equity Gas is delivered for Processing.
3. ASSIGNMENT OF GAS PROCESSING RIGHTS.
3.1 Grant of Processing Rights. Subject to the other provisions of this
Agreement, Producers hereby grant, sell, transfer, convey and assign to
Processor the following (the "Gas Processing Rights"):
(1) the exclusive right to process any and all Equity Gas for the
extraction and retention of liquefiable hydrocarbons and other
constituents of Raw Make and/or Products;
(2) all title, interest and /or ownership in Raw Make and/or Products
recovered from Processing Equity Gas; and
(3) the right and option to assume all economic burdens and to obtain all
economic benefits reserved to the Gas producer under a contract for
Processing Equity Gas that is assumed by a Producer in connection with
the acquisition of a Lease.
It is the intention of the parties to confer on the Processor all of the
economic benefits to be derived from Processing all Gas from Leases, whether
derived from Leases currently owned and/or Dedicated or Leases subsequently
acquired by a Producer and/or subsequently Dedicated, subject only to (i) rights
previously granted by the transferors of subsequently acquired Leases to third
parties as provided in Section 3.3 and (ii) the right of Producers under Section
3.2 to transfer, free of Processor's rights under this Agreement, Leases that at
the time of transfer are not Dedicated Leases.
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3.2 Attachment of Gas Processing Rights. This conveyance of Gas Processing
Rights shall be irrevocable as to "Dedicated Leases". A Lease shall be
considered a Dedicated Lease upon the earliest of that point in time (the
"Commitment Date"): when (i) when a well is spud on the Lease; (ii) a Plan of
Exploration ("POE") or similar document including all or part of the Lease is
submitted or amended to the appropriate regulatory agency and a well is or has
been spud on any of the Leases included in the POE; (iii) a Development
Operations Coordination Document ("DOCD") or similar document including all or
part of the Lease is submitted or amended to the appropriate regulatory agency;
or (iv) Gas production begins from the Lease. A Lease acquired by a Producer
shall become a Dedicated Lease on the later of (1) the effective date of the
acquisition of such Lease by Producer if at any time prior to such acquisition
an event occurred that would constitute a Commitment Date had the Producer owned
an interest in such Lease at the time of such event, or (2) the later Commitment
Date for such Lease. Dedicated Leases as of August 1, 1999 are listed on Exhibit
A (said Exhibit A to be provided by Producers within 30 days of Producers'
execution of this Agreement and verified by Processor within 90 days of receipt
of said Exhibit A from Producers). Producer shall have the right to transfer,
sell, assign, exchange or otherwise alienate a Lease free of any obligations
under this Agreement and without any obligation to the Processor with respect to
the Lease prior to the Commitment Date with respect to a Lease.
3.3 Producers Nondisturbance Covenant; Prior Reservations or Contracts.
Excepting Producers' rights to sell, assign, exchange or otherwise alienate
Leases as provided for in Section 3.2, Producers agree not to make any
assignment or conveyance of, or enter into any other obligation concerning Gas
Processing Rights with respect to any Lease to the prejudice of Processor or its
rights under this Agreement. Producers further agree that, in connection with
the acquisition of a Lease, they will not permit the transferor to reserve to
itself or convey to any person any right to Process Equity Gas to be produced
from the Lease. However, as to any Lease acquired by a Producer subject to a
prior grant of rights to Process Equity Gas to be produced under the Lease to
Persons other than a Producer, Processor's rights under this Agreement shall be
subject to such rights previously granted, to the extent thereof.
3.4 Processor's Right to Consume PTR. In conveying the Gas Processing
Rights under this Agreement, Producers acknowledge and agree that the Equity Gas
Processed in a Plant will be subject to a PTR incidental to the exercising of
the Gas Processing Rights, and Producers hereby grant to Processor the rights to
consume Equity Gas as PTR associated with Processor's Retrograde and Products.
3.5 Title to Raw Make, Products, Processor's Retrograde and PTR Producers
hereby (i) represent and warrant to Processor that title to the liquefiable
hydrocarbons in Equity Gas is and will be free from all production burdens,
liens and adverse claims, (ii) warrant their right to sell the same and (iii)
agree to indemnify, defend and hold harmless Processor against all claims to
said liquefiable hydrocarbons arising (x) by, through, or under Producers or (y)
prior to Producers' delivery of said liquefiable hydrocarbons to Processor. The
transfer of title to, and risk of loss for, the extracted liquefiable
hydrocarbons shall pass to Processor at the meters for Raw Make and/or Products,
as appropriate, of the applicable Plant. As between the parties, Producers shall
be deemed to be in exclusive control and possession of the liquefiable
hydrocarbons prior to such transfer of
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title to Processor. The Processor and Producers acknowledge and agree that title
to PTR does not pass to Processor.
3.6 Limitations on Upstream Processing.
3.6.1 Producer's Operational Requirements. Producers agree that, except as
dictated by operational requirements, including the need to meet pipeline
specifications, they will not remove or permit to be removed any liquefiable
hydrocarbons from Equity Gas upstream of the Plants except for liquefiable
hydrocarbons that condense from the gas during transportation to the Plants.
3.6.2 Processor's Exclusive Rights. The rights granted to Processor herein
are exclusive, and Producers shall use their commercially reasonable efforts to
ensure that no owner or operator of an Upstream Pipeline shall have or exercise
any right or opportunity to Process, or extract Products from, Equity Gas as to
which the Gas Processing Rights have been conveyed to Processor under this
Agreement.
3.7 NGL Banks. In the event that any Upstream Pipeline or the shippers on
an Upstream Pipeline institute a bona fide mechanism to mitigate inequities that
may occur between shippers on such Upstream Pipeline as a result of such
shippers' Gas streams containing different liquifiable hydrocarbon compositions
being commingled in a pipeline with multiple delivery points located upstream of
Gas Processing Plants (an "NGL Bank"), Producers and Processor agree to
participate in the NGL Bank so as to confer on Processor the financial benefits
and detriments related to such liquifiable hydrocarbons under the terms of the
NGL Bank. Producers and Processor agree to execute and deliver to one another
such instruments as may be necessary or useful and to take such further actions
as may be reasonably necessary to carry out or further evidence the intent of
this Section 3.7. Pending execution of such instruments, Producers shall not be
required to curtail any Equity Gas production. However, Producers shall ensure
Processor receives all financial benefits and detriments referenced in this
Section 3.7 from the date of initiation of the NGL Bank.
4. PROCESSOR'S OBLIGATION TO PROCESS AND REDELIVER; LIMITATIONS.
4.1 Processor's Obligation to Process and Redeliver Residue Gas. Subject to
the provisions of this Agreement, throughout the term of this Agreement and for
any subsequent period of time as contemplated by Section 2.3.1, Processor agrees
to Process, or cause to be Processed, all Equity Gas. After Processing Equity
Gas and/or Slug Liquids and the recovery of the Raw Make, Products and
Processor's Retrograde therefrom, Processor shall deliver or cause to be
delivered Producers' Residue Gas to Producers or Producers' designee at the
applicable Plant Redelivery Point. 4.2 Temporary Cessation of Processing. If at
any time or from time to time Processor reasonably determines that the temporary
cessation of Processing Equity Gas at a Plant would not cause curtailment of the
applicable Equity Gas, then Processor shall have the option, in its sole
discretion, to temporarily cease Processing at that Plant. Processor shall
provide Producer with at least two business days notice of any such election to
temporarily cease Processing or to
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subsequently recommence Processing at a Plant and shall not change its election
more than two times in a month.
