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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2001
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number: 1-14323
Enterprise Products Partners L.P.
(Exact name of Registrant as specified in its charter)
Delaware 76-0568219
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2727 North Loop West
Houston, Texas
77008-1037
(Address of principal executive offices) (Zip code)
(713) 880-6500
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days.
Yes _X_ No ___
The registrant had 51,524,515 Common Units outstanding as of August 13, 2001.
Enterprise Products Partners L.P. and Subsidiaries
TABLE OF CONTENTS
Page
No.
----
Glossary
Part I. Financial Information
Item 1. Consolidated Financial Statements
Enterprise Products Partners L.P. Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets, June 30, 2001 and December 31, 2000 1
Statements of Consolidated Operations
for the three and six months ended June 30, 2001 and 2000 2
Statements of Consolidated Cash Flows
for the three and six months ended June 30, 2001 and 2000 3
Statements of Consolidated Partners' Equity and Comprehensive Income
for the three and six months ended June 30, 2001 and 2000 4
Notes to Unaudited Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operation 22
Item 3. Quantitative and Qualitative Disclosures about Market Risk 36
Part II. Other Information
Item 2. Use of Proceeds 40
Item 6. Exhibits and Reports on Form 8-K 41
Signature Page
Glossary
The following abbreviations, acronyms or terms used in this Form 10-Q are defined below:
Acadian Gas Acadian Gas, LLC
BBtu/d Billion British thermal units per day, a measure of heating value
Bcf Billion cubic feet
Bcf/d Billion cubic feet per day
BPD Barrels per day
Btu British thermal unit, a measure of heating value
Company Enterprise Products Partners L.P. and subsidiaries
Enron Enron North America Corp. and subsidiaries
EPCO Enterprise Products Company, an affiliate of the Company
EPE El Paso Corporation, its subsidiaries and affiliates
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
General Partner Enterprise Products GP, LLC, the general partner of the Company and Operating
Partnership
Manta Ray A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Manta Ray
Offshore Gathering Company, LLC
MBFC Mississippi Business Finance Corporation
MBPD Thousand barrels per day
MLP Denotes Enterprise Products Partners L.P. as guarantor of certain debt obligations of
the Operating Partnership
MMBbls Millions of barrels
MMBtus Million British thermal units, a measure of heating value
MMcf Million cubic feet
MMcf/d Million cubic feet per day
MTBE Methyl tertiary butyl ether
Nautilus A Gulf of Mexico offshore Louisiana natural gas pipeline system owned by Nautilus
Pipeline Company, LLC
NGL or NGLs Natural gas liquid(s)
NYSE New York Stock Exchange
Operating Partnership Enterprise Products Operating L.P. and subsidiaries
Operating Surplus As defined within the Partnership Agreement
Partnership Agreement Second Amended and Restated Agreement of Limited Partnership of the Company
PTR Plant thermal reduction
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
Shell Shell Oil Company, its subsidiaries and affiliates
Subordination Period As defined within the Partnership Agreement
TNGL acquisition Refers to the acquisition of Tejas Natural Gas Liquids, LLC from Shell effective
August 1, 1999
PART 1. FINANCIAL INFORMATION.
Item 1. CONSOLIDATED FINANCIAL STATEMENTS.
Enterprise Products Partners L.P.
Consolidated Balance Sheets
(Dollar amounts in thousands)
June 30,
2001 December 31,
ASSETS (Unaudited) 2000
---------------------------------------
Current Assets
Cash and cash equivalents (includes restricted cash of $7,321 at June 30, $ 123,279 $ 60,409
2001)
Accounts receivable - trade, net of allowance for doubtful accounts of
$17,032 at June 30, 2001 and $10,916 at December 31, 2000 383,680 409,085
Accounts receivable - affiliates 9,011 6,533
Inventories 99,783 93,222
Prepaid and other current assets 79,260 12,107
---------------------------------------
Total current assets 695,013 581,356
Property, Plant and Equipment, Net 1,232,792 975,322
Investments in and Advances to Unconsolidated Affiliates 414,808 298,954
Intangible assets, net of accumulated amortization of $7,874 at
June 30, 2001 and $5,374 at December 31, 2000 90,369 92,869
Other Assets 9,011 2,867
---------------------------------------
Total $2,441,993 $1,951,368
=======================================
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Accounts payable - trade $ 59,208 $ 96,559
Accounts payable - affiliate 51,266 56,447
Accrued gas payables 353,444 377,126
Accrued expenses 12,804 21,488
Other current liabilities 81,381 34,759
---------------------------------------
Total current liabilities 558,103 586,379
Long-Term Debt 855,608 403,847
Other Long-Term liabilities 17,260 15,613
Minority Interest 10,318 9,570
Commitments and Contingencies
Partners' Equity
Common Units (46,257,315 Units outstanding at June 30, 2001
and December 31, 2000) 565,469 514,896
Subordinated Units (21,409,870 Units outstanding at June 30, 2001
and December 31, 2000) 188,390 165,253
Special Units (16,500,000 Units outstanding at June 30, 2001
and December 31, 2000) 251,132 251,132
Treasury Units acquired by Trust, at cost (267,200 Common Units
outstanding at June 30, 2001 and December 31, 2000) (4,727) (4,727)
General Partner 10,151 9,405
Accumulated other comprehensive income (9,711)
---------------------------------------
Total Partners' Equity 1,000,704 935,959
---------------------------------------
Total $2,441,993 $1,951,368
=======================================
See Notes to Unaudited Consolidated Financial Statements
Page 1
Enterprise Products Partners L.P.
Statements of Consolidated Operations
(Unaudited)
(Amounts in thousands, except per Unit amounts)
Three Months Six Months
Ended June 30, Ended June 30,
------------------------------- -------------------------------
2001 2000 2001 2000
------------------------------- -------------------------------
REVENUES
Revenues from consolidated operations $959,397 $592,913 $1,795,712 $1,339,194
Equity income in unconsolidated affiliates 9,050 11,097 11,061 18,540
------------------------------- -------------------------------
Total 968,447 604,010 1,806,773 1,357,734
COST AND EXPENSES
Operating costs and expenses 851,639 546,306 1,629,380 1,219,212
Selling, general and administrative 7,737 7,658 13,905 13,042
------------------------------- -------------------------------
Total 859,376 553,964 1,643,285 1,232,254
------------------------------- -------------------------------
OPERATING INCOME 109,071 50,046 163,488 125,480
OTHER INCOME (EXPENSE)
Interest expense (16,331) (8,070) (23,318) (15,844)
Interest income from unconsolidated affiliates 7 126 31 270
Dividend income from unconsolidated affiliates 2,761 1,632 3,995
Interest income - other 1,479 1,225 5,477 2,706
Other, net (251) (62) (531) (425)
------------------------------- -------------------------------
Other income (expense) (15,096) (4,020) (16,709) (9,298)
------------------------------- -------------------------------
INCOME BEFORE MINORITY INTEREST 93,975 46,026 146,779 116,182
MINORITY INTEREST (944) (466) (1,478) (1,175)
------------------------------- -------------------------------
NET INCOME $ 93,031 $ 45,560 $ 145,301 $ 115,007
=============================== ===============================
ALLOCATION OF NET INCOME TO:
Limited partners $ 91,643 $ 45,104 $ 142,931 $ 113,857
=============================== ===============================
General partner $ 1,388 $ 456 $ 2,370 $ 1,150
=============================== ===============================
BASIC EARNINGS PER UNIT
Income before minority interest $ 1.37 $ 0.68 $ 2.13 $ 1.72
=============================== ===============================
Net income per Common and Subordinated unit $ 1.35 $ 0.68 $ 2.11 $ 1.71
=============================== ===============================
DILUTED EARNINGS PER UNIT
Income before minority interest $ 1.10 $ 0.56 $ 1.72 $ 1.42
=============================== ===============================
Net income per Common, Subordinated
and Special unit $ 1.09 $ 0.56 $ 1.70 $ 1.40
=============================== ===============================
See Notes to Unaudited Consolidated Financial Statements
Page 2
Enterprise Products Partners L.P
Statements of Consolidated Cash Flows
(Unaudited)
(Dollar amounts in Thousands)
Six Months Ended
June 30,
-------------------------------------
2001 2000
-------------------------------------
OPERATING ACTIVITIES
Net income $145,301 $115,007
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities:
Depreciation and amortization 23,234 18,347
Equity in income of unconsolidated affiliates (11,061) (18,540)
Distributions received from unconsolidated affiliates 13,212 14,268
Leases paid by EPCO 5,267 5,270
Minority interest 1,478 1,175
Gain (loss) on sale of assets (387) 2,303
Changes in fair market value of financial instruments (see Note 10) (55,880)
Net effect of changes in operating accounts (30,569) 57,003
-------------------------------------
Operating activities cash flows 90,595 194,833
-------------------------------------
INVESTING ACTIVITIES
Capital expenditures (57,090) (154,246)
Proceeds from sale of assets 563 52
Business acquisitions, net of cash received (225,665)
Collection of notes receivable from unconsolidated affiliates 6,519
Investments in and advances to unconsolidated affiliates (115,282) (3,040)
-------------------------------------
Investing activities cash flows (397,474) (150,715)
-------------------------------------
FINANCING ACTIVITIES
Long-term debt borrowings 449,716 463,818
Long-term debt repayments (355,000)
Debt issuance costs (3,125) (2,759)
Cash dividends paid to partners (76,112) (67,639)
Cash dividends paid to minority interest by Operating Partnership (783) (690)
Cash contributions from EPCO to minority interest 53 57
Increase in restricted cash (7,321)
-------------------------------------
Financing activities cash flows 362,428 37,787
-------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS 55,549 81,905
CASH AND CASH EQUIVALENTS, JANUARY 1 60,409 5,230
-------------------------------------
CASH AND CASH EQUIVALENTS, JUNE 30 $115,958 $ 87,135
=====================================
See Notes to Unaudited Consolidated Financial Statements
Page 3
Enterprise Products Partners L.P.
Statements of Consolidated Partners' Equity and
Comprehensive Income
(Unaudited, amounts in thousands)
Partners' Equity
----------------------------------------------------------------------------
at June 30, 2001 at June 30, 2000
------------------------------------- -------------------------------------
Units Amount Units Amount
------------------------------------- -------------------------------------
Limited Partners
Balance, beginning of year 84,434 $ 931,281 81,463 $786,250
Net income 142,931 113,857
Leases paid by EPCO 5,213 5,218
Cash distributions (74,434) (66,964)
------------------------------------- -------------------------------------
Balance, end of period 84,434 1,004,991 81,463 838,361
------------------------------------- -------------------------------------
------------------------------------- -------------------------------------
Treasury Units (267) (4,727) (267) (4,727)
------------------------------------- -------------------------------------
General Partner
Balance, beginning of year 9,405 7,942
Net income 2,370 1,150
Leases paid by EPCO 54 53
Cash distributions (1,678) (676)
------------------- ------------------
Balance, end of period 10,151 8,469
------------------- ------------------
Accumulated Other
Comprehensive Loss
Balance, beginning of year
Cumulative transition adjustment
recorded on January 1, 2001
upon adoption of SFAS 133 (42,190)
(see Note 10)
Reclassification of cumulative
transition adjustment to
earnings 32,479
-------------------
Balance, end of period (9,711)
-------------------
------------------------------------- -------------------------------------
Total Partners' Equity 84,167 $1,000,704 81,196 $842,103
===================================== =====================================
Comprehensive Income
For Six Months Ended
----------------------------------------------------------------------------
at June 30, 2001 at June 30, 2000
------------------------------------- -------------------------------------
Net Income $145,301 $115,007
Less: Accumulated Other
Comprehensive Loss (9,711)
------------------- ------------------
Comprehensive Income $135,590 $115,007
=================== ==================
See Notes to Unaudited Consolidated Financial Statements
Page 4
Enterprise Products Partners L.P.
Notes to Unaudited Consolidated Financial Statements
1. GENERAL
In the opinion of Enterprise Products Partners L.P. (the "Company"), the accompanying unaudited consolidated
financial statements include all adjustments consisting of normal recurring accruals necessary for a fair
presentation of the Company's consolidated financial position as of June 30, 2001 and consolidated results of
operations, cash flows, partners' equity and comprehensive income for the three and six month periods ended June
30, 2001 and 2000. Although the Company believes the disclosures in these financial statements are adequate to
make the information presented not misleading, certain information and footnote disclosures normally included in
annual financial statements prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. These
unaudited financial statements should be read in conjunction with the financial statements and notes thereto
included in the Company's annual report on Form 10-K (File No. 1-14323) for the year ended December 31, 2000.
The preparation of financial statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
The results of operations for the three and six month periods ended June 30, 2001 are not necessarily indicative
of the results to be expected for the full year due to the effects of, among other things, (a) seasonal
variations in NGL and natural gas prices, (b) timing of maintenance and other expenditures and (c) acquisitions
of assets and other interests.
Certain reclassifications have been made to prior years' financial statements to conform to the presentation of
the current period financial statements. These reclassifications do not affect historical earnings of the
Company.
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
The Company owns interests in a number of related businesses that are accounted for under the equity method or
cost method. The investments in and advances to these unconsolidated affiliates are grouped according to the
operating segment to which they relate. For a general discussion of the Company's business segments, see Note
11.
At June 30, 2001, the Company's equity method investments (grouped by operating segment) included:
Fractionation segment:
o Baton Rouge Fractionators LLC ("BRF") - an approximate 32.25% interest in a natural gas liquid ("NGL")
fractionation facility located in southeastern Louisiana.
o Baton Rouge Propylene Concentrator, LLC ("BRPC") - a 30.0% interest in a propylene concentration unit
located in southeastern Louisiana.
o K/D/S Promix LLC ("Promix") - a 33.33% interest in a NGL fractionation facility and related storage
facilities located in south Louisiana. The Company's investment includes excess cost over the underlying
equity in the net assets of Promix of $8.0 million which is being amortized using the straight-line method
over a period of 20 years. The unamortized balance of excess cost over the underlying equity in the net
assets of Promix was $7.2 million at June 30, 2001.
Page 5
Pipeline segment:
o EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, "EPIK") - a 50% aggregate interest in a
refrigerated NGL marine terminal loading facility located in southeast Texas.
o Wilprise Pipeline Company, LLC ("Wilprise") - a 37.35% interest in a NGL pipeline system located in
southeastern Louisiana.
o Tri-States NGL Pipeline LLC ("Tri-States") - an aggregate 33.33% interest in a NGL pipeline system
located in Louisiana, Mississippi, and Alabama.
o Belle Rose NGL Pipeline LLC ("Belle Rose") - a 41.67% interest in a NGL pipeline system located in
south Louisiana.
o Dixie Pipeline Company ("Dixie") - a 19.9% interest in a 1,301-mile propane pipeline and associated
facilities extending from Mont Belvieu, Texas to North Carolina.
o Starfish Pipeline Company LLC ("Starfish") - a 50% interest in a natural gas gathering system and
related dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore
Louisiana.
o Ocean Breeze Pipeline Company LLC ("Ocean Breeze") - a 25.67% interest in a limited liability company
("LLC") owning a 1% interest in the natural gas gathering and transmission systems owned by Manta Ray
Offshore Gathering Company, LLC ("Manta Ray") and Nautilus Pipeline Company LLC ("Nautilus") located in the
Gulf of Mexico offshore Louisiana.
o Neptune Pipeline Company LLC ("Neptune") - a 25.67% interest in a limited liability company owning a 99%
interest in the Manta Ray and Nautilus natural gas gathering and transmission systems.
o Nemo Gathering Company, LLC ("Nemo") - a 33.92% interest in a natural gas gathering system being
constructed in the Gulf of Mexico offshore Louisiana. The system is scheduled for completion during the
third quarter of 2001.
o Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, "Evangeline") - an
approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana. The
Company acquired its interests in these entities as a result of the Acadian Gas, LLC acquisition (see Note 3
for a description of this acquisition).
2001 Gulf of Mexico natural gas pipeline equity investments
The Company acquired its equity interests in Ocean Breeze, Neptune, Nemo and Starfish and their underlying
investments on January 29, 2001 from EPE using proceeds from the issuance of the $450 Million Senior Notes
(see Note 5 for discussion of long-term debt). The cash purchase price of the Ocean Breeze, Neptune and
Nemo interests was $86.9 million with the purchase price of the Starfish interests being $25.1 million.
As a result of its investment in Ocean Breeze and Neptune, the Company acquired a 25.67% interest in each of
the Manta Ray and Nautilus systems and a 33.92% interest in the Nemo system. Affiliates of Shell own an
interest in all three systems, and an affiliate of Marathon Oil Company owns an interest in the Manta Ray
and Nautilus systems. The Manta Ray system comprises approximately 225 miles of pipeline with a capacity
of 750 MMcf/d and related equipment, the Nautilus system comprises approximately 101 miles of pipeline with
a capacity of 600 MMcf/d, and the Nemo system, when completed in the third quarter of 2001, will comprise
approximately 24 miles of pipeline with a capacity of 300 MMcf/d. Shell is responsible for the commercial
and physical operations of these pipeline systems.
