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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON AUGUST 26, 1999
REGISTRATION NO. 333-
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SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
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FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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LEVIATHAN GAS PIPELINE PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
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<S> <C> <C>
DELAWARE 1311 76-0396023
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification Number)
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<TABLE>
<S> <C>
GRANT E. SIMS
BRITTON WHITE, JR. CHIEF EXECUTIVE OFFICER
EL PASO ENERGY BUILDING EL PASO ENERGY BUILDING
1001 LOUISIANA STREET, 30(TH) FLOOR 1001 LOUISIANA STREET, 26(TH) FLOOR
HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002
(713) 420-2131 (713) 420-2131
(Address, including zip code, and telephone number (Name, address, including zip code, and telephone
including area code of registrant's principal number, including area code of agent for service)
executive offices)
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Copies to:
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<S> <C>
J. VINCENT KENDRICK G. MICHAEL O'LEARY
AKIN, GUMP, STRAUSS, HAUER & FELD, L.L.P. ANDREWS & KURTH L.L.P.
1900 PENNZOIL PLACE, SOUTH TOWER 4200 CHASE TOWER
711 LOUISIANA STREET 600 TRAVIS STREET
HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002
(713) 220-5800 (713) 220-4200
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Approximate date of commencement of proposed sale of the securities to the
public: As soon as practicable following the effectiveness of this registration
statement.
If any of the securities being registered on this form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [ ]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ] ____________________
If this form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective statement for the same
offering. [ ] ____________________
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ] ____________________
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
CALCULATION OF REGISTRATION FEE
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TITLE OF EACH CLASS OF PROPOSED MAXIMUM AMOUNT OF
SECURITIES TO BE REGISTERED AGGREGATE OFFERING PRICE(1)(2) REGISTRATION FEE(2)
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<S> <C> <C>
Common units representing limited partner interests $112,125,000 $31,170.75
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(1) Includes common units issuable upon underwriters' over-allotment.
(2) Estimated in accordance with Rule 457 solely for purposes of calculating the
registration fee, based on the average high and low sale prices for the
common units on the New York Stock Exchange on August 25, 1999.
The registrant hereby amends this registration statement on such date or
dates as may be necessary to delay its effective date until the registrant shall
file a further amendment which specifically states that this registration
statement shall thereafter become effective in accordance with Section 8(a) of
the Securities Act of 1933 or until the registration statement shall become
effective on such date as the Commission, acting pursuant to said Section 8(a),
may determine.
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THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY
NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER
TO SELL THESE SECURITIES AND IT IS NOT SOLICITING AN OFFER TO BUY THESE
SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED.
SUBJECT TO COMPLETION, DATED AUGUST 26, 1999
PROSPECTUS
4,000,000 COMMON UNITS
LEVIATHAN GAS PIPELINE PARTNERS, L.P.
REPRESENTING LIMITED PARTNER INTERESTS
$ PER UNIT
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Leviathan Gas Pipeline Partners, L.P. is selling 4,000,000 common units.
The underwriters named in this prospectus may purchase up to 600,000 additional
common units from Leviathan under certain circumstances.
The common units are listed for trading on the New York Stock Exchange
under the symbol "LEV". The last reported sale price of the common units on the
New York Stock Exchange on August 25, 1999, was $23.875 per common unit.
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INVESTING IN THE COMMON UNITS INVOLVES CERTAIN RISKS. LIMITED PARTNER
INTERESTS ARE INHERENTLY DIFFERENT FROM CAPITAL STOCK OF A CORPORATION. SEE
"RISK FACTORS" BEGINNING ON PAGE 14.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
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PER COMMON UNIT TOTAL
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Public Offering Price $ $
Underwriting Discount $ $
Proceeds to Leviathan (before expenses) $ $
</TABLE>
The underwriters are offering the units subject to various conditions. The
underwriters expect to deliver the units to purchasers on or about ,
1999.
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SALOMON SMITH BARNEY
GOLDMAN, SACHS & CO.
PAINEWEBBER INCORPORATED
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN
RAUSCHER INCORPORATED
FIRST UNION CAPITAL MARKETS CORP.
, 1999
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[MAP]
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YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
DIFFERENT INFORMATION. LEVIATHAN IS NOT MAKING AN OFFER OF THESE SECURITIES IN
ANY STATE WHERE THE OFFER IS NOT PERMITTED. YOU SHOULD NOT ASSUME THAT THE
INFORMATION PROVIDED BY THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN
THE DATE ON THE FRONT OF THIS PROSPECTUS.
TABLE OF CONTENTS
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PAGE
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Forward-Looking Statements and Other Information............ iii
Where You Can Find More Information......................... iii
Prospectus Summary.......................................... 1
The Offering and Use of Proceeds.......................... 1
Leviathan................................................. 1
Business Strategy......................................... 3
Recent Operational Developments........................... 3
Structure and Management of Leviathan..................... 6
The Offering.............................................. 7
Tax Considerations........................................ 10
Risk Factors.............................................. 11
Summary Historical and Pro Forma Consolidated Financial
Data................................................... 12
Risk Factors................................................ 14
Risks Inherent in an Investment in Our Common Units....... 14
Risks Related to Our Business............................. 16
Conflicts of Interest..................................... 21
Risks Related to Our Legal Structure...................... 24
Tax Risks................................................. 25
Use of Proceeds............................................. 27
Market Price of and Distribution on Units................... 28
Capitalization.............................................. 29
Selected Historical Consolidated Financial Data............. 30
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 32
Business and Properties..................................... 45
Management.................................................. 71
Certain Relationships and Related Transactions.............. 78
Principal Unitholders....................................... 80
Description of Common Units................................. 81
Certain Other Partnership Agreement Provisions.............. 90
Income Tax Considerations................................... 95
Underwriting................................................ 110
Legal Matters............................................... 111
Experts..................................................... 112
Financial Statements........................................ F-1
</TABLE>
ii
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FORWARD-LOOKING STATEMENTS AND OTHER INFORMATION
This prospectus includes and incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. These statements relate to analyses and other information which are based
on forecasts of future results and estimates of amounts not yet determinable.
These statements also relate to our future prospects, developments and business
strategies.
These forward-looking statements are identified by their use of terms and
phrases such as "anticipate," "believe," "could," "estimate," "expect,"
"intend," "may," "plan," "predict," "project," "will," and similar terms and
phrases, including references to assumptions. These statements are contained in
the sections entitled "Prospectus Summary," "Risk Factors," "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
other sections of this prospectus and in the documents incorporated by reference
in this prospectus.
These forward-looking statements involve risks and uncertainties that may
cause our actual future activities and results of operations to be materially
different from those suggested or described in this prospectus. These risks
include the risks that are identified in this prospectus, which are primarily
listed in the "Risk Factors" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations" sections. These risks may also be
specifically described in our Annual Report on Form 10-K and Quarterly Reports
on Form 10-Q and other documents we have filed with the Securities and Exchange
Commission. We undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future or
otherwise. If one or more of these risks or uncertainties materialize, or if
underlying assumptions prove incorrect, our actual results may vary materially
from those expected, estimated or projected.
You should rely only on the information contained in this prospectus. We
have not authorized anyone to provide you with different information. Leviathan
is not making an offer of these securities in any state where the offer is not
permitted. You should not assume that the information provided by this
prospectus is accurate as of any date other than the date on the front of this
prospectus.
You should not assume that the information in this document or any
supplement is current as of any date other than the date on the front page of
this prospectus. This document is not an offer to sell nor is it seeking an
offer to buy these securities in any state or jurisdiction where the offer or
sale is not permitted.
WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and special reports, proxy statements and other
information with the Securities Exchange Commission under the Securities
Exchange Act of 1934. You can inspect and/or copy these reports and other
information at offices maintained by the SEC, including:
- the principal offices of the SEC located at Judiciary Plaza, 450 Fifth
Street, N.W., Room 1024, Washington, D.C. 20549;
- the Regional Offices of the SEC located at Northwestern Atrium Center,
500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511;
- the Regional Offices of the SEC located at 7 World Trade Center, New
York, New York 10048; and
- the SEC's website at http://www.sec.gov.
Further, our common units are listed on the New York Stock Exchange, and
you can inspect similar information at the offices of the New York Stock
Exchange, located at 20 Broad Street, New York, New York 10005.
iii
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PROSPECTUS SUMMARY
This prospectus summary highlights some basic information from this
prospectus to help you understand the common units. It likely does not contain
all the information that is important to you. You should read the entire
prospectus carefully to understand fully the terms of the common units, as well
as the tax and other considerations that are important to you in making your
investment decision. You should pay special attention to the "Risk Factors"
section beginning on page 14 of this prospectus to determine whether an
investment in the common units is appropriate for you. For purposes of this
prospectus, unless the context otherwise indicates, when we refer to "us," "we,"
"our," "ours," "Leviathan" or the "partnership," we are describing ourselves,
Leviathan Gas Pipeline Partners, L.P., together with our subsidiaries.
THE OFFERING AND USE OF PROCEEDS
We are offering 4,000,000 common units by this prospectus, which will
represent an aggregate 12.9% of the interest in the partnership. After this
offering, our general partner and its affiliates will own an aggregate 30.3%
interest in us, comprised of a 28.3% interest represented by 8,953,764 common
units, a 1.0% interest represented by the sole general partner interest and a
1.0% interest represented by a non-managing membership interest in substantially
all of our subsidiaries.
We plan to use the estimated $91.6 million of net proceeds from this
offering to repay indebtedness under our revolving credit facility. Over the
past 12 months, we have borrowed money under our revolving credit facility to
fund certain of our pipeline and platform investments, including approximately
$165.0 million to increase our ownership interest in several joint ventures and
to fund certain capital expenditures. We may reborrow funds available under the
revolving credit facility in the future to fund our portion of pipeline
construction costs for our new Nemo joint venture; to construct a platform and
other infrastructure facilities at our Ewing Bank 958 Unit oil and natural gas
property; to construct and purchase pipelines, platforms and other hydrocarbon
related facilities; and for general business purposes.
LEVIATHAN
WHO WE ARE
We are a publicly-traded Delaware limited partnership that provides
integrated energy services, including natural gas and oil gathering,
transportation, midstream and other related services in the U.S. Gulf of Mexico.
Either directly or through joint ventures, we own interests in nine operating
pipeline systems. These pipeline systems extend approximately 1,500 miles and
have a design capacity of 6.8 billion cubic feet of natural gas and 400,000
barrels of oil per day. We also own interests in production handling,
dehydration and other energy infrastructure facilities, multi-purpose platforms,
and oil and natural gas properties. Our pipeline and infrastructure network
currently extends from the shoreline, through the Flextrend (water depths of 600
to 1,500 feet) and up to and, in some places, into the Deepwater (water depths
greater than 1,500 feet) in certain areas offshore Louisiana, Texas and
Mississippi.
We believe our assets are well-positioned to maintain a stable base of
operations and will continue to provide growth opportunities. These assets
should allow us to compete for the transportation of new crude oil and natural
gas production in our areas of service, especially those assets in the Flextrend
and Deepwater regions. Either directly or through joint ventures, we own
interests in offshore pipelines and related facilities, including:
- eight offshore natural gas pipeline systems;
- one offshore crude oil gathering system;
- six strategically-located, multi-purpose offshore platforms that serve to
interconnect the pipeline grid;
- production handling and dehydration facilities; and
- four oil and natural gas properties associated with infrastructure
opportunities.
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In addition, we have recently completed the construction of a wholly owned oil
pipeline which we expect to become operational in the fourth quarter of 1999
and, with our joint venture partners, we are constructing two natural gas
gathering systems.
We conduct a large portion of our business through joint ventures and
strategic alliances. We believe these arrangements are particularly well suited
for Deepwater operations. We use joint ventures to reduce our capital
requirements and risk exposure to individual projects, as well as to realize the
benefits from combining resources with our joint venture partners. Our joint
venture partners are generally integrated or very large independent energy
companies with substantial interests, operations and assets in the Gulf of
Mexico. Our current joint venture partners include affiliates of Coastal/ANR,
Equilon, Marathon, Shell and Texaco.
Through our network of subsidiary and joint venture owned pipelines and
other facilities and businesses, we believe we provide customers with an
efficient and cost effective midstream alternative. We offer some customers a
unique single point of contact through which they may access a wide range of
integrated or independent midstream services, including gathering,
transportation, production handling, dehydration and other services. We also
provide producers operating in certain Deepwater and Flextrend areas with
relatively low-cost access to numerous onshore long-haul pipelines and,
accordingly, multiple end-use markets. Additionally, our Deepwater experience
and specialized expertise in this area allows us to provide operational
solutions to producers looking for economic improvements in their development
activities.
OUR GENERAL PARTNER
El Paso Energy Corporation owns our sole general partner, Leviathan Gas
Pipeline Company, whose primary assets are its ownership interests in us. El
Paso Energy's strategy is to use us, when practical, as its primary growth
vehicle for future offshore gathering and transportation activities in the Gulf
of Mexico. El Paso Energy is a publicly-traded diversified energy holding
company. It is engaged, through its subsidiaries, in the interstate and
intrastate transportation, gathering and processing of natural gas; the
marketing of natural gas, power and other commodities; power generation; and the
development and operation of energy infrastructure facilities worldwide. For the
year ended December 31, 1998, El Paso Energy reported operating revenues of
approximately $5.8 billion and net income of approximately $225.0 million. El
Paso Energy expects to complete its $6.0 billion acquisition of Sonat Inc., a
diversified energy holding company, in late 1999. Sonat is engaged, through its
subsidiaries and joint ventures, in domestic oil and natural gas exploration and
production, the transmission and storage of natural gas, and natural gas and
power marketing.
PROSPECTS FOR CONTINUED LONG-TERM GROWTH IN THE GULF OF MEXICO
We plan to focus our Gulf of Mexico operations on the more substantial
properties being developed in the frontier regions of the Flextrend and
Deepwater. Our pipeline and infrastructure network currently extends from the
shoreline, through the Flextrend and up to and, in some areas, into the
Deepwater. The location of some of our facilities in relation to properties
currently being developed, as well as to the onshore long-haul pipelines which
producers need in order to access the most attractive markets, should provide us
with an economic advantage over some of our competitors. We believe more
extensive Deepwater operations will permit us to enhance our financial stability
and growth for many reasons, including the substantial reserves associated with
Deepwater fields and the large capital commitments and longer-term view required
by producers developing these regions. Accordingly, we believe that Deepwater
projects are less sensitive to short term changes in natural gas and crude oil
prices.
We believe that development and exploration activity in the Gulf of Mexico
will continue and that it will continue to be one of the most prolific producing
regions in the U.S. The Gulf of Mexico currently represents approximately 20.3%
of total domestic production of oil and 25.6% of total domestic production of
natural gas. Oil production from the Gulf of Mexico is expected to increase from
1.3 million barrels per day in 1998 to 1.8 million barrels per day in 2003,
according to industry sources. Production of natural gas is also expected to
increase from 14.0 billion cubic feet per day in 1998 to 16.6 billion cubic feet
per day
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in 2003. The principal source of this growth is expected to be related to
production in the Flextrend and Deepwater regions. Recent developments in oil
and natural gas exploration and production techniques, such as 3-D seismic
analysis, horizontal drilling, remote subsea completions via satellite templates
and sea floor wellheads, and non-stationary surface production facilities, have
substantially reduced finding, development and production costs, allowing
operators to move into deeper hydrocarbon producing regions. By year-end 2003,
production from deeper water fields is projected to account for 54.6% and 24.0%
of the Gulf of Mexico's oil and natural gas production up from 35.6% and 13.4%
in 1998.
We have pipelines, platforms and other infrastructure facilities
strategically positioned throughout a large portion of the Flextrend area of the
Gulf of Mexico, predominantly offshore Louisiana and Mississippi, extending out
to and, in some cases, into the Deepwater. Because of their proximity to oil and
natural gas development in the Gulf of Mexico, we expect these assets to play an
important role in the development of oil and natural gas in surrounding areas of
the Flextrend and Deepwater. We expect the development of new major discoveries,
the extension of infrastructure and facilities and advances in exploration
technology to result in additional development of the Flextrend and accelerate
development of the Deepwater. A number of major discoveries in the Deepwater
regions of the Gulf of Mexico have been announced by Shell, Exxon, BP Amoco,
Unocal and other energy companies in recent years.
BUSINESS STRATEGY
Our business objective is to maintain and enhance our position as a
provider of integrated energy services, to continue to enhance the quality of
our cash flow, earnings and other financial results of operations and to provide
additional growth opportunities by pursuing the following strategies:
- focus on high potential Deepwater operations, leveraging our existing
assets and Deepwater expertise;
- provide independent, multiple market access for the Deepwater and
Flextrend regions of the Gulf of Mexico;
- offer a single source alternative for a complete range of midstream
services;
- diversify our portfolio with respect to geography, projects, customers
and services;
- share capital costs and risks through joint ventures and strategic
alliances, principally with partners with substantial financial resources
and strategic interests in the Gulf of Mexico;
- design new infrastructure projects based on long-term commitments of
dedicated production and/or fixed payments, with the ability to expand
capacity and service in the future to capture potential growth
opportunities; and
- selectively invest in oil and natural gas properties associated with
infrastructure opportunities.
RECENT OPERATIONAL DEVELOPMENTS
WE FORMED A NEW NATURAL GAS DEEPWATER PIPELINE JOINT VENTURE WITH AN
AFFILIATE OF SHELL. On August 10, 1999, we formed Nemo Gathering Company, LLC, a
joint venture owned 66.1% by Tejas Offshore Pipeline, LLC, a subsidiary of Shell
Oil Company, and 33.9% by us, to construct, own and operate a natural gas
gathering system. The Nemo System will deliver natural gas production from the
Shell-operated Brutus and Glider Deepwater development properties to another of
our joint venture pipelines, the Manta Ray Offshore Gathering System. We expect
the Nemo System to be placed in service in late 2001 at a total cost of
approximately $36.0 million.
WE INCREASED OUR OWNERSHIP INTEREST IN THREE OF OUR EXISTING PIPELINE JOINT
VENTURES--UTOS, HIOS AND EAST BREAKS, WHICH IS A NEW DEEPWATER EXPANSION. On
June 30, 1999, we increased our ownership interest in three complementary,
interconnecting natural gas pipeline systems located offshore Louisiana and the
eastern portion of Texas. Through our acquisition of several companies from
Natural Gas Pipeline
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Company of America for approximately $51.0 million, we increased our ownership
interest in the U-T Offshore System to 66.7% from 33.3%, the High Island
Offshore System to 60.0% from 40.0%, and the East Breaks System to 60.0% from
40.0%. UTOS is a 30-mile pipeline extending from onshore Louisiana to a point of
interconnection with HIOS, and receives substantially all of its throughput from
HIOS for redelivery to an onshore production handling facility. HIOS is an
expansive 204-mile pipeline system extending through the Flextrend and up to the
Deepwater in our service areas. The East Breaks System is an 85-mile expansion
currently under construction that will connect HIOS to the Diana and Hoover
fields being developed by subsidiaries of Exxon and BP Amoco. Both Exxon and BP
Amoco recently committed to the East Breaks System production from their Diana
and Hoover properties. These two Deepwater properties are located in over 4,800
feet of water. With a throughput capacity of 400.0 million cubic feet per day of
natural gas and the ability to expand its throughput capacity further, the East
Breaks System and, therefore, the HIOS and UTOS systems have the ability to
compete to gather and transport the substantial reserves associated with
properties being, and expected to be, developed in these Deepwater frontier
regions. We estimate that construction of the East Breaks System should be
completed late in 2000 at a total cost of approximately $90.0 million.
WE ARE CONSTRUCTING A DEEPWATER PLATFORM IN CONNECTION WITH THE DEVELOPMENT
OF OUR EWING BANK 958 UNIT. We believe our Ewing Bank 958 Unit development
project, formerly known as the Sunday Silence Property, provides us with an
opportunity to apply to the Deepwater area several strategies we have
successfully implemented in the shallow and Flextrend areas. Similar to three
other oil and natural gas properties we have developed, this project is
associated with other independent infrastructure opportunities. Although the
Ewing Bank 958 Unit development is a stand-alone project, we expect it to
position us to play a significant role in the extension of pipeline, platform
and other infrastructure facilities and service opportunities in this potential
emerging Deepwater region. Currently, we anticipate building gathering
extensions off of our Poseidon oil pipeline joint venture and our Manta Ray
Offshore Gathering natural gas pipeline joint venture.
Pursuant to our current plan of development for the Ewing Bank 958 Unit, we
are constructing a Moses Tension Leg Platform from which we would conduct all
activities related to that development, including additional drilling,
maintenance, and separation and handling operations. This platform is designed
for use in water depths of up to 6,000 feet and will have production handling
facilities with a throughput design capacity of 55.0 million cubic feet of
natural gas per day and 25,000 barrels of oil per day.
To date there has been no production from the Ewing Bank 958 Unit. We
currently own a 100% working interest in our Ewing Bank 958 Unit, which we
purchased in October 1998 from a wholly owned, indirect subsidiary of El Paso
Energy for $12.2 million. In addition to the initial discovery well drilled in
1994 and the two delineation wells drilled in 1994 and 1998, the Ewing Bank 958
Unit development program may require drilling up to five additional wells,
depending on the level of actual production and other factors. As with many of
our strategic assets, we continually evaluate various alternatives for the Ewing
Bank 958 Unit and the related infrastructure to optimize the amount and quality
of our cash flow. Given the size and nature of this project and the various
strategic arrangements that might be available with a producer or another
industry participant, we believe the Ewing Bank 958 Unit is well suited for a
co-ownership, joint venture or other participatory arrangement. If we do not
consummate such an arrangement, we may need to raise substantial amounts of
additional capital to fund this development project.
WE HAVE CONSTRUCTED OUR ALLEGHENY OIL PIPELINE TO DELIVER CRUDE OIL FROM
THE FLEXTREND AND DEEPWATER REGIONS TO OUR POSEIDON JOINT VENTURE. We recently
completed construction of the Allegheny oil pipeline, a 100% owned, 40-mile long
crude oil pipeline that will connect British Borneo's Allegheny Field in the
Green Canyon area of the Gulf of Mexico with our Poseidon oil pipeline joint
venture. British Borneo has committed to the Allegheny System production from
its Allegheny Field. The Allegheny System, which will have a daily capacity of
more than 80,000 barrels of oil per day, is scheduled to begin operating in the
fourth quarter of 1999.
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WE INCREASED OUR OWNERSHIP INTEREST IN OUR VIOSCA KNOLL JOINT VENTURE, A
NATURAL GAS PIPELINE LOCATED PRIMARILY IN THE FLEXTREND WATERS. On June 1, 1999,
we acquired an additional 49.0% interest in Viosca Knoll Gathering Company from
a subsidiary of El Paso Energy, which resulted in us owning 99.0% of Viosca
Knoll with an option to purchase the remaining 1.0%. We formed the Viosca Knoll
joint venture in 1994 with a subsidiary of Tenneco Inc. to construct and operate
a 125-mile long pipeline system, with an initial throughput capacity of 400.0
million cubic feet of natural gas per day, in an emerging producing region with
limited infrastructure. The system design involved the construction of our first
multi-purpose hub-platform and included the ability to expand throughput
capacity at relatively nominal costs. Due to customer needs, including some
recent Deepwater commitments, we have completed two expansion projects. These
expansions more than doubled the Viosca Knoll System's capacity to 1.0 billion
cubic feet per day. The Viosca Knoll System provides its customers access to
interstate pipelines of, among others, El Paso Energy, Columbia Gulf
Transmission Company, Sonat, Transco and Destin Pipeline Company.
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STRUCTURE AND MANAGEMENT OF LEVIATHAN
Leviathan Gas Pipeline Company, our sole general partner and an indirect,
wholly owned subsidiary of El Paso Energy, manages our activities and conducts
our business. We and the general partner utilize the employees of, and
management services provided by, El Paso Energy and its affiliates under a
management agreement. Our principal executive office is located at the El Paso
Energy Building, 1001 Louisiana Street, 26th Floor, Houston, Texas, 77002. Our
telephone number is (713) 420-2131. The following chart depicts the ownership
structure of Leviathan and certain of its affiliates after giving effect to the
transactions described in this prospectus.
[CHART]
<TABLE>
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OWNERSHIP OWNERSHIP OWNERSHIP
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<S> <C> <C> <C> <C> <C>
S Green Canyon 100.0% S Viosca Knoll Block 817 100.0% S Viosca Knoll Block 817 100.0%
S Tarpon 100.0% S East Cameron Block 373 100.0% S Ewing Bank 958 Unit 100.0%
S Viosca Knoll 99.0%(3) S Ship Shoal Block 332 100.0% S Garden Banks Block 72 50.0%
S UTOS 66.7% S South Timbalier Block 292 100.0% S Garden Banks Block 117 50.0%
S HIOS 60.0% S Ship Shoal Block 331 100.0% S West Delta Block 35 38.8%
S East Breaks 60.0% S Garden Banks Block 72 50.0%
S Stingray 50.0% S West Cameron Dehy 50.0%
S Nemo 33.9%
S Manta Ray Offshore 25.7%
S Nautilus 25.7%
S Allegheny 100.0%
S Poseidon 36.0%
</TABLE>
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(1) Represents ownership interest after giving effect to the offering, assuming
the underwriters do not exercise their over-allotment option. Prior to the
consummation of this offering, El Paso Energy has a 34.5% effective interest
in us.
(2) Leviathan Gas Pipeline Company, a wholly owned subsidiary of El Paso Energy,
is our general partner. El Paso Energy's 30.3% effective interest in us,
which is held by our general partner and its affiliates, includes a 1.0%
general partner interest, a 28.3% limited partner interest comprised of
8,953,764 common units, and a 1.0% non-managing member interest in
substantially all of our subsidiaries.
(3) The remaining 1.0% interest in Viosca Knoll is held by El Paso Energy. We
have an option to acquire this remaining 1.0% from El Paso Energy,
exercisable after June 1, 2000.
6
<PAGE> 12
THE OFFERING
Common units offered....... 4,000,000 common units
4,600,000 common units if the underwriters exercise
in full their over-allotment option.
<TABLE>
<CAPTION>
Number of Percent of
Units to be outstanding Units Total
after the offering.................. ---------- ----------
<S> <C> <C> <C>
Common units......................... 30,737,465 99.1%
Preference units..................... 291,299 0.9%
---------- -----
31,028,764 100.0%
========== =====
</TABLE>
If the underwriters exercise in full their
over-allotment option, we will issue an additional
600,000 common units, which will result in
31,337,465 common units outstanding representing a
99.1% interest and 291,299 preference units
outstanding representing a 0.9% interest.