4.3 Refused Volumes .
4.3.1 Insufficient Capacity; Option to Refuse Volumes. Processor may, at
its option, elect not to Process a volume of Equity Gas that exceeds its
available Processing capacity at a Plant ("Refused Volumes") and agrees to
provide the applicable Producer with notice of such election as soon as
reasonably practicable. If Processor elects not to Process such Refused Volumes,
Producer may, nonetheless, by written notice to Processor, require that
Processor and Producer enter into exclusive good faith negotiations for a period
of 90 days from the date of the notice to negotiate the terms and conditions of
a mutually agreeable alternative Processing arrangement for the Refused Volumes
that would allow Processor in its sole judgment to economically acquire or
construct additional capacity at the Plant. If within the 90 day period
Processor and Producer are unable to negotiate and execute such a definitive
agreement, then Producer shall be free to negotiate with any third party for
Processing services for the Refused Volumes for a primary terms not to exceed
one year and Processor shall have no further obligation to negotiate with
Producer. In any event, Processor shall have no obligation to acquire or
construct new capacity. Producers shall make a reasonable effort to deliver
Equity Gas to Upstream Pipelines that will subsequently deliver it to Plants in
which Processor has sufficient capacity to Process such Equity Gas.
4.3.2 Option to Reacquire Refused Volumes. Processor shall have the option,
exercisable by three months written notice to the Producers, to acquire the
right to Process such Refused Volumes beginning on any anniversary date of the
third party agreement and may do so without prejudice to subsequent exercise of
its rights under Section 4.3.1.
4.4 Excludable Gas.
4.4.1 Option to Exclude Certain Gas Processor may, at its option, elect to
not Process all or any part of Equity Gas that contains less than or equal to
one GPM of ethane and heavier hydrocarbons as measured at a Field Delivery Point
("Excludable Gas") and agrees to provide the applicable Producer with notice of
such election as soon as reasonably practicable. If Processor elects not to
Process such Excludable Gas, a Producer may, nonetheless, by written notice to
Processor, require that Processor and Producer enter into exclusive good faith
negotiations for a period of 90 days from the date of the notice to negotiate
the terms and conditions of a mutually agreeable alternative Processing
arrangement for the Excludable Gas. If within the 90 day-period Processor and
Producer are unable to negotiate and execute a definitive agreement related
thereto, then Producer shall be free to negotiate with any third party for
Processing services for the Excludable Gas for a primary term not to exceed one
year and Processor shall have no further obligation to negotiate with Producer.
4.4.2 Terms of Continued Processing Pending Third Party Contract. Upon the
written request of a Producer, Processor shall continue to Process such
Producer's Excludable Gas until the earlier of (i) 12 months after the
expiration of the 90 day period referenced in Section 4.4.1, or (ii) the
effective date of the new third party Processing agreement. In any such case, if
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Processor's expenses incurred exceed revenues obtained from Processing a
Producer's Excludable Gas in any given month during that period of time, such
Producer shall reimburse Processor on a monthly basis the difference between the
Processor's expenses and revenues for such month. Producer shall pay Processor
any cash due no later than 60 days following the end of the month in which the
Producer's Excludable Gas is delivered for Processing.
4.4.3 Option to Reacquire Excludable Gas. Processor shall have the option,
exercisable by three months written notice to the Producers, to acquire the
right to Process any Excludable Gas under this Agreement beginning on any
anniversary date of the third party agreement and may do so without prejudice to
subsequent exercise of its rights under Section 4.4.1.
4.5 Unprofitable Plant.
4.5.1 Right to Close Unprofitable Plant. If for any 12 month period,
expenses of operating one or more Plants that Process Equity Gas exceed revenues
obtained from Processing, then Processor shall have the right upon at least 90
day's prior written notice to all affected Producers in accordance with Section
18.6 to elect to shut down any such Plant for a continuous period of at least
one year and, if such Equity Gas cannot be delivered to another Plant, to
exclude the Equity Gas delivered to the shut down Plant from this Agreement.
After delivery of such notice, at the written request of Processor or any
Producer, the Processor and Producer shall enter into exclusive good faith
negotiations for a period of 90 days from delivery of such notice to negotiate
the terms and conditions of a mutually agreeable alternative Processing
arrangement for the Equity Gas delivered to the Plant that would allow the Plant
to remain profitable. If the Processor and Producer are unable to negotiate and
execute the definitive agreement for such alternative Processing arrangement
within the 90-day period, then any Producer that has not entered into such a
definitive agreement shall be free to negotiate and enter into an agreement with
any one or more third parties for Processing services; provided, however, that
the terms agreed to between such Producer and a potential third party processor
for Processing services are, taken as a whole, more favorable to the Producer
than the latest terms for Processing services previously offered by Processor to
Producer during such 90-day period. The parties shall promptly amend Exhibit B
to include among Excluded Leases any Lease that is excluded from this agreement
under the terms of this Section 4.5.1.
4.5.2 Terms of Continued Processing. Upon the written request of a
Producer, Processor shall continue to process such Equity Gas at the Plant for a
period of time not to exceed 12 months after the expiration of the 90 day
period. In any such case, if Processor's expenses incurred exceed the revenues
obtained through Processing such Producer's Equity Gas in any given month during
that period of time, such Producer shall reimburse Processor on a monthly basis
the difference between the Processor's expenses and revenues for the month.
Producer shall pay Processor any cash due no later than 60 days following the
end of the month in which the Equity Gas is delivered for Processing.
4.6 Suspension in Case of Dangerous Condition. If any of Producer's
operations or any of the Equity Gas or Slug Liquids delivered hereunder create a
condition that, in the exclusive judgment of Processor, may endanger the Plant
or property of Processor or the lives or property of Processor's employees or
any third party, Processor may, without liability, immediately discontinue
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receipt of Equity Gas and/or Slug Liquids, as the case may be, until the
condition has been remedied to the reasonable satisfaction of Processor.
5. SPECIFICATIONS FOR GAS AND SLUG LIQUIDS.
5.1 Quality Specifications. Producers shall deliver Equity Gas and Injected
Liquids to each Field Delivery Point in conformity with the specifications of
the applicable Upstream Pipeline (the "Quality Specifications").
5.2 Testing. The determination as to the conformity of Equity Gas or
Injected Liquids to the Quality Specifications shall be made by Processor in
accordance with generally accepted procedures of the gas processing industry.
Such determinations shall be made as often as Processor deems necessary, and
Producer may witness such determinations or make joint determinations with its
own appliances. If in Producer's judgment, the result of any such test or
determination is inaccurate, Processor, at Producer's request, will again
conduct the questioned test or determination, and the costs of such additional
test or determination shall be borne by Producer unless same shows the original
test or determination to be materially inaccurate.
5.3 Off-Spec Deliveries. If any of Equity Gas or Injected Liquids delivered
at a Field Delivery Point fail to meet the Quality Specifications ("Off-Spec
Deliveries"), Processor, subject to the provisions of Sections 5.4, 5.5 and 5.6,
at its sole option, may accept or notify the appropriate Producer to discontinue
or curtail such Off-Spec Deliveries. Processor's acceptance of Off-Spec
Deliveries shall not be deemed a waiver of Processor's right to later reject
such Off-Spec Deliveries, nor shall acceptance of Off-Spec Deliveries from one
Field Delivery Point require Processor to accept similar Off-Spec Deliveries
from any other Field Delivery Point.