The Company's investment in Ocean Breeze and Neptune includes excess cost over the underlying equity in the
net assets of these entities of $22.7 million which is being amortized using the straight-line method over a
period of 35 years (as a pipeline asset). The unamortized balance of excess cost over the underlying
equity in the net assets of Ocean Breeze and Neptune was $22.4 million at June 30, 2001. Likewise, the
Company's investment in Nemo includes excess cost over the underlying equity in the net assets of $0.8
million which will be amortized using the straight-line method over a period of 35 years (as a pipeline
asset) when Nemo becomes operational during the third quarter of 2001.
As a result of its investment in Starfish, the Company acquired a 50% interest in the Stingray system and a
related onshore natural gas dehydration facility. The Company's sole partner in Starfish is an affiliate of
Shell. The Stingray system comprises approximately 375 miles of pipeline with a capacity of 1.2 Bcf per
Page 6
day and is located offshore Louisiana in the Gulf of Mexico. Shell is responsible for the commercial and
physical operations of the Stingray system and related facilities.
Historical information for periods prior to January 1, 2001 do not reflect any impact associated with the
Company's equity investments in Ocean Breeze, Neptune, Nemo and Starfish. See Note 3 for combined pro
forma impact of these investments on selected financial information of the Company.
Octane Enhancement segment:
o Belvieu Environmental Fuels ("BEF") - a 33.33% interest in a MTBE production facility located in
southeast Texas. The production of MTBE is driven by oxygenated fuels programs enacted under the federal
Clean Air Act Amendments of 1990 and other legislation. Any changes to these programs that enable
localities to elect not to participate in these programs, lessen the requirements for oxygenates or favor
the use of non-isobutane based oxygenated fuels reduce the demand for MTBE and could have an adverse effect
on the Company's results of operations.
In recent years, MTBE has been detected in water supplies. The major source of the ground water
contamination appears to be leaks from underground storage tanks. Although these detections have been
limited and the great majority have been well below levels of public health concern, there have been calls
for the phase-out of MTBE in motor gasoline in various federal and state governmental agencies and advisory
bodies.
In light of these developments, the owners of BEF have been formulating a contingency plan for use of the
BEF facility if MTBE were banned or significantly curtailed. Management is exploring a possible conversion
of the BEF facility from MTBE production to alkylate production. Depending upon the type of alkylate
process chosen and the level of alkylate production desired, the cost to convert the facility from MTBE
production to alkylate production can range from $20 million to $90 million, with the Company's share of
these costs ranging from $6.7 million to $30 million.
At June 30, 2001, the Company's investments in and advances to unconsolidated affiliates also includes Venice
Energy Services Company, LLC ("VESCO"). The VESCO investment consists of a 13.1% interest in a LLC owning a
natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines in Louisiana. This
investment is accounted for using the cost method under the Processing segment.
Page 7
The following table summarizes investments in and advances to unconsolidated affiliates at:
June 30, December 31,
2001 2000
-------------------------------------
Accounted for on equity basis:
Fractionation:
BRF $ 30,210 $ 30,599
BRPC 19,638 25,925
Promix 48,214 48,670
Pipeline:
EPIK 15,467 15,998
Wilprise 8,617 9,156
Tri-States 27,238 27,138
Belle Rose 11,591 11,653
Dixie 38,179 38,138
Starfish 26,763
Ocean Breeze 960
Neptune 76,282
Nemo 10,814
Evangeline 5,574
Octane Enhancement:
BEF 62,261 58,677
Accounted for on cost basis:
Processing:
VESCO 33,000 33,000
-------------------------------------
Total $414,808 $298,954
=====================================
The following table shows equity in income (loss) of unconsolidated affiliates for the periods indicated:
For Three Months Ended For Six Months Ended
June 30, June 30,
------------------------------------- -------------------------------------
2001 2000 2001 2000
------------------------------------- -------------------------------------
Fractionation:
BRF $ 42 $ 208 $ 60 $ 737
BRPC 252 (29) 404 (19)
Promix 1,396 1,546 1,789 3,208
Pipeline:
EPIK (172) 178 (1,094) 1,970
Wilprise 85 74 (137) 162
Tri-States 135 843 100 1,521
Belle Rose 29 (30) (60) 149
Dixie 69 960
Starfish 1,022 1,973
Ocean Breeze 12 14
Neptune 1,095 1,789
Nemo 1 10
Evangeline (149) (149)
Octane Enhancement:
BEF 5,233 8,307 5,402 10,812
------------------------------------- -------------------------------------
Total $9,050 $11,097 $11,061 $18,540
===================================== =====================================
Page 8
The following table presents summarized income statement information for the unconsolidated affiliates accounted
for by the equity method for the periods indicated (on a 100% basis):
Summarized Income Statement data for the Six Months ended
-----------------------------------------------------------------------------------------------
June 30, 2001 June 30, 2000
---------------------------------------------- -----------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
---------------------------------------------- -----------------------------------------------
Fractionation:
BRF $ 7,825 $ 300 $ 350 $ 9,215 $ 2,222 $ 2,284
BRPC 6,833 1,232 1,347 (187) (65)
Promix 21,343 5,888 5,964 24,726 10,141 10,255
Pipeline:
EPIK 1,967 (1,782) (1,725) 12,972 3,884 3,981
Wilprise 893 (378) (367) 1,423 470 485
Tri-States 3,953 262 299 7,247 4,470 4,562
Belle Rose 554 (205) (192) 1,266 366 366
Dixie (a) 24,036 8,301 4,829
Starfish (b) 13,467 4,390 3,916
Ocean Breeze (b) 87 87 65
Neptune (b) 16,747 8,648 8,581
Nemo (b) (42) 36
Evangeline (c) 47,609 1,010 (144)
Octane Enhancement:
BEF 113,918 15,922 16,207 137,430 32,373 32,437
---------------------------------------------- -----------------------------------------------
Total $259,232 $43,633 $39,166 $194,279 $53,739 $54,305
============================================== ===============================================
Summarized Income Statement data for the Three Months ended
-----------------------------------------------------------------------------------------------
June 30, 2001 June 30, 2000
---------------------------------------------- -----------------------------------------------
Operating Net Operating Net
Revenues Income Income Revenues Income Income
---------------------------------------------- -----------------------------------------------
Fractionation:
BRF $ 3,802 $ 265 $ 294 $ 4,244 $ 569 $ 648
BRPC 3,400 793 842 (187) (99)
Promix 12,340 4,447 4,487 12,517 4,752 4,809
Pipeline:
EPIK 792 (375) (348) 3,816 324 387
Wilprise 494 224 227 691 212 222
Tri-States 2,321 388 403 3,513 2,490 2,527
Belle Rose 407 13 21 409 (64) (64)
Dixie (a) 8,799 2,001 1,124
Starfish (b) 7,051 2,571 2,299
Ocean Breeze (b) 53 39 39
Neptune (b) 9,362 5,223 5,195
Nemo (b) (27) 2
Evangeline (c) 47,609 1,010 (144)
Octane Enhancement:
BEF 76,054 15,509 15,700 84,097 24,766 24,921
---------------------------------------------- -----------------------------------------------
Total $172,484 $32,081 $30,141 $109,287 $32,862 $33,351
============================================== ===============================================
Page 9
Notes to Summarized Income Statement data tables:
(a) Dixie became an equity method investment in October 2000.
(b) These entities became equity method investments of the Company beginning in January 2001.
(c) This entity became an equity method investment of the Company in April 2001 as a result of the Acadian Gas
acquisition (see Note 3).
3. ACQUISITIONS
Since January 1, 2001, the Company has invested approximately $338 million (net of cash acquired) in natural gas
pipeline businesses. These include:
o a combined $112 million in Ocean Breeze, Neptune, Nemo and Starfish (see Note 2 for a discussion of
these equity investments); and,
o an initial $226 million for the purchase of Acadian Gas, LLC ("Acadian Gas").
Acquisition of Acadian Gas
On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an affiliate of Shell, for
approximately $226 million in cash using proceeds from the issuance of the $450 Million Senior Notes. The cash
purchase price is subject to certain post-closing adjustments expected to be completed during the third quarter
of 2001 (see below). The effective date of the transaction was April 1, 2001.
Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. Acadian
Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas pipeline
systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are wholly-owned by
Acadian Gas with the exception of the Evangeline system in which Acadian Gas owns an aggregate 49.5% interest.
The assets acquired include a leased natural gas storage facility located in Napoleonville, Louisiana.
The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and, through
connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies, electric
generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor.
In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.
The Acadian Gas acquisition was accounted for under the purchase method of accounting and, accordingly, the
initial purchase price has been allocated to the assets acquired and liabilities assumed based on their estimated
fair values at April 1, 2001, as follows:
Current assets $83,123
Investments in unconsolidated affiliates 2,723
Property, plant and equipment 220,856
Current liabilities (79,577)
Other long-term liabilities (1,460)
---------------
Total purchase price $225,665
===============
The balances related to the Acadian Gas acquisition included in the consolidated balance sheet dated June 30,
2001 are based upon preliminary information and are subject to change as additional information is obtained. As
noted earlier, the initial purchase price is subject to certain post-closing adjustments attributable to working
capital items expected to be finalized during the third quarter of 2001.
Historical information for periods prior to April 1, 2001 do not reflect any impact associated with the Acadian
Gas acquisition.
Page 10
Pro Forma effect of Acadian Gas acquisition and recently acquired equity investments
The following table presents selected unaudited pro forma information for the three month period ended June 30,
2000 and six month periods ended June 30, 2001 and 2000 as if the acquisition of the Acadian Gas natural gas
pipeline systems had been made as of the beginning of the years presented. This table also incorporates selected
unaudited pro forma information for the three and six month periods ended June 30, 2000 relating to the Company's
equity investments in Starfish, Ocean Breeze and Neptune.
The pro forma information is based upon information currently available to and certain estimates and assumptions
by management and, as a result, are not necessarily indicative of the financial results of the Company had the
transactions actually occurred on these dates. Likewise, the unaudited pro forma information is not necessarily
indicative of future financial results of the Company.
Three Months Six Months Ended
Ended June 30,
------------------------------------
June 30, 2000 2001 2000
-------------------------------------------------------
Revenues $756,769 $2,018,700 $1,608,252
=======================================================
Income before extraordinary item
and minority interest $ 45,502 $151,063 $ 115,187
=======================================================
Net income $ 45,041 $149,542 $ 114,022
=======================================================
Allocation of net income to
Limited partners $ 44,590 $147,130 $ 112,881
=======================================================
General Partner $ 450 $ 2,412 $ 1,140
=======================================================
Units used in earnings per Unit calculations
Basic 66,696 67,667 66,696
=======================================================
Diluted 81,196 84,167 81,196
=======================================================
Income per Unit before minority interest
Basic $ 0.68 $ 2.20 $ 1.71
=======================================================
Diluted $ 0.56 $ 1.77 $ 1.40
=======================================================
Net income per Unit
Basic $ 0.67 $ 2.17 $ 1.69
=======================================================
Diluted $ 0.55 $ 1.75 $ 1.39
=======================================================
4. RECENTLY ISSUED ACCOUNTING STANDARDS
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, " Business Combinations", and SFAS No. 142,
"Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest method for
business combinations initiated after June 30, 2001 and also applies to all business combinations accounted for
by the purchase method that are completed after June 30, 2001. There are also transition provisions that apply
to business combinations completed before July 1, 2001, that were accounted for by the purchase method. SFAS 142
is effective for fiscal years beginning after December 15, 2001 to all goodwill and other intangible assets
recognized in an entity's statement of financial position at that date, regardless of when those assets were
Page 11
initially recognized. The Company is currently evaluating the provisions of SFAS 141 and SFAS 142 and has not
adopted such provisions in its June 30, 2001 financial statements.
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
June 30, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 350,000 350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
------------------------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 2,015
Less unamortized discount on:
$350 Million Senior Notes (135) (153)
$450 Million Senior Notes (272)
Less current maturities of long-term debt
------------------------------------
Long-term debt $855,608 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility and $150
Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit
facilities at June 30, 2001 or December 31, 2000.
At June 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its $250
Million Multi-Year Credit Facility of which $19.9 million was outstanding.
$450 Million Senior Notes. On January 24, 2001, a subsidiary of the Company completed a public offering of $450
million in principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of
99.937% per Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting
discounts and commissions, of approximately $446.8 million. The proceeds from this offering were used to
acquire the Acadian Gas, Ocean Breeze, Neptune, Nemo and Starfish natural gas pipeline systems for $338 million
and to finance the cost to construct certain NGL pipelines and related projects and for working capital and other
general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is also
applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As with
the $350 Million Senior Notes, the $450 Million Senior Notes:
o are subject to a make-whole redemption right;
o are an unsecured obligation and rank equally with existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness; and,
o are guaranteed by the Company through an unsecured and unsubordinated guarantee.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 $800 million
universal registration statement; therefore, the amount of securities available under this registration statement
was reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration
statement (the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity
or debt securities or a combination thereof. The Company expects to use the net proceeds from any sale of
securities under the February 2001 Registration Statement for future business acquisitions and other general
Page 12
corporate purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or
the repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will
be applied to partnership purposes will depend on a number of factors, including the Company's funding
requirements and the availability of alternative funding sources. The Company routinely reviews acquisition
opportunities.
The Company was in compliance with the restrictive covenants associated with all of its fixed-rate and
variable-rate debt instruments at June 30, 2001.
Increase in fair value of fixed-rate debt. Upon adoption of SFAS 133, Accounting for Derivative Instruments and
Hedging Activities (as amended and interpreted) on January 1, 2001, the Company recorded a $2.3 million non-cash
increase in the fair value of its fixed-rate debt. SFAS 133 required that the Company's interest rate swaps and
their associated hedged fixed-rate debt be recorded at fair value upon adoption of the standard. After adoption
of the standard, the interest rate swaps were dedesignated due to differences in the estimated maturity dates of
the interest rate swaps versus the fixed-rate debt. As a result, the fair value of the hedged fixed-rate debt
will not be adjusted for future changes in fair value and the $2.3 million increase in the fair value of the debt
will be amortized to earnings over the remaining life of the fixed-rate debt to which it applies, which
approximates 10 years. The fair value adjustment of $2.3 million is not a cash obligation of the Company and
does not alter the amount of the Company's indebtedness. See Note 10 for additional information concerning the
Company's financial instruments.
6. CAPITAL STRUCTURE
Final issue of Special Units. On or about June 30, 2001, Shell met certain year 2001 performance criteria for
the issuance of the last installment of 3.0 million non-distribution bearing, convertible Contingency Units
(referred to as Special Units once they are issued). Per a contingent unit agreement with Shell, the Company
issued these Special Units on August 2, 2001.
The value of these Special Units was determined to be $117.1 million using present value techniques. This
amount will increase the purchase price of the TNGL acquisition and the value of the Shell Processing Agreement
when the issue is recorded during the third quarter of 2001. The $117.1 million increase in value of the Shell
Processing Agreement will be amortized over the remaining life of the contract. As a result, amortization
expense will increase by approximately $1.6 million per quarter ($6.5 million annually).
Conversion of Special Units to Common Units. In accordance with existing agreements with Shell, 5.0 million of
Shell's original issue of Special Units converted into Common Units on August 2, 2001.