To satisfy its obligation under our partnership
agreement to maintain a 1.0% general partner
interest, our general partner will contribute
approximately $925,000 in cash to us upon the
consummation of this offering, approximately
$1,065,000 in cash if the underwriters exercise in
full their over-allotment option.
Use of proceeds............ We plan to use the proceeds from this offering to
repay indebtedness under our revolving credit
facility. Over the past 12 months, we have borrowed
money under our revolving credit facility to fund
certain of our pipeline and platform investments,
including approximately $165.0 million to increase
our ownership interest in several joint ventures
and to fund certain capital expenditures. We may
reborrow funds available under the revolving credit
facility in the future to fund our portion of
pipeline construction costs for our new Nemo joint
venture; to construct a platform and other
infrastructure facilities at our Ewing Bank 958
Unit oil and natural gas property; to construct and
purchase pipelines, platforms and other hydrocarbon
related facilities; and for general business
purposes.
New York Stock Exchange
symbol................... LEV
Distributions of available
cash..................... Our partnership agreement requires us to
distribute, within 45 days after the end of each
calendar quarter, all of our "available cash, "as
such term is defined in our partnership agreement.
Generally, "available cash" means, for the
applicable quarter, all cash receipts for such
quarter and any reductions in reserves established
in prior quarters less all cash disbursements made
in such quarter and additions to reserves, as
determined by our general partner.
Except to the extent our general partner has earned
the right to receive any incentive distributions,
we will distribute 98.0% of our available cash
constituting cash from operations to our limited
partners in respect of their common units and
preference units and 2.0% of such available cash to
our general partner in respect of its 1.0% general
partner interest and its 1.0% non-managing member
interest.
7
<PAGE> 13
Senior, subordinated,
non-cumulative
distribution rights...... The common unit distribution rights with respect to
available cash constituting cash from operations
(1) are subordinate to the right of preference
units to receive the minimum quarterly distribution
amount of $0.275 per preference unit, $1.10
annually per preference unit, including arrearages,
and (2) until the common units receive an amount,
excluding arrearages, equal to the minimum
quarterly distribution amount, are senior to the
right of any other unit to receive a share of
distributions of available cash constituting cash
from operations.
After the holders of our preference units have
received distributions of available cash
constituting cash from operations during any
relevant quarter equal to the minimum quarterly
distribution amount plus any arrearages, but before
any other units may participate in distributions of
such available cash during such quarter, the
holders of our common units are entitled to receive
during such quarter distributions of such available
cash, if any, in an amount up to the minimum
quarterly distribution amount. However, our common
units do not have cumulative distribution
participation rights, and arrearages do not accrue
on the common units for any shortfall in the
minimum quarterly distribution amount.
Fully participating
distribution rights........ The holders of our common units are entitled to
fully participate in quarterly distributions of
available cash constituting cash from operations,
subject to the right of our general partner to
receive its regular distribution of 2.0% and any
incentive distributions described below, the right
of holders of our preference units to receive
minimum quarterly distributions and any arrearages,
and the right of holders of any securities we issue
after this offering to receive any priority
distributions attributable to such securities. The
holders of our preference units do not have the
right to participate in distributions of available
cash constituting cash from operations in excess of
the minimum quarterly distribution amount plus
arrearages, if any.
General partner incentive
distributions............ The following table illustrates the percentage
allocation of distributions of available cash among
the unitholders and our general partner up to the
various target distribution levels.
<TABLE>
<CAPTION>
PERCENT OF MARGINAL
AVAILABLE CASH
QUARTERLY DISTRIBUTED TO
DISTRIBUTION ---------------------
AMOUNT PER COMMON GENERAL
UNIT UP TO UNITHOLDERS PARTNER
------------ ----------- -------
<S> <C> <C> <C>
Minimum Quarterly Distribution $0.275 98% 2%
First Target Distribution 0.325 98% 2%
Second Target Distribution 0.375 85% 15%
Third Target Distribution 0.425 75% 25%
Thereafter -- 50% 50%
</TABLE>
Adjustments to minimum
quarterly and target
distribution amounts..... The minimum quarterly distributions and the
specified target levels relating to incentive
distributions may be adjusted under certain
circumstances in accordance with our partnership
agreement.
8
<PAGE> 14
Interim capital
transactions
distributions and
liquidating
distributions............ Because of their unique nature, our partnership
agreement specially allocates among our partners
distributions of available cash constituting cash
from "interim capital transactions" and
distributions made in connection with our
termination and the liquidation of our assets and
businesses. For a detailed explanation, see the
section in this prospectus entitled "Description of
Common Units" beginning on page 81.
Subsequent issuances....... We have the ability to issue an unlimited number of
additional securities from time to time, which may
have rights equal or superior to the rights of our
outstanding units.
Lack of dissenter's rights
or preemptive rights..... Holders of common units do not have dissenters'
rights of appraisal in the event of a merger or
consolidation of the partnership or a sale of
substantially all of its assets or preemptive
rights.
Limited call right......... If, at any time, non-affiliates of our general
partner own 15.0% or less of the issued and
outstanding units of any class (including common
units), then our general partner may call, or
assign to us or its affiliates our right to call,
such remaining publicly-held units at a
market-based price.
Voting Rights.............. Our general partner manages and operates our
business. Unlike the holders of common stock in a
corporation, you will have only very limited voting
rights on matters affecting our business. You will
have no right to elect our general partner on an
annual or other continuing basis.
Restrictions on transfers
of units................. Purchases, sales and other transfers of our units
will be effective only if they comply with the
requirements of our partnership agreement,
including the requirements that the transferee be
an eligible U.S. person, make certain
representations and warranties and become a party
to our partnership agreement.
Information contained in "The Offering" section of this prospectus is a
summary and should be read in conjunction with the rest of this prospectus,
including the sections entitled "Description of Common Units" beginning on page
81 and "Certain Other Partnership Agreement Provisions" beginning on page 90.
9
<PAGE> 15
TAX CONSIDERATIONS
The tax consequences to you of an investment in units will depend in part
on your own tax circumstances. For a discussion of the principal federal income
tax considerations associated with our operations and the purchase, ownership
and disposition of units, see "Income Tax Considerations" beginning on page 95.
You should consult your own tax advisor about the federal, state, local and
foreign tax consequences peculiar to your circumstances.
We estimate that if you purchase a unit in this offering and hold the unit
through the record date for the distribution with respect to the final calendar
quarter of 2001 (assuming quarterly distributions on the units with respect to
that period are equal to the current quarterly distribution rate of $0.525 per
unit), you will be allocated an amount of federal taxable income for that period
that is less than or equal to approximately 30% of the amount of cash
distributed to you with respect to that period.
This estimate is based upon many assumptions regarding our business and
operations, including assumptions as to tariffs, capital expenditures, cash
flows and anticipated cash distributions. This estimate and the assumptions are
subject to, among other things, numerous business, economic, regulatory and
competitive uncertainties beyond our control and to certain tax reporting
positions that we have adopted. The Internal Revenue Service could disagree with
our tax reporting positions, including estimates of the relative fair market
values of our assets and the validity of curative allocations. Accordingly, we
cannot assure you that the estimate will be correct. The actual percentage of
distributions that will constitute taxable income could be higher or lower, and
any differences could be material.
10
<PAGE> 16
RISK FACTORS
You should carefully consider the discussion of risks beginning on page 14
and the other information included in this prospectus prior to investing in our
common units. Some of the risks discussed include:
- You will have limited voting rights and will not control our general
partner.
- We may issue additional units, diluting your interests.
- Our ability to distribute cash to you depends on factors out of our
control, including the rates for, and volume of, production that we
handle, and on successful exploration and development of additional oil
and natural gas reserves.
- Our substantial indebtedness could adversely affect our financial
condition, prevent us from making distributions to you and restrict our
ability to operate.
- Our actual project costs could exceed our forecast, and our cash flow
from projects may not be immediate.
- The interruption of distributions to us from our subsidiaries and joint
ventures may affect our ability to make cash distributions to you.
- Federal Energy Regulatory Commission regulation and a changing regulatory
environment could affect our cash flow and, accordingly, distributions.
- The Year 2000 date change may result in decreased revenues for us.
- El Paso Energy and its affiliates may have conflicts of interest with us
and, accordingly, you.
- Our partnership agreement purports to limit our general partner's
fiduciary duties and certain other obligations relating to us.
- We cannot cause our joint ventures to take or not to take certain actions
unless some or all of our joint venture partners agree.
- If we proceed with the development of our Ewing Bank 958 Unit without a
partner who will share a significant portion of the costs, we will
require more capital than is currently available from our existing
sources.
- We do not have the same flexibility as other types of organizations to
accumulate cash and equity to protect against illiquidity in the future.
- A change of control of our general partner may adversely affect you.
- We have not received a ruling or assurances from the IRS on any matters
affecting us.
- Our tax treatment depends on our partnership status.
- We can only deduct certain losses.
- Your tax liability resulting from an investment in our units could exceed
any cash you receive as a distribution from us or the proceeds from
dispositions of those units.
11
<PAGE> 17
SUMMARY HISTORICAL AND PRO FORMA
CONSOLIDATED FINANCIAL DATA
The historical financial data for each of the three years ended December
31, 1996, 1997 and 1998, and as of December 31, 1997 and 1998 was derived from
our consolidated financial statements and notes thereto included elsewhere in
this prospectus. The historical financial data as of December 31, 1996 has been
derived from our historical consolidated financial statements (not included
herein). The historical financial data for each of the six months ended June 30,
1998 and 1999 and as of June 30, 1999 was derived from our unaudited
consolidated financial statements and notes thereto included elsewhere in this
prospectus. The historical financial data as of June 30, 1998 has been derived
from our unaudited historical consolidated financial statements (not included
herein). We believe that all material adjustments, consisting only of normal
recurring adjustments necessary for the fair presentation of our interim
results, have been included. Results of operations for any interim period are
not necessarily indicative of the results of operations for the entire year due
to the seasonal nature of our business. The unaudited pro forma consolidated
financial data reflects (1) the issuance of 4,000,000 common units pursuant to
this offering, (2) the consummation of the UTOS/HIOS/East Breaks acquisition,
(3) the issuance of our subordinated notes, (4) the consummation of the Viosca
Knoll transaction, (5) the repayment and cancellation of Viosca Knoll's credit
facility, (6) the reduction of our revolving credit facility, and (7) the
payment and amortization of transaction costs. The unaudited pro forma
consolidated financial data is based on the assumptions described in the notes
to the unaudited pro forma consolidated financial statements located on pages
F-3 through F-10 and is not necessarily indicative of the results of operations
that may be achieved in the future. You should read this information along with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" beginning on page 32, "Business and Properties" beginning on page 45
and the consolidated financial statements and notes thereto listed on pages F-1
and F-2.
<TABLE>
<CAPTION>
PRO FORMA SIX MONTHS PRO FORMA
YEAR ENDED DECEMBER 31, YEAR ENDED ENDED JUNE 30, SIX MONTHS
------------------------------ DECEMBER 31, ------------------- ENDED
1996 1997 1998 1998 1998 1999 JUNE 30, 1999
-------- -------- -------- ------------ -------- -------- ----------------
(UNAUDITED) (UNAUDITED) (UNAUDITED)
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS:
Oil and natural gas
sales................. $ 47,068 $ 58,106 $ 31,411 $ 31,939 $ 15,734 $ 15,100 $ 15,141
Gathering,
transportation and
platform services..... 24,005 17,329 17,320 47,415 7,782 10,798 23,740
Equity in earnings...... 20,434 29,327 26,724 21,048 12,571 19,953 17,404
-------- -------- -------- -------- -------- -------- --------
Total revenue..... 91,507 104,762 75,455 100,402 36,087 45,851 56,285
-------- -------- -------- -------- -------- -------- --------
Operating expenses...... 9,068 11,352 11,369 14,595 5,546 5,025 6,061
Depreciation, depletion
and amortization...... 31,731 46,289 29,267 34,797 14,845 13,727 16,315
Impairment, abandonment
and other............. -- 21,222 (1,131) (1,131) -- -- --
General and
administrative
expenses and
management fee........ 8,540 14,661 16,189 16,343 7,503 5,909 5,972
-------- -------- -------- -------- -------- -------- --------
Total operating
costs.......... 49,339 93,524 55,694 64,604 27,894 24,661 28,348
-------- -------- -------- -------- -------- -------- --------
Operating income........ 42,168 11,238 19,761 35,798 8,193 21,190 27,937
Interest income and
other................. 1,710 1,475 771 1,821 157 268 799
Interest and other
financing costs....... (5,560) (14,169) (20,242) (29,212) (8,429) (13,868) (17,336)
Minority interest in
(income) loss......... (427) 7 (15) (321) (3) (80) (216)
-------- -------- -------- -------- -------- -------- --------
Income (loss) before
income taxes.......... 37,891 (1,449) 275 8,086 (82) 7,510 11,184
</TABLE>
12
<PAGE> 18
<TABLE>
<CAPTION>
PRO FORMA SIX MONTHS PRO FORMA
YEAR ENDED DECEMBER 31, YEAR ENDED ENDED JUNE 30, SIX MONTHS
------------------------------ DECEMBER 31, ------------------- ENDED
1996 1997 1998 1998 1998 1999 JUNE 30, 1999
-------- -------- -------- ------------ -------- -------- ----------------
(UNAUDITED) (UNAUDITED) (UNAUDITED)
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
Income tax benefit...... 801 311 471 471 168 177 177
-------- -------- -------- -------- -------- -------- --------
Net income
(loss)......... $ 38,692 $ (1,138) $ 746 $ 8,557 $ 86 $ 7,687 $ 11,361
======== ======== ======== ======== ======== ======== ========
Basic and diluted net
income (loss) per
unit.................. $ 1.57 $ (0.06) $ 0.02 $ 0.22 $ 0.00 $ 0.25 $ 0.30
======== ======== ======== ======== ======== ======== ========
CASH DISTRIBUTIONS
DECLARED PER UNIT:
Preference unit......... $ 1.45 $ 1.85 $ 1.60 $ 1.60 $ 1.05 $ 0.55 $ 0.55
======== ======== ======== ======== ======== ======== ========
Common unit............. $ 1.45 $ 1.85 $ 2.10 $ 2.10 $ 1.05 $ 1.05 $ 1.05
======== ======== ======== ======== ======== ======== ========
BALANCE SHEET DATA (AT
END OF PERIOD):
Total assets............ $453,526 $409,842 $442,726 (1) $406,087 $625,913 $625,913
Total debt.............. 227,000 238,000 338,000 (1) 270,000 481,500 388,975
Partners' capital....... 192,023 143,966 82,896 (1) 113,557 120,036 212,561
OTHER FINANCIAL DATA:
EBITDA(2)............... $ 73,899 $ 78,749 $ 47,897 $ 69,464 $ 23,038 $ 34,917 $ 44,252
Adjusted EBITDA(3)...... 90,288 76,557 52,344 74,790 23,765 39,072 47,039
Net cash provided by
operating
activities............ 50,179 67,485 25,677 (1) 12,884 23,640 (1)
Net cash used in
investing
activities............ 101,721 41,769 65,624 (1) 19,366 92,818 (1)
Net cash provided by
(used in) financing
activities............ 52,525 (35,775) 36,625 (1) 1,194 69,371 (1)
Capital expenditures
included in investing
activities............ 101,721 41,957 66,111 (1) 19,366 92,818 (1)
</TABLE>
- ------------------
(1) This information is not included in this table as it is not required.
(2) EBITDA is defined for this purpose as operating income before depreciation,
depletion and amortization and impairment, abandonment and other. EBITDA is
used as a supplemental financial measurement in the evaluation of our
business and should not be considered as an alternative to net income, as an
indicator of our operating performance or as an alternative to cash flows
from operating activities as a measure of liquidity. EBITDA may not be a
comparable measurement among different companies. EBITDA is presented here
to provide additional information about us.
(3) Adjusted EBITDA is defined for this purpose as EBITDA plus cash
distributions from equity investments less earnings attributable to equity
investments. We believe Adjusted EBITDA is a meaningful disclosure because
of the significance of our equity investments. Adjusted EBITDA is used as a
supplemental financial measurement in the evaluation of our business and
should not be considered as an alternative to net income, as an indicator of
our operating performance or as an alternative to cash flows from operating
activities as a measure of liquidity. Adjusted EBITDA may not be a
comparable measurement among different companies. Adjusted EBITDA is
presented here to provide additional information about us.
13
<PAGE> 19
RISK FACTORS
LIMITED PARTNER INTERESTS ARE INHERENTLY DIFFERENT FROM CAPITAL STOCK OF A
CORPORATION, ALTHOUGH MANY OF THE BUSINESS RISKS TO WHICH WE ARE SUBJECT ARE
SIMILAR TO THOSE THAT WOULD BE FACED BY A CORPORATION ENGAGED IN THE SAME
BUSINESS. YOU SHOULD CAREFULLY CONSIDER THE FOLLOWING FACTORS BEFORE INVESTING
IN COMMON UNITS.
This prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934 including, in particular, the statements about our plans,
strategies and prospects under the headings "Prospectus Summary," "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Business." Although we believe that our plans, intentions and expectations
reflected in or suggested by such forward-looking statements are reasonable, we
cannot assure you that we will achieve such plans, intentions or expectations.
Important factors that could cause actual results to differ materially from the
forward-looking statements we make in this prospectus are set forth below and
elsewhere in this prospectus. All forward-looking statements attributable to us
or persons acting on our behalf are expressly qualified in their entirety by the
following cautionary statements.
RISKS INHERENT IN AN INVESTMENT IN OUR COMMON UNITS
YOU WILL HAVE LIMITED VOTING RIGHTS AND WILL NOT CONTROL OUR GENERAL
PARTNER.
Unlike the holder of capital stock in a corporation, you only have limited
voting rights on matters affecting our business. Our general partner, whose
directors you do not elect, manages our activities. You will have no right to
elect the general partner on an annual or any other continuing basis. If the
general partner voluntarily withdraws, however, the holders of a majority of the
outstanding units (excluding for purposes of such determination units owned by
the withdrawing general partner and its affiliates) may elect its successor.
The general partner may not be removed as our general partner except upon
approval by the affirmative vote of the holders of at least 55% of the
outstanding units (including units owned by the general partner and its
affiliates), subject to the satisfaction of certain conditions. Any removal of
the general partner is not effective until the holders of a majority of the
outstanding units approve a successor general partner. Before the holders of
outstanding units may remove the general partner, they must receive an opinion
of counsel that:
- such action will not result in the loss of limited liability of any
limited partner or of any member of any of our subsidiaries or cause us
or any of our subsidiaries to be taxable as a corporation or to be
treated as an association taxable as a corporation for federal income tax
purposes; and
- all required consents by any regulatory authorities have been obtained.
The general partner has agreed not to withdraw voluntarily as our general
partner on or before December 31, 2002 (with limited exceptions), unless the
holders of at least a majority of the outstanding units (excluding units owned
by the general partner and its affiliates) approve the withdrawal. The
withdrawal or removal of the general partner as general partner of the
partnership would effectively result in its concurrent withdrawal or removal as
the manager of our subsidiaries.
WE MAY ISSUE ADDITIONAL UNITS, DILUTING YOUR INTERESTS.
We can issue additional limited partner interests and other equity
securities, including equity securities with rights to distributions and
allocations or in liquidation equal or superior to the common units, for any
amount and on any terms and conditions established by the general partner. If we
issue more units or other equity securities, it will reduce your proportionate
ownership interest in us. This could cause the market price of your units to
fall and reduce the cash distributions paid to you as a common unitholder.
Further, we have the ability to issue partnership interests with voting rights
superior to yours. If we issued any such securities, it could adversely affect
your already limited voting power.
14
<PAGE> 20
YOU MAY NOT HAVE LIMITED LIABILITY IN THE CIRCUMSTANCES DESCRIBED BELOW AND
MAY BE LIABLE FOR THE RETURN OF WRONGFUL DISTRIBUTIONS.
You will not be liable for assessments in addition to your initial capital
investment in the common units. However, you may be required to repay to us
amounts wrongfully returned or distributed to you under some circumstances.
Under Delaware law, a limited partnership may not make a distribution to a
partner to the extent that at the time of the distribution, after giving effect
to the distribution, all liabilities of the partnership (other than liabilities
to partners on account of their partnership interests and nonrecourse
liabilities) exceed the fair value of the assets of the limited partnership.
Delaware law provides that a limited partner who receives such a distribution
and knew at the time of the distribution that the distribution violated the law
will be liable to the limited partnership for the amount of the distribution for
three years from the date of the distribution. Under Delaware law, an assignee
who becomes a substitute limited partner of a limited partnership is liable for
the obligations of his assignor to make contributions to the partnership, except
the assignee is not obligated for liabilities that were unknown to him at the
time he became a limited partner and that could not be ascertained from the
partnership agreement.
Our limited partners have the right to take certain limited actions,
including the removal of the general partner, under our partnership agreement.
If it were determined under Delaware law such actions constituted "control" of
our business, then you could be held personally liable for our obligations to
the same extent as the general partner.
COMMON UNITS ARE SUBJECT TO RESTRICTIONS ON TRANSFER.
All purchasers of common units who wish to become unitholders of record
must deliver an executed transfer application in which the purchaser or
transferee must certify that, among other things, he, she or it is eligible to
purchase the units before the purchaser or transferee of the units will be
registered on our records and before cash distributions can be made and federal
income tax information furnished to the purchaser or transferee. A person
purchasing units who does not execute a transfer application and certify that
the purchaser is eligible to purchase the units acquires no rights in the units
other than the right to resell the units. Further, our general partner may
request each record holder of a unit to furnish certain information about the
holder's nationality, citizenship or other related status. If the record holder
fails to furnish the information or if the general partner determines, on the
basis of the information furnished by the holder in response to the request,
that the cancellation or forfeiture of any property in which we have an interest
may occur, the general partner may be substituted as a unitholder for the record
holder, who will then be treated as a non-citizen assignee, and we will have the
right to redeem the units held by the record holder. As a result of these
restrictions, your ability to transfer your units may be adversely affected. See
"Description of Common Units--Transfer of Units."
OUR GENERAL PARTNER HAS A LIMITED CALL RIGHT THAT MAY REQUIRE YOU TO SELL
YOUR COMMON UNITS AT AN UNDESIRABLE TIME OR PRICE.
If at any time our general partner and its affiliates hold 85% or more of
the issued and outstanding common units, the general partner will have the right
to purchase all, but not less than all, of the outstanding common units held by
nonaffiliates. This purchase would take place as of a record date which would be
selected by the general partner, on at least 30 but not more than 60 days'
notice. The general partner may assign and transfer this call right to any of
its affiliates or to us. If the general partner (or its assignee) exercises this
call right, it must purchase the common units at the higher of (1) the highest
cash price paid by the general partner or its affiliates for any common unit
purchased within the 90 days preceding the date the general partner mails notice
of the election to call the common units or (2) the average of the last reported
sales price per common unit over the 20 trading days preceding the date five
days before the general partner mails such notice. Accordingly, under certain
circumstances you may be required to sell your common units against your will
and the price you receive for those common units may be less than you would like
to receive. Upon consummation of this offering, our general partner and its
affiliates will hold an effective 30.3% interest in us.
15
<PAGE> 21
RISKS RELATED TO OUR BUSINESS
OUR ABILITY TO DISTRIBUTE CASH TO YOU DEPENDS ON FACTORS OUT OF OUR
CONTROL, INCLUDING THE RATES FOR, AND VOLUME OF, PRODUCTION THAT WE HANDLE.
We do not guarantee that we will make cash distributions to you. Our
ability to make cash distributions, as well as our ability to make payments on
our indebtedness and to fund future working capital, capital expenditures and
other general corporate requirements will depend on our ability to generate cash
in the future. This, to a certain extent, is subject to economic, financial,
competitive, legislative, regulatory and other factors that are beyond our
control.
Our future performance and, therefore, our ability to make cash
distributions, will largely depend on the volume of, and rates for, the natural
gas and oil handled by our pipelines, platforms and other infrastructure. Many
factors outside of our control can affect these volumes and rates. The following
factors, among others, affect the rates that our pipelines may charge:
- commodity prices for the production handled;
- competition from other pipelines; and
- the maximum rates established by the FERC for our regulated pipelines.
Any decrease in the rates charged or volumes handled by any of our pipelines and
other facilities could reduce our available cash. Accordingly, we cannot assure
you that we will be able to continue to generate enough cash flow to satisfy our
existing commitments and make cash distributions to you.
Based on our current and anticipated level of operations and revenue
growth, we believe our cash flow from operations, available cash and available
borrowings under our revolving credit facility will be adequate to conduct our
businesses as they currently exist and make cash distributions at our current
rate for the foreseeable future. We cannot assure you, however, that these or
other sources of capital will be available to us in amounts sufficient to enable
us to pay our indebtedness or to fund our other liquidity needs, including the
purchase, construction or other acquisition of assets or businesses in the
future, let alone make cash distributions to you.
IF WE PROCEED WITH THE DEVELOPMENT OF OUR EWING BANK 958 UNIT WITHOUT A
PARTNER WHO WILL SHARE A SIGNIFICANT PORTION OF THE COSTS, WE WILL REQUIRE MORE
CAPITAL THAN IS CURRENTLY AVAILABLE FROM OUR EXISTING SOURCES.
The development plan we filed with the U.S. Department of Interior Minerals
Management Service ("MMS") estimates that it will cost approximately $100.0
million in drilling costs, including amounts to drill, complete and tie-back the
producing wells, and $150.0 million in infrastructure costs, including amounts
to design, construct and install the producing platform and export pipelines.
These estimates are inherently uncertain, and the drilling costs in particular
could exceed materially our forecast because of the uncertainties and
difficulties associated with Deepwater drilling operations.
We currently do not have, and may not be able to obtain, the capital
required to undertake 100% of the development of our Ewing Bank 958 Unit and the
related infrastructure. While we expect to have a partner in this project
pursuant to an exchange, sale, farmout, joint venture or similar arrangement, we
cannot assure you that we will be successful in structuring such an arrangement.
If no such arrangement exists, we will have to raise additional capital through
another source or we will not be able to proceed with this development as
currently planned. We cannot assure you that any such source of capital would be
available to complete this project or that this project will be completed as
contemplated, if at all.
OUR FUTURE PERFORMANCE, AND THUS OUR ABILITY TO MAKE CASH DISTRIBUTIONS,
DEPENDS ON SUCCESSFUL EXPLORATION AND DEVELOPMENT OF ADDITIONAL OIL AND NATURAL
GAS RESERVES.
The natural gas and oil reserves available to our pipelines and other
infrastructure from existing wells naturally decline over time. In order to
offset this natural decline, our pipelines and other infrastructure
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must access additional reserves. This means that our long-term prospects depend
upon the successful exploration and development of additional reserves by third
parties in areas accessible to our pipelines and other infrastructure.