5.4 Notification of Non-Conformity; Rejection of Delivery. Processor shall
notify a Producer of any Off-Spec Deliveries, and Producer shall make a diligent
effort to conform such Equity Gas and/or Injected Liquids to the Quality
Specifications. If any Producer reasonably concludes that it cannot economically
deliver Equity Gas and/or Injected Liquids conforming to the Quality
Specifications, then such Producer shall so advise Processor in writing within
30 days after receipt of Processor's notice. Within 30 days after receipt of
Producer's notice, Processor shall give notice to the Producer in writing of its
election to accept or reject such Off-Spec Deliveries. If Processor rejects such
Off-Spec Deliveries, then upon receipt of said notice by such Producer, this
Agreement will be suspended with respect to the Field Delivery Points with such
Off-Spec Deliveries until such time as the Off-Spec Deliveries conform to the
Quality Specifications or Processor subsequently notifies such Producer of its
acceptance of the Off-Spec Deliveries.
5.5 Acceptance of Nonconforming Product. If Processor accepts such Off-Spec
Deliveries, Processor, after written notice to Producers as specified in Section
5.4, may charge Producers any reasonable costs incurred by Processor to monitor
the quality of Equity Gas and/or Injected Liquids and bring them within the
Quality Specifications. Processor shall invoice Producer on a monthly basis for
any such costs, the payment of which shall be due and payable within 30 days
after Produce's receipt thereof.
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5.6 Processor's Limited Commitment to Accept Non-Conforming Product.
Notwithstanding the provisions of Sections 5.3, 5.4 and 5.5, Processor agrees
that it will use reasonable efforts to continue acceptance of a Producer's
Off-Spec Deliveries for Processing in those cases where (i) Section 4.6 does not
apply and (ii) the acceptance of such Off-Spec Deliveries does not (x) cause
damage to the Plant, (y) render the Plant unable to meet applicable
specifications of the pipelines receiving Residue Gas at the Plant Redelivery
Points or of the purchaser or transporter of the Products from the Plant, or (z)
does not cause the Plant to violate applicable emissions permits or other
regulatory requirements.
5.7 Specifications for Residue Gas Redelivered by Processor. The Residue
Gas redelivered by Processor shall comply with the Quality Specifications in
effect on the date of delivery to the transporter receiving such Residue Gas at
the Plant Redelivery Point if that Equity Gas and/or Injected Liquids meets the
Quality Specifications upon delivery to the Upstream Pipeline at the Field
Delivery Point or Processor has elected to accept Off-Spec Deliveries under the
conditions of Sections 5.5 and 5.6 of this Agreement.
5.8 Off Spec Pipeline. Nothing in this Agreement shall require Processor to
accept delivery of any Gas that does not conform to the Quality Specifications
at the Plant Delivery Point.
6. CONSIDERATION
6.1 Payment . During the term of this Agreement, Processor agrees for each
Plant to pay to each of the respective Producers delivering Equity Gas to such
Plant, a cash amount equal to the product of:
(1) the Consideration Basis as defined in Section 6.2 for the respective
Plant for such Producer's Equity Gas Processed at such Plant; and
(2) the PTR for (1) such Producer's Equity Gas Processed at such Plant and
(2) any Processor's Retrograde associated with such Producer's Equity
Gas.
6.2 Consideration Basis. For purposes of Section 6.1, at the beginning of
each calendar month, the Consideration Basis shall be the respective adjusted
index price listed by Plant and Upstream Pipeline, as applicable, on Exhibit C
(Inside FERC) for all Producers' Equity Gas processed; provided, however,
Processor may elect to change the Consideration Basis from the adjusted index
price listed on Exhibit C to the respective adjusted index price listed on
Exhibit D (Gas Daily) for all Producers' Equity Gas processed. Processor shall
provide notice of such election to Producers no later than 3:00 p.m. Houston,
Texas time on the last business day of the month preceeding the month during
which such election is to be effective. If Processor elects to change the
Consideration Basis from Exhibit C to Exhibit D, the Consideration Basis shall
be the arithmetic average of the daily postings for all days of the month for
the applicable indices (the preceeding Friday's posting will be used for the
following Saturdays and Sundays in such calculation).
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6.3 Consideration Timing. Processor shall pay Producer the applicable
consideration set forth in Section 6.1 no later than 60 days following the last
day of the month in which subject PTR and Processor's Retrograde is delivered to
a Plant.
6.4 Consideration Basis Updates. Processor and Producers shall periodically
amend Exhibits C and D, as appropriate, if (i) another Plant is added by
Processor, (ii) the price indexes listed in Exhibits C or D are no longer
available or (iii) different index prices would, in the reasonable judgment of
Processor and Producers, more accurately represent market conditions. Any new
Consideration Basis shall represent either (i) the price of Gas at the Field
Delivery Point of the Upstream Pipeline that is connected to a respective Plant,
multiplied by 1.05 or (ii) the price of the Gas at another mutually agreeable
location, whichever more closely represents the value of the Gas at the Plant
Redelivery Point.
6.5 Processor Provided PTR. Producers acknowledge that Processor currently
is and may from time to time be required to provide PTR at a particular Plant
for Producer's Equity Gas Processed at such Plant for Processor's own account
(for example, aggregation of PTR for Plant owners and third parties who process
Gas at the Calumet Plant on Trunkline pipeline). Producers agree that Processor
has the right to provide PTR for Producer's Equity Gas Processed at such
Plant(s) for Processor's own account as may be required from time to time.
Processor agrees to initiate any such change from Producers providing PTR to
Processor providing PTR on the first day of a month and to provide Producers
with at least ten days notice of any such change. During any period of time that
Processor provides PTR for its own account as allowed under this Section 6.5, no
consideration under Section 6.1 is due to the Producers for any such PTR
provided by Processor.
7. PTR AND PTR TRANSPORTATION
Producers, at their sole expense, shall provide, or cause to be provided,
the PTR and the transportation for (i) the PTR associated with the Processing of
Equity Gas and (ii) Processor's Retrograde from the wellhead to the Plant
Delivery Point, for all Equity Gas and Processor's Retrograde subject to the
payment of consideration under Section 6.1. Producers shall also pay for all
necessary facilities to cause the Equity Gas and/or Injected Liquids to meet the
Quality Specifications and all other costs associated with delivering such PTR
and Processor's Retrograde to the Plant Delivery Point. If Processor provides
PTR for its own account under Section 6.5, Processor shall provide, or cause to
be provided, transportation for such PTR at its sole expense
8. ROYALTY
8.1 Responsibility for Royalty Payments. As between Processor and
Producers, the obligation to pay royalty due on Equity Gas production and
Processor's Retrograde, including but not limited to the Products recovered
through Processing, shall be divided as follows:
(a) Producers shall remain fully liable to remit payment to the Department
of the Interior, the Minerals Management Service, the States of
Louisiana, Texas, Mississippi, Alabama and Florida, and any private
lessors who are not federal
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or state lessors, for any royalty and severance taxes due on all
hydrocarbon production; and
(b) Processor shall fully reimburse Producers for any royalty payments
required by the Department of the Interior, the Minerals Management
Service, the States of Louisiana, Texas, Mississippi, Alabama and
Florida, and any private lessors who are not federal or state lessors,
on any Incremental Value (as defined hereafter) associated with
Processing the Equity Gas and Processor's Retrograde. "Incremental
Value" is defined as the value of the NGL Products extracted from the
Equity Gas and Processor's Retrograde less (i) the value of the PTR as
a Gas and (ii) any other expenses or allowances associated with
Processing that are allowed as deductions for royalty purposes under a
Lease. Prices used to determine the value of the NGL Products and PTR
shall be those that are recognized by the respective lessor. Processor
will tender such monthly payments of cash on or before 60 days
following the calendar month in which Equity Gas was delivered to the
Plant Delivery Point for Processing.