Page 13
7. EARNINGS PER UNIT
Basic earnings per Unit is computed by dividing net income available to limited partner interests by the
weighted-average number of Common and Subordinated Units outstanding during the period. Diluted earnings per
Unit is computed by dividing net income available to limited partner interests by the weighted-average number of
Common, Subordinated and Special Units outstanding during the period. The following table reconciles the
number of shares used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three
and six months ended June 30, 2001 and 2000:
For Three Months Ended For Six Months Ended
June 30, June 30,
------------------------------------- ------------------------------------
2001 2000 2001 2000
------------------------------------- ------------------------------------
Income before minority interest $93,975 $46,026 $146,779 $116,182
General partner interest (1,388) (456) (2,370) (1,150)
------------------------------------- ------------------------------------
Income before minority interest 92,587 45,570 144,409 115,032
available to Limited Partners
Minority interest (944) (466) (1,478) (1,175)
------------------------------------- ------------------------------------
Net income available to Limited Partners $91,643 $45,104 $142,931 $113,857
===================================== ====================================
BASIC EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $92,587 $45,570 $144,409 $115,032
Net income available
to Limited Partners $91,643 $45,104 $142,931 $113,857
Denominator
Common Units outstanding 46,257 45,286 46,257 45,286
Subordinated Units outstanding 21,410 21,410 21,410 21,410
------------------------------------- ------------------------------------
Total 67,667 66,696 67,667 66,696
===================================== ====================================
Basic Earnings per Unit
Income before minority interest
available to Limited Partners $ 1.37 $ 0.68 $ 2.13 $ 1.72
===================================== ====================================
Net income available
to Limited Partners $ 1.35 $ 0.68 $ 2.11 $ 1.71
===================================== ====================================
DILUTED EARNINGS PER UNIT
Numerator
Income before minority interest
available to Limited Partners $92,587 $45,570 $144,409 $115,032
Net income available
to Limited Partners $91,643 $45,104 $142,931 $113,857
Denominator
Common Units outstanding 46,257 45,286 46,257 45,286
Subordinated Units outstanding 21,410 21,410 21,410 21,410
Special Units outstanding 16,500 14,500 16,500 14,500
------------------------------------- ------------------------------------
Total 84,167 81,196 84,167 81,196
===================================== ====================================
Diluted Earnings per Unit
Income before minority interest
available to Limited Partners $ 1.10 $ 0.56 $ 1.72 $ 1.42
===================================== ====================================
Net income available
to Limited Partners $ 1.09 $ 0.56 $ 1.70 $ 1.40
===================================== ====================================
Page 14
8. DISTRIBUTIONS
The Company intends, to the extent there is sufficient available cash from Operating Surplus, as defined by the
Partnership Agreement, to distribute to each holder of Common Units at least a minimum quarterly distribution of
$0.45 per Common Unit. The minimum quarterly distribution is not guaranteed and is subject to adjustment as set
forth in the Partnership Agreement. With respect to each quarter during the Subordination Period, the Common
Unitholders will generally have the right to receive the minimum quarterly distribution, plus any arrearages
thereon, and the General Partner will have the right to receive the related distribution on its interest before
any distributions of available cash from Operating Surplus are made to the Subordinated Unitholders. As an
incentive, the General Partner's interest in quarterly distributions is increased after certain specified target
levels are met. The Company made incentive cash distributions to the General Partner of $0.5 million and $0.9
million during the three and six months ended June 30, 2001 and none during the same periods in 2000.
On January 17, 2000, the Company declared an increase in its quarterly cash distribution to $0.50 per Unit.
This amount was subsequently raised to $0.525 per Unit on July 17, 2000 and $0.55 per Unit on December 7, 2000.
On May 3, 2001, the Board of Directors of the General Partner approved an increase in the quarterly distribution
rate to $.5875 per Unit beginning with the distribution pertaining to the second quarter of 2001 (payable in
August 2001).
The following is a summary of cash distributions to partnership interests since the first quarter of 1999:
Cash Distributions
--------------------------------------------------------------------
Per
Per Common Subordinated Record Payment
Unit Unit Date Date
--------------------------------------------------------------------
1999 First Quarter $ 0.450 $ 0.450 Jan. 29, 1999 Feb. 11, 1999
Second Quarter $ 0.450 $ 0.070 Apr. 30, 1999 May 12, 1999
Third Quarter $ 0.450 $ 0.370 Jul. 30, 1999 Aug. 11, 1999
Fourth Quarter $ 0.450 $ 0.450 Oct. 29, 1999 Nov. 10, 1999
2000 First Quarter $ 0.500 $ 0.500 Jan. 31, 2000 Feb. 10, 2000
Second Quarter $ 0.500 $ 0.500 Apr. 28, 2000 May 10, 2000
Third Quarter $ 0.525 $ 0.525 Jul. 31, 2000 Aug. 10, 2000
Fourth Quarter $ 0.525 $ 0.525 Oct. 31, 2000 Nov. 10, 2000
2001 First Quarter $ 0.550 $ 0.550 Jan. 31, 2001 Feb. 9, 2001
Second Quarter $ 0.550 $ 0.550 Apr. 30, 2001 May 10, 2001
Third Quarter $ 0.5875 $ 0.5875 Jul. 31, 2001 Aug. 10, 2001
(through August 13, 2001)
Page 15
9. SUPPLEMENTAL CASH FLOW DISCLOSURE
The net effect of changes in operating assets and liabilities is as follows for the periods indicated:
Six Months Ended
June 30,
------------------------------------------
2001 2000
------------------------------------------
(Increase) decrease in:
Accounts receivable $ 96,860 $ 66,374
Inventories 522 (104,477)
Prepaid and other current assets (10,831) 3,154
Intangible assets (3,736)
Other assets (129) (1,890)
Increase (decrease) in:
Accounts payable (55,755) (64,675)
Accrued gas payable (78,008) 168,683
Accrued expenses (11,232) (11,698)
Other current liabilities 27,817 5,904
Other liabilities 187 (636)
------------------------------------------
Net effect of changes in operating accounts $(30,569) $ 57,003
==========================================
Business acquisitions (net of cash received) for the 2001 period reflects a net $226 million paid to an affiliate
of Shell for Acadian Gas. Investments in and advances to unconsolidated affiliates for the 2001 period reflects
$112 million paid to EPE for equity interests in various Gulf of Mexico natural gas pipeline systems. Capital
expenditures for 2000 included $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets.
As a result of the Company's adoption of SFAS 133 on January 1, 2001, the Company records various financial
instruments relating to interest rate and commodity positions at their respective fair values. For the six
months ended June 30, 2001, the Company recognized a net $55.9 million in non-cash mark-to-market gains related
to increases in the fair value of these financial instruments ($52.5 million of this amount was attributable to
commodity financial instruments with the remainder resulting from interest rate hedging activities). See Note
10 below for a further description of the Company's financial instruments.
Cash and cash equivalents at June 30, 2001 per the Statements of Consolidated Cash Flows excludes $7.3 million of
restricted cash associated with commodity hedging activities.
10. FINANCIAL INSTRUMENTS
The Company holds and issues financial instruments for the purpose of hedging the risks of certain identifiable
and anticipated transactions. In general, the types of risks hedged are those relating to the variability of
future earnings and cash flows caused by changes in commodity prices and interest rates.
Commodity Financial Instruments - Gas Processing and related NGL and natural gas businesses
The Company is exposed to commodity price risk through its natural gas processing and related NGL and natural gas
businesses. In order to effectively manage this risk, the Company may enter into swaps, forwards, commodity
futures, options and other commodity financial instruments with similar characteristics that are permitted by
contract or business custom to be settled in cash or with another financial instrument. The purpose of these
risk management activities is to hedge exposure to price risks associated with natural gas, NGL production and
inventories, firm commitments and certain anticipated transactions.
The Company has adopted a commercial policy to manage its exposure to the risks generated by its gas processing
and related NGL and natural gas businesses. The objective of this policy is to assist the Company in achieving
Page 16
its profitability goals while maintaining a portfolio of conservative risk, defined as remaining within the
position limits established by the General Partner. The Company enters into risk management transactions to
manage price risk, basis risk, physical risk, or other risks related to the energy commodities on both a
short-term (less than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the
strategies of the Company associated with physical and financial risks, approves specific activities of the
Company subject to the policy (including authorized products, instruments and markets) and establishes specific
guidelines and procedures for implementing and ensuring compliance with the policy.
On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of
the commodity financial instruments on the balance sheet based upon then current market conditions. The fair
market value of the then outstanding commodity financial instruments was a net liability of $42.2 million (the
"cumulative transition adjustment") with an offsetting equal amount recorded in Other Comprehensive Income. The
amounts in Other Comprehensive Income are reclassified to earnings in the accounting period associated with the
hedged transaction (e.g. production month). The $42.2 million cumulative transition adjustment was or will be
reclassified to earnings as follows:
o $21.7 million during the first quarter of 2001;
o $10.7 million during the second quarter of 2001;
o $7.3 million during the third quarter of 2001; with the remaining
o $2.5 million reclassified during the fourth quarter of 2001.
The amounts recorded in Other Comprehensive Income at adoption of SFAS 133 will not be adjusted for changes in
fair value; rather, any change in the fair value of these commodity financial instruments will be recorded in
earnings (i.e., mark-to-market accounting treatment). The decision to record changes in the fair value of
these commodity financial instruments directly to earnings rather than Other Comprehensive Income is based upon
the determination by management that on an ongoing basis these commodity financial instruments would be
ineffective under the guidelines of SFAS 133.
The Company has entered into commodity financial instruments for time periods extending through June 2002. These
commodity financial instruments may not qualify for hedge accounting treatment under the specific guidelines of
SFAS 133. The Company continues to refer to these financial instruments as hedges in as much as this was the
intent when such contracts were executed. This characterization is consistent with the actual economic
performance of the contracts and the Company expects these financial instruments to continue to mitigate
commodity price risk in the future. The specific accounting for these contracts, however, is consistent with
the requirements of SFAS 133. As such, since these contracts do not qualify for hedge accounting under the
specific guidelines of SFAS 133, the change in fair value of these commodity financial instruments will be
reflected on the balance sheet and in earnings (i.e., mark-to-market accounting treatment).
The following table shows the impact of commodity financial instruments on earnings for the three and six months
ended June 30, 2001:
For the Three For the Six
Months Ended Months Ended
June 30, June 30,
2001 2001
--------------------------------------
End of period non-cash mark-to-market
accounting adjustments $39.0 $52.5
Net Gains (losses) realized on early
closeouts and settlements 25.7 17.8
--------------------------------------
Net gain (loss) recorded in
earnings $64.7 $70.3
======================================
Page 17
Other Financial Instruments - Interest rate swaps
The objective of holding interest rate swaps is to manage debt service costs by converting a portion of the
fixed-rate debt into variable-rate debt. An interest rate swap, in general, requires one party to pay a
fixed-rate on the notional amount while the other party pays a floating-rate based on the notional amount.
Management believes that it is prudent to maintain a balance between variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate exposure
that impact future cash flows and evaluating hedging opportunities. The Company uses analytical techniques to
measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to estimate the
expected impact of changes in interest rates on the Company's future cash flows. The General Partner oversees
the strategies of the Company associated with financial risks and approves instruments that are appropriate for
the Company's requirements.
On January 1, 2001, the Company adopted SFAS 133 which required the Company to record the fair market value of
the interest rate swaps on the balance sheet since the swaps were considered fair value hedges. SFAS 133
required that management determine (at the standard's adoption date) (a) the fair value of the swaps based upon
then current market conditions and (b) the estimated maturity date of the swaps (including an estimate of the
impact of any early termination clauses). The recording of the fair market value of the swaps was offset by an
equal increase in the fair value of the associated hedged debt instruments and, therefore, had no impact on
earnings upon transition. See Note 5 for further information regarding the impact of SFAS 133 on the Company's
fixed-rate long-term debt.
After adoption, the interest rate swaps were dedesignated as hedging instruments due to differences between the
maturity dates of the swaps and the associated hedged debt instruments. Dedesignation means that the financial
instrument (in this case, the interest rate swaps) will not be accounted for using hedge accounting under SFAS
133. Upon dedesignation, any future changes in the fair value of the interest rate swap agreements will be
recorded on the balance sheet through earnings. Dedesignation also entails that the previously associated
hedged item (in this case, the debt instrument) will not be adjusted for future changes in its fair value. As a
result, the $2.3 million change in fair value of the debt instrument recorded at the adoption date of SFAS 133
will be amortized to earnings over the life of the previously associated debt instrument of approximately 10
years.
Despite the dedesignation of the interest rate swaps, these financial instruments continue to be effective in
achieving the risk management objectives for which they were intended. Interest expense for 2001 includes a
$5.5 million benefit related to a change in fair value of the Company's interest rate swaps. The change in fair
value of the interest rate swaps does not represent a cash gain or loss for the Company. The actual cash gain
or loss on the interest rate swap agreements will be based upon market interest rates in effect on the specified
settlement dates in the swap agreements. The $5.5 million benefit is primarily due to the decision of one
counterparty not to exercise its early termination right under its swap agreement with the Company and, to a
lesser extent, lower overall borrowing rates.
Due to the complexity of SFAS 133, the Financial Accounting Standards Board ("FASB") organized a formal
committee, the Derivatives Implementation Group ("DIG"), to provide ongoing recommendations to the FASB about
implementation issues. Implementation guidance issued through the DIG process is still continuing; therefore,
the initial conclusions reached by the Company concerning the application of SFAS 133 upon adoption may be
altered. As a result, additional SFAS 133 transition adjustments may be recorded in future periods as the
Company adopts new DIG interpretations approved by the FASB.
11. SEGMENT INFORMATION
Operating segments are components of a business about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing
performance. Generally, financial information is required to be reported on the basis that it is used internally
for evaluating segment performance and deciding how to allocate resources to segments.
Page 18
The Company has five reportable operating segments: Fractionation, Pipeline, Processing, Octane Enhancement and
Other. The reportable segments are generally organized according to the type of services rendered (or process
employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the Chief
Executive Officer of the General Partner. Fractionation includes NGL fractionation, butane isomerization
(converting normal butane into high purity isobutane) and polymer grade propylene fractionation services.
Pipeline consists of both liquids and natural gas pipeline systems, storage and import/export terminal
services. Processing includes the natural gas processing business and its related NGL merchant activities.
Octane Enhancement represents the Company's 33.33% ownership interest in a facility that produces motor gasoline
additives to enhance octane (currently producing MTBE). The Other operating segment consists of fee-based
marketing services and other plant support functions.
The Company evaluates segment performance based on gross operating margin. Gross operating margin reported for
each segment represents operating income before depreciation and amortization, lease expense obligations retained
by EPCO, gains and losses on the sale of assets and general and administrative expenses. In addition, segment
gross operating margin is exclusive of interest expense, interest income (from unconsolidated affiliates or
others), dividend income from unconsolidated affiliates, minority interest, extraordinary charges and other
income and expense transactions. The Company's equity earnings from unconsolidated affiliates are included in
segment gross operating margin.
Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are
allocated to each segment on the basis of each asset's or investment's principal operations. The principal
reconciling item between consolidated property, plant and equipment and segment property is
construction-in-progress. Segment property represents those facilities and projects that contribute to gross
operating margin and is net of accumulated depreciation on these assets. Since assets under construction do not
generally contribute to segment gross operating margin, these assets are not included in the operating segment
totals until they are deemed operational.
Segment gross operating margin is inclusive of intersegment revenues, which are generally based on transactions
made at market-related rates. These revenues have been eliminated from the consolidated totals.
Page 19
Information by operating segment, together with reconciliations to the consolidated totals, is presented in the
following table:
Operating Segments Adjs.
------------------------------------------------------------------
Octane and Consol.
Fractionation Pipelines Processing Enhancement Other Elims. Totals
---------------------------------------------------------------------------------------------
Revenues from
external customers
for three months ended:
June 30, 2001 $ 86,566 $178,958 $693,242 $631 $959,397
June 30, 2000 97,004 16,914 478,244 751 592,913
for six months ended:
June 30, 2001 176,245 186,145 1,432,011 1,311 1,795,712
June 30, 2000 188,901 23,926 1,125,101 1,266 1,339,194
Intersegment revenues
for three months ended:
June 30, 2001 44,133 24,631 131,657 96 $(200,517)
June 30, 2000 47,264 14,826 139,654 94 (201,838)
for six months ended:
June 30, 2001 85,785 45,410 241,966 191 (373,352)
June 30, 2000 82,729 28,025 281,885 188 (392,827)
Equity income in
unconsolidated affiliates
for three months ended:
June 30, 2001 1,692 2,125 $5,233 9,050
June 30, 2000 1,725 1,065 8,307 11,097
for six months ended:
June 30, 2001 2,253 3,406 5,402 11,061
June 30, 2000 3,926 3,802 10,812 18,540
Total revenues
for three months ended:
June 30, 2001 132,391 205,714 824,899 5,233 727 (200,517) 968,447
June 30, 2000 145,993 32,805 617,898 8,307 845 (201,838) 604,010
for six months ended:
June 30, 2001 264,283 234,961 1,673,977 5,402 1,502 (373,352) 1,806,773
June 30, 2000 275,556 55,753 1,406,986 10,812 1,454 (392,827) 1,357,734
Gross operating margin
by segment
for three months ended:
June 30, 2001 32,803 24,696 68,112 5,233 411 131,255
June 30, 2000 29,591 14,192 18,486 8,307 872 71,448
for six months ended:
June 30, 2001 58,471 42,819 96,510 5,402 946 204,148
June 30, 2000 63,922 28,827 58,040 10,812 1,426 163,027
Segment property at:
June 30, 2001 357,142 670,311 125,657 7,884 71,798 1,232,792
December 31, 2000 356,207 448,920 126,895 8,942 34,358 975,322
Investments in and advances
to unconsolidated
affiliates at:
June 30, 2001 98,062 221,485 33,000 62,261 414,808
December 31, 2000 105,194 102,083 33,000 58,677 298,954
Page 20
All consolidated revenues were earned in the United States. The operations of the Company are centered along
the Texas, Louisiana and Mississippi Gulf Coast areas.