Finding and developing new natural gas and oil reserves from offshore
properties is very expensive. The Flextrend and Deepwater areas, especially,
will require large capital expenditures by third party producers for
exploration, development drilling, installation of production facilities and
pipeline extensions to reach the new wells.
Many economic and business factors out of our control can adversely affect
the decision by any third party producer to explore for and develop new
reserves. These factors include relatively low natural gas and oil prices, cost
and availability of equipment, capital budget limitations or the lack of
available capital. For example, because of the decline in hydrocarbon prices
during 1998 and the first quarter of 1999, the level of overall oil and natural
gas activity in the Gulf of Mexico has declined from recent years. If
hydrocarbon prices decline again or capital spending by the energy industry
continues to decrease or remains at low levels for prolonged periods, our
results of operations and cash flow could suffer. Consequently, we cannot assure
you that additional reserves will be discovered or developed in the near future,
or that they exist at all.
PRICE AND VOLUME VOLATILITY IS SUBSTANTIALLY OUT OF OUR CONTROL AND IT
COULD HAVE AN ADVERSE AFFECT ON OUR PRODUCTION BUSINESS.
Our business and, to a certain extent, our ability to make cash
distributions will be substantially affected by our future production from our
oil and natural gas properties. The level of success of our future production
from such properties is largely dependent on factors out of our control, such as
the volume of, and prices realized for, the natural gas and oil produced from
our oil and natural gas properties. In 1998, oil and natural gas prices
dramatically declined, and although prices have increased in 1999, we cannot
assure you that there will not be further declines in commodity prices. Based on
1998 production levels of our currently producing properties which are depleting
assets, for every $0.10 decline in the average price for natural gas and every
$1.00 decline in the average price for oil we actually realized, our cash flow
from operations would be reduced by $1.1 million and $0.5 million, respectively.
OUR SUBSTANTIAL INDEBTEDNESS COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION
AND PREVENT US FROM MAKING DISTRIBUTIONS TO YOU.
We have a significant amount of indebtedness and the ability to incur more
indebtedness. In May 1999, we issued $175.0 million of 10 3/8% senior
subordinated notes due in 2009, which are supported by guarantees of our
subsidiaries. We are also party to a $375.0 million revolving credit facility,
which is collateralized by a pledge of the equity of our subsidiaries and
supported by guarantees of our subsidiaries. As of August 9, 1999, we had $300.0
million outstanding under this revolving credit facility and would have been
permitted to borrow up to an additional $44.5 million. Our substantial
indebtedness could have important consequences to you. For example, it could:
- increase our vulnerability to general adverse economic and industry
conditions;
- limit our ability to make distributions to you, or to fund future working
capital, capital expenditures and other general partnership requirements,
future acquisition, construction or development activities, or to
otherwise fully realize the value of our assets and opportunities because
of the need to dedicate a substantial portion of our cash flow from
operations to payments on our indebtedness or to comply with any
restrictive terms of our indebtedness;
- limit our flexibility in planning for, or reacting to, changes in our
businesses and the industries in which we operate; and
- place us at a competitive disadvantage as compared to our competitors
that have less debt.
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OUR INDEBTEDNESS MAY RESTRICT OUR ABILITY TO OPERATE.
We must comply with various affirmative and negative covenants contained in
the indenture related to our senior subordinated notes and our revolving credit
facility, which is secured by substantially all of our assets. Among other
things, these covenants limit our ability to:
- incur additional indebtedness or liens;
- make payments in respect of or redeem or acquire any debt or equity
issued by us;
- sell assets;
- make loans or investments;
- acquire or be acquired by other companies; and
- amend certain contractual arrangements.
The restrictions under our indebtedness may prevent us from engaging in certain
transactions which might otherwise be considered beneficial to us. Our
indebtedness also requires us to make mandatory repayments under certain
circumstances, including when we sell certain assets, fail to achieve or
maintain certain financial targets or experience a change in control. In
addition, we cannot prepay the balance outstanding under our senior subordinated
notes without incurring substantial penalties.
If we incur additional indebtedness in the future, it would be under our
existing credit agreement or under arrangements which, we believe, would have
terms and conditions at least as restrictive as those contained in our existing
credit agreement. Failure to comply with the terms and conditions of any
existing or future indebtedness would constitute an event of default. If an
event of default occurs, the lenders will have the right to accelerate the
maturity of such indebtedness and foreclose upon the collateral, if any,
securing that indebtedness. Such an event could limit our ability to make cash
distributions to you, and could affect the market price of the common units.
WE WILL FACE COMPETITION FROM THIRD PARTIES TO HANDLE ANY NEW PRODUCTION.
Even if additional reserves exist in the areas accessed by our pipelines
and are ultimately produced, we cannot assure you that any of these reserves
will be gathered, transported, processed or otherwise handled by any of our
pipelines and other infrastructure. We would compete with others, including
producers of oil and natural gas, for any such production on the basis of many
factors, including:
- geographic proximity to the production;
- costs of connection;
- available capacity;
- rates; and
- access to onshore markets.
POTENTIAL FUTURE EXPANSIONS MAY ADVERSELY AFFECT OUR BUSINESS BY
SUBSTANTIALLY INCREASING THE LEVEL OF OUR INDEBTEDNESS AND CONTINGENT
LIABILITIES AND INCREASING OUR RISKS OF BEING UNABLE TO EFFECTIVELY INTEGRATE
THESE NEW OPERATIONS.
We intend to continue to construct and purchase assets, including entire
businesses, that we believe will present opportunities to realize synergies,
expand our role in the energy infrastructure business and/or increase our market
position. This strategy may require substantial capital, and we may not be able
to raise the necessary funds on satisfactory terms or at all.
We regularly engage in discussions with respect to potential acquisition
and investment opportunities. If we consummate any future acquisitions, our
capitalization and results of operations may change
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significantly and you will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider in determining
the application of these funds.
We are currently considering some specific future acquisitions or
investments, although we cannot assure you that we will be able to reach
agreement with respect to any of these opportunities. If consummated, any
acquisition would likely result in the incurrence of indebtedness and contingent
liabilities and an increase in interest expense and amortization expenses
related to goodwill and other intangible assets, which could have a material
adverse effect upon our business.
Acquisitions and business expansions involve numerous risks, including
difficulties in the assimilation of the operations, technologies, services and
products of the acquired companies or business segments and the diversion of
management's attention from other business concerns. For all of these reasons,
if any acquisitions or expansions occur, our business could be adversely
affected.
OUR ACTUAL PROJECT COSTS COULD EXCEED OUR FORECAST, AND OUR CASH FLOW FROM
PROJECTS MAY NOT BE IMMEDIATE.
Our forecast contemplates significant expenditures for the acquisition,
construction and expansion of our pipelines and related infrastructure.
Underwater operations, especially those in water depths in excess of 600 feet,
are very expensive and involve much more uncertainty and risk than other
operations. Further, if a problem occurs, the solution, if one exists, may be
very expensive and time consuming. Accordingly, there is an increase in the
frequency and amount of cost overruns related to underwater operations,
especially in depths in excess of 600 feet. We cannot assure you that we will be
able to complete our projects at the costs currently estimated. If we experience
material cost overruns, we would have to finance these overruns using one or
more of the following methods:
- borrowing from our revolving credit facility;
- using cash from operations;
- delaying other planned projects;
- issuing additional debt or equity.
Any or all of these methods may not be available when needed or could adversely
affect our future results of operations.
Our revenues may not increase immediately upon the expenditure of funds on
a particular project. For instance, if we build a new pipeline, the construction
will occur over an extended period of time and we may not receive any material
increase in revenue from that project until after the reserves committed to it
are developed and produced. If our revenues do not increase at projected levels
because of substantial unanticipated delays of any future projects, we might not
meet our obligations as they become due.
FERC REGULATION AND A CHANGING REGULATORY ENVIRONMENT COULD AFFECT OUR CASH
FLOW.
The FERC extensively regulates certain of our pipelines. This regulation
extends to such matters as:
- rate structures;
- rates of return on equity;
- the services that our regulated pipelines are permitted to perform;
- their ability to seek recovery of various categories of costs;
- the acquisition, construction and disposition of assets; and
- to an extent, the level of competition in the interstate pipeline
industry.
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Given the extent of this regulation, the extensive changes in FERC policy
over the last several years, the evolving nature of regulation and the
possibility for additional changes, we cannot assure you that the current
regulatory regime will remain unchanged or of the effect any changes in that
regime would have on our financial position, results of operations or cash
flows.
All but one of our regulated pipelines is over 20 years old. As a result,
each such pipeline has depreciated significant portions of its initial capital
expenditures. Unless those pipelines make additional capital expenditures, they
could be fully depreciated within a couple of years. This would reduce the rate
base and increase the likelihood that FERC would reduce the approved rates for
each of those pipelines.
A NATURAL DISASTER, CATASTROPHE OR OTHER INTERRUPTION EVENT COULD DAMAGE
OUR PIPELINES AND OTHER INCOME-PRODUCING ASSETS, CURTAIL THEIR OPERATIONS AND,
POSSIBLY, ADVERSELY AFFECT OUR CASH FLOW.
If one or more of our pipelines or other income-producing assets is damaged
by severe weather or any other natural disaster, accident, catastrophe or other
event, our operations could be significantly interrupted. Similar interruptions
could result from damage to production facilities or other production stoppages
arising from factors beyond our control. These interruptions might range from a
week or less for a minor incident to six months or a year or more for a major
interruption. Any event that interrupts the fees generated by our pipelines or
other income-producing assets, or which causes us to make significant
expenditures not covered by insurance, could adversely impact the market price
of, and the amount of cash available for distribution to, the common units.
Further, although we carry business interruption insurance that we consider to
be appropriate, we cannot assure you that it would cover all types of
interruptions that might occur, and in the future we may not be able to obtain
other desirable insurance on commercially reasonable terms.
ENVIRONMENTAL COSTS AND LIABILITIES AND CHANGING ENVIRONMENTAL REGULATION
COULD AFFECT OUR CASH FLOW.
Our operations are subject to extensive federal, state and local regulatory
requirements relating to environmental affairs, health and safety, waste
management and chemical products. Governmental authorities have the power to
enforce compliance with applicable regulations and permits and to subject
violators to civil and criminal penalties, including civil fines, injunctions or
both. Third parties may also have the right to pursue legal actions to enforce
compliance. We will probably make expenditures in connection with environmental
matters as part of normal capital expenditure programs. However, future
environmental law developments, such as stricter laws, regulations or
enforcement policies, could significantly increase our cost of handling,
manufacture, use, emission or disposal of substances or wastes. Moreover, as
with other companies engaged in similar or related businesses, our operations
always have some risk of environmental costs and liabilities because we handle
petroleum products. We cannot assure you that we will not incur material
environmental costs and liabilities.
THE YEAR 2000 DATE CHANGE MAY RESULT IN DECREASED REVENUES FOR US.
We have established a project team that works with the El Paso Energy Year
2000 executive steering committee to coordinate the phases of our Year 2000
project. We have substantially completed the awareness, assessment, remediation,
testing, implementation and contingency planning phases of our Year 2000
program. However, the responses that we have received from third parties,
including partners, third party customers and vendors and operators of joint
ventures in which we have an interest, regarding their Year 2000 efforts,
although generally encouraging, are inconclusive. Further, certain of our
systems and processes may be interrelated with systems outside of our control.
Unsuccessful Year 2000 efforts, either on our part or on the part of third
parties, may adversely affect our financial position, results of operations
and/or cash flows. A significant portion of the oil and natural gas handled by
our pipelines is owned by third parties. Accordingly, failure by the owners of
oil and natural gas to be ready for the Year 2000 could significantly disrupt
the flow of the hydrocarbons to customers. However, in many cases, the owners
have no direct contractual relationship with us, and we are relying on our
customers to verify the Year 2000 readiness of the producers from whom they
purchase oil
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and natural gas. A portion of our revenue is based upon fees paid by our
customers for the reservation of capacity and a portion of the revenue is based
upon the volume of actual throughput. As such, short-term disruptions in
throughput caused by factors beyond our control may have a financial impact on
us and could cause operational problems for our customers. Longer-term
disruptions could materially impact our operational and financial condition, and
therefore affect the market price of, and our ability to make distributions to,
the common units.
CONFLICTS OF INTEREST
EL PASO ENERGY AND ITS AFFILIATES MAY HAVE CONFLICTS OF INTEREST WITH US
AND, ACCORDINGLY, YOU.
El Paso Energy is a New York Stock Exchange-traded company whose principal
operations include the interstate and intrastate transportation, gathering and
processing of natural gas; the marketing of natural gas, power, and other
energy-related commodities; power generation and the development and operation
of energy infrastructure facilities worldwide. Through its subsidiaries and
before giving effect to this offering, El Paso Energy has an effective 34.5%
ownership interest in us that it acquired for consideration totalling
approximately $482.0 million. El Paso Energy paid approximately $422.0 million
in 1998 to acquire an effective 27.3% interest in us, including all of our
general partner interests. Then, in June 1999, El Paso Energy acquired $59.8
million in our common units in connection with the Viosca Knoll transaction.
Following this offering, El Paso Energy will have an effective 30.3% interest in
us. With respect to future investments, El Paso Energy's strategy is for us,
when practical, to serve as its primary offshore gathering and transportation
growth vehicle in the Gulf of Mexico, although El Paso Energy is not precluded
from retaining gathering and transportation opportunities for itself.
El Paso Energy (through a wholly owned subsidiary) elects all of the
general partner's directors, who in turn select all of our executive officers
and those of the general partner. In addition, El Paso Energy's beneficial
ownership of 30.3% of our outstanding units could have a substantial effect on
the outcome of some actions requiring unitholder approval.
Although El Paso Energy controls our general partner and has financial
incentives to protect its investment by encouraging our success, and it plans to
use us when practical as its principal offshore gathering and transportation
growth vehicle in the Gulf of Mexico, El Paso Energy is not contractually bound
to do so and may reconsider at any time, without notice. Additionally, El Paso
Energy is not required to pursue a business strategy that will favor our
business opportunities over the business opportunities of El Paso Energy or any
of its affiliates (or any other competitor of ours acquired by El Paso Energy).
In fact, El Paso Energy may have financial motives to favor our competitors. El
Paso Energy and its subsidiaries (many of which are wholly owned) operate in
some of the same lines of business and in some of the same geographic areas in
which we operate. Although we acquired the remaining interest in Viosca Knoll
from El Paso Energy excluding a 1.0% interest in profits and capital, El Paso
Energy continues to own pipelines and related facilities located in the Gulf of
Mexico, including the Bluewater and Seahawk Shoreline systems. In addition,
shareholders of El Paso Energy and Sonat Inc. recently approved a planned merger
that is expected to close in late 1999. Sonat also owns pipelines and related
assets in the Gulf of Mexico, as well as numerous oil and natural gas
properties, including properties in the Gulf of Mexico. To the extent we
continue to acquire interests in oil and natural gas properties and if the
merger between El Paso Energy and Sonat is completed, our activities may compete
with the exploration, development and marketing activities of Sonat conducted by
El Paso Energy.
In addition, we have, and we expect to enter into other, significant
business relationships with El Paso Energy, our general partner and their
affiliates. For instance, in June 1999, we purchased substantially all of El
Paso Energy's interest in the Viosca Knoll gathering system, and in October
1998, we purchased the Ewing Bank 958 Unit from El Paso Energy. See "Certain
Relationships and Related Transactions" beginning on page 78 and
"Business--Recent Developments, Acquisitions and New Projects" beginning on page
48 for a further discussion of the Viosca Knoll and Ewing Bank 958 Unit
transactions.
We and our general partner and its affiliates share and, therefore, will
compete for, the time and effort of general partner personnel who provide
services to us. Officers of the general partner and its affiliates do
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not, and will not be required to, spend any specified percentage or amount of
time on our business. Since these shared officers function as both our
representatives and those of our general partner and its affiliates, conflicts
of interest could arise between our general partner and its affiliates, on the
one hand, and us or you, on the other.
In most instances in which an actual or potential conflict of interest
arises between us, on the one hand, and our general partner or its affiliates,
on the other hand, there will be a benefit to our general partner or its
affiliates in which neither we nor you will share. Such conflicts may arise in
situations which include (1) compensation paid to the general partner, which
includes incentive distributions and reimbursements for reasonable general and
administrative expenses; (2) payments to the general partner and its affiliates
for any services rendered to us or on our behalf; (3) our general partner's
determination of which direct and indirect costs we must reimburse; (4)
decisions to enter into and the terms of transactions between us and our general
partner or any of its affiliates, including transactions involving joint
ventures, acquisitions and gathering and transportation; (5) the acquisition or
operation of businesses by our general partner or its affiliates that would
compete with us; and (6) our general partner's determination to establish cash
reserves under certain circumstances and thereby decrease cash available for
distributions to you.
OUR GENERAL PARTNER RECEIVES MANY FORMS OF COMPENSATION.
Our general partner receives the following compensation:
- distributions in respect of its general and limited partner interests in
the partnership;
- distributions in respect of its 1.01% interest in each of our
subsidiaries organized as a limited liability company;
- the incentive distributions described in the section entitled
"Description of Common Units" beginning on page 81; and
- reimbursements for reasonable general and administrative expenses, and
other reasonable expenses, incurred by the general partner and its
affiliates for or on our behalf.
Our partnership agreement was not, and many of the other agreements, contracts
and arrangements between us, on the one hand, and the general partner and its
affiliates, on the other hand, were not and may not be the result of
arm's-length negotiations. In addition, we expect to enter into other
significant business relationships with the general partner and its affiliates.
OUR GENERAL PARTNER HAS BROAD DISCRETION WITH RESPECT TO OUR MANAGEMENT.
Our general partner, in its capacity as general partner, will make all
decisions relating to us. Our general partner's directors and officers have
fiduciary duties to manage the general partner, including its investments in its
subsidiaries and affiliates, in a manner beneficial to the stockholders of the
general partner. In general, the general partner has a fiduciary duty to manage
the partnership in a manner beneficial to us and to you. However, the
partnership agreement contains provisions that allow the general partner broad
discretion in managing our operations and to take into account the interests of
parties in addition to us and you in resolving conflicts of interest. By
purchasing a common unit, you are deemed to have executed the partnership
agreement. Under the partnership agreement, you agree that certain actions by
the general partner and its officers and directors, including specifically those
identified in this prospectus, are deemed not to breach any duty owed by them to
us or to you. Accordingly, if those provisions of the partnership agreement are
enforced, the general partner and its officers and directors may not be liable
to us or to you for certain actions or omissions that might otherwise be deemed
to be a breach of fiduciary duty under Delaware or other applicable state law.
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CASH RESERVES, EXPENDITURES AND OTHER MATTERS WITHIN THE DISCRETION OF THE
GENERAL PARTNER MAY AFFECT DISTRIBUTIONS.
Our general partner has broad discretion to establish and make additions to
cash reserves for any proper partnership purpose, including reserves for the
purpose of:
- providing for future capital expenditures;
- stabilizing distributions of cash to unitholders; and
- complying with the terms of any agreement or obligation of ours.
The timing and amount of additions to discretionary reserves could
significantly reduce potential distributions that you could receive.
OUR PARTNERSHIP AGREEMENT PURPORTS TO LIMIT OUR GENERAL PARTNER'S FIDUCIARY
DUTIES AND CERTAIN OTHER OBLIGATIONS RELATING TO US.
Although our general partner owes certain fiduciary duties to us and will
be liable for all our debts, other than non-recourse debts, to the extent not
paid by us, certain provisions of our partnership agreement contain exculpatory
language purporting to limit the liability of the general partner to us and you.
For example, the partnership agreement provides that:
- borrowings of money by us, or the approval thereof by the general
partner, will not constitute a breach of any duty of the general partner
to us or you whether or not the purpose or effect of the borrowing is to
permit distributions on common units or to result in or increase
incentive distributions to the general partner;
- any action taken by the general partner consistent with the standards of
reasonable discretion set forth in certain definitions in our partnership
agreement will be deemed not to breach any duty of the general partner to
us or to you; and
- in the absence of bad faith by the general partner, the resolution of
conflicts of interest by the general partner will not constitute a breach
of the partnership agreement or a breach of any standard of care or duty.
Provisions of the partnership agreement also purport to modify the
fiduciary duty standards to which the general partner would otherwise be subject
under Delaware law, under which a general partner owes its limited partners the
highest duties of good faith, fairness and loyalty. The duty of loyalty would
generally prohibit the general partner from taking any action or engaging in any
transaction as to which it had a conflict of interest. The partnership agreement
permits the general partner to exercise the discretion and authority granted to
it in that agreement in managing us and in conducting its retained operations,
so long as its actions are not inconsistent with our interests. The general
partner and its officers and directors may not be liable to us or to you for
certain actions or omissions which might otherwise be deemed to be a breach of
fiduciary duty under Delaware or other applicable state law. Further, the
partnership agreement requires us to indemnify the general partner to the
fullest extent permitted by law, which indemnification, in light of the
exculpatory provisions in the partnership agreement, could result in us
indemnifying the general partner for negligent acts. Neither El Paso Energy nor
any of its other affiliates, other than our general partner, owes fiduciary
duties to us.
OUR GENERAL PARTNER AND ITS AFFILIATES MAY SELL UNITS IN THE TRADING
MARKET, WHICH COULD REDUCE THE MARKET PRICE OF YOUR COMMON UNITS.
Our general partner and its affiliates currently own 8,953,764 common
units. If they were to sell a substantial number of these units in the trading
markets, it could reduce the market price of your common units. Our partnership
agreement, and other agreements to which we are party, allow our general partner
and certain of its affiliates to cause us to register for sale the common units
held by such persons. These
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registration rights allow our general partner and its affiliates to request
registration of those common units and to include any of those common units in a
registration of other units by us.
RISKS RELATED TO OUR LEGAL STRUCTURE
THE INTERRUPTION OF DISTRIBUTIONS TO US FROM OUR SUBSIDIARIES AND JOINT
VENTURES MAY AFFECT OUR ABILITY TO MAKE CASH DISTRIBUTIONS TO YOU.
Leviathan is a holding company. As such, our primary assets are the capital
stock and other equity interests in our subsidiaries and joint ventures.
Consequently, our ability to make cash distributions depends upon the earnings
and cash flow of our subsidiaries and joint ventures and the distribution of
that cash to us. Distributions from our joint ventures are subject to the
discretion of their respective management committees. In addition, several of
our joint ventures have credit arrangements that contain various restrictive
covenants. Among other things, those covenants limit or restrict such joint
ventures' ability to make distributions to us under certain circumstances.
Further, the joint venture charter documents typically vest in their management
committees sole discretion regarding distributions. We cannot assure you that
our joint ventures will continue to make distributions to us at current levels
or at all.
Moreover, pursuant to some of the joint venture credit arrangements, we
have agreed to return a limited amount of the distributions made to us by the
applicable joint venture if certain conditions exist. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Sources of Cash" beginning on page
37.
WE CANNOT CAUSE OUR JOINT VENTURES TO TAKE OR NOT TO TAKE CERTAIN ACTIONS
UNLESS SOME OR ALL OF OUR JOINT VENTURE PARTNERS AGREE.
Due to the nature of joint ventures, each partner (including Leviathan) in
each of our joint ventures has made substantial contributions and other
commitments to that joint venture and, accordingly, has required that the
relevant charter documents contain certain features designed to provide each
partner with the opportunity to protect its investment in that joint venture, as
well as any other assets which may be substantially dependent on or otherwise
affected by the activities of that joint venture. These protective features
include a corporate governance structure which requires at least a majority in
interest vote to authorize many basic activities and requires a greater voting
interest (sometimes up to 100%) to authorize more significant activities.
Depending on the particular joint venture, these more significant activities
might involve large expenditures or contractual commitments, the construction or
acquisition of assets, borrowing money, transactions with affiliates of a joint
venture partner, litigation and/or transactions not in the ordinary course of
business, among others. Thus, without the concurrence of joint venture partners
with enough voting interests, we cannot cause any of our joint ventures to take
or not to take certain actions, even though such actions may be in the best
interest of the particular joint venture or Leviathan.
WE DO NOT HAVE THE SAME FLEXIBILITY AS OTHER TYPES OF ORGANIZATIONS TO
ACCUMULATE CASH AND EQUITY TO PROTECT AGAINST ILLIQUIDITY IN THE FUTURE.
Unlike a corporation, our partnership agreement requires us to make
quarterly distributions to our unitholders of all available cash reduced by any
amounts reserved for commitments and contingencies, including capital and
operating costs and debt service requirements. The value of our common units
will decrease in direct correlation with decreases in the amount we distribute
per unit. Accordingly, if we experience a liquidity problem in the future, we
may not be able to issue more equity to recapitalize.
CHANGES OF CONTROL OF OUR GENERAL PARTNER MAY ADVERSELY AFFECT YOU.
Our results of operations and, thus, our ability to make cash distributions
could be adversely affected if there is a change in management resulting from a
change of control of our general partner. Although such an action would result
in a change of control under the terms of the indenture governing our
publicly-held debt, El Paso Energy is not restricted from selling the general
partner or any of the common
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units it holds. As a result, El Paso Energy could sell control of our general
partner to another company with less familiarity and experience with our
businesses and with different business philosophies and objectives. We cannot
assure you that any such acquiror would continue our current business strategy,
or even a business strategy economically compatible with our current business
strategy.
TAX RISKS
For general discussion of the expected federal income tax consequences of
owning and disposing of common units, see "Income Tax Considerations" beginning
on page 95.
WE HAVE NOT RECEIVED A RULING OR ASSURANCES FROM THE IRS ON ANY MATTERS
AFFECTING US.
We have not requested, and will not request, any ruling from the Internal
Revenue Service with respect to our classification, or the classification of any
of our subsidiaries which are organized as limited liability companies or
partnerships, as a partnership for federal income tax purposes or any other
matter affecting us or our subsidiaries. Accordingly, the IRS may propose
positions that differ from the conclusions expressed by our counsel in this
prospectus. It may be necessary to resort to administrative or court proceedings
in an effort to sustain some or all of those conclusions, and some or all of
those conclusions ultimately may not be sustained. The common unitholders and
the general partner will bear, directly or indirectly, the costs of any contest
with the IRS.
OUR TAX TREATMENT DEPENDS ON OUR PARTNERSHIP STATUS.