(c) Producers and Processor agree to work together to establish a process
to ensure that all information required for the calculation of royalty
payments to be made under the terms of this Section 8 is exchanged in
a timely manner.
8.2 Delivery of Royalty Taken In Kind. Any request by a private, state or
federal governmental lessor to take royalty production in kind for any Raw Make
or Products recovered through Processing shall, if lawful, be fulfilled by
Processor's delivery to the lessor or its designee of such in kind royalty at a
specified location, all as may be required in accord with properly promulgated
notices, regulations, or lease terms and to the extent that such delivery by
Processor is approved (if required) by private, state or federal lessor. In such
case, Processor shall be entitled to recover all costs allowed by statute,
regulation or lease term including but not limited to costs of transportation
and administrative services. In the event that Processor is prohibited from
fulfilling such in kind royalty requests by the private state or federal lessor,
then Processor shall be relieved of such obligation but shall tender to
Producers an amount of Raw Make or Products recovered from Processing sufficient
to fulfill such obligations at a mutually agreeable delivery point.
8.3 Compliance with Federal Acts. As between Processor and Producers,
Processor agrees to fulfill Producers' obligation under Section 8(b)(7) of the
Outer Continental Shelf Lands Act of 1978 by offering Processor's Retrograde and
Products recovered through processing at the market value and point of delivery
provided by regulators to small and independent refiners as defined in the
Emergency Petroleum Allocations Act of 1973. Processor shall be entitled to
retain the proceeds derived from such sale. In the event Processor is prevented
for any reason from fulfilling this obligation, Processor shall tender to
Producers' sufficient volumes of such Processor's Retrograde and Products
sufficient for Producers themselves to fulfill such obligation, and Producers
shall reimburse Processor for such liquids at a mutually agreed price which
shall include the cost of
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handling and administration of such sales. Producer shall be entitled to retain
the proceeds derived from such sale.
9. METERING, ANALYSIS, AND ALLOCATION
9.1 Gas Metering, Analysis and Reports.
9.1.1 Producers shall be responsible for the metering at the Field Delivery
Points of all Equity Gas and Injected Liquids, the calibration of such meters
and any disputes with respect to such metering. Producers agree to use
reasonable efforts to cause Gas meters to be tested on a minimum 45 day
frequency for correct calibration and agree to provide, or cause to be provided,
to Processor reasonable access to all meters.
9.1.2 Producers shall furnish to Processor such statements as Processor may
reasonably require to show the volume in MCF of Equity Gas delivered to Upstream
Pipelines during a month at each of Producers' Field Delivery Points no later
than the tenth business day of the month immediately following the month in
which such Gas is delivered to the Upstream Pipeline. This information may be
conveyed by facsimile transmission, with subsequent written confirmation, if
necessary to meet the aforesaid deadline.
9.1.3 Producers shall furnish to Processor a representative sample of
Equity Gas measured at each Field Delivery Point that identifies GPM for each
liquefiable hydrocarbon component in accordance with generally accepted industry
standards by no later than the tenth business day of the month immediately
following the month in which such Gas is delivered to the Upstream Pipeline.
This information may be conveyed by facsimile transmission, with subsequent
written confirmation, if necessary to meet the aforementioned deadline.
9.2 Liquids Metering and Analysis. Processor shall be responsible for the
metering and analysis of all liquefiable hydrocarbons extracted from Equity Gas,
calibration of such meters and any disputes with respect to such metering.
Processor agrees to cause such liquids meters to be tested on a minimum 45 day
frequency for correct calibration and agrees to provide, or cause to be provided
to Producers, reasonable access to such meters.
9.3 Meter Failure. In the case of the failure of any measurement meter of a
Plant with multiple Gas suppliers, the residue stream attributable to Equity Gas
production shall be determined and allotted to Producers according to the
provisions of either the applicable agreement controlling the construction and
operation of the Plant involved or according to related agreements executed
between the owners of the Plant and the owners of any Upstream Pipeline.
10. INDEMNITY.
Processor hereby indemnifies and holds Producers harmless against any and
all claims, demands, and causes of action of any kind and all losses, damages,
costs, and expenses (including court costs and reasonable attorneys' fees)
arising from injuries to persons or property attributable to the Equity Gas or
Processor's Retrograde, after delivery thereof has been made to Processor at a
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Plant Delivery Point. Producers hereby indemnify and hold Processor harmless
against any and all claims, demands, and causes of action of any kind and all
losses, damages, costs, and expenses (including court costs and reasonable
attorneys' fees) arising from injuries to persons or property attributable to
the Equity Gas or Injected Liquids, including but not limited to Processor's
Retrograde prior to delivery to Processor at the Plant Delivery Point(s) and
after Producer's share of the Residue Gas and Products (if applicable under
Section 8.2) is delivered to Producer or Producer's designee at the Plant
Redelivery Point(s).
11. CURTAILMENT
11.1 Mutual Agreement Not to Curtail or Withhold. Producers agree not to
unreasonably or arbitrarily withhold production of Equity Gas solely to
prejudice the rights granted to Processor hereunder. However, Producers will
have no liability to Processor under this Agreement if production is restricted
or curtailed for any good faith reason. Likewise, Processor agrees not to
arbitrarily withhold Processing services solely to prejudice the rights granted
to Producer hereunder. In any such case, Processor shall have no liability to
Producer if Processing services are withheld for any good faith reason.
11.2 Limited Right to Interrupt Performance for Maintenance, etc..
Processor and any Producer may, without liability, interrupt its performance
hereunder for the purpose of making necessary or desirable inspections,
maintenance, repairs, alterations and replacements; and the Processor or
Producer requiring such relief shall give to the other reasonable notice of its
intention to interrupt its performance hereunder, except in cases of emergency
where such notice is impracticable or in cases where the operations of the other
party will not be affected. The Processor or Producer requiring such relief
shall endeavor to arrange such interruptions so as to minimize any adverse
economic effect on the other party.
12. FORCE MAJEURE
12.1 Performance Excused. If either Processor or any Producer is rendered
unable, wholly or in part by Force Majeure to perform its obligations under this
Agreement, other than the obligation to make payments then due or thereafter
becoming due as a result of performance of an obligation prior to such Force
Majeure, it is agreed that performance of the respective obligations of
Processor and such Producer hereunder, so far as they are affected by such Force
Majeure, shall be suspended from the inception of any such inability until it is
corrected, but for no longer period. The party claiming such inability shall
give notice thereof to the other party as soon as reasonably practicable after
the occurrence of the Force Majeure. The party claiming such inability shall
promptly correct such inability to the extent it may be corrected through the
exercise of reasonable diligence. Neither party shall be liable to the other for
any losses or damages, regardless of the nature thereof and howsoever occurring,
whether such losses or damages be direct or indirect, immediate or remote, by
reason of, caused by, arising out of, or in any way attributable to the
suspension or performance of any obligation of either party to the extent that
such suspension occurs because a party is rendered unable, wholly or in part, by
Force Majeure to perform its obligations.