A reconciliation of segment gross operating margin to consolidated income before minority interest follows:
For Three Months Ended For Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2001 2000 2001 2000
--------------------------------- ---------------------------------
Total segment gross operating margin $131,255 $71,448 $204,148 $163,027
Depreciation and amortization (11,793) (8,754) (21,822) (16,878)
Retained lease expense, net (2,660) (2,687) (5,320) (5,324)
Loss (gain) on sale of assets 6 (2,303) 387 (2,303)
Selling, general and administrative (7,737) (7,658) (13,905) (13,042)
--------------------------------- ---------------------------------
Consolidated operating income 109,071 50,046 163,488 125,480
Interest expense (16,331) (8,070) (23,318) (15,844)
Interest income from unconsolidated affiliates 7 126 31 270
Dividend income from unconsolidated affiliates 2,761 1,632 3,995
Interest income - other 1,479 1,225 5,477 2,706
Other, net (251) (62) (531) (425)
--------------------------------- ---------------------------------
Consolidated income before minority interest $ 93,975 $46,026 $146,779 $116,182
================================= =================================
Page 21
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATION.
For the Interim Periods ended June 30, 2001 and 2000
The following discussion and analysis should be read in conjunction with the unaudited consolidated
financial statements and notes thereto of the Company included elsewhere herein.
Cautionary Statement regarding Forward-Looking Information
This quarterly report on Form 10-Q contains various forward-looking statements and information that are
based on the belief of the Company and the General Partner, as well as assumptions made by and information
currently available to the Company and the General Partner. When used in this document, words such as
"anticipate," "estimate," "project," "expect," "plan," "forecast," "intend," "could," "believe," "may" and similar
expressions and statements regarding the plans and objectives of the Company for future operations, are intended
to identify forward-looking statements. Although the Company and the General Partner believe that the
expectations reflected in such forward-looking statements are reasonable, they can give no assurance that such
expectations will prove to be correct. Such statements are subject to certain risks, uncertainties, and
assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, actual results may vary materially from those anticipated, estimated, projected, or expected.
Risk Factors
An investment in the Company's securities involves a degree of risk. Among the key risk factors that
may have a direct bearing on the Company's results of operations and financial condition are: (a) competitive
practices in the industries in which the Company competes, (b) fluctuations in oil, natural gas, and natural gas
liquid ("NGL") prices and production due to weather and other natural and market forces, (c) operational and
systems risks, (d) environmental liabilities that are not covered by indemnity or insurance, (e) the impact of
current and future laws and governmental regulations (including environmental regulations) affecting the NGL
industry in general, and the Company's operations in particular, (f) loss of a significant customer, (g) the use
of financial instruments to hedge commodity and interest rate risks and (h) failure to complete one or more new
projects on time or within budget.
The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market
uncertainty and a variety of additional factors that are beyond the Company's control. These factors include
the level of domestic oil, natural gas and NGL production, the availability of imported oil and natural gas,
actions taken by foreign oil and natural gas producing nations, the availability of transportation systems with
adequate capacity, the availability of competitive fuels and products, fluctuating and seasonal demand for oil,
natural gas and NGLs and conservation and the extent of governmental regulation of production and the overall
economic environment.
The products that the Company processes, sells or transports are principally used as feedstocks in
petrochemical manufacturing and in the production of motor gasoline and as fuel for residential and commercial
heating. A reduction in demand for the Company's products or processing or transportation services by the
petrochemical, refining or heating industries, whether because of general economic conditions, reduced demand by
consumers for the end products made with NGL products, increased competition from petroleum-based products due to
pricing differences, adverse weather conditions, governmental regulations affecting prices and production levels
of natural gas or the content of motor gasoline or other reasons, could have a negative impact on the Company's
results of operations. A material decrease in natural gas production or crude oil refining, as a result of
depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in
the volumes of NGLs processed or sold by the Company, thereby reducing revenue and operating income.
In addition, the Company's expectations regarding its future capital expenditures as described in
"Liquidity and Capital Resources" are only its forecasts regarding these matters. These forecasts may be
substantially different from actual results due to various uncertainties including the following key factors:
(a) the accuracy of the Company's estimates regarding its spending requirements, (b) the occurrence of any
unanticipated acquisition opportunities, (c) the need to replace any unanticipated losses in capital assets, (d)
Page 22
changes in the strategic direction of the Company and (e) unanticipated legal, regulatory and contractual
impediments with regards to its construction projects.
For a further description of the tax and other risks of owning limited partner interests in the Company,
see the Company's registration documents (together with any amendments thereto) filed with the SEC on Form S-1/A
dated July 21,1998, Form S-3 dated December 21, 1999 and Form S-3 dated February 23, 2001.
Company Overview
The Company is a publicly traded master limited partnership (NYSE, symbol "EPD") that conducts
substantially all of its business through Enterprise Products Operating L.P. (the "Operating Partnership"), the
Operating Partnership's subsidiaries, and a number of joint ventures with industry partners. The Company was
formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise
Products Company ("EPCO"). The general partner of the Company, Enterprise Products GP, LLC, a majority-owned
subsidiary of EPCO, holds a 1.0% general partner interest in the Company and a 1.0101% general partner interest
in the Operating Partnership.
The principal executive office of the Company is located at 2727 North Loop West, Houston, Texas,
77008-1038, and the telephone number of that office is 713-880-6500. References to, or descriptions of, assets
and operations of the Company in this document include the assets and operations of the Operating Partnership and
its subsidiaries.
The Company is a leading North American provider of a wide range of midstream energy services to its
customers along the central and western Gulf Coast. The Company's services include the:
o gathering, transmission and storage of natural gas from both onshore and offshore Louisiana developments;
o purchase and sale of natural gas in south Louisiana;
o processing of natural gas into a merchantable and transportable form of energy that meets industry
quality specifications by removing NGLs and impurities;
o fractionating for a processing fee mixed NGLs produced as by-products of oil and natural gas production
into their component products: ethane, propane, isobutane, normal butane and natural gasoline;
o converting normal butane to isobutane through the process of isomerization;
o producing MTBE from isobutane and methanol;
o transporting NGL products to end users by pipeline and railcar;
o separating high purity propylene from refinery-sourced propane/propylene mix; and
o transporting high purity propylene to plastics manufacturers by pipeline.
Natural gas transported, processed and/or sold by the Company generally is consumed as fuel by residential,
electric and industrial centers. NGL and petrochemical products processed by the Company generally are used as
feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential and
commercial heating.
Company Operations and Assets
The Company's operations are concentrated in the Texas, Louisiana, and Mississippi Gulf Coast area. A
large portion of these operations take place in Mont Belvieu, Texas, which is the hub of the domestic NGL
industry and is adjacent to the largest concentration of refineries and petrochemical plants in the United
States. The facilities the Company operates at Mont Belvieu include: (a) one of the largest NGL fractionation
facilities in the United States with a net processing capacity of 131 MBPD; (b) the largest commercial butane
isomerization complex in the United States with a potential isobutane production capacity of 116 MBPD; (c) a MTBE
production facility with a net production capacity of 5 MBPD; and (d) two propylene fractionation units with a
combined production capacity of 31 MBPD. The Company owns all of the assets at its Mont Belvieu facility except
for the NGL fractionation facility, in which it owns an effective 62.5% interest; one of the propylene
fractionation units, in which it owns a 54.6% interest and controls the remaining interest through a long-term
Page 23
lease; the MTBE production facility, in which it owns a 33.3% interest; and one of its three isomerization units
and one deisobutanizer which are held under long-term leases with purchase options.
The Company's operations in Louisiana and Mississippi include varying interests in twelve natural gas
processing plants with a combined capacity of 11.6 Bcf/d and net capacity of 3.2 Bcf/d, six NGL fractionation
facilities with a combined net processing capacity of 159 MBPD and a propylene fractionation facility with a net
capacity of 7 MBPD.
The Company owns, operates or has an interest in approximately 65.0 million barrels of gross NGL and
petrochemical storage capacity (44.3 million barrels of net capacity) in Texas, Louisiana and Mississippi that
are an integral part of its processing operations. The Company also leases and operates one of only two
commercial NGL import/export terminals on the Gulf Coast. In addition, the Company has operating and
non-operating ownership interests in over 2,900 miles of NGL and petrochemical pipelines.
Beginning in January 2001, the Company owns varying equity interests in four Gulf of Mexico offshore
Louisiana natural gas pipeline systems totaling 725 miles of pipeline (with an aggregate gross capacity of 2.85
Bcf/d) and related assets. These equity interests were purchased from EPE at a cost of approximately $112
million. With the completion of the Acadian Gas, LLC ("Acadian Gas") acquisition in April 2001, the Company now
owns varying interests in an additional 1,042 miles of natural gas pipeline systems (with an aggregate gross
capacity of over 1.1 Bcf/d) and related facilities located in south Louisiana. For additional information
regarding these recent investments and business acquisitions, see "Recent acquisitions and other investments"
below.
The Company's operating margins are primarily derived from services provided to its tolling customers
and from merchant activities. In its tolling operations, the Company is paid a fee based on volumes processed,
transported, stored or handled. The Company generally does not take title to products as part of its tolling
operations; however, in those instances where title to products does transfer to the Company, the Company
generally matches the timing and purchase price of the products with those of the sale of the products so as to
reduce or eliminate exposure to fluctuations in commodity prices. Examples of the Company's tolling operations
include isomerization tolling arrangements, propylene fractionation, liquids pipeline transportation services,
fee-based marketing services and most NGL fractionation services. In addition, the Company's newly acquired
natural gas pipeline businesses are viewed as fee-based operations. See "Recent acquisitions and other
investments" below for a further discussion of the impact of commodity price risk on these operations.
In its merchant activities, the Company is exposed to fluctuations in commodity prices. In the
Company's isobutane merchant business (and to a certain extent its propylene fractionation activities), the
Company takes title to feedstock products and sells processed end products. The Company's profitability from
this type of merchant activity is dependent upon the prices of feedstocks and end products, which may vary on a
seasonal basis. In order to limit the exposure to commodity price fluctuations in these business areas, the
company attempts to match the timing and price of its feedstock purchases with those of the sales of end
products. Operating margins from the company's natural gas processing (and related merchant businesses) are
generally derived from the price spread earned on the sale of purity NGL products extracted from natural gas
stream. To the extent the Company takes title to the NGLs removed from the natural gas stream and reimburses the
producer for the reduction in the Btu content and/or the natural gas used as fuel (the "PTR" or "shrinkage"), the
Company's operating margins are affected by the prices of NGLs and natural gas. As part of its natural gas
processing and related merchant activities, the Company uses commodity financial instruments to reduce its
exposure to the market risks associated with changes in natural gas and NGL prices.
Recent acquisitions and other investments
Natural gas pipelines
General. Since January 1, 2001, the Company has invested approximately $338 million (net of cash
acquired) in natural gas pipeline businesses. These include an initial $226 million paid to Shell for the
purchase of Acadian Gas (an onshore Louisiana system) and a combined $112 million paid to EPE for equity
interests in four Gulf of Mexico natural gas pipelines (primarily offshore Louisiana systems). The acquisition
of these natural gas pipeline businesses from EPE and Shell represents a strategic investment for the Company.
Management believes that these assets have attractive growth attributes given the expected long-term increase in
Page 24
natural gas demand for industrial and power generation uses. In addition, these assets extend the Company's
midstream energy service relationship with long-term NGL customers (producers, petrochemical suppliers and
refineries) and provide opportunities for enhanced services to customers as well as generating additional
fee-based cash flows. These businesses are accounted for as part of the Company's Pipeline operating segment.
Natural gas pipeline systems receive natural gas from producers, other pipelines or shippers through
system interconnects and redeliver the natural gas at other points. Generally, natural gas transportation
agreements provide these systems with a fee per unit of volume (generally in MMBtus) transported. Natural gas
pipeline businesses (such as those of Acadian Gas) may also involve gathering and purchasing natural gas from
producers and suppliers and transporting and reselling such natural gas to electric utility companies, local
distribution companies, industrial customers, affiliates of other pipeline and gas marketing companies as well as
transporting and gathering natural gas for shippers on a fee basis. Overall, the Company's Gulf of Mexico
systems do not take title to the natural gas that they transport; the shipper retains title and the associated
commodity price risk. In the Company's Acadian Gas operations, it does take title to certain natural gas
streams and is exposed to commodity price risk through its natural gas inventories and certain of its contracts.
The results of operation for the six months ended June 30, 2001 include three month's impact of the
Acadian Gas acquisition and six month's impact of the Gulf of Mexico natural gas pipelines. See Note 3 of the
Notes to Unaudited Consolidated Financial Statements for selected pro forma financial data regarding these
transactions as if they had both occurred on January 1, 2001 and 2000.
Acadian Gas. On April 2, 2001, the Company acquired Acadian Gas from Shell US Gas and Power LLC, an
affiliate of Shell, for approximately $226 million in cash using proceeds from the issuance of the $450 Million
Senior Notes. The cash purchase price is subject to certain post-closing adjustments expected to be completed
during the third quarter of 2001. The effective date of the transaction was April 1, 2001.
Acadian Gas is involved in the purchase, sale, transportation and storage of natural gas in Louisiana.
Acadian Gas' assets are comprised of the 438-mile Acadian, 577-mile Cypress and 27-mile Evangeline natural gas
pipeline systems, which together have over 1.1 Bcf/d of capacity. These natural gas pipeline systems are
wholly-owned by Acadian Gas with the exception of the Evangeline system in which Acadian Gas holds an approximate
49.5% interest. The assets acquired include a leased natural gas storage facility located in Napoleonville,
Louisiana.
The Acadian, Cypress and Evangeline systems link supplies of natural gas from onshore developments and,
through connections with offshore pipelines, Gulf of Mexico production to local gas distribution companies,
electric generation and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River
corridor. In addition, these systems have interconnects with 12 interstate and four intrastate pipelines and a
bi-directional interconnect with the U.S. natural gas marketplace at Henry Hub.
Interests in four Gulf of Mexico natural gas pipeline systems. On January 29, 2001, the Company
purchased equity interests in four Gulf of Mexico natural gas pipeline systems and related assets from EPE for
$112 million, after taking into account certain post-closing adjustments.
The Company acquired a 50% equity interest in Starfish Pipeline Company LLC ("Starfish") which owns the
Stingray natural gas pipeline system and a related natural gas dehydration facility. The Stingray system is a
375-mile FERC-regulated natural gas pipeline system that transports natural gas and injected condensate from
certain production areas offshore Louisiana in the Gulf of Mexico to onshore transmission systems located in
south Louisiana. The natural gas dehydration facility is connected to the onshore terminal of the Stingray
system in south Louisiana.
In addition to Starfish, the Company acquired a 25.67% equity interest in Ocean Breeze Pipeline Company
LLC ("Ocean Breeze") and Neptune Pipeline Company LLC ("Neptune") as well as a 33.92% equity interest in Nemo
Gathering Company, LLC ("Nemo"). Ocean Breeze and Neptune collectively own the Manta Ray and Nautilus natural
gas gathering and transmission systems located in the Gulf of Mexico offshore Louisiana. The Manta Ray system
comprises approximately 225 miles of unregulated pipelines with a capacity of 750 MMcf/d and related equipment,
the Nautilus system comprises approximately 101 miles of FERC-regulated pipelines with a capacity of 600 MMcf/d,
Page 25
and the Nemo system, when completed in the fourth quarter of 2001, will comprise approximately 24 miles of
pipeline with a capacity of 300 MMcf/d.
Affiliates of Shell own the remaining equity interests in Starfish and varying interests in Ocean
Breeze, Neptune and Nemo. An affiliate of Marathon Oil Company owns an interest in Ocean Breeze and Neptune.
In addition, Shell is the operator of the assets held by Starfish, Ocean Breeze, Neptune and Nemo.
These natural gas pipeline systems and related assets are strategically located to serve continental
shelf and deepwater developments in the central Gulf of Mexico. Management believes that the equity interests
acquired from EPE complement and integrate well with those of the Acadian Gas acquisition. These investments are
expected to benefit the Company's midstream focus by:
o broadening its midstream business by providing additional services to customers; and by
o contributing to the Company's ability to obtain anticipated increases in natural gas production from
deepwater Gulf of Mexico development.
Management believes that these assets have a significant upside potential, since Shell and Marathon have
dedicated production from over 1,000 square miles of Gulf of Mexico offshore Louisiana natural gas leases to
these systems and only a small portion of this total has been developed to date.
Regulatory environment of natural gas systems. The Stingray and Nautilus natural gas pipeline systems
are regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each system
operates under separate FERC approved tariffs that establish rates, terms and conditions under which each system
provides services to its customers. Generally, the FERC's authority extends to:
o transportation of natural gas, rates and charges;
o certification and construction of new facilities;
o extension or abandonment of services and facilities;
o maintenance of accounts and records;
o depreciation and amortization policies;
o acquisition and disposition of facilities;
o initiation and discontinuation of services; and
o various other matters.