Based upon the continued accuracy of the representations of the general
partner set forth in "Income Tax Considerations--Partnership Status" on page 96,
our counsel believes that under current law and regulations we and our
subsidiaries which are limited liability companies or partnerships have been and
will be classified as partnerships for federal income tax purposes. However, as
stated above, we have not requested, and will not request, any ruling from the
IRS as to this status, and our counsel's opinion is not binding on the IRS. In
addition, you cannot be sure that those representations will continue to be
accurate. If the IRS were to challenge our federal income tax status or the
status of one of our subsidiaries, such a challenge could result in (1) an audit
of your entire tax return, and (2) adjustments to items on that return that are
unrelated to the ownership of common units. In addition, you would bear the cost
of any expenses incurred in connection with an examination of your personal tax
return. Except as specifically noted, this discussion assumes that we and our
subsidiaries which are organized as limited liability companies or partnerships
have been and are treated as partnerships for federal income tax purposes.
If we or any of our subsidiaries which are organized as limited liability
companies were taxable as a corporation for federal income tax purposes in any
taxable year, its income, gain, losses and deductions would be reflected on its
tax return rather than being passed through (proportionately) to you, and its
net income would be taxed at corporate rates. In addition, some or all of the
distributions made to you would be treated as dividend income and would be
reduced as a result of the federal, state and local taxes paid by us or our
subsidiaries.
WE MAINTAIN UNIFORMITY OF COMMON UNITS THROUGH NONCONFORMING DEPRECIATION
CONVENTIONS.
Since we cannot match transferors and transferees of common units, we must
maintain uniformity of the economic and tax characteristics of the common units
to their purchasers. To maintain uniformity and for other reasons, we have
adopted certain depreciation conventions which do not conform with all aspects
of certain proposed and final Treasury Regulations. The IRS may challenge those
conventions and, if such a challenge were sustained, the uniformity or the value
of common units may be affected. For example, non-uniformity could adversely
affect the amount of tax depreciation available to you and could have a negative
impact on the value of your common units.
25
<PAGE> 31
WE CAN ONLY DEDUCT CERTAIN LOSSES.
Any losses that we generate will be available to offset future income
(except certain portfolio net income) that we generate and cannot be used to
offset income from any other source, including other passive activities or
investments.
YOUR PARTNERSHIP TAX INFORMATION MAY BE AUDITED.
We will furnish you a substitute Schedule K-1 that sets forth your
allocable share of income, gains, losses and deductions. In preparing this
schedule, we will use various accounting and reporting conventions and various
depreciation and amortization methods we have adopted. You cannot be sure that
this schedule will yield a result that conforms to statutory or regulatory
requirements or to administrative pronouncements of the IRS. Further, our tax
return may be audited, and any such audit could result in an audit of your
individual tax return as well as increased liabilities for taxes because of
adjustments resulting from the audit.
YOUR TAX LIABILITY RESULTING FROM AN INVESTMENT IN OUR UNITS COULD EXCEED
ANY CASH YOU RECEIVE AS A DISTRIBUTION FROM US OR THE PROCEEDS FROM DISPOSITIONS
OF THOSE UNITS.
You will be required to pay federal income tax and, in certain cases, state
and local income taxes on your allocable share of our income, whether or not you
receive any cash distributions from us. You cannot be sure that you will receive
cash distributions equal to your allocable share of taxable income from us. In
fact, you may incur tax liability in excess of the amount of cash distribution
we make to you or the cash you receive on the sale of your units.
TAX-EXEMPT ORGANIZATIONS AND CERTAIN OTHER INVESTORS SHOULD CAREFULLY
CONSIDER OWNERSHIP OF COMMON UNITS.
Investment in common units by tax-exempt organizations and regulated
investment companies raises issues unique to such persons.
WE ARE REGISTERED AS A TAX SHELTER. ANY IRS AUDIT WHICH ADJUSTS OUR RETURNS
WOULD ALSO ADJUST YOURS.
We have been registered with the IRS as a "tax shelter." The tax shelter
registration number is 93084000079. As a result, you cannot be sure that we will
not be audited by the IRS or that tax adjustments will not be made. If you own
less than a 1% profit interest in us, your right to participate in the income
tax audit process is limited. Further, any adjustments in our tax returns will
lead to adjustments in your returns and may lead to audits of your returns and
adjustments of items unrelated to us. You would bear the cost of any expenses
incurred in connection with an examination of your personal tax return.
26
<PAGE> 32
USE OF PROCEEDS
We expect to realize approximately $91.6 million in net proceeds from the
sale of common units offered by this prospectus. We plan to use the net
proceeds, including any related to the exercise of the underwriters'
over-allotment option, to repay indebtedness under our revolving credit
facility. We may reborrow funds available under the revolving credit facility in
the future to fund our portion of pipeline construction costs for our new Nemo
joint venture; to construct a platform and other infrastructure facilities at
our Ewing Bank 958 Unit oil and natural gas property; to construct and purchase
pipelines, platforms and other hydrocarbon related facilities; and for general
business purposes.
As of August 9, 1999, we had $300.0 million outstanding under our revolving
credit facility bearing interest at an average floating rate of 7.7% per annum
with a final maturity of May 2002. Over the past 12 months, we used borrowings
under our revolving credit facility to, among other things, (1) finance the
UTOS/HIOS/East Breaks acquisition (approximately $51.0 million), (2) finance a
portion of the acquisition and development of our non-producing oil and gas
property, the Ewing Bank 958 Unit ($30.0 million), (3) finance the construction
and installation of a new platform and production handling facilities at East
Cameron Block 373 ($9.4 million), (4) pay amounts related to the abandonment of
the Ewing Bank flowlines ($2.9 million), (5) finance the construction of the
Allegheny oil pipeline ($22.8 million), (6) pay employee benefits costs related
to El Paso Energy's acquisition of our general partner ($8.6 million), (7) pay
transaction costs and (8) fund general working capital requirements. In addition
to the expenditures from borrowings under our revolving credit facility listed
above, we used a portion of the proceeds from our May 1999 offering of our
senior subordinated notes to repay indebtedness under our revolving credit
facility, to finance a portion of the Viosca Knoll transaction (approximately
$19.9 million), and to repay indebtedness under the Viosca Knoll credit facility
(approximately $33.4 million).
Over the next 12 months, we expect our capital expenditures for budgeted
projects to range from $30.0 to $100.0 million, depending on the number and
types of projects in which we participate and the level and nature of that
participation. We may use borrowings under our revolving credit facility to fund
these projects. We currently are reviewing a large number of potential natural
gas and oil pipeline, platform, development and other infrastructure
opportunities with a total capital cost estimated to be in excess of $200
million. We expect to pursue many of these projects, including some in which we
currently own a 100% interest, through joint ventures, strategic alliances or
other participatory arrangements. Often, we structure these joint ventures, in
which we usually own an interest of 50.0% or less, so they may independently
access capital, like non-recourse or limited recourse project financing.
We used the $33.4 million that El Paso Energy contributed to Viosca Knoll
at the closing of that acquisition and $33.4 million of the proceeds from our
senior subordinated note offering to repay in full and terminate the Viosca
Knoll credit facility on June 1, 1999. Over the past 12 months, Viosca Knoll
used borrowings under its credit facility for the addition of compression
facilities to and expansion of the Viosca Knoll system and for other working
capital needs. For additional information on the Viosca Knoll transaction, see
"Business--Natural Gas and Oil Pipelines--Viosca Knoll System" beginning on page
53.
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<PAGE> 33
MARKET PRICE OF AND DISTRIBUTIONS ON UNITS
MARKET INFORMATION
The common units and preference units are listed on the NYSE, which is the
principal trading market for these securities. The common units are listed under
the symbol "LEV" and the preference units are listed under the symbol "LEV.P".
On August 25, 1999, the last reported per unit sales prices of the common units
and preference units on the NYSE were $23.875 and $24.00, respectively. The
following table sets forth the high and low sales prices for the common units
and preference units as reported on the NYSE and the cash distributions declared
per common unit and preference unit for the periods indicated.
<TABLE>
<CAPTION>
DISTRIBUTIONS DECLARED
PRICE RANGE PER UNIT
---------------------------------------- -----------------------
COMMON UNITS PREFERENCE UNITS
------------------ ------------------ COMMON PREFERENCE
HIGH LOW HIGH LOW UNIT UNIT
------- ------- ------- ------- -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Year ended December 31, 1999
Second Quarter.............. $24.750 $21.375 $23.250 $20.500 $0.525 $0.275
First Quarter............... 23.125 19.500 20.875 17.625 0.525 0.275
Year ended December 31, 1998
Fourth Quarter.............. $28,500 $19.750 $25.000 $17.375 $0.525 $0.275
Third Quarter*.............. 27.875 21.500 29.750 21.250 0.525 0.275
Second Quarter.............. * * 34.000 25.500 0.525 0.525
First Quarter............... * * 33.625 27.000 0.525 0.525
Year ended December 31, 1997
Fourth Quarter.............. * * $33.125 $28.000 $0.500 $0.500
Third Quarter............... * * 28.750 23.250 0.475 0.475
Second Quarter.............. * * 26.375 20.375 0.450 0.450
First Quarter............... * * 24.250 19.000 0.425 0.425
Year ended December 31, 1996
Fourth Quarter.............. * * $ 22.81 $ 20.75 $0.400 $0.400
Third Quarter............... * * 21.19 18.00 0.375 0.375
Second Quarter.............. * * 18.00 15.69 0.350 0.350
First Quarter............... * * 16.19 13.75 0.325 0.325
</TABLE>
- ---------------
* At the close of business on August 5, 1998, we issued replacement common units
to the holders of then outstanding preference units that elected to convert
their preference units into common units. The holders of approximately 94% of
preference units elected to convert. Trading commenced for the common units on
the NYSE on August 6, 1998. Prior to such date, there was no active trading
market for the common units.
HOLDERS
As of March 5, 1999, there were approximately 468 and 125 holders of record
of common units and preference units, respectively.
DISTRIBUTIONS
Our partnership agreement requires us to distribute, within 45 days after
the end of each calendar quarter, all of our "available cash," as such term is
defined in our partnership agreement. Generally, "available cash" means, for the
applicable quarter, all cash receipts for such quarter and any reductions in
reserves established in prior quarters less all cash disbursements made in such
quarter and additions to reserves, as determined by our general partner. Our
partnership agreement characterizes available cash into two categories -- "cash
from operations" and "cash from interim capital contributions," each of which is
described in the section "Description of Common Units." To date, we have only
distributed available cash constituting cash from operations, and we do not
anticipate making distributions of available cash constituting cash from interim
capital transactions in the next six months.
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<PAGE> 34
CAPITALIZATION
The following table sets forth our consolidated capitalization on a
historical basis as of June 30, 1999 and our unaudited consolidated
capitalization as adjusted to reflect (1) sale of the common units offered
pursuant to this prospectus and (2) the capital contribution by our general
partner in order to maintain its 1% general partner interest in us as a result
of issuing additional common units. See "Use of Proceeds" beginning on page 27.
You should read this table along with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" beginning on page 32.
<TABLE>
<CAPTION>
AS OF JUNE 30, 1999
----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt:
Revolving credit facility................................. $306,500 $213,975
Senior subordinated notes due 2009........................ 175,000 175,000
-------- --------
Total long-term debt.............................. 481,500 388,975
Minority interest........................................... (249) (249)
Partners' capital........................................... 120,036 212,561
-------- --------
Total capitalization.............................. $601,287 $601,287
======== ========
</TABLE>
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<PAGE> 35
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
The historical financial information for each of the three years ended
December 31, 1996, 1997 and 1998 and as of December 31, 1997 and 1998 was
derived from our consolidated financial statements and notes thereto included
elsewhere in this prospectus. The historical financial information for the years
ended December 31, 1994 and 1995 and as of December 31, 1994, 1995 and 1996 has
been derived from our historical consolidated financial statements (not included
herein). The historical financial data for each of the six months ended June 30,
1998 and 1999 and as of June 30, 1999 was derived from our historical unaudited
consolidated financial statements and notes thereto included elsewhere in this
prospectus. The historical financial data as of June 30, 1998 has been derived
from our unaudited historical consolidated financial statements (not included
herein). We believe that all material adjustments, consisting only of normal
recurring adjustments necessary for the fair presentation of our interim
results, have been included. Results of operations for any interim period are
not necessarily indicative of the results of operations for the entire year due
to the seasonal nature of our business. You should read this information along
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" beginning on page 32, "Business and Properties" beginning on page 45
and the consolidated financial statements and notes thereto listed on pages F-1
and F-2.
<TABLE>
<CAPTION>
(UNAUDITED)
-------------------
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
---------------------------------------------------- -------------------
1994 1995 1996 1997 1998 1998 1999
-------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS:
Oil and natural gas sales.... $ 796 $ 1,858 $ 47,068 $ 58,106 $ 31,411 $ 15,734 $ 15,100
Gathering, transportation and
platform services.......... 18,554 20,547 24,005 17,329 17,320 7,782 10,798
Equity in earnings........... 14,786 19,588 20,434 29,327 26,724 12,571 19,953
-------- -------- -------- -------- -------- -------- --------
Total revenue....... 34,136 41,993 91,507 104,762 75,455 36,087 45,851
-------- -------- -------- -------- -------- -------- --------
Operating expenses........... 1,876 4,092 9,068 11,352 11,369 5,546 5,025
Depreciation, depletion and
amortization............... 5,085 8,290 31,731 46,289 29,267 14,845 13,727
Impairment, abandonment and
other...................... -- -- -- 21,222 (1,131) -- --
General and administrative
expenses and management
fee........................ 5,408 7,069 8,540 14,661 16,189 7,503 5,909
-------- -------- -------- -------- -------- -------- --------
Total operating
costs............. 12,369 19,451 49,339 93,524 55,694 27,894 24,661
-------- -------- -------- -------- -------- -------- --------
Operating income............. 21,767 22,542 42,168 11,238 19,761 8,193 21,190
Interest income and other.... 1,293 1,884 1,710 1,475 771 157 268
Interest and other financing
costs...................... (912) (833) (5,560) (14,169) (20,242) (8,429) (13,868)
Minority interest in (income)
loss....................... (216) (251) (427) 7 (15) (3) (80)
-------- -------- -------- -------- -------- -------- --------
Income (loss) before income
taxes...................... 21,932 23,342 37,891 (1,449) 275 (82) 7,510
Income tax benefit........... 136 603 801 311 471 168 177
-------- -------- -------- -------- -------- -------- --------
Net income (loss)... $ 22,068 $ 23,945 $ 38,692 $ (1,138) $ 746 $ 86 $ 7,687
======== ======== ======== ======== ======== ======== ========
Basic and diluted net income
(loss) per unit............ $ 1.02 $ 0.97 $ 1.57 $ (0.06) $ 0.02 $ 0.00 $ 0.25
======== ======== ======== ======== ======== ======== ========
CASH DISTRIBUTIONS DECLARED
PER UNIT:
Preference unit.............. $ 1.20 $ 1.20 $ 1.45 $ 1.85 $ 1.60 $ 1.05 $ 0.55
======== ======== ======== ======== ======== ======== ========
Common unit.................. $ 1.20 $ 1.20 $ 1.45 $ 1.85 $ 2.10 $ 1.05 $ 1.05
======== ======== ======== ======== ======== ======== ========
</TABLE>
30
<PAGE> 36
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
---------------------------------------------------- -------------------
1994 1995 1996 1997 1998 1998 1999
-------- -------- -------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA (AT END OF
PERIOD):
Property and equipment,
net........................ $126,802 $285,275 $286,555 $200,639 $241,992 $201,503 $381,210
Equity investments........... 80,560 82,441 107,838 182,301 186,079 186,147 219,732
Total assets................. 231,043 398,696 453,526 409,842 442,726 406,087 625,913
Total debt................... 8,000 135,780 227,000 238,000 338,000 270,000 481,500
Total partners' capital...... 192,431 186,841 192,023 143,966 82,896 113,557 120,036
OTHER FINANCIAL DATA:
EBITDA(1).................... $ 26,852 $ 30,832 $ 73,899 $ 78,749 $ 47,897 $ 23,038 $ 34,917
Adjusted EBITDA(2)........... 27,136 35,886 90,288 76,557 52,344 23,765 39,072
Net cash provided by
operating activities....... 51,716 74,886 50,179 67,485 25,677 12,884 23,640
Net cash used in investing
activities................. 98,285 172,382 101,721 41,769 65,624 19,366 92,818
Net cash provided by (used
in) financing activities... 57,744 95,580 52,525 (35,775) 36,625 1,194 69,371
Capital expenditures included
in investing activities.... 98,398 173,632 101,721 41,957 66,111 19,366 92,818
</TABLE>
- ------------------
(1) EBITDA is defined for this purpose as operating income before depreciation,
depletion and amortization and impairment, abandonment and other. EBITDA is
used as a supplemental financial measurement in the evaluation of our
business and should not be considered as an alternative to net income, as an
indicator of our operating performance or as an alternative to cash flows
from operating activities as a measure of liquidity. EBITDA may not be a
comparable measurement among different companies. EBITDA is presented here
to provide additional information about us.
(2) Adjusted EBITDA is defined for this purpose as EBITDA plus cash
distributions from equity investments less earnings attributable to equity
investments. We believe Adjusted EBITDA is a meaningful disclosure because
of the significance of our equity investments. Adjusted EBITDA is used as a
supplemental financial measurement in the evaluation of our business and
should not be considered as an alternative to net income, as an indicator of
our operating performance or as an alternative to cash flows from operating
activities as a measure of liquidity. Adjusted EBITDA may not be a
comparable measurement among different companies. Adjusted EBITDA is
presented here to provide additional information about us.
31
<PAGE> 37
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion in conjunction with (1) our
consolidated financial statements and the notes thereto incorporated into this
prospectus by reference and (2) the information set forth under the heading
"Selected Historical Consolidated Financial Data." The following discussion
should assist your understanding of our financial position and results of
operations for the six months ended June 30, 1999 and 1998 and for each of the
years ended December 31, 1998 and 1997. Unless the context otherwise requires,
all references below to "we," "us" or "our" are also references to our
subsidiaries.
OVERVIEW
We are a provider of integrated energy services, including natural gas and
oil gathering, transportation, midstream and other related services in the Gulf
of Mexico. Either directly or through our joint ventures, we own interests in
eight natural gas pipeline systems, an oil gathering system, six
strategically-located multi-purpose offshore platforms, production handling and
dehydration facilities and five oil and natural gas properties.
Our natural gas pipelines, located primarily offshore Louisiana and
Mississippi, gather and transport natural gas for producers, marketers,
pipelines and end-users for a fee. Our current interests in operating natural
gas pipelines consist of: a 100% interest in each of Green Canyon and Tarpon; a
99.0% interest in Viosca Knoll; a 50.0% interest in Stingray; a 60.0% interest
in HIOS; a 66.7% interest in UTOS; and an effective 25.7% interest in each of
Manta Ray Offshore and Nautilus. Our natural gas pipelines include 1,200 miles
of pipeline with a throughput capacity of 6.8 billion cubic feet ("Bcf") of
natural gas per day.
We own a 36.0% interest in the Poseidon oil pipeline. The Poseidon oil
pipeline is located primarily offshore Louisiana and consists of approximately
300 miles of pipeline with a throughput capacity of 400,000 barrels of oil per
day.
We operate and own interests in six strategically-located, multi-purpose
platforms in the Gulf of Mexico, including a 100% interest in five
platforms--Viosca Knoll Block 817, East Cameron Block 373, Ship Shoal Block 332,
South Timbalier Block 292 and Ship Shoal Block 331--and a 50.0% interest in the
Garden Banks Block 72 platform. These platforms have production handling
capabilities which complement our pipeline operations and play a key role in the
development of oil and natural gas reserves. We also own a 50.0% interest in
West Cameron Dehy, a dehydration and production handling facility located at the
northern terminus of the Stingray system, onshore Louisiana.
In addition, with our joint venture partners, we are constructing two
natural gas pipelines through newly created joint ventures, East Breaks
Gathering Company, L.L.C. and Nemo Gathering Company, LLC, and we have recently
completed the construction of a wholly owned oil pipeline which we expect to
become operational in the fourth quarter of 1999, the Allegheny System.
RECENT FINANCING DEVELOPMENTS
PREFERENCE UNIT CONVERSION. Holders of approximately 71% of our remaining
outstanding preference units as of August 12, 1999 opted to convert those units
into common units by the expiration of our second 90 day conversion option
period, which commenced on May 14, 1999 and ended on August 12, 1999. During the
first conversion option period, during substantially the same period in 1998,
approximately 94% of our then outstanding preference units were converted into
common units. As a result of the completion of the second conversion option
period, a total of 291,299 preference units are outstanding.
SUBORDINATED NOTES OFFERING. On May 27, 1999, we borrowed $175 million
pursuant to the issuance, at par, of senior subordinated notes. These senior
subordinated notes, which were issued under an indenture, bear interest at a
rate of 10 3/8% per annum, payable semi-annually, mature on June 1, 2009, and
32
<PAGE> 38
are currently guaranteed by all of our subsidiaries. For more information about
our subordinated notes, see "--Liquidity and Capital Resources--Sources of
Cash."
EXTENSION OF OUR CREDIT FACILITY. Concurrently with the closing of the
offering of our senior subordinated notes, we amended our $375.0 million
revolving credit facility to, among other things, extend the maturity to May
2002 from December 1999. As of August 9, 1999, we had $300.0 million outstanding
under the revolving credit facility bearing interest at an average floating rate
of 7.7% per annum.
NEW WESTERN GULF JOINT VENTURE CREDIT FACILITY. Western Gulf, which owns
HIOS and East Breaks, entered into a $100.0 million revolving credit facility in
February 1999 with a syndicate of commercial banks to fund substantially all of
the costs of the East Breaks system and other working capital needs of Western
Gulf, East Breaks and HIOS. This credit facility is secured by certain assets of
the joint venture and matures in February 2004. As of August 9, 1999, Western
Gulf had $50.1 million outstanding under its credit facility, bearing interest
at an average floating rate of 6.5% per annum, and $49.9 million of additional
availability under the facility. Including the 20% interest we recently acquired
from NGPL, we now own 60.0% of Western Gulf.
TERMINATION OF VIOSCA KNOLL JOINT VENTURE CREDIT FACILITY. In connection
with our acquisition of substantially all of the interest that we did not
previously own in our Viosca Knoll joint venture, we repaid the balance
outstanding under and terminated the $100.0 million credit facility which that
joint venture had obtained in December 1996.
RESULTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1999 COMPARED WITH SIX MONTHS ENDED JUNE 30, 1998
Oil and natural gas sales totaled $15.1 million for the six months ended
June 30, 1999 as compared with $15.7 million for the same period in 1998. The
decrease is attributable to (1) substantially lower realized oil and natural gas
prices and (2) normal production declines from our oil and natural gas
properties, partially offset by production from properties we acquired in August
1998. During the six months ended June 30, 1999, we produced and sold 6,877
million cubic feet ("MMcf") of natural gas and 193,000 barrels of oil at average
prices of $1.83 per thousand cubic feet ("Mcf") and $12.69 per barrel,
respectively. During the same period in 1998, we produced and sold 4,874 MMcf of
natural gas and 308,000 barrels of oil at average prices of $2.16 per Mcf and
$16.53 per barrel.
Revenue from gathering transportation and platform services totaled $8.3
million for the six months ended June 30, 1999, net of $2.4 million related to
the effect of consolidating Viosca Knoll's results beginning on June 1, 1999 as
compared with $7.8 million for the same period in 1998. The $0.5 million
increase primarily reflects an increase of $2.7 million in platform services
revenue from our East Cameron Block 373 platform which was placed in service in
April 1998 offset by decreases of (1) $1.3 million in gathering revenues as a
result of lower throughput on the Green Canyon and Tarpon systems primarily due
to normal declines in production and (2) $0.9 million in platform access fees
because we acquired additional interests in the Viosca Knoll Block 817 lease in
August 1998.
Revenue from our joint ventures totaled $20.0 million for the six months
ended June 30, 1999 as compared with $11.8 million for the same period in 1998
after taking out the effect of consolidating Viosca Knoll's results of
operations beginning on June 1, 1999. The increase of $8.2 primarily reflects
increases of (1) $0.8 million related to Stingray as a result of reductions in
prior period estimates of reserves of uncollectible revenues and (2) $8.4
million from Poseidon Oil Pipeline Company, West Cameron Dehy, Nautilus and
Manta Ray Offshore as a result of increased throughput, offset by a decrease of
$1.0 million as a result of decreased throughput on HIOS and UTOS. Total natural
gas throughput volumes for our joint ventures increased approximately 3% from
the six months ended June 30, 1998 to the same period in 1999 primarily as a
result of increased throughput on the Viosca Knoll, Nautilus and Manta Ray
Offshore systems. Oil volumes from the Poseidon pipeline totaled 29.5 million
barrels and 15.7 million barrels for the six months ended June 30, 1999 and
1998.
33
<PAGE> 39
Depreciation, depletion and amortization totaled $13.4 million for the six
months ended June 30, 1999 after taking out the effect of consolidating Viosca
Knoll's results of operations beginning on June 1, 1999 as compared with $14.8
million for the same period in 1998. The decrease of $1.4 million reflects a
decrease of $1.8 million in depreciation and depletion of oil and natural gas
wells and facilities located on the Viosca Knoll Block 817, Garden Banks Block
72 and the Garden Banks Block 117 as a result of decreased depletion and
abandonment accrual rates offset by a $0.4 million increase in depreciation on
our East Cameron Block 373 and Ship Shoal Block 331 platforms placed in service
after March 31, 1998.
General and administrative expenses, including our general partner's
management fee, totaled $5.9 million for the six months ended June 30, 1999, as
compared with $7.5 million for the same period in 1998. The decrease of $1.6
million reflects decreases of (1) $0.1 million in our general partner's
management fee and (2) $1.5 million in direct general and administrative
expenses primarily related to the appreciation and vesting of unit rights
granted to certain officers and employees under a compensation plan that was
terminated in October 1998.
Interest and other financing costs, excluding capitalized interest, for the
six months ended June 30, 1999 totaled $14.6 million as compared with $8.4
million for the same period in 1998. During the six months ended June 30, 1999
and 1998, we capitalized $0.8 million and $0.5 million, respectively, of
interest costs in connection with construction projects and drilling activities
in progress during such periods. During the six months ended June 30, 1999 and
1998, we had outstanding indebtedness under our credit facility averaging
approximately $332.0 million and $254.0 million, respectively, at average
interest rates of 7.3% and 6.5% per annum. Additionally, our senior subordinated
notes, issued in May 1999, bear interest at 10 3/8% per annum.
Net income for the six months ended June 30, 1999, totaled $7.7 million, or
$0.25 per unit, as compared with $86,000, or $0.00 per unit, for the six months
ended June 30, 1998, as a result of the items discussed below.