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12.2 Force Majeure Defined. For purposes of this Agreement, the term "Force
Majeure" shall mean an event, which (i) is not within the reasonable control of
the party claiming suspension, and which by the exercise of reasonable diligence
such party is unable to overcome or (ii) acts of God; strikes, lockouts or other
industrial disturbances, acts of the public enemy, wars, blockades,
insurrections, civil disturbances and riots, and epidemics; landslides,
lightning, earthquakes, fires, storms, hurricanes and threats of hurricanes,
floods and washouts; arrests, orders, requests, directives, restraints and
requirements of the government and governmental agencies, either federal or
state, civil or military; explosions, breakage or accident to machinery,
equipment or lines of pipe and outages (shutdowns) of equipment, machinery or
lines of pipe. The term "Force Majeure" shall also include any event of force
majeure occurring with respect to the facilities or services of either party's
suppliers or customers delivering or receiving any Raw Make, Products, Slug
Liquids, Gas, fuel, or other substance necessary to the performance of such
party's obligations, and shall also include curtailment or interruption of
deliveries or services by such third party suppliers or customers as a result of
an event of force majeure.
13. AUDIT RIGHTS
For a period of two years following any statement or payment hereunder or
such other period of time, if any, as may be prescribed under applicable COPAS
standards, Producers or Processor or any third party representative thereof
shall have the right, at its expense, upon reasonable notice and at reasonable
times, to examine the books and records of the other party hereto, to the extent
reasonably necessary to verify the accuracy of any such statement or payment
under this Agreement. In addition, Processor and Producer shall be required to
retain all records, contracts and files pertaining to royalty payments for the
period of time necessary to comply with contractual or regulatory obligations to
lessors, and the same shall be made available upon reasonable notice to the
other parties hereunder.
14. NOTIFICATIONS.
14.1 Annual Information. On or before September 1 of each year, each
Producer shall provide to Processor, without warranty as to accuracy, in
reasonable form and substance, Producer's projected volumes and Gas richness
(best available composition data) at each existing and projected Field Delivery
Point by prospect, Upstream Pipeline and year for the following ten year period.
Producers' current "C" volume exploration models or other statistical production
models shall be included but may be reported in aggregate. Such provided
information shall be referred to collectively as, the "Annual Information".
Producers shall also inform Processor as part of the Annual Information of any
plans to purchase or sell Dedicated Lease(s).
14.2 Notice of Material Changes to Annual Information. Processor and
Producers shall review the Annual Information regularly. Producer shall advise
Processor as soon as reasonably practicable of any changes to the Annual
Information that could materially impact Processor's plans to Process the
projected Equity Gas Volumes.
14.3 Notice of Proposed Transfers of Dedicated Leases. In addition to
notifying Processor as a part of the Annual Information, Producers shall notify
Processor, as soon as
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reasonably practicable, of, but in any case prior to, any efforts to sell,
exchange, or otherwise assign any Dedicated Lease, and Processor shall inform
the Producer of its intent to reserve or release such Dedicated Lease from this
Agreement.
14.4 Notice of Pending Transportation Agreements. Each Producer shall
notify Processor as soon as reasonably practicable of any ongoing or planned
negotiation for the transportation of Equity Gas in an Upstream Pipeline, in
order to facilitate Processor's entering into a Gas Processing Agreement for
such Equity Gas. Processor and Producer agree to enter into such transportation
and Gas Processing contracts contemporaneously, to the extent reasonably
practicable and provided that a Producer shall not be obligated to delay entry
into any transportation contract when such Producer reasonably believes such
delay will result in curtailment of Equity Gas.
14.5 Notice of Scheduled Plant Downtime. Processor agrees to notify
Producers as soon as reasonably practicable of any scheduled Plant downtime that
could impact Producer's ability to continue to produce Equity Gas.
15. CONFIDENTIALITY
15.1 General Producers or Processor shall not disclose the terms of this
Agreement (or the results of any audit pursuant to Section 13) to a third party
(other than the employees, lenders, counsel, consultants, or accountants of a
Processor or a Producer who have agreed to keep such terms confidential) except
(i) in order to comply with any applicable law, order, regulation or exchange
rule, (ii) in connection with bona fide negotiations with a potential third
party transferee of a Dedicated Lease or (iii) in connection with bona fide
negotiations involving the acquisition or construction of Plant capacity or
negotiations on contracts for third party Gas Processing agreements. Each party
shall notify the other party of any proceeding of which it is aware which may
result in disclosure and use reasonable efforts to prevent or limit the
disclosure. Such confidentiality obligations shall terminate two years after the
Termination Date.
15.2 Annual Information. Processor hereby agrees to maintain Annual
Information as confidential and agrees to disclose Annual Information only (i)
to employees, lenders, counsel, consultants, or accountants of Processor or an
Affiliate of Processor, who need to know and agree to maintain the
confidentiality of such Annual Information, and (ii) to the extent necessary to
comply with any applicable law, order, regulation or exchange rule. Processor
shall notify the applicable Producers of any proceeding of which it is aware
which may result in disclosure and use reasonable efforts to prevent or limit
the disclosure. Such confidentiality obligations shall terminate two years after
the Termination Date.
16. DISPUTE RESOLUTION
16.1 Arbitration. Producers and Processor hereby agree that any claim,
controversy or dispute arising among the parties or their successors in interest
or between any of them relating to this Agreement, or any of their respective
rights, duties or obligations under or in connection with this Agreement (a
"Dispute"), if not resolved by the parties in the ordinary course of business or
under the procedures set forth in this Section 16, shall with reasonable
promptness be submitted to
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and determined by binding arbitration in Houston, Texas in accordance with the
commercial arbitration rules of the American Arbitration Association ("AAA")
then in effect; and judgment upon any award rendered may be entered in any court
having jurisdiction thereof; and any such party may institute proceedings in any
court having jurisdiction for the specific performance by any party of any such
award. Each of the parties specifically agrees to be bound by any award or
determination made in any such arbitration proceeding. This Section 16 will be
the sole and exclusive procedure for the resolution of any Dispute, except that
any party, without prejudice to the following procedures, may file a complaint
to seek preliminary injunctive or other provisional judicial relief in a court
of competent jurisdiction, if in its sole judgment, that action is necessary to
avoid irreparable damage or to preserve the status quo; provided, however, that
any such provisional relief granted shall be vacated or extended upon the
determination of the arbitrators.
16.2 Initiation of Procedures. Any party wishing to initiate the dispute
resolution procedures set forth in this Section 16 with respect to a Dispute not
resolved in the ordinary course of business must give written notice of the
Dispute to the other parties ("Dispute Notice"). The Dispute Notice must include
(1) a statement of that party's position and a summary of arguments supporting
that position, and (2) the name and title of (a) the executive responsible for
administering this Agreement or the matter in Dispute and who will represent
that party and (b) any other person who will accompany the executive in the
negotiations under Section 16.3. Within 15 days after delivery of the Dispute
Notice, the receiving parties will submit to the other a written response. The
response will include (1) a statement of that party's position and a summary of
arguments supporting that position, and (2) the name and title of (x) the
executive who will represent that party and (y) any other person who will
accompany the executive in the negotiations conducted under Section 16.3.
16.3 Negotiation Between Executives. If any party has given a Dispute
Notice under Section 16.2, the parties will attempt in good faith to resolve the
Dispute within 30 days after the receipt of the written response to the Dispute
Notice by negotiations between executives identified in Section 16.2. During the
30 days following the receipt of the written response to the Dispute Notice, the
executives (identified in Section 16.2) will meet no less than eight hours a day
and exhaustively negotiate in good faith and at the expense of all other
responsibilities.