As noted above, the Stingray and Nautilus systems have tariffs established through filings with the FERC that
have a variety of terms and conditions, each of which affect the operations of each system and their ability to
recover fees for the services they provide. Generally, changes to these fees or terms can only be implemented
upon approval by the FERC.
Collectively, the Acadian Gas and Gulf of Mexico pipeline systems acquired by the Company are subject to
various governmental and environmental legislation. Each of these systems has a continuing program of
inspection designed to ensure compliance with such legislation including pollution control and pipeline safety
requirements. The Company believes that these systems are in substantial compliance with the applicable
requirements.
Equistar storage facility
In addition to the natural gas pipeline acquisitions, the Company announced on February 1, 2001 that it
had acquired a NGL storage facility from Equistar Chemicals, LP for approximately $3.4 million. The salt dome
storage cavern, which is located near the Company's Mont Belvieu, Texas complex, has a capacity of one million
barrels. The purchase also includes adjacent acreage which would support the development of additional storage
capacity.
Page 26
Current Business Environment
The second quarter of 2001 was a period of recovery for the NGL industry. The decline in natural gas
prices from the record levels of the first quarter of 2001 resulted in increased NGL extraction rates throughout
the industry. Consequently, the Company saw a rebound in NGL volumes available for fractionation and/or
transportation.
At the Company's gas processing facilities, equity NGL production volumes increased from the 46 MBPD
of the first quarter of 2001 to 63 MBPD in the second quarter of 2001. Natural gas prices, which approached
$10 per MMBtu in January 2001, fell to nearly $3 per MMBtu during July 2001. The price of natural gas relative
to the price of NGLs plays a major role in gas processing costs since high natural gas prices result in increased
fuel and shrinkage costs which may, at times, exceed the value of the NGLs extracted from the gas. The low
equity NGL production rate seen in the first quarter was the result of minimal NGL extraction caused by the
abnormally high cost of natural gas. As natural gas prices moderated in the second quarter, NGL extraction rates
at the Company's processing facilities and those of other industry participants increased, resulting in
additional volumes throughout its NGL value chain.
In the second quarter of 2001, NGL prices declined along with those of other forms of energy. The
resultant loss of value has been mitigated (or in some cases, reversed) by the Company's hedging activities.
During the third quarter of 2001, the Company expects that natural gas prices will generally weaken and that NGL
prices will stabilize. In light of these expectations, management continues to monitor its commodity financial
instruments portfolio due to the volatility of the energy markets. Third quarter equity NGL production is
expected to approximate 75 MBPD.
The Company's recently acquired natural gas pipeline businesses (i.e. Acadian Gas and the Gulf of Mexico
joint ventures) have experienced strong demand for their services. In response to the long-term expected
increase in natural gas demand, many producers have stepped up their drilling activities resulting in an increase
in natural gas volumes available for transportation. Producers believe that natural gas demand will increase
near-term due to new gas-fired electric generation facilities commencing operations and a rebound in industrial
and commercial demand with the moderation of natural gas prices and an improving economy. Conversely, any
material downturn in either the domestic or global economy or long-term decrease in natural gas pricing below
$2.75 to $3.00 per MMBTU could result in decreased drilling activities. Barring the latter scenario, the
Company's natural gas pipelines expect to maintain or grow their current throughput levels for the near term
associated with third-party activities, the most significant of which is the start-up of operations at the Shell
Brutus field. This field is expected to generate approximately 130 BBtu/d of natural gas throughput volume and
10 MBPD of equity NGL production by the end of 2001.
During the second quarter of 2001, the Company's isomerization services and isobutane merchant business
benefited from strong demand for isobutane used in the manufacture of gasoline. The increase in demand stemmed
from refiners increasing gasoline production in anticipation of short-term gasoline supply imbalances heading
into the summer driving season. In response, the Company's Mont Belvieu isomerization units ran at near full
rates during the early part of the second quarter with the isobutane merchant business profiting on strong spot
and contract sales. Also, the Company's Houston Ship Channel import facility and related pipeline system
experienced significant volume and margin increases as commercial butane imports (used as feedstock for
isobutane) were transported to Mont Belvieu to satisfy the demands of increased isobutane production. By the
end of the second quarter, isobutane demand returned to more normalized levels as refiners perceived that
gasoline supplies had stabilized. As a result, the Company anticipates that its isomerization and related
merchant business (along with its import dock and related pipelines) will experience normalized margins and
volumes during the third quarter of 2001.
Propylene fractionation margins are slightly less than last year due to continuing weakness in the
propylene markets. Management expects prices to stabilize during the third quarter of 2001 with a slight rise
expected in the fourth quarter of 2001 due to a strengthening domestic economy and increased propylene demand.
The Company's MTBE operations (reported under the Octane Enhancement business segment) experienced healthy
margins early in the second quarter of 2001 due to the seasonal surge in gasoline blending requirements from
refiners; however, as gasoline supplies and demand have stabilized, MTBE prices and margins have fallen. The
Page 27
Company expects results from MTBE operations to be near breakeven for the third and fourth quarters of 2001 as a
result of this seasonal decrease in prices.
With regards to its major liquids pipelines, the Company expects the Louisiana Pipeline System to
benefit from the seasonal rise in propane shipments that are carried on the Dixie Pipeline with the strongest
movements anticipated during the fourth quarter of 2001. EPIK's financial performance is expected to improve
significantly over the last half of 2001. Exports of butane and propane are expected to increase as a result
of moderating domestic prices for both products relative to foreign markets. This situation should make these
products more attractive on the world market and EPIK should benefit from a heavy slate of vessel loadings for
export.
The following table illustrates selected average quarterly prices for natural gas, crude oil, selected
NGL products and polymer grade propylene since the first quarter of 1999:
Polymer
Natural Normal Grade
Gas, Crude Oil, Ethane, Propane, Butane, Isobutane, Propylene,
$/MMBtu $/barrel $/gallon $/gallon $/gallon $/gallon $/pound
-----------------------------------------------------------------------------------------
(a) (b) (a) (a) (a) (a) (a)
Fiscal 1999:
First quarter $1.70 $13.05 $0.20 $0.24 $0.29 $0.31 $0.12
Second quarter $2.12 $17.66 $0.27 $0.31 $0.37 $0.38 $0.13
Third quarter $2.56 $21.74 $0.34 $0.42 $0.49 $0.49 $0.16
Fourth quarter $2.52 $24.54 $0.30 $0.41 $0.52 $0.52 $0.19
Fiscal 2000:
First quarter $2.49 $28.84 $0.38 $0.54 $0.64 $0.64 $0.21
Second quarter $3.41 $28.79 $0.36 $0.52 $0.60 $0.68 $0.26
Third quarter $4.22 $31.61 $0.40 $0.60 $0.68 $0.67 $0.26
Fourth quarter $5.22 $31.98 $0.49 $0.67 $0.75 $0.73 $0.24
Fiscal 2001:
First quarter (c) $7.00 $28.81 $0.43 $0.55 $0.63 $0.69 $0.23
Second quarter (c) $4.61 $27.88 $0.33 $0.46 $0.53 $0.63 $0.19
- ----------------------------------------------------------------------------------------------------------------
(a) Natural gas, NGL and polymer grade propylene prices represent an average of index prices
(b) Crude oil price is representative of West Texas Intermediate
(c) After reaching a high of $9.87 per MMBtu in January 2001, natural gas prices have declined to an
average of $3.68 per MMBtu in June 2001.
Results of Operation of the Company
The Company has five reportable operating segments: Fractionation, Pipeline, Processing, Octane
Enhancement and Other. Fractionation includes NGL fractionation, butane isomerization (converting normal butane
into high purity isobutane) and polymer grade propylene fractionation services. Pipeline consists of liquids and
natural gas pipeline systems, storage and import/export terminal services. Processing includes the natural gas
processing business and its related NGL merchant activities. Octane Enhancement represents the Company's 33.3%
ownership interest in a facility that produces motor gasoline additives to enhance octane (currently producing
MTBE). The Other operating segment consists of fee-based marketing services and other plant support functions.
The management of the Company evaluates segment performance based on gross operating margin ("gross
operating margin" or "margin"). Gross operating margin reported for each segment represents operating income
before depreciation and amortization, lease expense obligations retained by EPCO, gains and losses on the sale of
assets and selling, general and administrative expenses. In addition, segment gross operating margin is
exclusive of interest expense, interest income (from unconsolidated affiliates or others), dividend income from
Page 28
unconsolidated affiliates, minority interest, extraordinary charges and other income and expense transactions.
The Company's equity earnings from unconsolidated affiliates are included in segment gross operating margin.
The Company's gross operating margin by segment (in thousands of dollars) along with a reconciliation to
consolidated operating income for the three and six month periods ended June 30, 2001 and 2000 were as follows:
For Three Months Ended For Six Months Ended
June 30, June 30,
------------------------------------ -----------------------------------
2001 2000 2001 2000
------------------------------------ -----------------------------------
Gross Operating margin by segment:
Fractionation $ 32,803 $29,591 $ 58,471 $ 63,922
Pipeline 24,696 14,192 42,819 28,827
Processing 68,112 18,486 96,510 58,040
Octane enhancement 5,233 8,307 5,402 10,812
Other 411 872 946 1,426
------------------------------------ -----------------------------------
Gross Operating margin total 131,255 71,448 204,148 163,027
Depreciation and amortization 11,793 8,754 21,822 16,878
Retained lease expense, net 2,660 2,687 5,320 5,324
Loss (gain) on sale of assets (6) 2,303 (387) 2,303
Selling, general and administrative expenses 7,737 7,658 13,905 13,042
------------------------------------ -----------------------------------
Consolidated operating income $109,071 $50,046 $163,488 $125,480
==================================== ===================================
The Company's significant production and other volumetric data (on a net basis) for the three and six
month periods ended June 30, 2001 and 2000 were as follows:
For Three Months Ended For Six Months Ended
June 30, June 30,
--------------------------------- ----------------------------------
2001 2000 2001 2000
--------------------------------- ----------------------------------
MBPD, Net
---------
Equity NGL Production 63 72 54 72
NGL Fractionation 202 215 184 217
Isomerization 94 81 82 74
Propylene Fractionation 29 30 30 30
Octane Enhancement 5 5 4 5
Major NGL and Petrochemical Pipelines 519 340 438 350
MMBtu/D, Net
------------
Natural Gas Pipelines 1,295,370 1,263,039
Three Months Ended June 30, 2001 compared with Three Months Ended June 30, 2000
Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 60% to $968.4
million in 2001 compared to $604.0 million in 2000. The Company's operating costs and expenses increased by 56%
to $851.6 million in 2001 versus $546.3 million in 2000. Operating income increased 118% to $109.1 million in
2001 from $50.0 million in 2000. Second quarter 2001 revenues and expenses have primarily been impacted by the
acquisition of Acadian Gas and increased merchant business activities. The majority of the increase in
operating income for 2001 relates to $39.0 million in non-cash mark-to-market gains relating to the Company's
commodity hedging activities.
Fractionation. The Company's gross operating margin for the Fractionation segment increased to $32.8
million in 2001 from $29.6 million in 2000. NGL fractionation margin declined $4.3 million quarter-to-quarter
primarily the result of higher energy costs and lower fractionation volumes. NGL fractionation net volumes were
202 MBPD for 2001 compared to 215 MBPD during 2000. With the decline in natural gas prices since February 2001,
Page 29
NGL fractionation volumes have improved since the first quarter 2001's 165 MBPD rate due to higher liquids
extraction rates at gas processing facilities. The 2000 volume is representative of a period when the industry
was maximizing NGL production.
The Company's isomerization business posted a $6.7 million increase in margin in 2001 over 2000 levels
with isomerization volumes increasing from 81 MBPD in 2000 to 94 MBPD in 2001. The increase in both margin and
volume is attributable to a strong isobutane market early in the second quarter of 2001 which led to an increase
in demand for the Company's isomerization services. Gross operating margin from propylene fractionation
declined by $0.5 million primarily due to moderating prices and a slight decrease in volumes. Propylene
fractionation volumes were 29 MBPD in 2001 versus 30 MBPD during the 2000 period.
Pipeline. The Company's gross operating margin for the Pipeline segment was $24.7 million in 2001
compared to $14.2 million in 2000. Of the $10.5 million increase, $5.2 million is attributable to natural gas
pipelines (i.e., the newly acquired Acadian Gas and the Gulf of Mexico systems) which benefited from a strong
natural gas marketplace. Natural gas pipeline volumes averaged 1,295 BBtu/d on a net basis. Of the Company's
liquids-oriented assets, the recently completed Lou-Tex NGL Pipeline added $2.4 million in margin on volumes of
21 MBPD and the Houston Ship Channel import facility and related pipeline system added $3.1 million primarily due
to strong imports of commercial butane. Net liquids throughput volumes increased to 519 MBPD in 2001 compared
with 340 MBPD in 2000. Of the 179 MBPD increase in net throughput volumes, 143 MBPD is attributable to the
higher import activity.
Processing. For the second quarter of 2001, the Processing segment generated gross operating margin of
$68.1 million compared to $18.5 million during the same period in 2000. The Processing segment includes the
Company's natural gas processing business and related merchant activities. Gross operating margin from natural
gas processing plants posted a $44.1 million increase over 2000 levels primarily due to a $59.1 million increase
in net hedging gains from $5.6 million in 2000 to $64.7 million in 2001 (see discussion below). The net hedging
gains more than offset the effects of lower equity NGL volumes and prices and a rise in energy-related operating
costs. The Company's equity NGL production was 63 MBPD for the 2001 quarter versus 72 MBPD for the same period
in 2000. Although lower on a quarter-to-quarter basis, equity NGL production for the second quarter of 2001
improved from the 46 MBPD rate of the first quarter of 2001. The improvement is related to the overall decline
in natural gas prices that have led processors industrywide to increase NGL recoveries. Gross operating margin
from merchant activities in 2001 increased $5.5 million over 2000 primarily due to strong demand for isobutane.
Gross operating margin for the 2001 period includes $64.7 million of net hedging profits resulting from
the Company's commodity hedging activities. Of this amount, $39.0 million is attributable to net non-cash
mark-to-market gains on the commodity financial instruments that were outstanding at June 30, 2001. The Company
employs various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL prices)
on its natural gas processing business and related merchant activities.
A large number of the Company's commodity financial instruments are based on the historical relationship
between natural gas prices and NGL prices. This type of hedging strategy utilizes the forward sale of natural
gas at a fixed-price with the expected margin on the settlement of the position offsetting or mitigating changes
in the anticipated margins on NGL merchant activities and the value of its NGL equity production. During the
second quarter of 2001, the Company benefited from a decline in natural gas prices relative to its fixed
positions. The decline in natural gas prices created gains on the settlement and early closeout of certain
positions of approximately $25.7 million. If natural gas prices had not declined to the degree seen during the
quarter, a smaller gain or a loss on hedging activities may have resulted offset somewhat by anticipated higher
NGL prices. A variety of factors influence whether or not the Company's hedging strategy is successful. For
additional information regarding the Company's commodity financial instruments, see Item 3 "Quantitative and
Qualitative Disclosures about Market Risk" on page 36.
Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $3.1 million
in the second quarter of 2001 compared with 2000 levels. MTBE production, on a net basis, was 5 MBPD in both
2001 and 2000. The decline in margin is primarily due to lower MTBE prices in 2001 relative to the 2000 period
and higher energy costs.
Page 30
Interest expense. Interest expense for the second quarter of 2001 increased $8.3 million over the same
period in 2000. The increase is primarily due to interest associated with the $450 Million Senior Notes issued
in January 2001.
Six Months Ended June 30, 2001 compared with Six Months Ended June 30, 2000
Revenues, Costs and Expenses and Operating Income. The Company's revenues increased 29% to $1.8
billion in 2001 compared to $1.4 billion in 2000. The Company's operating costs and expenses increased by 33%
to $1.6 billion in 2001 versus $1.2 billion in 2000. Operating income increased 30% to $163.5 million in 2001
from $125.5 million in 2000. Year-to-date 2001 revenues and expenses have increased due to the acquisition of
Acadian Gas and increased merchant business activities. In addition year-to-date 2001 expenses have increased
due to higher than normal natural gas prices which affects energy-related operating costs at the Company's
facilities. The majority of the increase in operating income for 2001 relates to $52.5 million in non-cash
mark-to-market gains relating to the Company's commodity hedging activities.