YEAR ENDED DECEMBER 31, 1998 COMPARED WITH YEAR ENDED DECEMBER 31, 1997
Oil and natural gas sales totaled $31.4 million for the year ended December
31, 1998 as compared with $58.1 million for the same period in 1997. The
decrease is attributable to (1) substantially lower realized oil and natural gas
prices, (2) decreased production as a result of two tropical storms and
Hurricane Georges passing through the Gulf of Mexico during the third quarter of
1998, (3) normal production declines from our oil and natural gas properties and
(4) the lack of acceptable markets downstream of the Viosca Knoll system. The
production decline attributable to the capacity constraints of the downstream
transporter was alleviated during the third quarter of 1998. During the year
ended December 31, 1998, we produced and sold 11,324 MMcf of natural gas and
540,000 barrels of oil at average prices of $2.01 per Mcf and $15.69 per barrel.
During the same period in 1997, we produced and sold 19,792 MMcf of natural gas
and 801,000 barrels of oil at average prices of $2.08 per Mcf and $20.61 per
barrel.
Revenue from gathering, transportation and platform services totaled $17.3
million for each of the years ended December 31, 1998 and 1997. The activity for
1998 remained consistent with the prior year as a result of an increase of $5.5
million in platform services revenue from our East Cameron Block 373 platform,
which was placed in service in April 1998, offset by decreases of (1) $2.8
million related to the cessation of production in May 1997 from the only well
connected to the Ewing Bank system, (2) $1.9 million as a result of lower
throughput on the Green Canyon system and the contribution of a significant
portion of the Manta Ray system to Manta Ray Offshore on January 17, 1997,
resulting in revenue from these assets being included in equity in earnings for
the entire year ended December 31, 1998 as compared with a portion of the year
ended December 31, 1997 and (3) $0.8 million in platform revenue services from
our Viosca Knoll Block 817 platform as a result of lower oil and natural gas
volumes processed on the platform due to capacity constraints of a downstream
transporter which were alleviated during the third quarter of 1998. Throughput
volumes for our wholly owned gathering systems decreased approximately 8.0% for
the year ended December 31, 1998 as compared with the same period in 1997.
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Revenue from our joint ventures totaled $26.7 million for the year ended
December 31, 1998 as compared with $29.3 million for the same period in 1997.
The decrease of $2.6 million primarily reflects decreases of (1) $6.7 million
related to non-recurring start-up costs, changes in prior period estimates and a
change in equity ownership of Nautilus and Manta Ray Offshore and (2) $2.5
million related to Stingray and HIOS as a result of increased maintenance costs
and decreased throughput offset by an increase of $6.6 million from Poseidon,
Viosca Knoll, UTOS and West Cameron Dehy as a result of increased throughput.
Total natural gas throughput volumes for our joint ventures increased
approximately 20.0% from the year ended December 31, 1997 to the same period in
1998 primarily as a result of increased throughput on the Viosca Knoll, UTOS,
Nautilus and Manta Ray Offshore systems. Oil volumes from Poseidon totaled 35.6
million barrels ("MMbbls") and 19.0 MMbbls for the year ended December 31, 1998
and 1997, respectively. Our joint ventures were impacted by two tropical storms
and Hurricane Georges passing through the Gulf of Mexico during the third
quarter of 1998.
Operating expenses totaled $11.4 million for each of the years ended
December 31, 1998 and 1997. The 1998 activity remained consistent with the prior
year as a result of lower operating and transportation costs associated with our
oil and natural gas properties offset by higher operating costs associated with
the East Cameron Block 373 platform placed in service in April 1998, the
acquisition of the Ship Shoal Block 331 platform in August 1998 and additional
activities associated with the Ship Shoal Block 332 platform.
Depreciation, depletion and amortization totaled $29.3 million for the year
ended December 31, 1998 as compared with $46.3 million for the same period in
1997. The decrease of $17.0 million reflects decreases of (1) $14.0 million in
depreciation and depletion on oil and natural gas wells and facilities located
on the Viosca Knoll Block 817, Garden Banks Block 72 and the Garden Banks Block
117 as a result of decreased production from these leases and slightly lower
estimated abandonment obligations and (2) $3.0 million in depreciation on
pipelines, platforms and facilities as a result of us fully depreciating our
investment in the Ewing Bank and Ship Shoal systems in June 1997, offset by
increased depreciation attributable to our East Cameron Block 373 and Ship Shoal
Block 331 platforms placed in service in 1998.
Impairment, abandonment and other totaled ($1.1 million) for the year ended
December 31, 1998 and represented the excess of accrued costs over actual costs
incurred associated with the abandonment of our Ewing Bank flowlines.
Impairment, abandonment and other totaled $21.2 million for the year ended
December 31, 1997 and consisted of a non-recurring charge to reserve our
investment in certain gathering facilities and other assets associated with
Tatham Offshore's Ewing Bank 914 #2 well and Ship Shoal Block 331 property, to
accrue our abandonment obligations associated with the gathering facilities
serving these properties, to reserve our noncurrent receivable related to the
prepayment of the demand charge obligations under certain agreements related to
the Ewing Bank and Ship Shoal leases and to accrue certain abandonment
obligations associated with its oil and natural gas properties.
General and administrative expenses, including the management fee allocated
from our general partner, totaled $16.2 million for the year ended December 31,
1998 as compared with $14.7 million for the same period in 1997. The increase of
$1.5 million reflects increases of (1) $1.0 million in management fee allocated
by our general partner to us as a result of our increased construction and
operational activities and (2) $0.5 million in our direct general and
administrative expenses primarily related to the vesting and appreciation of
unit rights to certain of our officers and employees.
Interest income and other totaled $0.8 million for the year ended December
31, 1998 as compared with $1.5 million for the same period in 1997.
Interest and other financing costs, excluding capitalized interest, for the
year ended December 31, 1998 totaled $20.2 million as compared with $14.2
million for the same period in 1997. During the year ended December 31, 1998 and
1997, we capitalized $1.1 million and $1.7 million, respectively, of interest
costs in connection with construction projects and drilling activities in
progress during such periods. During the years ended December 31, 1998 and 1997,
we had outstanding indebtedness averaging approximately $288.0 million and
$232.5 million.
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Net income for the year ended December 31, 1998 totaled $0.7 million, or
$0.02 per unit, as compared with a net loss of $1.1 million, or $0.06 per unit,
for the year ended December 31, 1997 as a result of the items discussed above.
YEAR ENDED DECEMBER 31, 1997 COMPARED WITH YEAR ENDED DECEMBER 31, 1996
Oil and natural gas sales totaled $58.1 million for the year ended December
31, 1997 as compared with $47.1 million for the year ended December 31, 1996.
The increase of $11.0 million is attributable to increased production from our
oil and natural gas properties as a result of initiating full production from
Viosca Knoll Block 817 in March 1996, Garden Banks Block 72 in May 1996 and
Garden Banks Block 117 in July 1996. During the year ended December 31, 1997, we
produced and sold 19,792 MMcf of natural gas and 801.0 Mbbls of oil at average
prices of $2.08 per Mcf and $20.61 per barrel, respectively. During 1996, we
produced and sold 15,730 MMcf of natural gas and 393.0 Mbbls of oil at average
prices of $2.37 per Mcf and $21.76 per barrel, respectively.
Revenue from gathering, transportation and platform services totaled $17.3
million for the year ended December 31, 1997 as compared with $24.0 million for
the year ended December 31, 1996. The decrease of $6.7 million reflects
decreases of (1) $7.6 million as a result of the contribution of a significant
portion of the Manta Ray system to Manta Ray Offshore in January 1997 resulting
in revenue from these assets being included in equity in earnings for the
remainder of the year ended December 31, 1997 and (2) $3.0 million related to
lower throughput on the Ewing Bank system offset by increases of (1) $1.8
million in platform services from our Viosca Knoll Block 817 platform as a
result of additional oil and natural gas volumes processed on the platform and
(2) $2.1 million from the Tarpon and Green Canyon systems primarily related to
(x) the deregulation of the Tarpon system allowing us to recognize additional
revenue during the current period related to the gathering fees collected in
prior periods and (y) new production attached to these systems. Throughput
volumes for our wholly owned gathering systems decreased 34.0% for the year
ended December 31, 1997 as compared with the year ended December 31, 1996
primarily due to an 82.0% decline from the Ewing Bank system due to a downhole
mechanical problem in May 1997 which caused Tatham Offshore's Ewing Bank 914 #2
well to be shut-in.
Revenue from our joint ventures totaled $29.3 million for the year ended
December 31, 1997 as compared with $20.4 million for the year ended December 31,
1996. The increase of $8.9 million primarily reflects increases of (1) $2.9
million from Viosca Knoll and UTOS as a result of increased throughput, (2) $1.6
million from Poseidon, which placed the Poseidon system in service in
three-phases, April 1996, December 1996 and December 1997, (3) $0.4 million from
West Cameron Dehy, (4) $3.7 million from Manta Ray Offshore related to the Manta
Ray assets contributed by Leviathan and (5) $2.2 million from Nautilus,
primarily as a result of Nautilus recognizing as other income an allowance for
funds used during construction, offset by (6) a $1.9 million decrease in
Stingray and HIOS as a result of increased maintenance costs during 1997. Total
natural gas throughput volumes for our joint ventures increased approximately
9.0% from 1996 to 1997 primarily as a result of increased throughput on the
Viosca Knoll and UTOS systems as well as the addition of the Manta Ray Offshore
system throughput as a joint venture, as discussed above. Oil volumes from
Poseidon totaled 19.0 MMbbls for the year ended December 31, 1997 as compared
with 7.5 MMbbls for the period from inception of operations in April 1996
through December 31, 1996.
Operating expenses for the year ended December 31, 1997 totaled $11.4
million as compared with $9.1 million for the year ended December 31, 1996. The
increase of $2.3 million is primarily attributable to additional maintenance
costs related to the platforms we operate and our operation of one additional
oil and natural gas well during 1997.
Depreciation, depletion and amortization totaled $46.3 million for the year
ended December 31, 1997 as compared with $31.7 million for the year ended
December 31, 1996. The increase of $14.6 million reflects an increase of $19.7
million in depreciation and depletion on the oil and natural gas wells and
facilities located on Viosca Knoll Block 817, Garden Banks Block 72 and Garden
Banks Block 117 as a result of increased production from these leases which
initiated production in December 1995, May 1996
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and July 1996, respectively, offset by a decrease of $5.1 million in
depreciation on pipelines, platforms and facilities.
Impairment, abandonment and other totaled $21.2 million for the year ended
December 31, 1997 and consisted of a non-recurring charge to reserve our
investment in certain gathering facilities and other assets associated with
Tatham Offshore's Ewing Bank 914 #2 well and Ship Shoal Block 331 property, to
accrue our abandonment obligations associated with the gathering facilities
serving these properties, to reserve our noncurrent receivable related to the
prepayment of the demand charge obligations under certain agreements related to
the Ewing Bank and Ship Shoal leases and to accrue certain abandonment
obligations associated with its oil and natural gas properties.
General and administrative expenses, including the management fee allocated
from our general partner, totaled $14.7 million for the year ended December 31,
1997 as compared with $8.5 million for the year ended December 31, 1996. General
and administrative expenses for the year ended December 31, 1996 were reduced by
a one-time $1.4 million reimbursement from Poseidon as a result of our
management of the initial construction of Poseidon. Excluding this one-time
reimbursement by Poseidon, general and administrative expenses for the year
ended December 31, 1997 increased $4.7 million as compared to the year ended
December 31, 1996. This increase reflects (1) a $1.5 million increase in
management fees allocated by our general partner to us as a result of our
increased construction and operational activities, (2) a $3.6 million increase
in our direct general and administrative expenses primarily related to the
appreciation and vesting of unit appreciation rights granted to certain officers
and employees in 1995, 1996 and 1997 and (3) a $0.4 million decrease in the
reimbursement to El Paso Energy for certain tax liabilities pursuant to the
management agreement with us.
Interest income and other totaled $1.5 million for the year ended December
31, 1997 as compared with $1.7 million for the year ended December 31, 1996.
Interest and other financing costs, excluding capitalized interest, for the
year ended December 31, 1997 totaled $14.2 million as compared with $5.6 million
for the year ended December 31, 1996. During the years ended December 31, 1997
and 1996, we capitalized $1.7 million and $11.9 million, respectively, of
interest costs in connection with construction projects and drilling activities
in progress during such periods. During the years ended December 31, 1997 and
1996, we had outstanding indebtedness averaging approximately $232.5 million and
$181.4 million, respectively.
Net loss for the year ended December 31, 1997 totaled $1.1 million, or
$0.06 per unit, as compared with net income of $38.7 million, or $1.57 per unit,
for the year ended December 31, 1996 as a result of the items discussed above.
LIQUIDITY AND CAPITAL RESOURCES
SOURCES OF CASH. We intend to satisfy our capital requirements and other
working capital needs primarily from cash on hand, cash from operations and
borrowings under our revolving credit facility (discussed below). However,
depending on market and other factors, we may issue additional equity to raise
cash or acquire assets, as in the acquisition of the additional interest in
Viosca Knoll. Net cash provided by operating activities for the year ended
December 31, 1998 and for the six months ended June 30, 1999 totaled $25.7
million and $23.6 million, respectively. In addition to funds available under
our credit facility or from the issuance of equity, we may use debt securities
to raise cash to fund our working capital requirements. At June 30, 1999, we had
cash and cash equivalents of $3.3 million.
Cash from operations is derived from (1) payments for gathering natural gas
through our 100% owned pipelines, (2) platform access and production handling
fees, (3) cash distributions from our joint ventures and (4) the sale of oil and
natural gas attributable to our interest in our producing properties. Oil and
natural gas properties are depleting assets and will produce reduced volumes of
oil and natural gas in the future unless additional wells are drilled or
recompletions of existing wells are successful. See "Business and
Properties--Natural Gas and Oil Properties Associated with Infrastructure
Opportunities" beginning on page 59 for current rates from our properties.
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Our cash flows from operations will be affected by the ability of each of
our joint ventures to make distributions. Distributions from such entities are
also subject to the discretion of their respective management committees.
Further, each of Stingray, Poseidon and Western Gulf is party to a credit
agreement under which it has outstanding obligations that may restrict the
payments of distributions to its owners. We received distributions from our
joint ventures during the year ended December 31, 1998 and for the six months
ended June 30, 1999 totaling $31.2 million and $24.1 million, respectively.
We entered into an indenture dated May 27, 1999, with Chase Bank of Texas,
National Association, pursuant to which we issued $175 million in aggregate
principal amount of Series A Senior Subordinated Notes (along with the
indenture, the "subordinated notes"). The subordinated notes bear interest at a
rate of 10 3/8% per annum, payable semi-annually on June 1 and December 1,
mature on June 1, 2009, and are junior to substantially all of our other
indebtedness other than trade payables and indebtedness that by its terms
expressly states it is equal or junior to the subordinated notes. Generally, we
do not have the right to prepay the subordinated notes prior to May 31, 2004,
and thereafter, we may prepay the subordinated notes at a premium of 5% of the
face amount, which premium declines ratably through maturity. Although the
subordinated notes are unsecured, all of our subsidiaries have guaranteed those
obligations. The subordinated notes contain customary terms and conditions,
including various affirmative and negative covenants and the obligation to offer
to repurchase the notes at a premium under certain circumstances. Among other
things, the terms of the subordinated notes limit our ability to make
distributions to our unitholders, redeem or otherwise reacquire any of our
equity, incur additional indebtedness, incur or permit to exist certain liens,
make additional investments, engage in transactions with affiliates, engage in
certain types of business and dispose of assets under certain circumstances,
including if certain financial tests are not satisfied or there is a default. In
addition, we will be obligated to offer to repurchase the subordinated notes if
we experience certain types of changes of control or if we dispose of certain
assets and do not reinvest the proceeds or repay senior indebtedness.
We currently have a revolving credit facility providing for up to $375.0
million of available credit, subject to customary terms and conditions,
including certain limitations on incurring additional indebtedness (including
borrowings under this facility) if certain financial targets are not achieved
and maintained. In addition, we will be required to prepay a portion of the
balance outstanding under our credit facility to the extent such financial
targets are not achieved and maintained. We may borrow money under the credit
agreement for general partnership purposes, including financing capital
expenditures, working capital requirements, and, subject to certain limitations,
distributions to our unitholders. We may also utilize this credit facility to
issue letters of credit as may be required from time to time; however, no
letters of credit are currently outstanding. Concurrently with the closing of
the offering of our subordinated notes, we amended our facility to, among other
things, extend the maturity to May 2002 from December 1999. Our revolving credit
facility is guaranteed by the general partner and each of our subsidiaries and
is collateralized by (1) the management agreement between the general partner
and a subsidiary of El Paso Energy, (2) substantially all of our assets and (3)
the general partner's 1.0% general partner interest in us and approximate 1.0%
nonmanaging interest in certain of our subsidiaries. Our revolving credit
facility has no scheduled amortization prior to maturity. As of August 9, 1999,
we had $300.0 million outstanding under our revolving credit facility bearing
interest at an average floating rate of 7.7% per annum and approximately $44.5
million of funds are available under the facility. We used all otherwise
unapplied proceeds from the offering of our subordinated notes (approximately
$112.3 million) to reduce the balance outstanding under our credit facility.
Poseidon has a revolving credit facility with a syndicate of commercial
banks to provide up to $150.0 million for other working capital needs of
Poseidon. Poseidon's ability to borrow money under the facility is subject to
certain customary terms and conditions, including certain limitations on
incurring additional indebtedness (including borrowings under this credit
facility) if certain financial targets are not achieved and maintained. In
addition, Poseidon will be required to prepay a portion of the balance
outstanding under this credit facility to the extent such financial targets are
not achieved and maintained. The Poseidon credit facility has no scheduled
amortization prior to maturity. The Poseidon credit facility is collateralized
by a substantial portion of Poseidon's assets and matures on April 30, 2001. As
of August 9,
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1999, Poseidon had $140.0 million outstanding under its credit facility bearing
interest at an average floating rate of 6.5% per annum and had approximately
$10.0 million of additional funds available under the facility.
Stingray has an existing term loan agreement with a syndicate of commercial
banks which matures on March 31, 2003. The agreement requires Stingray to make
18 quarterly principal payments of approximately $1.6 million commencing
December 31, 1998. The term loan agreement is principally collateralized by
current and future natural gas transportation contracts between Stingray and its
customers. On the earlier to occur of March 31, 2003 or the accelerated due date
pursuant to the Stingray credit agreement, if Stingray has not paid all amounts
due under its credit agreement, we are obligated to pay the lesser of (1) $8.5
million, (2) the aggregate amount of distributions received by us from Stingray
subsequent to January 1, 1998 or (3) 50.0% of any then outstanding amounts due
pursuant to the Stingray credit agreement. We do not expect to have to pay any
amount pursuant to this obligation. As of August 9, 1999, Stingray had $23.7
million outstanding under its term loan agreement bearing interest at an average
floating rate of 6.3% per annum.
Western Gulf, which owns all of HIOS and East Breaks, entered into a
revolving credit facility with a syndicate of commercial banks in February 1999
to provide up to $100.0 million for the construction of the East Breaks System
and for other working capital needs of Western Gulf, East Breaks and HIOS.
Western Gulf's ability to borrow money under the facility is subject to certain
customary terms and conditions, including certain limitations on incurring
additional indebtedness (including borrowings under this credit facility) if
certain financial targets are not achieved and maintained. In addition, Western
Gulf would be required to prepay a portion of the balance outstanding under this
credit facility to the extent such financial targets are not achieved and
maintained. The credit facility has no scheduled amortization prior to its
maturity in February 2004. The Western Gulf credit facility is collateralized by
substantially all of the material contracts and agreements of East Breaks and
Western Gulf, including Western Gulf's ownership in HIOS and East Breaks, and
supported by the guarantee of East Breaks. In addition, we have agreed to return
up to $3.0 million in distributions paid to us by Western Gulf under certain
circumstances. As of August 9, 1999, Western Gulf had $50.1 million outstanding
under this credit facility bearing interest at a floating rate of 6.5% per annum
and had approximately $49.9 million of additional funds available under this
facility.
Prior to the closing of the offering of our subordinated notes, Viosca
Knoll had a revolving credit facility with a syndicate of commercial banks to
provide up to $100.0 million for other working capital needs of Viosca Knoll,
which we repaid in full and terminated on June 1, 1999 in connection with our
acquisition of an additional 49.0% in Viosca Knoll from El Paso Energy.
USES OF CASH. Our primary capital requirements are (1) quarterly
distributions to holders of preference units and common units and to the general
partner, including incentive distributions, as applicable, (2) expenditures for
the maintenance of our pipelines and related infrastructure and the acquisition
and construction of additional energy-related infrastructure, (3) expenditures
related to our producing oil and natural gas properties, (4) expenditures
relating to the development of our non-producing property, the Ewing Bank 958
Unit, (5) administrative expenses (including management fees) and other
operating expenses, (6) contributions to our joint ventures as required to fund
capital expenditures for new facilities and (7) debt service on our outstanding
indebtedness, including reducing the balance outstanding under our revolving
credit facility with approximately $91.6 million of proceeds from this offering.
During the year ended December 31, 1998 and the six months ended June 30,
1999, we paid distributions to our partners totaling $62.4 million and $31.3
million, respectively. In May 1999, we paid an incentive distribution of $2.8
million to the general partner. On July 19, 1999, we declared our second quarter
cash distribution of $0.275 per preference unit and $0.525 per common unit
covering the three months ended June 30, 1999. The distributions were paid on
August 13, 1999 to all holders of record of common and preference units at the
close of business on July 30, 1999 and included an incentive distribution to our
general partner of $3.2 million. We believe that we will be able to continue to
pay at
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least the current quarterly distributions of $0.275 per preference unit and
$0.525 per common unit for the foreseeable future. At these distribution rates,
the quarterly distributions total $17.4 million ($20.3 million assuming the
issuance of at least 4,000,000 common units upon the consummation of this
offering) in respect of the preference units, common units and general partner
interest.
In April 1998, we completed the construction and installation of a new
platform and production handling facilities at East Cameron Block 373 at a cost
of $30.2 million, $9.4 million of which was incurred in 1998.
During 1998, we paid $2.9 million related to the abandonment of the Ewing
Bank flowlines and $8.6 million to our management in connection with the
accelerated vesting of certain rights granted under a compensation plan that was
terminated in 1998.
Substantially all of the capital expenditures by Poseidon, East Breaks,
Viosca Knoll and Stingray were funded by borrowings under credit facilities, and
any future capital expenditures by East Breaks, Poseidon, HIOS and Stingray are
anticipated to be funded by borrowings under credit facilities. Our capital
expenditures (including construction and installation of the Allegheny oil
pipeline and development costs of the Ewing Bank 958 Unit) and equity
investments and acquisitions for the year ended December 31, 1998 and for the
six months ended June 30, 1999 were $66.1 million and $92.8 million,
respectively. We have in the past contributed existing assets to joint ventures
as partial consideration for ownership interest therein and may in the future
contribute existing assets, including cash, to new joint ventures as partial
consideration for ownership interest.
Over the next twelve months, we expect our capital expenditures to range
from $30.0 to $100.0 million, depending on the number and types of projects in
which we participate and the level and nature of that participation. We
currently are reviewing a large number of potential natural gas and oil
pipeline, platform, development and other infrastructure opportunities with a
total capital cost estimated at in excess of $200.0 million. We expect to pursue
many of these projects (including some in which we currently own a 100%
interest) through joint ventures, strategic alliances or other participatory
arrangements. Often, we structure these joint ventures, in which we usually own
an interest of 50% or less, so they may independently access capital, like
non-recourse or limited recourse project financing.
We expect to make capital expenditures in connection with the maintenance
of the service capabilities of our subsidiary owned natural gas and oil
pipeline, platform, development and other infrastructure. We anticipate that
these capital expenditures will aggregate approximately $1.5 million to $2.0
million per year (which generally will be funded from cash generated from
operations), although the actual level of these capital expenditures may change
from time to time for many reasons, some of which may be beyond our control.
Interest costs incurred by us totaled $19.2 million and $14.6 million,
respectively, for the year ended December 31, 1998 and for the six months ended
June 30, 1999. We capitalized $1.1 million and $0.8 million, respectively, of
such interest costs in connection with construction projects and drilling
activities in process during such periods.
We anticipate that our capital expenditures and equity investments for 1999
will relate to continuing acquisition, construction and development activities,
including the completion of the Allegheny oil pipeline, the construction of the
Nemo pipeline described in this prospectus and the development of the Ewing Bank
958 Unit. We anticipate funding such cash requirements primarily with available
cash flow, borrowings under our credit facility and, depending on the capital
requirements and related market conditions, issuing additional debt and/or
equity. Further, with respect to the development of the Ewing Bank 958 Unit as
currently planned, we anticipate consummating an exchange, sale, farmout, joint
venture or similar arrangement to share in the drilling and infrastructure costs
associated with that development. If we do not make such an arrangement, we will
have to raise additional capital through another source or we will not be able
to proceed with this development as currently planned. We cannot assure you that
any such source of capital would be available to complete this development.
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NEW ACCOUNTING STANDARDS
REPORTING ON THE COSTS OF START-UP ACTIVITIES. In April 1998, the American
Institute of Certified Public Accountants issued Statement of Position 98-5,
"Reporting on the Costs of Start-Up Activities." This statement defines start-up
activities, requires start-up and organization costs to be expensed as incurred
and requires that any such costs that exist on the balance sheet be expensed
upon adoption of this pronouncement. We adopted the provisions of this statement
on January 1, 1999, the impact of which was not material to our financial
position or results of operations.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. In June 1998,
the Financial Accounting Standards Board issued Statement of Financial
Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and
Hedging Activities." SFAS No. 133 requires that entities recognize all
derivative investments as either assets or liabilities on the balance sheet and
measure those instruments at fair value. Changes in the fair value of
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as a hedge transaction.
For fair-value hedge transactions in which we are hedging changes in an asset's,
liability's or firm commitment's fair value, changes in the fair value of the
derivative instrument will generally be offset in the income statement by
changes in the hedged item's fair value. For cash-flow hedge transactions, in
which we are hedging the variability of cash flows related to a variable-rate
asset, liability, or a forecasted transaction, changes in the fair value of the
derivative instrument will be reported in other comprehensive income. The gains
and losses on the derivative instrument that are reported in other comprehensive
income will be reclassified as earnings in the periods in which earnings are
impacted by the variability of the cash flows of the hedged item. The
ineffective portion of all hedges will be recognized in current-period earnings.
This statement was amended by SFAS No. 137 issued in June 1999. The amendment
defers the effective date of SFAS No. 133 to fiscal years beginning after June
15, 2000. We have not yet determined the impact that the adoption of SFAS No.