16.4 Binding Arbitration. At the end of the 30 day period provided in
Section 16.3, if the executives have been unable to resolve the Dispute, and if
a disputing party wishes to submit the Dispute to binding arbitration, the
disputing party shall provide to the other disputing party three business days'
prior written notice of such disputing party's intention to submit the Dispute
to binding arbitration. The other disputing party shall be entitled to join in
the submission of the Dispute to binding arbitration in accordance with the
commercial arbitration rules of the AAA (expedited procedures). The AAA shall be
instructed to choose an arbitrator who shall have a minimum of 15 years
experience in the oil and gas processing industry, or such other experience such
that he or she is considered an expert on the business of the Processor. Notice
of a disputing party's submission of the matter for arbitration shall be given
to the other party or parties within three business days thereafter (the
"Arbitration Notice"). Upon delivery of the Arbitration Notice by the disputing
party, each disputing party shall have 30 days to provide the arbitrator (and
the disputing party) with a statement of its position (with supporting
documentation) regarding the matter or matters in dispute together with its best
and final offer for settlement of the Dispute. The
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failure to provide a statement of position within this period shall constitute a
waiver of a disputing party's right to have such materials considered by the
arbitrator. The arbitrator shall consider the statements of position submitted
by the disputing parties and shall, within 30 business days after receipt of
such materials, issue his or her decision in writing picking one of the
statements of position submitted by the disputing parties as the position to be
adopted to settle the Dispute. All determinations made by the arbitrator shall
be final, conclusive and binding on the disputing parties. Each of the disputing
parties will pay one-half of the fees of the arbitrator and all other
arbitration fees and expenses and the fees of their respective arbitrators (if
required).
17. TRANSFER AND ASSIGNMENT
17.1 Successors and Assigns. This Agreement shall be binding upon Producers
and Processor. Except for an assignment by Processor in connection with the sale
of all or a substantial part of Processor's assets, this Agreement shall not be
assignable by Processor except with the prior written consent of the affected
Producer, or by a Producer, except with the prior written consent of Processor;
provided, however, that no such consent may be unreasonably withheld or delayed.
17.2 Processor's Rights Under Leases. Subject to Section 17.5, Producers
hereby agree that it is their intent that, to the extent permitted by law, this
Agreement constitutes a conveyance by Producers of a portion of their rights as
lessee under the Dedicated Leases and that this Agreement shall bind all persons
that now or at any time hereafter have any right as lessee or otherwise under
any Dedicated Leases, whether by voluntary transfer, involuntary transfer, or
otherwise of Leases. Producers further agree to make any transfer of any
Dedicated Lease subject to the terms and conditions of this Agreement and not to
transfer Producer's interest in a Dedicated Lease without first requiring the
transferee to execute and deliver to Producer and Processor Letter of Attornment
in the form attached as Exhibit F.
17.3 Affiliates of Producer Parties. Subject to Section 17.5, It is the
intention of the parties that this Agreement shall bind not only the Producers
who are made a party to this Agreement but also their respective Affiliates,
successors and assigns. Each Producer covenants and agrees to exercise its best
efforts to have each of its Affiliates, successors and assigns that acquires an
interest in a Lease become and be made a party to this Agreement and to perform
its obligations hereunder.
17.4 Excepted Leases. As to any Dedicated Leases, or portions thereof, that
were transferred or assigned by Producers to third parties during the period of
January 1, 1998 through May 30, 1999, inclusive, that were not made subject to
the Third Amendment as a condition of any such transfer or assignment ("Excepted
Leases"), Processor waives the application of the Third Amendment as to the
Excepted Leases, and the parties agree that this Agreement shall not apply to
the Excepted Leases.
18. MISCELLANEOUS
18.1 Title and Captions. All section titles or captions in this Agreement
are for convenience of reference only. They are not intended to be part of this
Agreement or to in any way define, limit, extend, or describe the scope or
intent of any provisions of this Agreement. Except as
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specifically provided otherwise, reference to "Sections" and "Exhibits" are to
Articles and Sections of and Exhibits to this Agreement.
18.2 Pronouns and Plurals. Whenever the context so requires, any pronoun
used in this Agreement includes the corresponding masculine, feminine or neuter
forms, and the singular form of nouns, pronouns and verbs includes the plural
and vice versa.
18.3 Separability. Each provision of this Agreement shall be considered to
be separable and, if, for any reason, any such provision, is determined to be in
whole or part invalid and contrary to any existing or future applicable law,
such invalidity shall not impair the operation of or affect those portions of
this Agreement that are valid, and this Agreement shall be construed and
enforced in all respects as if the invalid or unenforceable provision had been
omitted.
18.4 Successors. This Agreement shall be binding upon and inure to the
benefit of the parties and their respective successors and assigns but this
provision shall not be deemed to permit any assignment by a party of any of its
rights or obligations under this Agreement except as expressly provided herein.
18.5 Further Actions. Each party agrees to execute and deliver such further
instruments and do such further acts and things as may be required or useful to
carry out or further evidence the intent and purpose of this Agreement and which
are not inconsistent with its terms.
18.6 Notices All notices or other communications hereunder must be in
writing and must be delivered either personally or by (i) facsimile means
(delivered during the recipient's regular business hours), (ii) registered or
certified mail (postage prepaid and return receipt requested), or (iii) express
courier or delivery service, addressed as follows:
Producers: [Producer] Processor: Tejas Natural Gas Liquids, LLC
c/o Shell Offshore, Inc. 1301 McKinney Street, Ste. 700
200 N. Dairy Ashford Houston, TX 77010
Houston, TX 77079 Fax #: (713) 230-1730
Fax #: (281) 544-3544 Attn: Vice President-NGL Assets
Attn: Team Leader
Marketing & Transportation
or at such other address and number as any party shall have previously
designated by notice given to the other parties in the manner provided in this
Section. Notices shall be deemed given when received during normal business
hours if sent by facsimile means (confirmation of such receipt by confirmed
facsimile transmission being deemed receipt of communications sent by facsimile
means), and when delivered and receipted for (or upon the date of attempted
delivery where delivery is refused), if hand-delivered, sent by express courier
or delivery service, or sent by certified or registered mail.
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18.7 Amendment only in Writing. No amendment, waiver, modification or
change of this Agreement shall be enforceable unless in writing signed by the
Party against whom enforcement is sought.
18.8 Right of Ingress and Egress. To the extent Producers are able to grant
such rights, Processor shall have the right of ingress and egress to and from
the premises of Producers and to and from the Field Delivery Points for all
purposes necessary for the fulfillment of this Agreement.
18.9 No Special Damages. No party shall be liable for any consequential,
incidental, punitive, exemplary, or indirect damages in tort, contract, under
any indemnity provision or otherwise.
18.10 Applicable Law. This Agreement shall be governed by, and construed,
interpreted and enforced in accordance with, the substantive law of the state of
Louisiana without regard to principles of conflicts of laws.
18.11 Entire Agreement. This Agreement embodies the entire agreement and
understanding between Producers and Processor and supersedes all prior
agreements and understandings relating to the subject matter hereof, except that
Section 2 of the Third Amendment is hereby incorporated in this Agreement by
reference and shall survive this Agreement as though fully set forth herein.
18.12 Counterparts. This Agreement may be executed in one or more
counterparts and each of such counterparts, for all purposes, shall be deemed to
be an original, but all of such counterparts together shall constitute but one
and the same instrument, binding upon all parties, notwithstanding that all of
the parties may not have executed the same counterpart.
IN WITNESS WHEREOF, the parties hereto, by their duly authorized
representatives have executed this Agreement effective as of the Effective Date.