Fractionation. The Company's gross operating margin for the Fractionation segment decreased to $58.5
million from $63.9 million. NGL fractionation margin decreased $14.7 million primarily due to lower processing
volumes and higher energy-related operating costs. NGL fractionation net volumes decreased to 184 MBPD for the
first six months of 2001 compared to 217 MBPD during the same period in 2000. The decrease is the result of
lower extraction rates at gas processing facilities in early 2001 (due to the high cost of natural gas) versus
2000 when the industry was maximizing NGL production. NGL fractionation volumes improved to 202 MBPD during the
second quarter of 2001 as extraction rates increased and the price of natural gas declined. For the first six
months of 2001, gross operating margin from isomerization services increased $11.2 million compared to 2000
primarily due to an increase in volumes and toll processing fees. Isomerization volumes increased to 82 MBPD
during the first six months of 2001 versus 74 MBPD during the same period in 2000 due to increased demand for the
Company's services. Gross operating margin from propylene fractionation decreased $2.8 million compared to the
first six months of 2001 primarily due to higher energy costs and moderating prices. Net propylene fractionation
volumes were 30 MBPD for both periods.
Pipeline. The Company's gross operating margin for the Pipeline segment was $42.8 million compared to
$28.8 million in 2000. Of the $14.0 million increase, $6.9 million is attributable to natural gas
transportation activities (i.e. Acadian Gas and the Gulf of Mexico systems) which benefited from a strong natural
gas marketplace in 2001. The Company's recently completed Lou-Tex NGL Pipeline added $5.1 million on volumes
of 22 MBPD. In addition, margin on the Company's Lou-Tex Propylene Pipeline for 2001 was $2.9 million higher
than 2000 (primarily due to this asset being purchased in March 2000). Strong imports of mixed NGLs
(particularly commercial butanes) resulted in a $3.1 million increase in margins for the Houston Ship Channel
import facility and related pipeline system. The increase in commercial butane imports was related to the
strong demand for isobutane which occurred between February and May 2001.
Overall, net throughput on the Company's major liquids pipelines improved to 438 MBPD in 2001 versus 350
MBPD in 2000, with 76 MBPD of the increase stemming from increased imports and related pipeline activity along
the Houston Ship Channel. Net throughput for the natural gas pipelines averaged 1,263 BBtu/d with Acadian Gas
accounting for 725 BBtu/d and the Gulf of Mexico systems for the balance.
Processing. For the 2001 period, the Processing segment generated gross operating margin of $96.5
million compared to $58.0 million in 2000. Gross operating margin from the natural gas processing plants posted
a $4.1 million increase over 2000 levels primarily due to a $67.3 million increase in net hedging gains from $3.0
million in 2000 to $70.3 million in 2001 (see discussion below). The net hedging gains more than offset the
effects of lower equity NGL volumes and prices and a rise in energy-related operating costs. Equity NGL
production averaged 54 MBPD during the 2001 period compared to 72 MBPD during the 2000 period. The 2001 rate
of 54 MBPD reflects the very low NGL extraction rates of the first quarter of 2001 (46 MBPD) when natural gas
prices were at their peak. As natural gas costs have declined since January 2001, equity NGL production has
begun returning to higher levels (63 MBPD during the second quarter of 2001). The 2000 rate reflects a period in
which processors were operating facilities at near full extraction rates. Gross operating margin from merchant
activities increased $34.4 million over 2000 primarily due to strong demand for propane in the first quarter of
2001 for heating and isobutane in the second quarter of 2001 for refining.
Page 31
Gross operating margin for the 2001 period includes $70.3 million of net hedging profits resulting from
the Company's commodity hedging activities. Of this amount, $52.5 million is attributable to non-cash
mark-to-market gains on the commodity financial instruments that were outstanding at June 30, 2001. As
discussed earlier under the Processing segment's quarter-to-quarter variance explanation (see Page 30), the
Company employs various hedging strategies to mitigate the effects of fluctuating commodity prices (primarily NGL
prices) on its natural gas processing business and related merchant activities. Of the $70.3 million in net
hedging profits, $17.8 million is attributable to realized gains on the settlement and early closeout of certain
positions.
Currently, the predominant strategy employed by the Company utilizes natural gas-based commodity
financial instruments to hedge future NGL production and sales. This type of hedge is based upon the historical
relationship between natural gas and NGL prices. The key factor behind the net hedging gains recognized by the
Company is the decline in natural gas prices relative to the fixed natural gas prices found in its commodity
financial instrument portfolio. If natural gas prices had not declined to the degree seen during the quarter, a
smaller gain or a loss on hedging activities may have resulted which should have been offset somewhat by
correlative higher NGL prices which would have increased the value of the Company's equity NGL production. A
variety of factors influence whether or not the Company's hedging strategy is successful. For additional
information regarding the Company's commodity financial instruments, see Item 3 "Quantitative and Qualitative
Disclosures about Market Risk" on page 36 and the quarter-to-quarter variance explanation for Processing found on
page 31.
Octane Enhancement. The Company's gross operating margin for Octane Enhancement decreased $5.4 million
in the first six months of 2001 compared with the same period in 2000. MTBE production, on a net basis, was 4
MBPD in 2001 and 5 MBPD in 2000. The decline in margin is primarily due to lower MTBE prices in 2001 relative
to the 2000 period, higher energy-related operating costs and a prolonged maintenance outage which lasted from
December 2000 until February 2001.
Interest expense. Interest expense for 2001 increased $7.5 million over 2000. The increase is
attributable to the interest associated with the $450 Million Senior Notes issued in January 2001. Interest
expense for 2001 includes a $5.5 million benefit related to a change in fair value of the Company's interest rate
swaps. The change in fair value of the interest rate swaps does not represent a cash gain or loss for the
Company. The actual cash gain or loss on the interest rate swap agreements will be based upon market interest
rates in effect on the specified settlement dates in the swap agreements. The $5.5 million benefit is primarily
due to the decision of one counterparty not to exercise its early termination right under its swap agreement with
the Company and, to a lesser extent, lower overall borrowing rates.
Liquidity and Capital Resources
General. The Company's primary cash requirements, in addition to normal operating expenses and debt
service, are for capital expenditures (both maintenance and expansion-related), business acquisitions and
distributions to its partners. The Company expects to fund its short-term needs for such items as maintenance
capital expenditures and quarterly distributions to its partners from operating cash flows. Capital expenditures
for long-term needs resulting from future expansion projects and business acquisitions are expected to be funded
by a variety of sources including (either separately or in combination) cash flows from operating activities,
borrowings under bank credit facilities and the issuance of additional Common Units and public debt. The
Company's debt service requirements are expected to be funded by operating cash flows or refinancing arrangements.
As noted above, certain of the Company's liquidity and capital resource requirements are met using
borrowings under bank credit facilities and/or the issuance of additional Common Units or public debt (separately
or in combination). As of June 30, 2001, availability under the Company's revolving bank credit facilities was
$400 million (which may be increased to $500 million under certain conditions). In addition to the existing
revolving bank credit facilities, a subsidiary of the Company issued $450 million of public debt in January 2001
(the "$450 Million Senior Notes") using the remaining shelf availability under its $800 million December 1999
universal shelf registration (the "December 1999 Registration Statement"). The proceeds from this offering were
used to acquire the Acadian Gas and Gulf of Mexico natural gas pipeline systems and to finance the cost to
construct certain NGL pipelines and related projects and for working capital and other general partnership
purposes. On February 23, 2001, the Company filed a $500 million universal shelf registration (the "February
Page 32
2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt securities or a
combination thereof. For a broader discussion of the Company's outstanding debt and changes therein, see the
section below labeled "Long-term Debt".
In June 2000, the Company received approval from its Unitholders to increase by 25,000,000 the number of
Common Units available (and unreserved) to the Company for general partnership purposes during the Subordination
Period. This increase has improved the future financial flexibility of the Company in any potential business
acquisition.
If deemed necessary, management believes that additional financing arrangements can be obtained at
reasonable terms. Management believes that maintenance of the Company's investment grade credit ratings
(currently, Baa2 by Moody's Investor Service and BBB by Standard and Poors) combined with a continued ready
access to debt and equity capital at reasonable rates and sufficient trade credit to operate its businesses
efficiently are a solid foundation to providing the Company with ample resources to meet its long and short-term
liquidity and capital resource requirements.
Operating, Investing and Financing Cash Flows for the six months ended June 30, 2001 and 2000. Cash
flows from operating activities were a $90.6 million inflow for 2001 compared to a $194.8 million inflow in
2000. Cash flows from operating activities primarily reflect the effects of net income, depreciation and
amortization, equity income and distributions from unconsolidated affiliates, fluctuations in fair values of
financial instruments and changes in working capital. Net income increased $30.3 million in 2001 compared to
2000 due to reasons mentioned previously under "Results of Operation of the Company". Depreciation and
amortization increased a combined $4.9 million in 2001 over 2000 primarily due to additional capital expenditures
and business acquisitions. The Company received $13.2 million in distributions from its equity method
investments in 2001 compared to $14.3 million in 2000. The $1.1 million decrease in distributions is primarily
related to a decrease in BEF's earnings due to lower MTBE prices and volumes, lower throughput volumes on the
Tri-States pipeline system and processing volumes at Promix attributable to lower NGL extraction rates during the
early part of 2001 offset by receipts from the newly acquired Gulf of Mexico natural gas pipelines. Operating
cash flow also includes an adjustment for the $55.9 million in non-cash mark-to-market gains related to commodity
and interest rate risk hedging activities. The net effect of changes in operating accounts from period to period
is generally the result of timing of NGL sales and purchases near the end of the period and changes in inventory
values related to pricing or volumes or a combination thereof.
The Company is exposed to various market risks including commodity price risk (primarily through its gas
processing and related NGL businesses) and interest rate risk. The Company attempts to manage its price risk by
utilizing certain hedging strategies defined elsewhere herein. These risks, however, may entail significant
cash outlays in the future that may not be entirely offset by their underlying hedged positions. During 2001,
the Company has recognized $70.3 million in net hedging profits related to its commodity hedging portfolio. Of
this amount, a net $17.8 million has been realized through settlements and the early closeout of certain
positions through June 30, 2001. The remaining $52.5 million represents non-cash mark-to-market gains on
commodity financial instruments that remained open at June 30, 2001. When appropriate, the Company may elect to
close certain of its commodity financial instruments prior to their contractual settlement dates in order to
realize gains or limit losses. As of August 1, 2001, the Company has realized $26.3 million of the $52.5
million in non-cash mark-to-market gains recorded at the end of the second quarter. The realization of the
remaining amount depends upon a number of factors including, most notably, the current market price of natural
gas on the settlement or closing date relative to the price in the underlying financial instruments. If the
price of natural gas rises beyond the hedging positions taken by the Company, it will result in losses rather
than gains on its hedging activities. The Company continues to aggressively monitor its commodity hedging
portfolio in light of the energy markets. For a more complete description of the Company's risk management
policies and potential exposures, see "Item 3. Quantitative and Qualitative Disclosures about Market Risk" on
page 36 and Note 10 of the Notes to Unaudited Consolidated Financial Statements.
Cash used for investing activities was $397.5 million in 2001 compared to $150.7 million in 2000. Cash
outflows included capital expenditures of $57.1 million in 2001 versus $154.2 million in 2000. Capital
expenditures for 2000 include $99.5 million for the purchase of the Lou-Tex Propylene Pipeline and related
assets. In addition, capital expenditures include maintenance capital project costs of $2.7 million in 2001 and
$0.5 million in 2000. The Company's completion of the Acadian Gas business acquisition resulted in an initial
Page 33
payment to Shell of $225.7 million in April 2001, subject to certain post-closing purchase price adjustments.
The 2000 period also includes $6.5 million in cash receipts related to the Company's participation in the BEF
note, which was extinguished in May 2000 with BEF's final principal payment. Lastly, investing cash outflows in
2001 includes $115.3 million in investments in and advances to unconsolidated affiliates compared to $3.0 million
in 2000. The increase is due to the purchase of the Gulf of Mexico natural gas pipeline systems in January
2001.
Cash receipts from financing activities were $362.4 million during 2001 compared to $37.8 million in
2000. Cash flows from financing activities are primarily affected by repayments of debt, borrowings under debt
agreements and distributions to partners. The 2001 period includes proceeds from the $450 Million Senior Notes
issued in January 2001 whereas the 2000 period includes proceeds from the $350 Million Senior Notes and $54
Million MBFC Loan and the associated repayments on various bank credit facilities. Distributions to partners
and the minority interest increased to $76.1 million in 2001 from $67.6 million in 2000 primarily due to an
increase in the quarterly distribution rate.
During the first six months of 2001, the Company has invested $338 million in business acquisitions and
the purchase of interests in other companies. These investments include the acquisition of Acadian Gas and
interests in four natural gas pipelines in the Gulf of Mexico. The Company will continue to analyze potential
acquisitions, joint ventures or similar transactions with businesses that operate in complementary markets and
geographic regions. In recent years, major oil and gas companies have sold non-strategic assets including
assets in the midstream natural gas industry in which the Company operates. Management believes that this trend
will continue, and the Company expects independent oil and natural gas companies to consider similar options.
In addition, management believes that the Company is well positioned to continue to grow through acquisitions
that will expand its platform of assets and through internal growth. The Company anticipates that it will
achieve its annual growth objective for 2001: investing $400 million in energy infrastructure projects and
acquisitions while increasing its cash distribution rate to Unitholders by at least 10% for the full year.
The cash distribution policy (as managed by the General Partner at its sole discretion) allows the
Company to retain a significant amount of cash flow for reinvestment in the growth of the business. Over the
last two years, the Company has reinvested approximately $238 million to fund expansions and acquisitions. The
Company's cash distribution policy provides management with a great deal of financial flexibility in executing
its growth strategy.
Future Capital Expenditures. The Company forecasts that $100.7 million will be spent during the
remainder of 2001 on currently approved capital projects that will be recorded as property, plant and equipment
(the majority of which relate to various pipeline projects such as the Sorrento to Napoleonville pipeline and
Port Arthur to Lake Charles system). In addition, the Company estimates that its share of currently approved
capital expenditures in the projects of its unconsolidated affiliates will be approximately $1.1 million for the
remainder of 2001.
As of June 30, 2001, the Company had $11.3 million in outstanding purchase commitments attributable to
its capital projects. Of this amount, $10.9 million is related to the construction of assets that will be
recorded as property, plant and equipment and $0.4 million is associated with capital projects which will be
recorded as additional investments in unconsolidated affiliates.
New Texas environmental regulations may necessitate extensive redesign and modification of the Company's
Mont Belvieu facilities to achieve the air emissions reductions needed for federal Clean Air Act compliance in
the Houston-Galveston area. Until litigation challenging these regulations is resolved, the technology to be
employed and the cost for modifying the facilities to achieve enough reductions cannot be determined, and capital
funds have not been budgeted for such work. Regardless of the outcome of this litigation, expenditures for
emissions reduction projects will be spread over several years, and management believes the Company will have
adequate liquidity and capital resources to undertake them. For additional information about this litigation,
see the discussion under the topic Clean Air Act--General on page 22 of the Company's Form 10-K for fiscal 2000.
Page 34
Long-term Debt. Long-term debt consisted of the following at:
June 30, December 31,
2001 2000
---------------------------------------
Borrowings under:
$350 Million Senior Notes, 8.25% fixed rate, due March 2005 350,000 350,000
$54 Million MBFC Loan, 8.70% fixed rate, due March 2010 54,000 54,000
$450 Million Senior Notes, 7.50% fixed rate, due February 2011 450,000
---------------------------------------
Total principal amount 854,000 404,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt 2,015
Less unamortized discount on:
$350 Million Senior Notes (135) (153)
$450 Million Senior Notes (272)
Less current maturities of long-term debt
---------------------------------------
Long-term debt $855,608 $403,847
=======================================
The Company has the ability to borrow under the terms of its $250 Million Multi-Year Credit Facility
and $150 Million 364-Day Credit Facility. No amount was outstanding under either of these two revolving credit
facilities at June 30, 2001 or December 31, 2000.
At June 30, 2001, the Company had a total of $75 million of standby letters of credit capacity under its
$250 Million Multi-Year Credit Facility of which $19.9 million was outstanding.
On January 24, 2001, a subsidiary of the Company completed a public offering of $450 million in
principal amount of 7.50% fixed-rate Senior Notes due February 1, 2011 at a price to the public of 99.937% per
Senior Note (the "$450 Million Senior Notes"). The Company received proceeds, net of underwriting discounts and
commissions, of approximately $446.8 million. The proceeds from this offering were used to acquire the Acadian
Gas and Gulf of Mexico natural gas pipeline systems and to finance the cost to construct certain NGL pipelines
and related projects and for working capital and other general partnership purposes.
The $450 Million Senior Notes were issued under the indenture agreement dated March 15, 2000 which is
also applicable to the $350 Million Senior Notes and therefore are subject to similar covenants and terms. As
with the $350 Million Senior Notes, the $450 Million Senior Notes are:
o subject to a make-whole redemption right;
o an unsecured obligation and rank equally with existing and future unsecured and unsubordinated
indebtedness and senior to any future subordinated indebtedness; and,
o guaranteed by the Company through an unsecured and unsubordinated guarantee.
The Company was in compliance with the restrictive covenants associated with the $350 Million and $450 Million
Senior Notes at June 30, 2001.