133 will have on our financial position or results of operations.
ACCOUNTING FOR CONTRACTS INVOLVED IN ENERGY TRADING AND RISK MANAGEMENT
ACTIVITIES. In November 1998, the Emerging Issues Task Force ("EITF") reached a
consensus on EITF 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." EITF 98-10 requires energy trading contracts to
be recorded at fair value on the balance sheet, with the changes in fair value
included in earnings and is effective for fiscal years beginning after December
15, 1998. We adopted the provisions of EITF 98-10 effective January 1, 1999, the
resulting impact of which did not have a material impact on our financial
position or results of operations.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We may utilize derivative financial instruments for purposes other than
trading to manage our exposure to movements in interest rates and commodity
prices. In accordance with procedures established by our Board of Directors, we
monitor current economic conditions and evaluate our expectations of future
prices and interest rates when making decisions with respect to risk management.
INTEREST RATE RISK. We utilize both fixed and variable rate long-term debt.
We are exposed to some market risk due to the floating interest rate under our
credit facility. Under our credit facility, the remaining principal and the
final interest payments are due in March 2002. As of August 9, 1999,
indebtedness outstanding under our credit facility was $300.0 million at an
average interest rate of 7.7% per annum. A 1 1/2% increase in interest rates
could result in a $4.5 million annual increase in interest expense on the total
existing principal balance. We are exposed to similar risk under the credit
facilities and loan agreements entered into by our joint ventures. See
"-- Liquidity and Capital Resources." We have determined that it is not
necessary to participate in interest rate-related derivative financial
instruments because we currently do not expect significant short-term increases
in the interest rates charged under our credit facility or the various joint
venture credit facilities and loan agreements.
COMMODITY PRICE RISK. We hedge a portion of our oil and natural gas
production to reduce our exposure to fluctuations in the market prices thereof.
We use commodity price swap transactions whereby monthly settlements are based
on differences between the prices specified in the commodity price swap
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agreements and the settlement prices of certain futures contracts quoted on the
New York Mercantile Exchange ("NYMEX") or certain other indices. We settle the
commodity price swap transactions by paying the negative difference or receiving
the positive difference between the applicable settlement price and the price
specified in the contract. The commodity price swap transactions we use differ
from futures contracts in that there are no contractual obligations which
require or allow for the future delivery of the product. The credit risk from
our price swap contracts is derived from the counter-party to the transaction,
typically a major financial institution. We do not require collateral and do not
anticipate non-performance by this counter-party, which does not transact a
sufficient volume of transactions with us to create a significant concentration
of credit risk. Gains or losses resulting from hedging activities and the
termination of any hedging instruments are initially deferred and included as an
increase or decrease to oil and natural gas sales in the period in which the
hedged production is sold. For the six months ended June 30, 1999, we recorded a
net loss of $0.7 million related to hedging activities.
As of June 30, 1999, we had open sales swap transactions for 10,000 MMbtu
of natural gas per day for calendar 2000 at a fixed price to be determined at
our option equal to the February 2000 Natural Gas Futures Contract on NYMEX as
quoted at any time during 1999 and January 2000, to and including the last two
trading days of the February 2000 contract, minus $0.5450 per MMbtu.
Additionally, we had open sales swap transactions of 10,000 MMbtu of natural gas
per day at a fixed price to be determined at our option equal to the January
2000 Natural Gas Futures Contract on NYMEX as quoted at any time during 1999, to
and including the last two trading days of the January 2000 contract, minus
$0.50 per MMbtu.
At June 30, 1999, we had open crude oil hedges on approximately 500 barrels
per day for the remainder of calendar 1999 at an average price of $16.10 per
barrel.
If we had settled our open natural gas hedging positions as of June 30,
1999 based on the applicable settlement prices of the NYMEX futures contracts,
we would have recognized a loss of approximately $2.2 million.
YEAR 2000
The Year 2000 issue is the result of computer programs that were written
using two digits rather than four to define the year. We have established a
project team that works with the El Paso Energy executive steering committee to
coordinate the phases of our Year 2000 project to ensure that our key automated
systems and related processes will remain functional through Year 2000. Those
phases include: (1) awareness, (2) assessment, (3) remediation, (4) testing, (5)
implementation of the necessary modifications and (6) contingency planning
(which was previously included as a component of our implementation phase). We
have hired outside consultants and are involved in several industry trade-
groups to supplement our project team.
The awareness phase recognizes the importance of Year 2000 issues and its
potential impact on us. Through the project team, we have established an
awareness program which includes participation of management in each business
area. The awareness phase is substantially completed, although we will
continually update awareness efforts for the duration of the Year 2000 project.
The assessment phase consists of conducting an inventory of our key
automated systems and related processes, analyzing and assigning levels of
criticality to those systems and processes, identifying and prioritizing
resource requirements, developing validation strategies and testing plans, and
evaluating business partner relationships. We estimate that we are more than
three-quarters complete with the portion of the assessment phase to determine
the nature and impact of the Year 2000 date change for hardware and equipment,
embedded chip systems, and third-party developed software. The assessment phase
of the project involves, among other things, efforts to obtain representations
and assurances from third parties, including joint ventures, partners, customers
and vendors, that their hardware and equipment products, embedded chip systems
and software products being used by or impacting us are or will be modified to
be Year 2000 compliant. To date, the responses from such third parties, although
generally encouraging, are inconclusive. Although we intend to interact only
with those third parties that have Year 2000 compliant computer systems, it is
impossible for us to monitor all such systems. As a result, we cannot predict
the
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potential consequences if our joint ventures, partners, customers or vendors are
not Year 2000 compliant. We are currently evaluating the exposure associated
with such business partner relationships.
The remediation phase involves converting, modifying, replacing or
eliminating selected key automated systems identified in the assessment phase.
The testing phase involves the validation of the identified key automated
systems. We are utilizing test tools and written procedures to document and
validate, as necessary, its unit, system, integration and acceptance testing.
The implementation phase involves placing the converted or replaced key
automated systems into operations. In some cases, the implementation phase will
also involve the implementation of contingency plans needed to support business
functions and processes that may be interrupted by Year 2000 failures that are
outside our control. As of August 9, 1999, we are substantially completed with
each phase.
The contingency planning phase consists of developing a risk profile of our
critical business processes and then providing for actions we will pursue to
keep such processes operational in the event of Year 2000 disruptions. The focus
of such contingency planning is on prompt response to Year 2000 events, and a
plan for subsequent resumption of normal operations. The plan is expected to
assess the risk of significant failure to critical processes performed by us,
and to address the mitigation of those risks. The plan will also consider any
significant failures in the event the most reasonably likely worst case scenario
develops, as discussed below. In addition, the plan is expected to factor in the
severity and duration of the impact of a significant failure. As of August 9,
1999, the contingency plan was substantially completed. This Year 2000
contingency plan will continue to be modified and adjusted through the year as
additional information from key external business partners becomes available.
Our goal is to ensure that all of our critical systems and processes that
are under our direct control remain functional. However, certain systems and
processes may be interrelated with or dependent upon systems outside our control
and systems within our control may have unpredicted problems. Accordingly, there
can be no assurance that significant disruptions will be avoided. Our present
analysis of our most reasonably likely worst case scenario for Year 2000
disruptions includes Year 2000 failures in the telecommunications and
electricity industries, as well as interruptions from suppliers that might cause
disruptions in our operations, thus causing temporary financial losses and an
inability to meet our obligations to customers. A significant portion of the oil
and natural gas transported through our pipelines is owned by third parties.
Accordingly, failures of the producers of oil and natural gas to be ready for
the Year 2000 could significantly disrupt the flow of the hydrocarbons for
customers. In many cases, the producers have no direct contractual relationship
with us, and we rely on our customers to verify the Year 2000 readiness of the
producers from whom they purchase oil and natural gas. A portion of our revenue
for the transportation of oil and natural gas is based upon fees paid by our
customers for the reservation of capacity and a portion of the revenue is based
upon the volume of actual throughput. As such, short-term disruptions in
throughput caused by factors beyond our control may have a financial impact on
us and could cause operational problems for our customers. Longer-term
disruptions could materially impact our operations, financial condition and cash
flows.
We estimate that the costs to be incurred in 1999 and 2000 associated with
assessing, remediating and testing hardware and equipment, embedded chip
systems, and third-party developed software will not exceed $1.0 million, all of
which will be expensed. As of June 30, 1999, we had incurred less than $0.1
million related to such costs. We have previously only tracked incremental
expenses related to our Year 2000 project. The costs of the Year 2000 project
related to salaried employees of El Paso Energy, including their direct salaries
and benefits, are not available and have not been included in the estimated
costs of the project. The management fee charged to us by the general partner
includes such incremental expenses.
Presently, we intend to reassess our estimate of Year 2000 costs in the
event we complete an acquisition of, or make a material investment in,
substantial facilities or another business entity.
Management does not expect the costs of our Year 2000 project will have a
material adverse effect on our financial position, results of operations or cash
flows. However, based on information available at this time, we cannot conclude
that disruption caused by internal or external Year 2000 related failures will
not
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adversely effect us. Specific factors which may affect the success of our Year
2000 efforts and the frequency or severity of Year 2000 disruption or amount of
any expense include failure by us or our outside consultants to properly
identify deficient systems, the failure of the selected remedial action to
adequately address the deficiencies, the failure by us or our outside
consultants to complete the remediation in a timely manner (due to shortages of
qualified labor or other factors), the failure of other parties to joint
ventures in which we are involved to meet their obligations, both financial and
operational under the relevant joint venture agreements to remediate assets used
by the joint venture, unforeseen expenses related to the remediation of existing
systems or the transition to replacement systems, and the failure of third
parties, including joint ventures, to become Year 2000 compliant or to
adequately notify us of potential noncompliance.
The above disclosure is a "Year 2000 Readiness Disclosure" made with the
intention to comply fully with the Year 2000 Information and Readiness
Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law
October 19, 1998. All statements made herein shall be construed within the
confines of the Act. To the extent that any reader of this Year 2000 Readiness
Disclosure is other than an investor or potential investor in our or an
affiliate's equity or debt securities, this disclosure is made for the sole
purpose of communicating or disclosing information aimed at correcting, helping
to correct and/or avoiding Year 2000 failures.
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BUSINESS AND PROPERTIES
OVERVIEW
We are a provider of integrated energy services, including natural gas and
oil gathering, transportation, midstream and other related services in the Gulf
of Mexico. We commenced operations in 1989, through a predecessor company, with
the objective of becoming a major natural gas gatherer and transporter in the
Gulf of Mexico, with specific focus on the emerging Deepwater, and identifying
and exploiting other energy-related opportunities. When we completed our initial
public offering in 1993, we owned interests in seven pipeline systems, which
extended approximately 721 miles and had a design capacity of 5.0 Bcf of natural
gas per day. Either directly or through joint ventures, we now own interests in
nine operating pipeline systems, which extend approximately 1,500 miles and have
a design capacity of 6.8 Bcf of natural gas and 400,000 barrels of oil per day.
We also own multi-purpose platforms; production handling, dehydration and other
energy-related infrastructure facilities; as well as oil and natural gas
properties. We have substantial assets in the Gulf of Mexico, primarily offshore
Louisiana and Mississippi, which we believe are well-positioned to maintain a
stable base level of operations and to provide growth opportunities by
successfully competing for new production in our areas of service, especially
those assets in the Deepwater (water depths greater than 1,500 feet) and
Flextrend (water depths of 600 to 1,500 feet) regions. Either directly or
through joint ventures, we own interests in:
- eight offshore natural gas pipeline systems;
- one offshore crude oil gathering system;
- six strategically-located, multi-purpose offshore platforms that serve to
interconnect the pipeline grid;
- production handling and dehydration facilities; and
- four oil and natural gas properties associated with infrastructure
opportunities.
In addition, with our joint venture partners, we are constructing two natural
gas pipelines through newly created joint ventures, East Breaks Gathering
Company, L.L.C. and Nemo Gathering Company, LLC, and we have recently completed
the construction of a wholly owned oil pipeline which we expect to become
operational in the fourth quarter of 1999, the Allegheny System.
In the past six years, our operations have grown through the acquisition
and construction of energy-related infrastructure, including:
- acquiring all of the Manta Ray system and constructing and acquiring a
50.0% interest in the Viosca Knoll system in 1994;
- constructing two multi-purpose platforms located at Viosca Knoll Block
817 and Garden Banks Block 72 in 1995;
- acquiring, developing and producing oil and natural gas reserves located
in the Gulf of Mexico in 1995;
- completing construction in 1996 of the Poseidon system, a crude oil
pipeline system in which we own a 36.0% working interest;
- acquiring in 1997 an effective 25.7% interest in each of Nautilus and
Manta Ray Offshore, to which we contributed substantially all of the
Manta Ray system (originally acquired during a period from 1992);
- constructing a multi-purpose platform located in East Cameron Block 373
and acquiring a 100% working interest in the Ewing Bank 958 Unit in 1998;
and
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- acquiring in 1999 an additional 49.0% interest in the Viosca Knoll
system, an additional indirect 33.3% interest in UTOS and an additional
indirect (through Western Gulf) 20.0% interest in HIOS and East Breaks.
In addition to our wholly owned assets and operations, we conduct a large
portion of our business through joint ventures/strategic alliances, which we
believe are ideally suited for Deepwater operations. We use joint ventures to
reduce our capital requirements and risk exposure to individual projects, as
well as to develop strategic relationships, realize synergies resulting from
combining resources, and benefit from the assets, experience and resources of
our partners. Generally, our partners are integrated or very large independent
energy companies with substantial interests, operations and assets in the Gulf
of Mexico, including affiliates of Coastal/ANR, Equilon, Marathon, Shell and
Texaco.
Through our strategically-located network of wholly owned and joint venture
pipelines and other facilities and businesses, we believe we provide customers
with an efficient and cost effective midstream alternative. Today, we offer some
customers a unique single point of contact through which they may access a wide
range of integrated or independent midstream services, including gathering,
transportation, production handling, dehydration and other services. We also
provide producers operating in certain Deepwater and Flextrend areas with
relatively low-cost access to numerous onshore long-haul pipelines and,
accordingly, multiple end-use markets. Additionally, our Deepwater experience
and specialized expertise in this area allows us to provide operational
solutions to producers looking for economic improvements in their development
activities.
INDUSTRY OVERVIEW
We believe that development and exploration activity in the Gulf of Mexico
will continue and that the Gulf of Mexico will continue to be one of the most
prolific producing regions in the U.S. Today, the Gulf of Mexico accounts for
approximately 20.3% and 25.6% of total U.S. production of oil and natural gas,
respectively. Oil production from the Gulf of Mexico is expected to increase
from 1.3 MMbbls/d in 1998 to 1.8 MMbbls/d in 2003, according to the Potential
Gas Committee, which is comprised of academic institutions, government agencies
and industry participants. That committee also expects production of natural gas
to increase from 14.0 Bcf/d in 1998 to 16.6 Bcf/d in 2003. The principal source
of this production growth is expected to be the Flextrend and Deepwater. Recent
developments in oil and natural gas exploration and production techniques, such
as 3-D seismic analysis, horizontal drilling, remote subsea completions via
satellite templates and sea floor wellheads, and non-stationary surface
production facilities, have substantially reduced finding, development and
production costs allowing operators to move into the Deepwater regions of the
Gulf of Mexico. For instance, the number of blocks under lease in the Gulf of
Mexico in water depths greater than 600 feet has increased from approximately
3,100 in February 1998 to approximately 4,200 in February 1999. By year-end
2003, production from deeper water fields is projected to account for 54.6% and
24.0% of the Gulf of Mexico's oil and natural gas production, respectively, up
from 35.6% and 13.4% in 1998, respectively, according to the Potential Gas
Committee.
We have pipelines, platforms and other infrastructure facilities
strategically positioned throughout a large portion of the Flextrend area of the
Gulf of Mexico, offshore Louisiana and Mississippi and extending out to and, in
some areas, into the Deepwater. Because of their location in relation to the way
in which oil and natural gas development has occurred in the Gulf of Mexico, we
expect these assets to contribute significantly to the development of natural
gas and oil in surrounding areas of the Flextrend and Deepwater. Historically,
development of nascent Gulf of Mexico regions has started with large pipelines
positioned in a north/south direction connecting new, significant discoveries to
existing shoreward infrastructure. Then, additional infrastructure has expanded
laterally in an east/west direction to access reserves between the north/south
pipelines. As this pipeline infrastructure became more accessible to more
producing regions, the incremental cost of placing reserves on production
declined, which facilitated the development of projects that could not support
the installation of pipelines on a stand-alone basis. This process of lateral
expansion has been continually repeated as advances in exploration and
development technology have allowed producers to economically explore for oil
and natural gas in progressively deeper
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water areas. We believe that the exploration and development of the deeper water
areas will accelerate in the future and, as a result, will continue to provide
attractive opportunities for companies strategically positioned to access
production in those areas.
In part because of the technological advancements and the expanded pipeline
infrastructure, the Gulf Coast was the only part of the United States to see an
increase in potential natural gas supplies in the last two years, while total
U.S. natural gas supplies have declined over that same period, according to the
Potential Gas Committee. That committee also projects that the Gulf Coast
natural gas resource base, including proved reserves, increased from 264.9
trillion cubic feet to 265.5 trillion cubic feet during 1998; thus, the Gulf was
the only major producing region in the U.S. which replaced more reserves than
were produced in 1998. Construction by us and others of the pipeline
infrastructure necessary to deliver this production to onshore markets is
expected to remain critical to the expansion and development efforts in these
deeper water regions.
We believe that we are strategically positioned to take advantage of new
discoveries and increased production in the Deepwater, Flextrend and subsalt
regions of the Gulf of Mexico. In addition to comprising a significant portion
of the network of pipelines in the shallow waters of the Gulf of Mexico off of
Louisiana, our pipelines also have substantial east/west facilities on the edge
of portions of the Flextrend and deeper water. We also have several existing and
planned extensions into the deeper water regions. However, we cannot assure you
that additional reserves in those areas will actually be developed or, if
developed, that any of our pipelines will gather, transport or otherwise handle
that production.
BUSINESS STRATEGY
Our strategically-positioned assets, as well as our knowledge and
expertise, enhance our ability to capitalize on infrastructure and other
energy-related business opportunities in the Gulf of Mexico, particularly in the
deeper water regions. By implementing the following business strategies, we
expect to maintain our position as a provider of integrated energy services,
including natural gas and oil gathering, transportation, midstream and other
related services in the Gulf of Mexico.
- FOCUS ON HIGH POTENTIAL DEEPWATER.
We believe Deepwater operations will provide us with significantly greater
profit opportunities for a number of reasons. First, our existing assets are
well-positioned for expansion into the Deepwater. Because of the location of
certain of our assets, we believe such expansion projects can be implemented
at a lower cost relative to our competition, thus enhancing our goal of
being a low-cost provider of gathering, transportation, production handling
and other midstream services. Second, Deepwater projects require large
capital investment by producers and, in return, produce substantial reserves
and cash flow, when successful. Given the significant return potential, such
projects are undertaken with a longer-term view toward the commodity cycle
and are substantially less sensitive to near-term oil and natural gas
prices. Therefore, by focusing on Deepwater projects we expect to increase
the stability of our operations and financial results.
- PROVIDE MULTIPLE MARKET ACCESS FOR GULF OF MEXICO PRODUCTION.
Unlike some of our competitors, we connect to numerous onshore, long-haul
pipelines and can offer producers access to multiple end-use markets. Our
ability to provide multiple pipeline connections and broad market access is
important, because it allows producers to take advantage of pricing
differentials, mitigate capacity constraints and avoid temporary suspensions
of service.
- OFFER A SINGLE SOURCE ALTERNATIVE FOR A COMPLETE RANGE OF MIDSTREAM
SERVICES.
Through our strategically-located network of wholly owned and joint venture
pipelines, other facilities and businesses, we offer some customers a unique
single point of contact through which they may access a wide range of
midstream services and assets, including (1) gathering, transportation,
production handling, dehydration, compression, pumping and other handling
services for both natural
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gas and oil, (2) access to platforms, compression and other infrastructure
facilities, (3) significant Flextrend and Deepwater experience and
expertise, and (4) other related assets and services. Under the more
conventional system used by many of our competitors, producers must contact
and negotiate with a number of unaffiliated parties, including natural gas
pipelines, oil pipelines, processors and other service providers, with
potentially competing interests. By providing a complete range of services
between the wellhead and the shore, we believe we provide producers with a
more efficient midstream solution, which should result in increased revenue
opportunities.
- SHARE CAPITAL COSTS AND RISKS WITH STRATEGIC JOINT VENTURE PARTNERS.
Given the significant cost to expand energy-related infrastructure in the
Flextrend and Deepwater areas of the Gulf of Mexico, we seek opportunities
to undertake such projects through joint ventures or partnerships,
principally with partners with substantial financial resources and
substantial strategic interests, assets and operations, especially in the
Deepwater, Flextrend and subsalt regions of the Gulf of Mexico. By forming
such joint ventures or partnerships, we reduce our capital requirements,
mitigate our risk exposure to individual projects, develop strategic
business relationships with other industry participants and benefit from
the assets, experience and resources of our partners. Generally, our
partners are integrated or very large independent energy companies with
substantial interests, operations and assets in the Gulf of Mexico,
including affiliates of Coastal/ANR, Equilon, Marathon, Shell and Texaco.
- DESIGN NEW INFRASTRUCTURE PROJECTS BASED ON DEDICATED PRODUCTION UNDER
LONG-TERM COMMITMENTS AND/OR FIXED PAYMENT ARRANGEMENTS WITH THE ABILITY
TO EXPAND CAPACITY AND SERVICES IN THE FUTURE TO CAPTURE POTENTIAL GROWTH
OPPORTUNITIES.
We base decisions to construct new infrastructure on both firm long-term
dedication agreements (and/or fixed payment arrangements) and our assessment
of potential production in the vicinity of the dedication. This strategy
allows us to recover our initial investment and receive a base return
through a stable, predictable source of cash flow. We also often design our
new pipeline, platform, production handling and other hydrocarbon handling
facilities with additional capacity and with the flexibility to expand
capacity or provide additional services, as required. For example, we may
design a platform to allow it to act as a pipeline landing and maintenance
hub or to facilitate drilling and development activities. Although this
approach increases the original cost of the asset, we believe that such
capacity and flexibility allows us to more effectively compete for new
production and to lower the overall cost of our services.
- SELECTIVELY INVEST IN OIL AND NATURAL GAS PROPERTIES ASSOCIATED WITH
INFRASTRUCTURE OPPORTUNITIES.
In areas we serve or desire to serve, we pursue opportunistic investments in
pipelines, platforms, production handling facilities and other
infrastructure assets, as well as selective investment in oil and natural
gas properties. By providing infrastructure to previously unserved
geographic regions, we can accelerate the development of oil and natural gas
properties in that area. The ability to access common facilities allows
producers to share the high fixed costs associated with infrastructure and,
in certain circumstances, results in the economic development of otherwise
marginal reserves and in an increase in the total reserves produced from
that region. Further, we will invest in oil and natural gas properties when
such investment will augment the utilization of our existing assets or lead
to a strategic infrastructure opportunity.
RECENT DEVELOPMENTS, ACQUISITIONS AND NEW PROJECTS
WE FORMED A NEW NATURAL GAS DEEPWATER PIPELINE JOINT VENTURE WITH AN
AFFILIATE OF SHELL. On August 10, 1999, we formed Nemo Gathering Company, LLC, a
joint venture owned 66.1% by Tejas Offshore Pipeline, LLC and 33.9% by us, to
construct, own and operate a natural gas gathering system. The Nemo System will
deliver natural gas production from the Shell-operated Brutus and Glider
Deepwater development properties to another of our joint venture pipelines, the
Manta Ray Offshore
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Gathering System. We expect the Nemo System to be placed in service in late 2001
at a total cost of approximately $36.0 million.
WE INCREASED OUR OWNERSHIP INTEREST IN THREE OF OUR EXISTING PIPELINE JOINT
VENTURES--UTOS, HIOS AND EAST BREAKS, WHICH IS A NEW DEEPWATER EXPANSION. In
December 1998, the partners of HIOS, a Delaware partnership then owned 40.0% by
us, 40.0% by subsidiaries of ANR Pipeline Company and 20.0% by a subsidiary of
NGPL, restructured the joint venture arrangement by (1) creating a holding
company named Western Gulf Holdings, L.L.C., (2) converting HIOS, which owns a
regulated natural gas pipeline located in the Gulf of Mexico, into a limited
liability company named High Island Offshore System, L.L.C., and (3) forming a
new limited liability company named East Breaks Gathering Company, L.L.C. to
construct and operate an unregulated natural gas pipeline system. Western Gulf
owns 100% of each of HIOS and East Breaks.
On June 30, 1999, we increased our ownership interest in these three
complementary, interconnecting natural gas pipeline systems located offshore
Louisiana and the eastern portion of Texas. Through our acquisition of several
companies from NGPL for approximately $51.0 million, we increased our ownership
interest in UTOS to 66.7% from 33.3%, in HIOS to 60.0% from 40.0%, and in the
East Breaks System to 60.0% from 40.0%. UTOS is a 30-mile pipeline extending
from onshore Louisiana to a point of interconnection with HIOS, and receives
substantially all of its throughput from HIOS for redelivery to an onshore
production handling facility. HIOS is an expansive 204-mile pipeline system
extending through the Flextrend and up to the Deepwater in our service areas.
The East Breaks System is an 85-mile expansion currently under construction that
will connect HIOS to the Diana and Hoover fields being developed by subsidiaries
of Exxon and BP Amoco. Both Exxon and BP Amoco recently committed to the East
Breaks System production from their Diana and Hoover properties. These two
Deepwater properties are located in over 4,800 feet of water. With a throughput
capacity of 400.0 MMcf per day of natural gas and the ability to expand its
throughput capacity further, the East Breaks System and, therefore, the HIOS and
UTOS systems have the ability to compete to gather and transport the substantial
reserves associated with properties being, and expected to be, developed in
these Deepwater frontier regions. We estimate that construction of the East
Breaks System should be completed late in 2000 at a total cost of approximately
$90.0 million.
WE ARE CONSTRUCTING A DEEPWATER PLATFORM IN CONNECTION WITH THE DEVELOPMENT
OF OUR EWING BANK 958 UNIT. We believe our Ewing Bank 958 Unit development
project, formerly known as the Sunday Silence Property, provides us with an
opportunity to apply to the Deepwater area several strategies we have
successfully implemented in the shallow and Flextrend areas. Similar to three
other oil and natural gas properties we have developed, this project is
associated with other independent infrastructure opportunities. Although the
Ewing Bank 958 Unit development is a stand-alone project, we expect it to
position us to play a significant role in the extension of pipeline, platform
and other infrastructure facilities and service opportunities in this potential
emerging Deepwater region. Currently, we anticipate building gathering
extensions off of our Poseidon oil pipeline joint venture and our Manta Ray
Offshore Gathering natural gas pipeline joint venture.