PRODUCERS:
SHELL OIL COMPANY WITNESSES:
By: /s/ B.K. Garrison /s/ Cindy Bustillo
Name: B.K. Garrison
Title: Attorney-in-Fact /s/ illegible signature
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SHELL OFFSHORE INC. WITNESSES:
By: /s/ J.W. Kimmel /s/ Cindy Bustillo
Name: J.W. Kimmel
Title: Attorney-in-Fact /s/ illegible signature
SHELL DEEPWATER PRODUCTION INC. WITNESSES:
By: /s/ J.W. Kimmel /s/ Cindy Bustillo
Name: J.W. Kimmel
Title: Attorney-in-Fact /s/ illegible signature
SHELL DEEPWATER DEWITNESSES:
INC.
By: /s/ J.W. Kimmel /s/ Cindy Bustillo
Name: J.W. Kimmel
Title: Attorney-in-Fact /s/ illegible signature
SHELL CONSOLIDATED ENERGY WITNESSES:
RESOURCES INC.
By: /s/ B.K. Garrison /s/ Cindy Bustillo
Name: B.K. Garrison
Title: Attorney-in-Fact /s/ illegible signature
SHELL LAND & ENERGWITNESSES:
By: /s/ B.K. Garrison /s/ Cindy Bustillo
Name: B.K. Garrison
Title: Attorney-in-Fact /s/ illegible signature
24
<PAGE>
SHELL FRONTIER OIL & GAS INC. WITNESSES:
By: /s/ B.K. Garrison /s/ Cindy Bustillo
Name: B.K. Garrison
Title: Attorney-in-Fact /s/ illegible signature
SHELL EXPLORATION & WITNESSES:
PRODUCTION COMPANY
By: /s/ Walter van de Vijver /s/ illegible signature
Name: Walter van de Vijver
Title: President & CEO /s/ illegible signature
PROCESSOR:
TEJAS NATURAL WITNESSES:S, LLC
By: /s/ A.J. Teague /s/ illegible signature
Name: A. J. Teague
Title: President /s/ illegible signature
25
<PAGE>
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared B.K.
Garrison, known to me to be the person whose name is subscribed to the foregoing
instrument and acknowledged to me that he, being fully authorized to do so,
executed and delivered the same as Agent and Attorney-in-Fact for Shell Oil
Company, a Delaware corporation, on the day and year therein mentioned and as
the act and deed of said corporation, for the purpose and consideration therein
expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this ____ day of _________, 1999.
/s/ Cindy Bustillo
Notary Public
My Commission Expires:_______________.
[NOTARY STAMP]
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared J.W.
Kimmel, known to me to be the person whose name is subscribed to the foregoing
instrument and acknowledged to me that he, being fully authorized to do so,
executed and delivered the same as Agent and Attorney-in-Fact for Shell Offshore
Inc., a Delaware corporation, on the day and year therein mentioned and as the
act and deed of said corporation, for the purpose and consideration therein
expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this _____ day of ________, 1999.
/s/ Cindy Bustillo
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
26
<PAGE>
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared J.W.
Kimmel, be the person whose name is subscribed to the foregoing instrument and
acknowledged to me that he, being fully authorized to do so, executed and
delivered the same as Agent and Attorney-in-Fact for Shell Deepwater Production
Inc., a Delaware corporation, on the day and year therein mentioned and as the
act and deed of said corporation, for the purpose and consideration therein
expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this ____ day of ________, 1999.
/s/ Cindy Bustillo
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared J.W.
Kimmel, known to me to be the person whose name is subscribed to the foregoing
instrument and acknowledged to me that he, being fully authorized to do so,
executed and delivered the same as Agent and Attorney-in-Fact for Shell
Deepwater Development Inc., a Delaware corporation, on the day and year therein
mentioned and as the act and deed of said corporation, for the purpose and
consideration therein expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this ___ day of ________, 1999.
/s/ Cindy Bustillo
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
27
<PAGE>
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared B.K.
Garrison, known to me to be the person whose name is subscribed to the foregoing
instrument and acknowledged to me that he, being fully authorized to do so,
executed and delivered the same as Agent and Attorney-in-Fact for Shell
Consolidated Energy Resources Inc., a Delaware corporation, on the day and year
therein mentioned and as the act and deed of said corporation, for the purpose
and consideration therein expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this _______ day of __________, 1999.
/s/ Cindy Bustillo
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared B.K.
Garrison, known to me to be the person whose name is subscribed to the foregoing
instrument and acknowledged to me that he, being fully authorized to do so,
executed and delivered the same as Agent and Attorney-in-Fact for Shell Land &
Energy Company, a Delaware corporation, on the day and year therein mentioned
and as the act and deed of said corporation, for the purpose and consideration
therein expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this _______ day of ___________, 1999.
/s/ Cindy Bustillo
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
28
<PAGE>
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared B.K.
Garrison, known to me to be the person whose name is subscribed to the foregoing
instrument and acknowledged to me that he, being fully authorized to do so,
executed and delivered the same as Agent and Attorney-in-Fact for Shell Frontier
Oil & Gas Inc., a Delaware corporation, on the day and year therein mentioned
and as the act and deed of said corporation, for the purpose and consideration
therein expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this _______ day of ___________, 1999.
/s/ Cindy Bustillo
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared Walter
van de Vijver, known to me to be the person whose name is subscribed to the
foregoing instrument and acknowledged to me that he, being fully authorized to
do so, executed and delivered the same as President & CEO for Shell Exploration
& Production Company, a Delaware corporation, on the day and year therein
mentioned and as the act and deed of said corporation, for the purpose and
consideration therein expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this _____ day of ____________, 1999.
/s/ Kathryn W. Coleman
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
29
<PAGE>
STATE OF TEXAS
COUNTY OF HARRIS
BEFORE ME, the undersigned Notary Public, on this day personally appeared A. J.
Teague, known to me to be the person whose name is subscribed to the foregoing
instrument and acknowledged to me that he, being fully authorized to do so,
executed and delivered the same as Agent and President for Tejas Natural Gas
Liquids, LLC, a Delaware limited liability company, on the day and year therein
mentioned and as the act and deed of said corporation, for the purpose and
consideration therein expressed.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this _______ day of ____________, 1999.
/s/ Phebia E. Watts
Notary Public
My Commission Expires_______________.
[NOTARY STAMP]
30
<PAGE>
EXHIBIT A
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
DEDICATED LEASES AS OF AUGUST 1, 1999
(to be provided by Producers under the terms of Section 3.2 of this Agreement)
31
<PAGE>
EXHIBIT B
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
EXCLUDED LEASES
<TABLE>
<CAPTION>
<S> <C> <C> <C>
SUPPLY SOURCE RECEIPT POINT RELATED PLANT / OPERATOR RELATED PIPELINE
Grand Isle 33 Grand Isle 33 Grand Isle / Exxon Exxon's Grand Isle Gathering System
</TABLE>
32
<PAGE>
EXHIBIT C Page 1 of 2
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
CONSIDERATION BASES
<TABLE>
<CAPTION>
PLANT CONSIDERATION BASIS
<S> <C>
Barracuda GMR - Transcontinental Gas Pipeline Corp., Zone 2 (pooling point)
Blue Water Average of GMR - Tennessee Gas Pipeline, La. & Offshore (zone 1) x 1.05
GMR - Columbia Gulf Transmission Co., Louisiana
Burns Point GMR - Koch Gateway Pipeline Co., South Louisiana/East Side x 1.05
Calumet
- - ANR GMR - ANR Pipeline Co., Louisiana x 1.05
- - Trunkline GMR - Trunkline Gas Co., Louisiana x 1.05
Garden City/Neptune Average of GMR - Koch Gateway Pipeline Co., South Louisiana/East Side
GMR - Columbia Gulf Transmission Co., Louisiana
GMR - Texas Gas Transmission Corp., Zone SL
GMR - Henry Hub
Iowa GMR - Texas Eastern Transmission Corp., West Louisiana zone x 1.05
N.Terrebonne GMR - Transcontinental Gas Pipeline Corp., Zone 3 (pooling point)
Mobile Bay* Average of GMR - Transcontinental Gas Pipe Line Corp., Mississippi, Alabama less 9.6 cents
(Yellowhammer only) GMR - Florida Gas Transmission Co., Zone 3
</TABLE>
Note: GMR ==> Inside F.E.R.C.'s Gas Market Report, First of Month Index
* Assumes Processor or Processor's agent pays any cost associated with
moving all of the Yellowhammer Gas to the Plant.