The issuance of the $450 Million Senior Notes was a final takedown under the December 1999 Registration
Statement; therefore, the amount of securities available under this universal shelf registration statement was
reduced to zero. On February 23, 2001, the Company filed a $500 million universal shelf registration statement
(the "February 2001 Registration Statement") covering the issuance of an unspecified amount of equity or debt
securities or a combination thereof. The Company expects to use the net proceeds from any sale of securities
under the February 2001 Registration Statement for future business acquisitions and other general corporate
purposes, such as working capital, investments in subsidiaries, the retirement of existing debt and/or the
repurchase of Common Units or other securities. The exact amounts to be used and when the net proceeds will be
applied to partnership purposes will depend on a number of factors, including the Company's funding requirements
and the availability of alternative funding sources. The Company routinely reviews acquisition opportunities.
Page 35
Upon adoption of Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for
Derivative Instruments and Hedging Activities (as amended and interpreted) on January 1, 2001, the Company
recorded a $2.3 million non-cash increase in the fair value of its fixed-rate debt. SFAS 133 required that the
Company's interest rate swaps and their associated hedged fixed-rate debt be recorded at fair value upon adoption
of the standard. After adoption of the standard, the interest rate swaps were dedesignated due to differences
in the estimated maturity dates of the interest rate swaps versus the fixed-rate debt. As a result, the fair
value of the hedged fixed-rate debt will not be adjusted for future changes in fair value and the $2.3 million
increase in the fair value of the debt will be amortized to earnings over the remaining life of the fixed-rate
debt to which it applies, which approximates 10 years. See Note 5 and Note 10 of the Notes to Unaudited
Consolidated Financial Statements for additional information regarding interest rate swaps and the associated
change in the fair value of the fixed-rate debt.
Recently Issued Accounting Standards
In June 2001, the FASB issued two new pronouncements: SFAS No. 141, " Business Combinations", and SFAS
No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 prohibits the use of the pooling-of-interest
method for business combinations initiated after June 30, 2001 and also applies to all business combinations
accounted for by the purchase method that are completed after June 30, 2001. There are also transition
provisions that apply to business combinations completed before July 1, 2001, that were accounted for by the
purchase method. SFAS 142 is effective for fiscal years beginning after December 15, 2001 to all goodwill and
other intangible assets recognized in an entity's statement of financial position at that date, regardless of
when those assets were initially recognized. The Company is currently evaluating the provisions of SFAS 141 and
SFAS 142 and has not adopted such provisions in its June 30, 2001 financial statements.
Issuance of last installment of Special Units to Shell
On or about June 30, 2001, Shell met certain year 2001 performance criteria for the issuance of the
remaining 3.0 million non-distribution bearing, convertible Contingency Units (referred to as Special Units once
they are issued). Per a contingent unit agreement with Shell, the Company issued these Special Units on August
2, 2001.
The value of these Special Units was determined to be $117.1 million using persent value techniques.
This amount will increase the purchase price of the TNGL acquisition and the value of the Shell Processing
Agreement when the issue is recorded during the third quarter of 2001. The $117.1 million increase in value of
the Shell Processing Agreement will be amortized over the remaining life of the contract. As a result, the
Company's amortization expense is expected to increase by approximately $1.6 million per quarter ($6.5 million
annually).
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to financial market risks, including changes in commodity prices in its natural
gas and NGL businesses and in interest rates with respect to a portion of its debt obligations. The Company may
use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar
characteristics) to mitigate these risks. The Company generally does not use financial instruments for
speculative (trading) purposes.
Commodity Price Risk
The Company is exposed to commodity price risk through its natural gas and related NGL businesses. The
prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty
and a variety of additional factors that are beyond the Company's control. These factors include the level of
domestic oil, natural gas and NGL production, the availability of imported oil and natural gas, actions taken by
foreign oil and natural gas producing nations, the availability of transportation systems with adequate capacity,
the availability of alternative fuels and products, seasonal demand for oil, natural gas and NGLs, conservation,
the extent of governmental regulation of production and the overall economic environment.
Page 36
In order to manage this risk, the Company may enter into swaps, forwards, commodity futures, options and
other commodity financial instruments with similar characteristics that are permitted by contract or business
custom to be settled in cash or with another financial instrument. The purpose of these risk management
activities is to hedge exposure to price risks associated with natural gas, NGL production and inventories, firm
commitments and certain anticipated transactions. As an ancillary service, Acadian Gas utilizes commodity
financial instruments to manage the sales price of natural gas for certain of its customers.
The Company has adopted a commercial policy to manage its exposure to the risks generated by its natural
gas and related NGL businesses. The objective of this policy is to assist the Company in achieving its
profitability goals while maintaining a portfolio of conservative risk, defined as remaining within the position
limits established by the General Partner. The Company enters into risk management transactions to manage price
risk, basis risk, physical risk, or other risks related to its commodity positions on both a short-term (less
than 30 days) and long-term basis, not to exceed 18 months. The General Partner oversees the strategies of the
Company associated with physical and financial risks, approves specific activities of the Company subject to the
policy (including authorized products, instruments and markets) and establishes specific guidelines and
procedures for implementing and ensuring compliance with the policy.
The Company assesses the risk of its commodity financial instrument portfolio using a sensitivity
analysis model. The sensitivity analysis performed on this portfolio measures the potential gain or loss in
earnings (i.e., the change in fair value of the portfolio) based on a hypothetical 10% movement in the underlying
quoted market prices of the commodity financial instruments outstanding at the dates noted within the table.
The sensitivity analysis model takes into account the following primary factors and assumptions:
- the current quoted market price of natural gas;
- the current quoted market price of related NGL production;
- changes in the composition of commodities hedged (i.e., the mix
between natural gas and related NGL hedges outstanding);
- fluctuations in the overall volume of commodities hedged (for
both natural gas and related NGL hedges outstanding);
- market interest rates, which are used in determining the present
value; and,
- a liquid market for such financial instruments.
An increase in fair value of the commodity financial instruments (based upon the factors and assumptions
noted above) approximates the gain that would be recognized in earnings if all of the commodity financial
instruments were settled at the respective balance sheet dates. Conversely, a decrease in fair value of the
commodity financial instruments would result in the recording of a loss at the respective balance sheet date.
The sensitivity analysis model does not include the impact that the same hypothetical price movement
would have on the hedged commodity positions to which they relate. Therefore, the impact on the fair value of
the commodity financial instruments of a change in commodity prices would be offset by a corresponding gain or
loss on the hedged commodity positions, assuming:
- the commodity financial instruments are not closed out in advance
of their expected term,
- the commodity financial instruments function effectively as
hedges of the underlying risk, and
- as applicable, anticipated underlying transactions settle as
expected.
The Company routinely reviews its open commodity financial instruments in light of current market
conditions. If market conditions warrant, some instruments may be closed out in advance of their contractual
settlement dates thus realizing a gain or loss depending on the specific exposure. When this occurs, the
Company may enter into new commodity financial instruments to reestablish the hedge of the commodity position to
which the closed instrument relates.
Under the guidelines of SFAS 133, as amended and interpreted, a hedge is normally regarded as effective
if, among other things, at inception and throughout the life of the hedge, the Company could expect changes in
the fair value of the hedged item to be almost fully offset by the changes in the fair value of the hedging
instrument. Currently, the Company's commodity financial instruments do not qualify as effective hedges under
Page 37
the guidelines of SFAS 133, with the result being that changes in the fair value of these financial instruments
are recorded on the balance sheet and in earnings through mark-to-market accounting. The use of mark-to-market
accounting for the commodity financial instruments portfolio results in a degree of non-cash earnings volatility
that is dependant upon changes in the underlying commodity prices. Even though the commodity financial
instruments do not qualify for hedge accounting treatment under the specific guidelines of SFAS 133, the Company
views these financial instruments as hedges in as much as this was the intent when such contracts are executed.
This characterization is consistent with the actual economic performance of the contracts and the Company expects
these financial instruments to continue to mitigate commodity price risk in the future. For additional
information regarding commodity financial instruments, see Note 10 of the Notes to Unaudited Consolidated
Financial Statements.
Sensitivity Analysis for Commodity Financial Instruments Portfolio
Estimates of Fair Value ("FV") and Earnings Impact ("EI")
due to selected changes in quoted market prices at dates selected
December June August
31, 2000 30, 2001 7, 2001
------------------------------------------
(in millions of dollars)
------------------------------------------
FV assuming no change in quoted market prices, Asset (Liability) $(38.6) $ 49.2 $32.7
FV assuming 10% increase in quoted market prices, Asset (Liability) $(56.3) $ 37.4 $24.9
EI assuming 10% increase in quoted market prices, Gain (Loss) $(17.7) $(11.8) $(7.8)
FV assuming 10% decrease in quoted market prices, Asset (Liability) $(20.9) $ 61.5 $41.2
EI assuming 10% decrease in quoted market prices, Gain (Loss) $ 17.7 $ 12.3 $ 8.5
The fair value of the commodity financial instruments at December 31, 2000 was estimated at $38.6
million payable. On June 30, 2001, the fair value of the commodity financial instruments outstanding was
estimated at $49.2 million receivable. The change in fair value between December 31, 2000 and June 30, 2001 was
primarily due to the lower natural gas prices, settlement of certain open positions and a change in the
composition of commodities hedged. By August 7, 2001, the fair value of the commodity financial instruments was
$32.7 million reflecting the early closeout of certain positions and changes in natural gas prices since June 30,
2001.
Historical gains or losses resulting from these hedging activities are a component of the Company's
operating costs and expenses as reflected in its Statements of Consolidated Operations.
Interest rate risk
Variable-rate Debt. At June 30, 2001 and 2000, the Company had no variable rate debt outstanding and as
such had no financial instruments in place to cover any potential interest rate risk on its variable-rate debt
obligations. Variable-rate debt obligations do expose the Company to possible increases in interest expense and
decreases in earnings if interest rates were to rise.
Fixed-rate Debt. In March 2000, the Company entered into interest rate swaps whereby the fixed-rate of
interest on a portion of the $350 Million Senior Notes and the $54 Million MBFC Loan was effectively swapped for
floating-rates tied to the six month London Interbank Offering Rate ("LIBOR"). The objective of holding
interest rate swaps is to manage debt service costs by effectively converting a portion of the fixed-rate debt
into variable-rate debt. An interest rate swap, in general, requires one party to pay a fixed-rate on the
notional amount while the other party pays a floating-rate based on the notional amount. Management believes
that it is prudent to maintain a balance between variable-rate and fixed-rate debt.
The Company assesses interest rate cash flow risk by identifying and measuring changes in interest rate
exposure that impact future cash flows and by evaluating hedging opportunities. The Company uses analytical
techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis to
Page 38
estimate the expected impact of changes in interest rates on the Company's future cash flows. The General
Partner oversees the strategies of the Company associated with financial risks and approves instruments that are
appropriate for the Company's requirements.
The following table presents the hypothetical changes in fair values arising from immediate selected
potential changes in quoted market prices of the Company's interest rate swaps outstanding at the dates noted
within the table. The sensitivity analysis model used to estimate the fair values of the interest rate swaps
takes into account the following primary factors/assumptions: (a)current market interest rates (including
forward LIBOR rates and current federal funds rate), (b) early termination options exercisable by the
counterparty (if the fair value of the swap indicates a receivable) and (c) a liquid market for interest rate
swaps. An increase in fair value of the interest rate swaps approximates the gain that would be recognized in
earnings if all of the interest rate swaps were settled at the respective balance sheet dates. Conversely, a
decrease in fair value of the interest rate swaps would result in the recording of a loss at the respective
balance sheet date. The gains or losses resulting from the interest rate hedging activities are a component of
the Company's interest expense as reflected in its Statements of Consolidated Operations.
Sensitivity Analysis for Interest Rate Swap Portfolio
Estimates of Fair Value ("FV") and Earnings Impact ("EI")
due to selected changes in quoted market prices at dates selected
December June August
31, 2000 30, 2001 7, 2001
------------------------------------------
(Estimates in millions of dollars)
------------------------------------------
FV assuming no change in quoted market prices, Asset (Liability) $ 2.5 $ 7.1 $ 8.8
FV assuming 10% increase in quoted market prices, Asset (Liability) $ 1.9 $ 5.9 $ 7.6
EI assuming 10% increase in quoted market prices, Gain (Loss) $(0.6) $(1.2) $(1.2)
FV assuming 10% decrease in quoted market prices, Asset (Liability) $ 3.1 $ 8.4 $ 9.9
EI assuming 10% decrease in quoted market prices, Gain (Loss) $ 0.6 $ 1.3 $ 1.1
The interest rate swaps outstanding at December 31, 2000 reflected a notional amount of $154 million of
fixed-rate debt with the fair value of swaps estimated at $2.5 million. By June 30, 2001, the notional amount
had been reduced to $104 million due to the early termination of one of the swaps by a counterparty with the
aggregate fair value of the remaining swaps estimated at $7.1 million. The change in fair value between
December 31, 2000 and June 30, 2001 is primarily related to lower interest rates and the decision by one
counterparty not to exercise its early termination right. At August 7, 2001, the fair value of the interest rate
swaps was estimated at $8.8 million due to lower interest rates.
The Company's interest rate swap agreements were dedesignated as hedging instruments after the adoption
of SFAS 133; therefore, the interest rate swap agreements are accounted for on a mark-to-market basis. However,
these financial instruments continue to be effective in achieving the risk management activities for which they
were intended. As a result, the change in fair value of these instruments will be reflected on the balance sheet
and in earnings (interest expense) using mark-to-market accounting. For additional information regarding the
interest rate swaps, see Note 10 of the Notes to Unaudited Consolidated Financial Statements that are part of
this Form 10-Q quarterly report.
Other. At June 30, 2001 and December 31, 2000, the Company had $123.3 million and $60.4 million
invested in cash and cash equivalents, respectively. All cash equivalent investments other than cash are highly
liquid, have original maturities of less than three months, and are considered to have insignificant interest
rate risk.
Page 39
Counterparty risk
The Company has credit risk from its extension of credit for sales of products and services, and has
credit risk with its counterparties in terms of settlement risk and performance risk associated with its
commodity financial instruments and interest rate swap agreements. On all transactions where the Company is
exposed to credit risk, the Company analyzes the counterparty's financial condition prior to entering into an
agreement, establishes credit limits and monitors the appropriateness of these limits on an ongoing basis. The
counterparty to a majority of the Company's commodity financial instruments is a major Houston, Texas-based
energy company. The credit risk to this party is somewhat mitigated by cash or letters of credit held by the
Company in an amount dependent upon the exposure to the counterparty.
Related Accounting Developments
Due to the complexity of SFAS 133, the FASB organized a formal committee, the Derivatives Implementation
Group ("DIG"), to provide ongoing recommendations to the FASB about implementation issues. Implementation
guidance issued through the DIG process is still continuing; therefore, the initial conclusions reached by the
Company concerning the application of SFAS 133 upon adoption may be altered. As a result, additional SFAS 133
transition adjustments may be recorded in future periods as the Company adopts new DIG interpretations approved
by the FASB. For additional information regarding SFAS 133, see Note 10 of the Notes to Unaudited Consolidated
Financial Statements.
PART II. OTHER INFORMATION
Item 2. Use of Proceeds
The following table shows the Use of Proceeds from the $450 Million Senior Notes offering completed on
January 29, 2001. The $450 Million Senior Notes represented a takedown of the remaining shelf availability
under the Company's December 1999 Registration Statement filed with the Securities and Exchange Commission (File
Nos. 333-93239 and 333-93239-01, effective January 14, 2000).
The title of the registered debt securities was "7.50% Senior Notes Due 2011." The underwriters of the
offering were Goldman, Sachs and Co., Salomon Smith Barney Inc., Banc One Capital Markets, Inc., First Union
Securities, Inc., Scotia Capital (USA) Inc. and Tokyo-Mitsubishi International plc. The 10-year Senior Notes
have a maturity date of February 1, 2011 and bear a fixed-rate interest coupon of 7.50%.
Amounts
(in millions)
--------------
Proceeds:
Sale of $450 Million Senior Notes to public at 99.937% per Note $ 450
Less underwriting discount of 0.650% per Note (3)
--------------
Total proceeds $ 447
==============
Use of Proceeds:
Initial payment to finance Acadian Gas acquisition $(226)
To finance investment in various Gulf of Mexico
natural gas pipelines (112)
To finance remainder of the costs to construct certain NGL
pipelines and related projects, and for working capital
and other general Company purposes (109)
--------------
Total uses of funds $(447)
==============
The initial $226 million payment to Shell for Acadian Gas was made in April 2001, subject to certain post-closing
purchase price adjustments. Also, the Company paid EPE $112 million in January 2001 for the purchase of equity
interests in four Gulf of Mexico natural gas pipeline systems (Starfish, Ocean Breeze, Neptune and Nemo).