Pursuant to our current plan of development for the Ewing Bank 958 Unit, we
are constructing a Moses Tension Leg Platform from which we would conduct all
activities related to that development, including additional drilling,
maintenance, and separation and handling operations. This platform is designed
for use in water depths of up to 6,000 feet and will have production handling
facilities with a throughput design capacity of 55.0 MMcf of natural gas per day
and 25,000 barrels of oil per day.
To date there has been no production from the Ewing Bank 958 Unit. We
currently own a 100% working interest in our Ewing Bank 958 Unit, which we
purchased in October 1998 from a wholly owned, indirect subsidiary of El Paso
Energy for $12.2 million. The Ewing Bank 958 Unit is located in approximately
1,500 feet of water and has received a royalty abatement from the MMS for the
first 52.5 MMbbls of oil equivalent to be produced from the field. In addition
to the initial discovery well drilled in 1994 and the two delineation wells
drilled in 1994 and 1998, the Ewing Bank 958 Unit development program may
require drilling up to five additional wells, depending on the level of actual
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production and other factors. As with many of our strategic assets, we
continually evaluate various alternatives for the Ewing Bank 958 Unit and the
related infrastructure, including joint ventures, strategic alliances and other
business arrangements. If we do not consummate such an arrangement, we may need
to raise substantial amounts of additional capital to fund this development
project.
WE HAVE CONSTRUCTED OUR ALLEGHENY OIL PIPELINE TO DELIVER CRUDE OIL FROM
THE FLEXTREND AND DEEPWATER REGIONS TO OUR POSEIDON JOINT VENTURE. We recently
completed construction of the Allegheny oil pipeline, a 100% owned, 40 mile long
crude oil pipeline that will connect British Borneo's Allegheny Field in the
Green Canyon area of the Gulf of Mexico with our Poseidon oil pipeline joint
venture. British Borneo has committed to the Allegheny System production from
its Allegheny Field. The Allegheny System, which will have a daily capacity of
more than 80,000 barrels of oil per day, is scheduled to begin operating during
the fourth quarter of 1999. We estimate the construction and tie-in costs for
the Allegheny oil pipeline to total approximately $27.0 million, $22.8 million
of which was incurred prior to June 30, 1999.
WE INCREASED OUR OWNERSHIP INTEREST IN OUR VIOSCA KNOLL JOINT VENTURE, A
NATURAL GAS PIPELINE LOCATED PRIMARILY IN THE FLEXTREND WATERS. On June 1, 1999,
we acquired an additional 49.0% interest in Viosca Knoll Gathering Company from
a subsidiary of El Paso Energy, which resulted in us owning 99.0% of Viosca
Knoll with an option to purchase the remaining 1.0%. At the closing of the
Viosca Knoll transaction, El Paso Energy contributed approximately $33.4 million
in cash to Viosca Knoll, which equaled 50.0% of the principal amount outstanding
under Viosca Knoll's credit facility, and we thereafter repaid and terminated
that credit facility. We paid El Paso Energy $79.7 million for the 49.0%
interest, comprised of approximately $19.9 million in cash and $59.8 million in
our common units. We formed the Viosca Knoll joint venture in 1994 with a
subsidiary of Tenneco Inc. to construct and operate a 125 mile long pipeline
system, with an initial throughput capacity of 400.0 MMcf of natural gas per
day, in an emerging producing region with limited infrastructure. The system
design involved the construction of our first multi-purpose hub-platform and
included the ability to expand throughput capacity at relatively nominal costs.
Due to customer needs, including some recent Deepwater commitments, we have
completed two expansion projects. These expansions more than doubled the Viosca
Knoll System's capacity to 1.0 Bcf per day. The Viosca Knoll System provides its
customers access to interstate pipelines of, among others, El Paso Energy,
Columbia Gulf Transmission Company, Sonat, Transco and Destin Pipeline Company.
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NATURAL GAS AND OIL PIPELINE SYSTEMS
GENERAL. We conduct a significant portion of our business activities
through joint ventures, currently organized as general partnerships or limited
liability companies, with subsidiaries of other substantial energy companies,
including Marathon, Shell, Texaco, Coastal/ANR, KN Energy/NGPL and El Paso
Energy. These joint ventures include Stingray and UTOS, both of which are
partnerships, and Manta Ray Offshore, HIOS, Poseidon, Nautilus, East Breaks and
West Cameron Dehydration, all of which are limited liability companies.
Management decisions related to the joint ventures are made by management
committees comprised of representatives of each partner or member, as
applicable, with authority appointed in direct relationship to ownership
interests.
Through our operating subsidiaries and our joint ventures, we own interests
in eight operating natural gas pipeline systems, strategically located offshore
Texas, Louisiana and Mississippi, which handle natural gas for producers,
marketers, pipelines and end-users for a fee. Our natural gas pipelines include
over 1,200 miles of pipeline with a throughput capacity of approximately 6.8 Bcf
of natural gas per day. During the years ended December 31, 1998, 1997 and 1996,
the natural gas pipelines handled an average of approximately 3.2 Bcf, 2.7 Bcf
and 2.7 Bcf, respectively, of natural gas per day. Each of our natural gas
pipelines interconnects with one or more long-line transmission pipelines that
provide access to multiple markets in the eastern half of the United States. In
addition, our East Breaks System, which has a design capacity of approximately
400.0 MMcf of natural gas per day, is being constructed and is expected to be
placed in service in late-2000. Our HIOS system is expected to be the primary
beneficiary of the East Breaks volumes.
None of our natural gas pipelines functions as a merchant to purchase and
resell natural gas, thus avoiding the commodity risk associated with the
purchase and resale of natural gas. Each of Nautilus, Stingray, HIOS and UTOS is
currently classified as a "natural gas company" under the Natural Gas Act of
1938, as amended (the "NGA"), and is therefore subject to regulation by the
FERC, including regulation of rates. None of Manta Ray Offshore, Viosca Knoll,
Green Canyon Pipe Line Company, L.L.C., Ewing Bank Gathering Company, L.L.C.,
East Breaks, or Tarpon Transmission Company is currently, nor is East Breaks
expected to be, considered a "natural gas company" under the NGA.
We own a 36.0% interest in the Poseidon oil pipeline, a major sour crude
oil pipeline system that was built in response to an increased demand for
additional sour crude oil pipeline capacity in the central Gulf of Mexico.
Poseidon was constructed and placed in service in three separate phases. Today,
Poseidon has a maximum design capacity of 400.0 Mbbls of oil per day. During
1998, 1997 and 1996, the Poseidon oil pipeline transported an average of
approximately 97.5 Mbbls, 52.0 Mbbls and 30.0 Mbbls, respectively, of oil per
day. During April 1999, this system averaged 170.0 Mbbls of oil per day. We
expect Poseidon's throughput to increase substantially in the next several years
as development progresses on the significant proved properties committed to that
system.
Our network of subsidiary and joint venture owned natural gas and crude oil
pipelines described in the following table provides our customers with gathering
and transportation services and relatively low-cost access to multiple end-use
markets. Our pipeline and infrastructure network currently extends from the
shoreline, through the Flextrend, and up to and, in some areas, into the
Deepwater in certain areas offshore Louisiana, Texas and Mississippi. We
currently operate all of our subsidiary owned pipelines (Green Canyon, Tarpon,
Viosca Knoll and Allegheny when operational later this year), and we are
scheduled to become the operator of the Stingray system on or before October 1,
1999. Our remaining joint venture pipelines are operated by unaffiliated
companies. In addition, we are constructing two natural gas pipelines through
two newly created joint ventures, East Breaks Gathering Company, L.L.C. and
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Nemo Gathering Company, LLC, and we have recently completed the construction of,
and are waiting to connect, a wholly owned oil pipeline, the Allegheny System.
<TABLE>
<CAPTION>
AVERAGE THROUGHPUT(1)
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
JV PARTNERS AGGREGATE 1998 1997
PIPELINE OWNERSHIP (OPERATOR IN-SERVICE MILES OF -------------- ---------------
SYSTEM INTEREST BOLD) DATE CAPACITY(1) PIPELINE GROSS NET(2) GROSS NET(2)
- -------- --------- ------------- ---------- ----------- --------- ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Green Canyon......... 100.0% LEVIATHAN 1990 220 68 126 126 148 148
Tarpon............... 100.0% LEVIATHAN 1978 80 40 63 63 50 50
Viosca Knoll......... 99.0%(4) LEVIATHAN 1994 1,000(5) 125 570 285(6) 388 194(6)
El Paso
Energy
UTOS................. 66.7% Leviathan, 1978 1,200 30 479 159(7) 316 105(7)
ANR PIPELINE
HIOS................. 60.0% Leviathan, 1977 1,800 204 842 337(8) 880 352(8)
ANR PIPELINE
Stingray............. 50.0% LEVIATHAN, 1975 1,120 417 658 329 706 353
NGPL
Manta Ray 25.7% Leviathan, 1987/88/97 755 225 281 72 195(10) 195(10)
Offshore(9)......... Marathon,
SHELL
Nautilus............. 25.7% Leviathan, 1997 600 101 153 39 --(11) --(11)
MARATHON,
Shell
Poseidon............. 36.0% Leviathan, 1996 400 314 97 35 52(12) 19(12)
TEXACO/EQUILON
PIPELINE CO.,
Marathon
<CAPTION>
PIPELINE
SYSTEM TYPE(3)
- -------- -------
<S> <C>
Green Canyon......... U
Tarpon............... U
Viosca Knoll......... U
UTOS................. R
HIOS................. R
Stingray............. R
Manta Ray U
Offshore(9).........
Nautilus............. R
Poseidon............. U
</TABLE>
- ------------------
(1) Measured in MMcf except for Poseidon, which is measured in Mbbls per day.
(2) Represents throughput net to our interest.
(3) U -- unregulated; R -- regulated. Regulated pipelines are subject to
extensive rate regulation by the FERC under the Natural Gas Act.
(4) We expect to acquire the remaining 1.0% interest in Viosca Knoll from El
Paso Energy after June 1, 2000.
(5) The original maximum design capacity of the Viosca Knoll system was 400.0
MMcf of natural gas per day. In 1996, Viosca Knoll installed a 7,000
horsepower compressor on our Viosca Knoll Block 817 platform to allow the
Viosca Knoll system to increase its throughput capacity to approximately
700.0 MMcf of natural gas per day. In 1997, Viosca Knoll added
approximately 25 miles of parallel 20-inch pipelines, increasing its
throughput capacity to approximately 1.0 Bcf of natural gas per day.
(6) Represents throughput net to our 50.0% ownership interest during such
period.
(7) Represents throughput net to our 33.3% ownership interest during such
period.
(8) Represents throughput net to our 40.0% ownership interest during such
period.
(9) In January 1997, we contributed substantially all of the Manta Ray
Gathering system (approximately 160 miles of pipeline) to Manta Ray
Offshore, decreasing our ownership in this system from 100% to an effective
25.7%. We continue to own and develop 19 miles of oil pipeline which were
formerly a part of the Manta Ray Gathering system.
(10) Represents throughput specifically allocated to us by Manta Ray Offshore
during the initial year of operations.
(11) The Nautilus system was placed in service in late December 1997.
(12) The Poseidon oil pipeline was placed in service in three phases, in April
1996, December 1996 and December 1997.
GREEN CANYON SYSTEM. The Green Canyon System, 100% owned and operated by
us, is an unregulated natural gas transmission system consisting of
approximately 68 miles of 10- to 20-inch diameter offshore pipeline which
transports natural gas from the South Marsh Island, Eugene Island, Garden Banks
and Green Canyon areas in the Gulf of Mexico to the west leg of the South
Lateral owned by Transcontinental Gas Pipe Line Corporation ("Transco") for
transportation to shore in eastern Louisiana.
TARPON SYSTEM. The Tarpon System, 100% owned and operated by us, is an
unregulated natural gas transmission facility consisting of approximately 40
miles of 16-inch diameter offshore pipeline that extends from the Ship Shoal
Block 274, South Addition, to the Eugene Island Area, South Addition, in an area
of the Gulf of Mexico adjacent to the Green Canyon System.
MANTA RAY OFFSHORE SYSTEM. The Manta Ray Offshore System, indirectly owned
25.7% by us, 50.0% by Tejas Offshore Pipelines (a subsidiary of Shell) and 24.3%
by Marathon Oil Company, is an unregulated natural gas transmission system
consisting of (1) three separate gathering lines, all located offshore Louisiana
in the Gulf of Mexico, which consist of a total of 76 miles of 12- to 24-inch
diameter pipeline, each interconnecting offshore with the east leg of the
Transco's Southeast Louisiana Lateral, which provides transportation for natural
gas to shore in eastern Louisiana, (2) approximately 51 miles of dual 14- and
16-inch diameter pipelines, with the 16-inch pipeline extending from Green
Canyon Block 29
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and the 14-inch pipeline extending from South Timbalier Block 301 northwesterly
to a shallow water junction platform with production handling facilities located
at Ship Shoal Block 207 and (3) approximately 47 miles of 24-inch pipeline
extending from Green Canyon Block 65 to Ship Shoal Block 207. Affiliates of
Marathon and Shell have dedicated for gathering on the Manta Ray Offshore System
significant deepwater acreage positions in the area. Marathon operates the Manta
Ray Offshore System. Manta Ray is a subsidiary of Neptune, in which we own a
25.7% interest.
VIOSCA KNOLL SYSTEM. The Viosca Knoll System is an unregulated gathering
system designed to serve the Main Pass, Mississippi Canyon and Viosca Knoll
areas of the Gulf of Mexico, southeast of New Orleans, offshore Louisiana. It
consists of 125 miles of predominantly 20-inch diameter natural gas pipelines
and a 7,000 horsepower compressor. The system provides its customers access to
the facilities of a number of major interstate pipelines, including El Paso
Energy, Columbia Gulf Transmission Company, Sonat, Transco and Destin Pipeline
Company.
The base system was constructed in 1994 and is comprised of (1) an
approximately 94 mile, 20-inch diameter pipeline from a platform in Main Pass
Block 252 owned by Shell to a pipeline owned by a wholly owned El Paso Energy
subsidiary at South Pass Block 55 and (2) a six mile, 16-inch diameter pipeline
from an interconnection with the 20-inch diameter pipeline at our Viosca Knoll
Block 817 platform to a pipeline owned by Southern Natural Gas Company at Main
Pass Block 289. A 7,000 horsepower compressor was installed in 1996 on the
Viosca Knoll Block 817 platform to allow the Viosca Knoll System to effect
deliveries at the operating pressures on downstream interstate pipelines with
which it is interconnected. The additional capacity created by such compression
allowed Viosca Knoll to transport new natural gas volumes during 1997 from the
Shell operated Southeast Tahoe and Ram-Powell fields as well as other new
deepwater projects in the area. Recently, Viosca Knoll added approximately 25
miles of parallel 20-inch pipelines to the system east of the Viosca Knoll Block
817 platform to improve deliverability from certain Main Pass producing areas
and redeliveries into the Transco pipeline at Main Pass Block 261 and the Destin
pipeline at Main Pass Block 260. We operate the Viosca Knoll System.
Prior to the closing of the offering of our senior subordinated notes,
Viosca Knoll was owned 50.0% by us and 50.0% by El Paso Energy (through a wholly
owned subsidiary). In June 1999, we acquired all of El Paso Energy's interest in
Viosca Knoll, other than a 1.0% interest, for $79.7 million, comprised of 25.0%
in cash ($19.9 million) and 75.0% in common units (2,661,870 common units based
on a price of $22.4625 per unit). At the closing of that transaction, (1) El
Paso Energy contributed its interest in Viosca Knoll to us and approximately
$33.4 million in cash to Viosca Knoll, which equaled 50.0% of the principal
amount then outstanding under Viosca Knoll's credit facility, (2) we delivered
to El Paso Energy the cash and common units discussed above and (3) as required
by our partnership agreement, the general partner contributed approximately
$604,000 to us in order to maintain its 1.0% capital account balance. Upon
consummation of the acquisition, our partnership agreement was amended to ensure
that, even though El Paso Energy beneficially owns an effective interest in us
of 34.5%, the other unitholders will still have the votes necessary to remove
the general partner and to call a meeting for such a purpose.
As a result of the acquisition, we own 99.0% of Viosca Knoll and have the
option to acquire the remaining 1.0% interest during the six-month period
commencing on the day after the first anniversary of the closing date. The
option exercise price, payable in cash, is equal to the sum of $1.6 million plus
the amount of additional distributions which would have been paid, accrued or
been in arrears had we acquired the remaining 1.0% of Viosca Knoll at the
initial closing by issuing additional common units in lieu of a cash payment of
$1.7 million.
Although certain federal and state securities laws would otherwise limit El
Paso Energy's ability to dispose of any common units held by it, El Paso Energy
would have the right on three occasions to require us to file a registration
statement covering such common units for a three-year period and to participate
in offerings made pursuant to certain other registration statements filed by us
during a ten-year period. Such registrations would be at our expense and,
generally, would allow El Paso Energy to dispose of all or any of its common
units. There can be no assurance (1) regarding how long El Paso Energy may hold
any of
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<PAGE> 59
its common units or (2) that El Paso Energy's disposition of a significant
number of common units in a short period of time would not depress the market
price of the common units.
Our unitholders of record as of January 28, 1999 ratified and approved the
transactions in a meeting held March 5, 1999 based upon the ratification,
approval and recommendation of the Board of Directors of the general partner and
a Special Committee of independent directors of the general partner and based a
fairness opinion of an independent financial advisor.
The acquisition of Viosca Knoll's interest closed on June 1, 1999.
STINGRAY SYSTEM. The Stingray System, owned 50.0% by us and 50.0% by NGPL,
is a regulated natural gas transmission system consisting of (1) approximately
361 miles of 6- to 36-inch diameter pipeline that transports natural gas from
the HIOS, West Cameron, East Cameron and Vermilion lease areas in the Gulf of
Mexico to onshore transmission systems at Holly Beach, Cameron Parish,
Louisiana, (2) approximately 12 miles of 16-inch diameter pipeline and
approximately 31 miles of 20-inch diameter pipeline, connecting the Garden Banks
Block 191 lease operated by Chevron U.S.A. Production Company and our
50.0%-owned Garden Banks Block 72 platform, respectively, to the system, and (3)
approximately 13 miles of 16-inch diameter pipeline connecting our platform at
East Cameron Block 373 to the Stingray System at East Cameron Block 338. NGPL
will continue to operate the Stingray System until we take over those
operations, probably by October 1, 1999.
HIOS SYSTEM. The HIOS System, indirectly owned 60.0% by us and 40.0% by
ANR, is a regulated natural gas transmission system consisting of approximately
204 miles of pipeline comprised of three supply laterals, the West, Central and
East Laterals, that connect to a 42-inch diameter mainline. The HIOS System
transports natural gas received from fields located in the Galveston, Garden
Banks, HIOS, West Cameron and East Breaks areas of the Gulf of Mexico to a
junction platform owned by HIOS located in West Cameron Block 167. There, it
interconnects with the UTOS system and a pipeline owned by ANR for further
transportation to points onshore. ANR operates the HIOS System. HIOS is a
subsidiary of Western Gulf, in which we own a 60.0% interest.
Prior to June 30, 1999, NGPL owned 20.0% of Western Gulf (and, thus, 20.0%
of HIOS). On June 30, 1999 we acquired NGPL's 20.0% interest in Western Gulf,
together with its 33.3% interest in UTOS and certain offshore pipeline laterals,
for total consideration of approximately $51.0 million.
UTOS SYSTEM. The UTOS System, owned 66.7% by us and 33.3% by ANR, is a
regulated natural gas transmission system consisting of approximately 30 miles
of 42-inch diameter pipeline extending from a point of interconnection with the
HIOS System at West Cameron Block 167 to the Johnson Bayou production handling
facility. The UTOS System transports natural gas from the terminus of the HIOS
System at West Cameron Block 167 to the Johnson Bayou facility, where it
interconnects with several pipelines. The UTOS System is essentially an
extension of the HIOS System, as almost all the natural gas transported through
UTOS comes from the HIOS System. UTOS also owns the Johnson Bayou facility,
which provides primarily natural gas and liquids separation and natural gas
dehydration for natural gas transported on the HIOS and UTOS systems. ANR
operates the UTOS System.
Prior to June 30, 1999, NGPL owned 33.3% of UTOS. On June 30, 1999 we
acquired NGPL's 33.3% interest in UTOS, together with its 20.0% interest in
Western Gulf and certain offshore pipeline laterals, for total consideration of
approximately $51.0 million.
NAUTILUS SYSTEM. The Nautilus System, indirectly owned 25.7% by us, 50.0%
by Tejas and 24.3% by Marathon, is a regulated natural gas transmission system
consisting of 101 miles of 30-inch pipeline running downstream from Ship Shoal
Block 207 and connecting to a natural gas production handling plant onshore
Louisiana operated by Exxon and some other facilities downstream of that plant
and effects deliveries to multiple interstate pipelines. Affiliates of Marathon
and Tejas have dedicated to the Nautilus System certain deepwater acreage
positions in the area. Marathon operates and maintains the Nautilus System and
Tejas performs financial, accounting and administrative services for Nautilus.
Nautilus is a subsidiary of Neptune, in which we own a 25.7% interest.
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POSEIDON SYSTEM. The Poseidon System, owned 36.0% by us, 36.0% by Equilon
Pipeline Company and 28.0% by a subsidiary of Marathon, is an unregulated major
new sour crude oil pipeline system that was built in response to an increased
demand for additional sour crude oil pipeline capacity in the central Gulf. The
Poseidon System consists of (1) approximately 117 miles of 16- to 20-inch
diameter pipeline extending in an easterly direction from our 50.0%-owned
platform located at Garden Banks Block 72 to our platform located at Ship Shoal
Block 332, (2) approximately 122 miles of 24-inch diameter pipeline extending in
a northerly direction from the Ship Shoal Block 332 platform to Houma, Louisiana
and (3) approximately 58 miles of 16-inch diameter pipeline extending
northwesterly from Ewing Bank Block 873 to the Texaco-operated Eugene Island
Pipeline System at Ship Shoal Block 141. In July 1998, Poseidon completed a
17-mile extension of 16-inch pipeline from Garden Banks Block 260 to South Marsh
Island Block 205. Texaco pipelines and related facilities accept oil from
Poseidon at Larose and Houma, Louisiana and redeliver it to St. James,
Louisiana, a significant market hub for batching, handling and transportation of
oil. Currently, Texaco operates the Poseidon system and has contracted with
Equilon, LLC, a newly-formed joint venture between Texaco and Shell, to operate
and perform the administrative functions related to Poseidon and the Poseidon
System. In April 1999, Texaco assigned its membership interest in Poseidon to
Equilon.
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OIL AND NATURAL GAS SUPPLY
A substantial portion of the reserves handled by our pipelines is committed
pursuant to long-term contracts, for the productive life of the relevant field.
Nonetheless, these reserves and other reserves that may become available to our
pipelines are depleting assets and, as such, will be produced over a finite
period. Each of our pipelines must access additional reserves to offset the
natural decline in production from existing connected wells or the loss of any
other production to a competitor.
As somewhat reflected by throughput for 1998, Manta Ray Offshore, Viosca
Knoll and Tarpon obtained commitments from new fields and some additional
commitments from existing fields. However, Green Canyon, Stingray, HIOS and UTOS
were not able to offset reductions in throughput associated with normal
production declines for committed reserves with throughput associated with
commitments of additional reserves. Nevertheless, we believe that there will be
sufficient reserves available to the natural gas pipelines for transportation to
maintain throughput at or near current levels for at least several years.
In addition to the production commitments from Texaco and Marathon,
Poseidon has been successful in obtaining long-term commitments of production
from several properties containing significant reserves. Poseidon has contracted
with affiliates of Exxon, Phillips Petroleum, BP Amoco, Anadarko, Newfield
Exploration, Mobil, Amerada Hess, Oryx, Sun, PennzEnergy, Enterprise Oil,
British Borneo, Occidental and us. We anticipate that Poseidon will add more
commitments as new subsalt and Deepwater fields are developed in the area which
the Poseidon System serves, but we cannot assure you any such commitment would
be made or when the production from such commitment would be initiated. However,
we do believe that there should be significant increases in reserves committed
to the Poseidon System for at least the next several years.
Tatham Offshore's Ewing Bank Block 914 #2 well was the only production
dedicated to the Ewing Bank system. In May 1997, the well was shut in due to a
mechanical problem. After approximately one year of evaluating certain remedies
to place the well on production, we decided, along with Tatham Offshore, to
abandon the well and the Ewing Bank system in May 1998.
OFFSHORE PLATFORMS AND RELATED FACILITIES
Our offshore platforms play a key role in the development of the oil and
natural gas offshore pipeline network. Platforms are used to interconnect the
offshore pipeline grid; to provide an efficient means to perform pipeline
maintenance; to locate compression, separation, production handling and other
facilities; and during the initial development phase of an oil and natural gas
property, to conduct drilling operations. In addition to numerous platforms
owned by our joint ventures, we own six strategically-located platforms in the
Gulf of Mexico, including three multi-purpose hub-platforms, Viosca Knoll 817,
Garden Banks 72 and East Cameron 373. These three platforms were specifically
designed to be used as Flextrend and Deepwater landing sites and production
handling and pipeline maintenance facilities. Further, we recently began
construction of a Moses Tension Leg Platform in connection with the development
of our Ewing Bank 958 Unit.
<TABLE>
<CAPTION>
VIOSCA GARDEN EAST SHIP SOUTH SHIP
KNOLL BANKS CAMERON SHOAL TIMBALIER SHOAL
817 72 373 332 292 331
------ ------- ------- -------- --------- -----
<S> <C> <C> <C> <C> <C> <C>
Ownership interest........ 100% 50% 100% 100% 100% 100%
In-service date........... 1995 1995 1998 1985 1984 1994
Water depth (in feet)..... 671 518 441 438 283 376
Acquired (A) or
constructed (C)......... C C C A A A
Product handling capacity:
Natural gas (MMcf per
day)................. 140 80 110 150(1) 150 --(1)
Oil and condensate (bbls
per day)............. 5,000 55,000 5,000 12,000(1) 2,500 --(1)
</TABLE>
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- ------------------
(1) Our Ship Shoal Block 331 platform is currently used as a satellite landing
area and all products transported over the platform are processed on our
Ship Shoal Block 332 platform.