33
<PAGE>
EXHIBIT C Page 2 of 2
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
CONSIDERATION BASES
<TABLE>
<CAPTION>
PLANT CONSIDERATION BASIS
<S> <C>
Pascagoula Average of GMR - Transcontinental Gas Pipe Line Corp., Mississippi, Alabama
GMR - Koch Gateway Pipeline Co., South Louisiana/East Side
GMR - Florida Gas Transmission Co., Zone 3
GMR - Southern Natural Gas, Louisiana
GMR - Tennessee Gas Pipeline, La. & Offshore (zone 1)
Sabine Pass GMR - Tennessee Gas Pipeline, La. & Offshore (zone 1) x 1.05
Sea Robin Average of GMR - Columbia Gulf Transmission Co., Louisiana
GMR - Southern Natural Gas Co., Louisiana
Stingray GMR - Natural Gas Pipeline Co. of America, Louisiana
Toca GMR - Southern Natural Gas, Louisiana x 1.05
Venice Average of GMR - Texas Eastern Transmission Corp., East Louisiana zone
GMR - Columbia Gulf Transmission Co., Louisiana
GMR - Koch Gateway Pipeline Co., South Louisiana/East Side
Yscloskey GMR - Tennessee Gas Pipeline, La. & Offshore (zone 1) x 1.05
</TABLE>
Note: GMR ==> Inside F.E.R.C.'s Gas Market Report, First of Month Index
34
<PAGE>
EXHIBIT D Page 1 of 2
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
CONSIDERATION BASES
PLANT CONSIDERATION BASIS
Barracuda GDLM - Transco, St.45
Blue Water Average of GDLM - Tennessee, 800 Leg X 1.05
GDLM - Columbia
Burns Point GDLM - Koch (Zones 2&4) X 1.05
Calumet
- - ANR GDLM - ANR X 1.05
- -Trunkline GDLM - Trunkline ELA X 1.05
Garden City/Neptune Average of GDLM - Koch (Zones 2&4)
GDLM - Columbia
GDLM - Texas Gas SL
GDLM - Henry Hub
Iowa GDLM - Texas E. (WLA) X 1.05
N. Terrebonne GDLM - Transco, St.65
Mobile Bay* Average of GDMAM - Transco, St 85 less 9.6 cents
(Yellowhammer only) GDLM - FGT Z3
GDLM = Gas Daily; Louisiana-Onshore South; Midpoint
GDMAM = Gas Daily; Mississippi-Alabama; Midpoint
* Assumes Processor or Processor's agent pays any cost associated with
moving all of the Yellowhammer Gas to the Plant.
35
<PAGE>
EXHIBIT D Page 2 of 2
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
CONSIDERATION BASES
PLANT CONSIDERATION BASIS
Pascagoula Average of GDMAM - Transco, St 85
GDLM - Koch (Zones 2&4)
GDLM - FGT Z3
GDLM - Sonat
GDLM - Tennessee, 500 Leg
Sabine Pass GDLM - Tennessee, 800 Leg X 1.05
Sea Robin Average of GDLM - Columbia
GDLM - Sonat
Stingray GDLM - NGPL (La.)
Toca GDLM - Sonat X 1.05
Venice Average of GDLM - Texas E. (ELA)
GDLM - Columbia
GDLM - Koch (Zones 2&4)
Yscloskey GDLM - Tennessee, 500 Leg X 1.05
GDLM = Gas Daily; Louisiana-Onshore South; Midpoint
GDMAM = Gas Daily; Mississippi-Alabama; Midpoint
36
<PAGE>
EXHIBIT E
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
UPSTREAM PIPELINES WITH PROCESSOR'S RETROGRADE
Upstream Pipeline Gas Plant County/Parish
Southern Natural Pipeline Toca St, Bernard, LA
Mississippi Canyon Gas Pipeline Venice Plaquemines, LA
Destin Pipeline Pascagoula Jackson, MS
37
<PAGE>
EXHIBIT F
FOURTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS
ATTORNMENT LETTER
[Name of Processor] [Name of Transferee of Lease]
[Address of Processor] [Address of Transferee of Lease]
Gentlemen:
Subject: Transfer of Certain Leases
Notification and Consent to Assignment
1. Agreement for Transfer of Leases. Per prior discussions, your respective
offices have been apprised that [name of producer] ("[name of producer]") and
[name of transferee] ("Successor Producer") have entered an agreement by which
[name of producer] will transfer to Successor Producer (the "Transfer") those
certain interests in and to certain properties and leases as described on
Exhibits A & B ( the "Properties").
2. Cognizance of Prior Conveyance of Processing Rights. The parties
acknowledge that all gas processing rights associated with the Properties have
been conveyed to Processor by virtue of that certain Fourth Amendment to
Conveyance of Gas Processing Rights (the "Conveyance of Processing Rights")
dated June 30, 1999 by and between Tejas Natural Gas Liquids, LLC ("Processor"),
on the one hand, and Shell Oil Company and certain of its named affiliates
(collectively, "Producers").
3. Reservation of Rights by Processor. Processor hereby expressly reserves
all its rights under the Conveyance of Processing Rights with respect to the
Properties. Successor Processor hereby acknowledges and agrees that it is
acquiring the Properties subject to the rights conveyed to Processor in the
Conveyance of Processing Rights.
4. Assumption of Producer's Obligations. Successor Producer hereby assumes
and agrees to perform all of the obligations of [name of producer] to Processor,
and receives and accepts all rights of [name of producer], under the Conveyance
of Processing Rights, insofar as they relate to the Properties.
5. Consent to Transfer. Processor hereby acknowledges and consents to the
Transfer and agrees to render to Successor Producer the performance of
Processor's obligations to Producers under the Conveyance of Processing Rights
insofar as they relate to the Properties.
38
<PAGE>
6. Counterparts. This document may be executed in any number of
counterparts, each of which when combined and taken together, shall be
considered but one and the same document.
7. Covenants Running with the Land. The parties intend that, to the extent
permitted by law, this instrument and the Conveyance of Gas Processing Rights
shall be considered to be covenants running with the Properties which shall
inure to the benefit of, and be binding upon, the successors and assigns of the
parties' interests insofar as they relate to the Conveyance of Gas Processing
Rights or the Properties.
Your prompt attention to this matter will be appreciated. Should you have
any questions or require further information in this regard, please contact our
office.
Yours very truly,
Name
[title]
[NAME OF TRANSFEREE]
Agreed to and approved this ______ day of
______________________, 1999.
By: ___________________________
Title: _________________________
[NAME OF PRODUCER]
Agreed to and approved this ______ day of
_____________________, 1999.
By:
Title:
TEJAS NATURAL GAS LIQUIDS, LLC
Agreed to and approved this ______ day of
_____________________, 1999.
By:
Title:
39