Page 40
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
*2.1 Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated as of
September 22, 2000. (Exhibit 10.1 to Form 8-K filed on September 26, 2000).
*3.1 Form of Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P.
(Exhibit 3.2 to Registration Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*3.2 Second Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "D"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*3.3 First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated
September 17, 1999. (Exhibit 99.8 on Form 8-K/A-1 filed October 27, 1999).
*3.4 Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Enterprise Products
Partners L.P. dated June 9, 2000. (Exhibit 3.6 to Form 10-Q filed August 11, 2000).
*4.1 Form of Common Unit certificate. (Exhibit 4.1 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 21, 1998).
*4.2 Unitholder Rights Agreement among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise
Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by
reference the above document included as Exhibit "C" to the Schedule 13D filed September 27, 1999 by
Tejas Energy, LLC.
*4.3 Contribution Agreement by and among Tejas Energy LLC, Tejas Midstream Enterprises, LLC, Enterprise
Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products Company, Enterprise
Products GP, LLC and EPC Partners II, Inc. dated September 17, 1999. (The Company incorporates by
reference the above document included as Exhibit "B" to the Schedule 13D filed September 27, 1999 by
Tejas Energy, LLC.
*4.4 Registration Rights Agreement between Tejas Energy LLC and Enterprise Products Partners L.P. dated
September 17, 1999. (The Company incorporates by reference the above document included as Exhibit "E"
to the Schedule 13D filed September 27, 1999 by Tejas Energy, LLC.
*4.5 Form of Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer,
Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee. (Exhibit
4.1 on Form 8-K filed March 10, 2000).
*4.6 Form of Global Note representing $350 million principal amount of 8.25% Senior Notes Due 2005.
(Exhibit 4.2 on Form 8-K filed March 10, 2000).
*4.7 $250 Million Multi-Year Revolving Credit Agreement among Enterprise Products Operating L.P., First Union
National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan
Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17,
2000. (Exhibit 4.2 on Form 8-K filed January 25, 2001).
*4.8 $150 Million 364-Day Revolving Credit Agreement among Enterprise Products Operating L.P. and First Union
National Bank, as administrative agent; Bank One, NA, as documentation agent; and The Chase Manhattan
Page 41
Bank, as syndication agent and the Several Banks from time to time parties thereto dated November 17,
2000. (Exhibit 4.3 on Form 8-K filed January 25, 2001).
*4.9 Guaranty Agreement (relating to the $250 Million Multi-Year Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.4 on Form 8-K filed January 25, 2001).
*4.10 Guaranty Agreement (relating to the $150 Million 364-Day Revolving Credit Agreement) by Enterprise
Products Partners L.P. in favor of First Union National Bank, as administrative agent dated November 17,
2000. (Exhibit 4.5 on Form 8-K filed January 25, 2001).
*4.11 Form of Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011. (Exhibit
4.1 to Form 8-K filed January 25, 2001).
*4.12 First Amendment to $250 million Multi-Year Revolving Credit Agreement dated April 19, 2001.
*10.1 Articles of Merger of Enterprise Products Company, HSC Pipeline Partnership, L.P., Chunchula Pipeline
Company, LLC, Propylene Pipeline Partnership, L.P., Cajun Pipeline Company, LLC and Enterprise
Products Texas Operating L.P. dated June 1, 1998.(Exhibit 10.1 to Registration Statement on Form S-1/A,
File No: 333-52537, filed on July 8, 1998).
*10.2 Form of EPCO Agreement among Enterprise Products Partners L.P., Enterprise Products Operating
L.P., Enterprise Products GP, LLC and Enterprise Products Company. (Exhibit 10.2 to Registration
Statement on Form S-1/A, File No. 333-52537, filed on July 21, 1998).
*10.3 Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company
dated June 1, 1998. (Exhibit 10.3 to Registration Statement on Form S-1/A, File No. 333-52537, filed on
July 8, 1998).
*10.4 Venture Participation Agreement among Sun Company, Inc. (R and M), Liquid Energy Corporation and Enterprise
Products Company dated May 1, 1992. (Exhibit 10.4 to Registration Statement on Form S-1,
File No. 333-52537, filed on May 13, 1998).
*10.5 Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products
Company dated May 1, 1992. (Exhibit 10.5 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.6 Amended and Restated MTBE Off-Take Agreement between Belvieu Environmental Fuels and Sun Company, Inc.
(R and M) dated August 16, 1995. (Exhibit 10.6 to Registration Statement on Form S-1, File No. 333-52537,
filed on May 13, 1998).
*10.7 Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules
Incorporated dated December 13, 1978. (Exhibit 10.9 to Registration Statement on Form S-1, File No.
333-52537, dated May 13, 1998).
*10.8 Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among
Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum
Company dated July 17, 1985. (Exhibit 10.10 to Registration Statement on Form S-1/A, File No. 333-52537,
filed on July 8, 1998).
*10.9 Ratification and Joinder Agreement relating to Mont Belvieu Associates Facilities among 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).
Page 42
*10.10 Amendment to Propylene Facility and Pipeline Sales Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1993. (Exhibit 10.12 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.11 Amendment to Propylene Facility and Pipeline Agreement between HIMONT U.S.A., Inc. and Enterprise
Products Company dated January 1, 1995. (Exhibit 10.13 to Registration Statement on Form S-1/A, File No.
333-52537, filed on July 8, 1998).
*10.12 Fourth Amendment to Conveyance of Gas Processing Rights among Tejas Natural Gas Liquids, LLC and Shell
Oil Company, Shell Exploration and Production Company, Shell Offshore Inc., Shell Deepwater Development
Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas Inc. dated August 1, 1999. (Exhibit
10.14 to Form 10-Q filed on November 15, 1999).
10.13 Fifth Amendment to Conveyance of Gas Processing Rights dated as of April 1, 2001 among Enterprise Gas
Processing, LLC, Shell Oil Company, Shell Exploration and Production Company, Shell Offshore, Inc., Shell
Consolidated Energy Resources, Inc., Shell Land and Energy Company and Shell Frontier Oil and Gas, Inc.
* Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith
(b) Reports on Form 8-K
The following Form 8-K reports were filed during the quarter ending June 30, 2001:
8-K filed on April 4, 2001. On April 2, 2001, the Company announced that its Operating Partnership had
completed the purchase of Acadian Gas from an affiliate of Shell. The effective date of the transaction was
April 1, 2001.
Page 43
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized.
Enterprise Products Partners L.P.
(A Delaware Limited Partnership)
By: Enterprise Products GP, LLC
as General Partner
/s/ Michael J. Knesek
------------------------------
Vice President, Controller and
Date: August 13, 2001 Principal Accounting Officer
FIFTH AMENDMENT TO CONVEYANCE
OF
GAS PROCESSING RIGHTS
Dated as of April 1, 2001
Between
Enterprise Gas Processing, LLC,
Shell Oil Company,
Shell Exploration and Production Company,
Shell Offshore, Inc.,
Shell Consolidated Energy Resources, Inc.,
Shell Land and Energy Company,
And
Shell Frontier Oil and Gas, Inc.
TABLE OF CONTENTS
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 7
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 8
3.1 Grant of Processing Rights 8
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 11
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
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 15
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. 16
9.3 Meter Failure. 17
10. INDEMNITY 17
11. CURTAILMENT 17
11.1 Mutual Agreement Not to Curtail or Withhold 17
11.2 Limited Right to Interrupt Performance for Maintenance, etc. 17
12. FORCE MAJEURE 17
12.1 Performance Excused 17
12.2 Force Majeure Defined 18
13. AUDIT RIGHTS 18
14. NOTIFICATIONS 18
14.1 Annual Information 18
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 19
15. CONFIDENTIALITY 19
15.1 General 19
15.2 Annual Information 19
16. DISPUTE RESOLUTION 20
16.1 Arbitration 20
16.2 Initiation of Procedures 20
16.3 Negotiation Between Executives 20
16.4 Binding Arbitration 21
17. TRANSFER AND ASSIGNMENT 21
17.1 Successors and Assigns 21
17.2 Processor's Rights Under Leases 21
17.3 Affiliates of Producer Parties 22
17.4 Excepted Leases 22
18. MISCELLANEOUS 22
18.1 Title and Captions 22
18.2 Pronouns and Plurals 22
18.3 Separability 22
18.4 Successors 22
18.5 Further Actions 23
18.6 Notices 23
18.7 Amendment only in Writing 23
18.8 Right of Ingress and Egress 23
18.9 No Special Damages 23
18.10 Applicable Law 23
18.11 Entire Agreement 23
18.12 Counterparts 24
EXHIBIT A Dedicated Leases as of August 1, 1999
EXHIBIT B Excluded Leases
EXHIBIT C Consideration Bases
EXHIBIT D Upstream Pipelines
EXHIBIT E Letter of Attornment
FIFTH AMENDMENT TO CONVEYANCE
OF GAS PROCESSING RIGHTS
THIS FIFTH AMENDMENT TO CONVEYANCE OF GAS PROCESSING RIGHTS (this "Agreement") dated as of April 1,
2001 ("Effective Date") is made by and between Enterprise Gas Processing, LLC ("Processor"), a Delaware limited
liability company, on the one hand, and Shell Oil Company ("SOC"), Shell Exploration and Production Company
("SEPCO"), Shell Offshore Inc., individually and as successor in interest by merger to Shell Deepwater
Development Inc. and Shell Deepwater Production Inc. ("SOI"), Shell Consolidated Energy Resources Inc. ("SCERI"),
Shell Land and Energy Company ("SLEC"), and Shell Frontier Oil and 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 EandP 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 January 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 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. Effective August 1, 1999, the Third Amendment was amended and, as so amended, restated
in its entirety (the "Fourth Amendment") to clarify the respective rights and obligations of the Processor and
Producers thereunder.
H. Effective September 30, 1999, Tejas Natural Gas Liquids LLC changed its name to
Enterprise Natural Gas Liquids, LLC.
I. Effective October 31, 1999, Enterprise Natural Gas Liquids, LLC merged with and into
Enterprise Products Operating L.P., with Enterprise Products Operating L.P. being the surviving entity of such
merger.
J. Effective March 31, 2001, Enterprise Products Operating L.P. assigned all of its
rights under the Fourth Amendment to its wholly-owned subsidiary, Enterprise Gas Processing, LLC, which
assignment is hereby in all respects approved and consented to by Producers.
K. The parties desire to further amend the Fourth Amendment to incorporate certain
changes in 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(degree)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 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.
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(degree)F and either the equilibrium pressure of the product at 60(degree)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.
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/or other generally accepted natural gas processing methods.
1.27 "Processor" means Enterprise Gas Processing, LLC, a Delaware limited liability
company, 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 D, 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.
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 August 1, 1999,
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, as soon as reasonably practicable,
with notice of the estimated quantity of New Volumes and the estimated date on which such New Volumes will be
available for Processing. 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 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 referenced in
Section 2.4.1, 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.
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. 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 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 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 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 days' 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 referenced in Section 4.5.1. 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 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 Producer's receipt thereof.
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. For each calendar month 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;
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, the term "Consideration Basis" shall
mean, and be defined as, for each calendar month during the term of this Agreement, the respective adjusted index
price listed by Plant on Exhibit C.
6.3 Consideration Timing. Processor shall pay to Producer the applicable cash consideration set
forth in Section 6.1 no later than the last business day of the second month following the month in which the
subject PTR and Processor's Retrograde is delivered to a Plant, such payment to be made by wire transfer of
immediately available funds to an account designated from time to time by Producers at least fifteen days prior
to the date any such payment is due and payable by Processor.
6.4 Consideration Basis Updates. Processor and Producers shall periodically amend Exhibit C,
as appropriate, if (i) another Plant is added by Processor, (ii) the price indexes listed in Exhibit C are no
longer available or (iii) different index prices would, in the reasonable judgment of Processor and Producers,
more accurately represent market conditions. The amount of any new Consideration Basis (as a result of any such
amendment to Exhibit C) shall represent the market value of Gas at the appropriate Plant Redelivery Point.
6.5 Processor Provided PTR. Producers and Processor acknowledge and agree that, in lieu of,
and as an alternative to, any cash payment required under Section 6.1 to be paid by Processor to Producers,
Processor shall have an election to provide, from time to time, PTR at a particular Plant for Processor's own
account in respect of all of Producer's Equity Gas Processed at such Plant. Processor agrees that any such
election to have Processor so provide PTR for its own account begin on the first day of a month and to provide
Producers with at least fifteen days' prior written notice of any such election. If, for any month, Processor
has provided to Producers a notice of any such election, Processor shall not be entitled to rescind, revoke or
change any such notice for such month. Processor agrees to provide any notifications with respect to such
Processor-provided PTR that may be required by an Upstream Pipeline to which Processor delivers such PTR.
7. PTR AND PTR TRANSPORTATION.
Producers 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. Processor shall pay Producers, for transportation of the PTR
and Processor's Retrograde referenced in this Section 7, an amount equal to three cents ($0.03) per MMBTU. 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.
(a) As between Processor and Producers, (i) Producers shall be and remain fully liable
for, and shall be fully responsible for remitting any and all payments to the Department of the
Interior, the Minerals Management Service, the States of Louisiana, Texas, Mississippi, Alabama and
Florida, any other governmental agencies or authorities, and any private lessors who are not federal or
state lessors in respect of, any and all federal, state or local royalties and/or severance taxes due on
any or all hydrocarbon production of Producers or which in any way relate to, or are in connection with,
any of the transactions under this Agreement, including, without limitation, any such federal, state or
local royalties and/or severance taxes on, relating to, or calculated on the basis of, any value of (x)
the PTR used by Processor, (y) the Products extracted from the Equity Gas and (z) Processor's Retrograde
(collectively, "Royalty Charges"), and (ii) Processor shall have no liability for or in respect of any
such Royalty Charges.
(b) Producers hereby agree to hold harmless and indemnify Processor (and its Affiliates)
from and against, and shall fully and promptly reimburse Processor (and its Affiliates) for, 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, relating to, or in connection with,
any Royalty Charges.
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
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 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.
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 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 Sections 16.2 and 16.3, shall with reasonable promptness be submitted to 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 arbitration award rendered pursuant to and in accordance with the
arbitration provisions of Section 16.4 may be entered in any court having jurisdiction over such arbitration
proceeding and over Producers and Processor; and any such party may institute proceedings in any court having
jurisdiction for the specific performance by any party of any such arbitration award. Each of the parties
specifically agrees to be bound by any arbitration 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 and in accordance with any determination of the
arbitrators with respect thereto.
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 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 17.4, 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; provided, however, that nothing in this Section
17.2 or any other provision of this Agreement shall require, or be deemed to require, Processor to pay, or be
responsible for, any Royalty Charges, it being the intent of the parties to this Agreement that Producers shall
pay, and be responsible for, any and all Royalty Charges, as provided in Section 8.1. Producers further agree
(i) to make any transfer of any Dedicated Lease subject to the terms and conditions of this Agreement and (ii)
not to transfer Producer's interest in a Dedicated Lease without first requiring the transferee to execute and
deliver to Producer and Processor a Letter of Attornment in the form attached hereto as Exhibit E.
17.3 Affiliates of Producer Parties. Subject to Section 17.4, 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 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: Enterprise Gas Processing, LLC
------------
c/o Shell Offshore, Inc. 2727 North Loop West - 7th Floor
200 N. Dairy Ashford Houston, TX 77008
Houston, TX 77079 Fax #: (713) 880-6960
Fax #: (281) 544-3544 Attn: Paul Johnson
Attn: Manager
Marketing and 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.
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:
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SHELL OIL COMPANY WITNESSES:
By: /s/ B.K. Garrison _____________________________
Name: B.K. Garrison
Title: Attorney-in-Fact _____________________________
SHELL OFFSHORE INC. WITNESSES:
By: /s/ J.W. Kimmel _____________________________
Name: J.W. Kimmel
Title: Attorney-in-Fact ______________________________
SHELL CONSOLIDATED ENERGY WITNESSES:
RESOURCES INC.
By: /s/ Jeri Eagan ______________________________
Name: Jeri Eagan
Title: Vice President ______________________________
SHELL LAND and ENERGY COMPANY WITNESSES:
By: /s/ Jeri Eagan ______________________________
Name: Jeri Eagan
Title: Executive Vice President and ______________________________
Chief Financial Officer
SHELL FRONTIER OIL and GAS INC. WITNESSES:
By: /s/ Jeri Eagan ______________________________
Name: Jeri Eagan
Title: Executive Vice President and ______________________________
Chief Financial Officer
SHELL EXPLORATION and WITNESSES:
PRODUCTION COMPANY
By: /s/ Jerri Eagan ______________________________
Name: Jeri Eagan
Title: Executive Vice President Finance and ______________________________
Chief Financial Officer
PROCESSOR:
ENTERPRISE GAS PROCESSING, LLC WITNESSES:
By: /s/ W. Ordemann ______________________________
Name: W. Ordemann
Title: Vice President ______________________________