VIOSCA KNOLL BLOCK 817. We constructed a multi-purpose platform located in
Viosca Knoll Block 817 in 1995. We used this platform as a base for conducting
drilling operations for oil and natural gas reserves located on the Viosca Knoll
Block 817 lease. In addition, the platform serves as a base for landing other
Deepwater production in the area, thereby generating platform access and
production handling fees for us. A 7,000 horsepower compressor was installed in
1996 on the Viosca Knoll Block 817 platform to allow the Viosca Knoll System to
effect deliveries at the operating pressures on downstream interstate pipelines
with which it is interconnected. The additional capacity created by such
compression allowed Viosca Knoll to transport new natural gas volumes during
1997 from the Shell-operated Southeast Tahoe and Ram-Powell fields as well as
other new Deepwater projects in the area. Viosca Knoll leases space on this
platform from us for the location of the new compression equipment for the
Viosca Knoll System. We own 100% of the Viosca Knoll 817 platform.
GARDEN BANKS BLOCK 72. We own a 50.0% interest in a multi-purpose platform
located in Garden Banks Block 72. This platform is located at the south end of
the Stingray System and serves as the westernmost terminus of the Poseidon
System. We also use this platform in our drilling and production operations. It
now serves as the landing site for production from our Garden Banks Block 117
lease located in an adjacent lease block.
EAST CAMERON BLOCK 373. In 1998, we placed in service a new multi-purpose
platform located in East Cameron Block 373 at a construction cost of $30.2
million. This four pile production platform with production handling facilities
is strategically located to exploit deeper water reserves in the East Cameron
and Garden Banks areas of the Gulf of Mexico and is the terminus for an
extension of the Stingray System. Kerr McGee Corporation has rights to utilize a
portion of the platform and has committed its production from multiple blocks in
the East Cameron and Garden Banks areas to be processed on this platform and
transported through the Stingray System. We own 100% of the East Cameron Block
373 platform.
SHIP SHOAL BLOCK 332. We own a 100% interest in a platform located in Ship
Shoal Block 332 which serves as a junction platform for natural gas pipelines in
the Manta Ray Offshore System as well as an eastern junction for the Poseidon
System.
SOUTH TIMBALIER BLOCK 292. The South Timbalier Block 292 platform is a
100%-owned facility located at the easternmost terminus of the Manta Ray
Offshore System and serves as a landing site for natural gas production in that
area.
SHIP SHOAL BLOCK 331. In August 1998, in connection with El Paso Energy's
acquisition of our general partner, we acquired the Ship Shoal Block 331
platform, a production facility located 75 miles off the coast of Louisiana in
approximately 370 feet of water. Pogo Producing Company has certain rights to
utilize the platform pursuant to a production handling and use of space
agreement. We own 100% of the Ship Shoal Block 331 platform.
OTHER FACILITIES. Through our 50.0% ownership interest in West Cameron
Dehy, we own an interest in certain dehydration facilities located at the
northern terminus of the Stingray System, onshore Louisiana.
MAINTENANCE
Each of our pipelines requires regular and thorough maintenance. The
interior of pipelines is maintained through the regular "pigging" of the lines.
Pigging involves propelling a large spherical object through the line which
collects, or pushes, any condensate and other liquids on the walls or at the
bottom of the pipeline through the line and out the far end. More sophisticated
pigging devices include those with scrapers, brushes and x-ray devices; however,
such pigging devices are usually deployed only on an as needed basis. Corrosion
inhibitors are also injected into all of the systems through the flow stream on
a continuous basis. To prevent external corrosion of the pipe, sacrificial
anodes are fastened to the pipeline at
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prescribed intervals, providing protection from sea water. Our platforms are
painted to the waterline every three to five years to prevent atmospheric
corrosion. Sacrificial anodes are also fastened to the platform legs below the
waterline to prevent corrosion. A sacrificial anode is a zinc aluminum alloy
fixture that is attached to the exterior of a steel object to attract the
corrosive reaction that occurs between steel and saltwater to the fixture
itself, thus protecting the steel object from corrosion. Remotely operated
vehicles or divers inspect our platforms below the waterline, usually every five
years.
The Stingray, HIOS, Viosca Knoll, Manta Ray Offshore and Poseidon systems
include platforms that are manned on a continuous basis. The personnel onboard
those platforms are responsible for site maintenance, operations of the
facilities on the platform, measurement of the natural gas stream at the source
of production and corrosion control (pig launching and inhibitor injection).
COMPETITION
Each of our natural gas pipelines is located in or near natural gas
production areas that are served by other pipelines. As a result, each of our
natural gas pipeline systems faces competition from both regulated and
unregulated systems. Some of these competitors are not subject to the same level
of rate and service regulation as, and may have a lower cost structure than, our
natural gas pipelines. Other competing pipelines, such as long-haul
transporters, have rate design alternatives unavailable to our natural gas
pipelines. Consequently, those competing pipelines may be able to provide
service on more flexible terms and at rates significantly below the rates
offered by our natural gas pipelines. The principal competitors of our regulated
pipeline systems are Shell, Texaco, ANR, Transco, Trunkline Gas Co., Texas
Eastern, Columbia Gas Transmission and their affiliates.
The Poseidon System was built as a result of our belief that additional
sour crude oil capacity was required to transport new subsalt and Deepwater oil
production to shore. Poseidon's principal competitors for additional crude oil
production are Equilon (a 36.0% owner of Poseidon), which owns the Texaco-
operated Eugene Island Pipeline and the Shell-operated Amberjack systems that
compete with Poseidon and oil pipelines built, owned and operated by producers
to handle their own production and, as capacity is available, production for
others. Our pipelines compete for new production with these and other
competitors on the basis of geographic proximity to the production, cost of
connection, available capacity, transportation rates and access to onshore
markets. In addition, the ability of the pipelines to access future reserves
will be subject to the ability of the pipelines or the producers to fund the
anticipated significant capital expenditures required to connect the new
production.
CUSTOMERS AND CONTRACTS
GENERAL. The rates we charge for our services are dependent on (1) whether
the relevant pipeline, platform, production handling, dehydration or other
facility is regulated or unregulated -- established maximum rate or fully
negotiated rate, (2) the quality of the service required by the customer --
interruptible or firm, and (3) the amount and term of the reserve commitment by
the customer. A significant portion of our arrangements involve life-of-reserve
commitments with both firm and interruptible components. Generally, we receive a
price per unit (Mcf of natural gas or barrel of oil or water) handled. And
depending on transaction specific factors, for firm arrangements, we often also
receive a monthly fixed fee which is paid by the customer regardless of the
level of throughput, except under individually specified circumstances.
The Poseidon System receives crude oil from committed properties under
buy/sell agreements, often surviving for the life of the property. The same
factors described above affect the contract amounts and other terms.
PRINCIPAL CUSTOMERS. See our consolidated financial statements and notes
thereto located elsewhere in this prospectus for certain information regarding
our principal transportation customers.
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<PAGE> 64
NATURAL GAS AND OIL PROPERTIES ASSOCIATED WITH INFRASTRUCTURE OPPORTUNITIES
In areas we serve or desire to serve, we occasionally pursue opportunistic
investments in pipelines, platforms, production handling facilities and other
infrastructure assets, as well as selective investment in oil and natural gas
properties. By providing infrastructure to previously unserved geographic
regions, we try to accelerate the development of oil and natural gas properties
in that area. The ability to access common facilities allows producers to share
the high fixed costs associated with infrastructure and, in certain
circumstances, results in the economic development of otherwise marginal
reserves and in an increase in the total reserves produced from that region.
Further, we may invest in oil and natural gas properties when it augments the
utilization of our existing assets or leads to a strategic infrastructure
opportunity. We use our pipelines and other facilities to process, gather and
transport the oil and gas produced from oil and natural gas properties in which
we have invested. We sell the majority of that production to Offshore Gas
Marketing, Inc., our affiliate and an indirectly owned subsidiary of El Paso
Energy.
Currently, we own interests in three material producing and one
non-producing oil and natural gas properties located primarily in waters
offshore Louisiana. We acquired our Viosca Knoll 817, Garden Banks 72 and Garden
Banks 117 properties from a financially distressed producer in 1995 for
approximately $30.0 million. We developed that property in connection with the
construction of our Viosca Knoll System, which at the time was a 50/50 joint
venture with Tenneco Inc. As operator, we concluded development and placed eight
wells on production on our Viosca Knoll 817 property. Currently, these wells
have gross aggregate average production of approximately 35.0 MMcf of natural
gas per day. In addition to developing an oil and natural gas property and
constructing one of the few natural gas pipelines in an emerging production
region in the Flextrend area offshore Louisiana and Mississippi, we successfully
constructed, marketed and operated our first multi-purpose hub-platform, which
has been used as a landing and processing site for Flextrend and Deepwater
properties in the area, as well as a pipeline maintenance facility and, during
the development phase, a drilling facility. Recently, due to demand, we
completed two expansion projects that more than doubled the throughput capacity
of our Viosca Knoll System to 1.0 Bcf of natural gas per day.
We completed the joint development of our Garden Banks 72 and 117
properties in 1997. That development project included a multi-purpose
hub-platform located on Garden Banks 72, which has been used:
- - to drill five wells on Garden Banks 72;
- - to tie-back the Garden Banks 117 #1 and #2 wells;
- - to locate separating and processing facilities; and
- - as a junction landing and maintenance site for our Poseidon and Stingray
systems.
The Garden Banks 72 and 117 properties contain seven wells, which are currently
producing a gross aggregate average of approximately 6.2 MMcf of natural gas per
day and 2,400 barrels of oil per day.
We purchased the Ewing Bank 958 Unit in October 1998 from a wholly owned,
indirect subsidiary of El Paso Energy. Our current plan of development
contemplates the construction of a gathering system and a Moses Tension Leg
Platform. This platform, which may be used in up to 6,000 feet of water, will
have production handling facilities with a throughput design capacity of 55.0
MMcf of natural gas per day and 25,000 barrels of oil per day. Accordingly, we
recently began construction of the Moses Tension Leg Platform, which will be
designed to support a deck and topside facilities weighing up to 6,000 short
tons and process 25,000 barrels of oil per day and 55.0 MMcf of natural gas per
day. In addition to the initial discovery well drilled in 1994 and the two
delineation wells drilled in 1994 and 1998, the Ewing Bank 958 Unit development
program could require drilling up to five additional wells, depending on the
level of actual production and other factors. To date there has been no
production from the Ewing Bank 958 Unit.
The following is a description of our currently held properties.
VIOSCA KNOLL BLOCK 817. Viosca Knoll Block 817 is a producing property that
is comprised of 5,760 gross and net acres located 40 miles off the coast of
Louisiana in approximately 670 feet of water.
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<PAGE> 65
Initially, we acquired a 75.0% working interest in Viosca Knoll Block 817 from
the sea-floor through the stratigraphic equivalent of the base of the Tex X-6
Sand, subject to certain reversionary rights. In connection with El Paso
Energy's acquisition of our general partner, those reversionary rights were
relinquished and we acquired the remaining 25.0% working interest in Viosca
Knoll Block 817. This working interest is subject to a production payment that
entitles the holders in the aggregate to 25.0% of the proceeds from the
production attributable to this working interest (after deducting all leasehold
operating expenses, including platform access and production handling fees)
until the holders have received the aggregate sum of $16.0 million. At December
31, 1998, the unpaid portion of the production payment obligation totaled $11.1
million.
As operator, we concluded a drilling program and placed eight wells on
production on Viosca Knoll Block 817. We do not anticipate drilling any more
wells or having any other major expenditures with respect to this property
except for the possible recompletion of certain existing wells. From inception
of production in December 1995 through December 31, 1998, the Viosca Knoll
property has produced 42,661 MMcf of natural gas and 67.6 Mbbls of oil, net to
our interest. During June 1999, Viosca Knoll Block 817 produced an aggregate of
approximately 35.0 MMcf of natural gas per day. Natural gas production from
Viosca Knoll Block 817 is dedicated to us for gathering through the Viosca Knoll
System and oil production is transported through a Shell-operated system. Our
recent expansion of the Viosca Knoll System eliminated downstream pipeline
capacity constraints on that system and is expected to allow us to produce
Viosca Knoll Block 817 at optimal rates in the future.
GARDEN BANKS BLOCK 72. Garden Banks Block 72 covers 5,760 gross (2,880 net)
acres and is located 120 miles off the coast of Louisiana in approximately 550
feet of water. In 1995, we acquired a 50.0% working interest (approximately
40.2% net revenue interest) in Garden Banks Block 72, subject to certain
reversionary interests which were relinquished in connection with El Paso
Energy's acquisition of our general partner. A subsidiary of Occidental
Petroleum Company owns the remaining 50.0% working interest in Garden Banks
Block 72.
Since May 1996, we have placed five wells on production at Garden Banks
Block 72. We do not anticipate drilling any more wells or having any other major
expenditures with respect to this property except for the possible recompletion
of certain existing wells. Production at Garden Banks Block 72 totaled 2,979
MMcf of natural gas and 902.1 Mbbls of oil, net to our interest, from the
inception of production in May 1996 through December 31, 1998. During June 1999,
the five wells produced a total of approximately 1.2 Mbbls of oil and 3.6 MMcf
of natural gas per day. Natural gas production from Garden Banks Block 72 is
being transported through the Stingray System and the oil production is
delivered to the Poseidon System.
GARDEN BANKS BLOCK 117. Garden Banks Block 117 covers 5,760 gross (2,880
net) acres adjacent to Garden Banks Block 72 and is located in approximately
1,000 feet of water. In 1995, we acquired a 50.0% working interest
(approximately 37.5% net revenue interest) in Garden Banks Block 117, subject to
certain reversionary interests which were relinquished in connection with El
Paso Energy's acquisition of our general partner. Midcon Exploration owns the
remaining 50.0% working interest in Garden Banks Block 117.
In July 1996 and May 1997, we completed and initiated production from the
Garden Banks Block 117 #1 and #2 wells, respectively. During June 1999, these
wells produced a total of approximately 1.2 Mbbls of oil and 2.6 MMcf of natural
gas per day. Since inception of production through December 31, 1998, Garden
Banks Block 117 produced 1,327 MMcf of natural gas and 761.8 Mbbls of oil, net
to our interest. We do not anticipate drilling any more wells on this property
except for a recompletion of the Garden Banks 117 #2 well. Natural gas
production from Garden Banks Block 117 is transported on the Stingray system and
oil production is delivered to the Poseidon System.
WEST DELTA BLOCK 35. In connection with El Paso Energy's acquisition of our
general partner, we acquired a 38.0% non-operating working interest in West
Delta Block 35, a producing field located 10 miles off the coast of Louisiana in
approximately 60 feet of water covering 4,985 gross (1,894 net) acres. The West
Delta Block 35 field commenced production in July 1993. Since August 14, 1998
through
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<PAGE> 66
December 31, 1998, West Delta Block 35 produced 272 MMcf of natural gas and 2.2
Mbbls of oil, net to our interest.
EWING BANK 958 UNIT. We purchased the Ewing Bank 958 Unit in October 1998
from a wholly owned, indirect subsidiary of El Paso Energy. Our current plan of
development contemplates the construction of a gathering system and a Moses
Tension Leg Platform. This platform, which may be used in up to 6,000 feet of
water, will have production handling facilities with a throughput design
capacity of 55.0 MMcf of natural gas per day and 25,000 barrels of oil per day.
Accordingly, we recently began construction of the Moses Tension Leg Platform,
which will be designed to support a deck and topside facilities weighing up to
6,000 short tons and process 25,000 barrels of oil per day and 55.0 MMcf of
natural gas per day. In addition to the initial discovery well drilled in 1994
and the two delineation wells drilled in 1994 and 1998, the Ewing Bank 958 Unit
development program could require drilling up to five additional wells,
depending on the level of actual production and other factors. To date there has
been no production from the Ewing Bank 958 Unit.
COMPETITION
The oil and natural gas industry is intensely competitive. In all segments
of our business, we compete with a substantial number of other companies,
including some with larger technical staffs and greater financial and
operational resources. Many such competitors are more vertically integrated than
we are -- that is, they not only acquire, explore for, develop, produce, gather
and transport oil and natural gas reserves, but also carry on refining
operations, generate electricity and market refined products. As a result, many
of our competitors may be better positioned to acquire and exploit prospects,
hire personnel, market production and withstand the effects of general and/or
industry-specific economic changes. We also face potential competition from
companies not previously active in oil and natural gas who may choose to acquire
reserves to establish a firm supply or simply as an investment. In addition, the
oil and natural gas industry competes with other industries supplying energy and
fuel to industrial, commercial and individual consumers.
PRODUCTION, UNIT PRICES AND COSTS
The following table sets forth certain information regarding the production
volumes of, average unit prices received for and average production costs for
our sale of oil and natural gas for the periods indicated:
<TABLE>
<CAPTION>
SIX SIX
OIL (BARRELS) MONTHS NATURAL GAS (MMCF) MONTHS
YEAR ENDED DECEMBER 31, ENDED YEAR ENDED DECEMBER 31, ENDED
------------------------------ JUNE 30, --------------------------- JUNE 30,
1996 1997 1998 1999 1996 1997 1998 1999
-------- -------- -------- -------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Net production(1)............ 393,000 801,000 540,000 193,000 15,730 19,792 11,324 6,877
Average sales price(1)....... $ 21.76 $ 20.61 $ 15.69 $ 12.69 $ 2.37 $ 2.08 $ 2.01 $ 1.83
Average production
costs(2)................... $ 1.59 $ 1.98 $ 3.04 $ 2.35 $ 0.27 $ 0.33 $ 0.51 $ 0.39
</TABLE>
- ------------------
(1) The information regarding production and unit prices excludes overriding
royalty interests.
(2) The components of production costs may vary substantially among wells
depending on the methods of recovery employed and other factors, but
generally include third party transportation expenses, maintenance and
repair, labor and utilities costs.
The relationship between average sales prices and average production costs
depicted by the table above is not necessarily indicative of future expected
results of our operations.
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<PAGE> 67
OIL AND NATURAL GAS RESERVES
The following estimates of our total proved developed and proved
undeveloped reserves of oil and natural gas as of December 31, 1998 have been
made by Netherland, Sewell & Associates, Inc., an independent petroleum
engineering consulting firm.
<TABLE>
<CAPTION>
OIL (BARRELS) NATURAL GAS (MCF)
------------- ------------------------
PROVED PROVED PROVED
DEVELOPED DEVELOPED UNDEVELOPED
------------- ---------- -----------
<S> <C> <C> <C>
Viosca Knoll Block 817....................... 80,592 21,700,344 2,452,000
Garden Banks Block 72........................ 495,437 2,306,934 --
Garden Banks Block 117....................... 991,888 1,645,839 --
West Delta Block 35.......................... 9,599 779,179 --
--------- ---------- ---------
Total.............................. 1,577,516 26,432,296 2,452,000
========= ========== =========
</TABLE>
In general, estimates of economically recoverable oil and natural gas
reserves and of the future net revenue therefrom are based upon a number of
variable factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices, future operating costs
and future plugging and abandonment costs, all of which may vary considerably
from actual results. All such estimates are to some degree speculative, and
classifications of reserves are only attempts to define the degree of
speculation involved. For these reasons, estimates of the economically
recoverable oil and natural gas reserves attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of the future net revenue expected therefrom, prepared by different
engineers or by the same engineers at different sites, may vary substantially.
The meaningfulness of such estimates is highly dependent upon the assumptions
upon which they are based.
Furthermore, production from Garden Banks Block 117, Garden Banks Block 72
and Viosca Knoll Block 817 was initiated in July 1996, May 1996 and December
1995, respectively, and, accordingly, estimates of future production are based
on this limited history. Estimates with respect to proved undeveloped reserves
that may be developed and produced in the future are often based upon volumetric
calculations and upon analogy to similar types of reserves rather than upon
actual production history. Estimates based on these methods are generally less
reliable than those based on actual production history. Subsequent evaluation of
the same reserves based upon production history will result in variations, which
may be substantial, in the estimated reserves. A significant portion of our
reserves is based upon volumetric calculations.
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<PAGE> 68
The following table sets forth, as of December 31, 1998, the estimated
future net cash flows and the present value of estimated future net cash flows,
discounted at 10.0% per annum, from the production and sale of the proved
developed and undeveloped reserves attributable to our interest in oil and
natural gas properties as of such date, as determined by Netherland, Sewell in
accordance with the requirements of applicable accounting standards, before
income taxes.
<TABLE>
<CAPTION>
DECEMBER 31, 1998
---------------------------------
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
--------- ----------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Undiscounted estimated future net cash flows from proved
reserves before income taxes(1)........................... $28,457 $864 $29,321
Present value of estimated future net cash flows from proved
reserves before income taxes, discounted at 10.0%(2)...... $26,131 $541 $26,672
</TABLE>
- ------------------------------------
(1) The average oil and natural gas prices, as adjusted by lease for gravity and
Btu content, regional posted price differences and oil and natural gas price
hedges in place and weighted by production over the life of the proved
reserves, used in the calculation of estimated future net cash flows at
December 31, 1998 are $9.80 per barrel of oil and $1.53 per Mcf of natural
gas.
(2) We estimate that, if all other factors (including the estimated quantities
of economically recoverable reserves) were held constant, a $1.00 per barrel
change in oil prices from that used in the Netherland, Sewell reserve report
would change the December 31, 1998 present value of future net cash flows
from proved reserves by approximately $1.3 million or a $0.10 per Mcf change
in gas prices from that used in the Netherland, Sewell reserve report would
change such present value by approximately $3.1 million.
In accordance with applicable requirements of the SEC, the estimated
discounted future net revenue from estimated proved reserves are based on prices
and costs at fiscal year end unless future prices or costs are contractually
determined at such date. Actual future prices and costs may be materially higher
or lower. Actual future net revenue also will be affected by factors such as
actual production, supply and demand for oil and natural gas, curtailments or
increases in consumption by natural gas purchasers, changes in governmental
regulations or taxation and the impact of inflation on costs.
In accordance with the methodology approved by the SEC, specific
assumptions were applied in the computation of the reserve evaluation estimates.
Under this methodology, future net cash flows are determined by reducing
estimated future gross cash flows to us for oil and natural gas sales by the
estimated costs to develop and produce the underlying reserves, including future
capital expenditures, operating costs, transportation costs, royalty and
overriding royalty burdens, production payments and net profits interest expense
on certain of our properties.
Future net cash flows were discounted at 10.0% per annum to arrive at
discounted future net cash flows. The 10.0% discount factor used to calculate
present value is required by the SEC, but such rate is not necessarily the most
appropriate discount rate. Present value of future net cash flows, irrespective
of the discount rate used, is materially affected by assumptions as to timing of
future oil and natural gas prices and production, which may prove to be
inaccurate. In addition, the calculations of estimated net revenue do not take
into account the effect of certain cash outlays, including, among other things,
general and administrative costs, interest expense and partner distributions.
The present value of future net cash flows shown above should not be construed
as the current market value as of December 31, 1998, or any prior date, of the
estimated oil and natural gas reserves attributable to our properties.
ACREAGE
The following table sets forth our developed and undeveloped oil and
natural gas acreage as of December 31, 1998. Undeveloped acreage is considered
to be those lease acres on which wells have not been drilled or completed to a
point that would permit the production of commercial quantities of oil and
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<PAGE> 69
natural gas, regardless of whether or not such acreage contains proved reserves.
Gross acres in the following table refer to the number of acres in which we own
directly a working interest. The number of net acres is our fractional ownership
of working interests in the gross acres.
<TABLE>
<CAPTION>
GROSS NET
------ ------
<S> <C> <C>
Developed acreage........................................... 6,792 5,416
Undeveloped acreage......................................... 59,577 48,862
------ ------
Total acreage..................................... 66,369 54,278
====== ======
</TABLE>
OIL AND NATURAL GAS DRILLING ACTIVITY
The following table sets forth the gross and net number of productive, dry
and total exploratory wells and development wells that we have drilled in each
of the respective years:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Exploratory
Natural gas............................... -- -- -- -- -- --
Oil....................................... -- -- -- -- 1.00 0.50
Dry....................................... -- -- -- -- -- --
Total............................. -- -- -- -- 1.00 0.50
==== ==== ==== ==== ===== ====
Development
Natural gas............................... -- -- -- -- 7.00 5.00
Oil....................................... 1.00 1.00 -- -- 5.00 2.75
Dry....................................... -- -- -- -- 3.00 1.75
---- ---- ---- ---- ----- ----
Total............................. 1.00 1.00 -- -- 15.00 9.50
==== ==== ==== ==== ===== ====
</TABLE>
The following table sets forth our ownership in producing wells at December
31, 1998:
<TABLE>
<CAPTION>
GROSS NET
----- -----
<S> <C> <C>
Natural gas................................................. 10.00 8.26
Oil......................................................... 6.00 3.00
----- -----
Total............................................. 16.00 11.26
===== =====
</TABLE>
MAJOR ENCUMBRANCES
Substantially all of the operating assets in which we own an interest are
owned by our subsidiaries or joint ventures. Substantially all of our assets
(primarily our interests in our subsidiaries) and our subsidiaries' assets are
pledged as collateral to secure obligations under our credit facility. In
addition, certain of our joint ventures currently have, and others are expected
to have, credit facilities pursuant to which substantially all of such joint
ventures' assets are or would be pledged.
REGULATION
The oil and natural gas industry is extensively regulated by federal and
state authorities in the U.S. Numerous departments and agencies, both federal
and state, have issued rules and regulations binding on the oil and natural gas
industry and its individual members, some of which carry substantial penalties
for the failure to comply. Legislation affecting the oil and natural gas
industry is under constant review and statutes are constantly being adopted,
expanded or amended. The regulatory burden on the oil and natural gas industry
increases its cost of doing business.
GENERAL. The design, construction, operation and maintenance of our natural
gas pipelines and of certain of their natural gas transmission facilities are
subject to regulation by the Department of
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Transportation under the Natural Gas Pipeline Safety Act of 1968 as amended (the
"NGPSA"). Operations in offshore federal waters are regulated by the Department
of Interior and the FERC. Under the Outer Continental Shelf Lands Act (the
"OCSLA") as implemented by the FERC, pipelines that transport natural gas across
the OCS must offer nondiscriminatory transportation of natural gas.
Substantially all of the pipeline network owned by our pipelines is located in
federal waters in the Gulf of Mexico, and the related rights-of-way were granted
by the federal government, the agencies of which oversee such pipeline
operations. Federal rights-of-way require compliance with detailed federal
regulations and orders which regulate such operations.
Poseidon is subject to regulation under the Hazardous Liquid Pipeline
Safety Act ("HLPSA"). In addition, under the OCSLA, as implemented by the FERC,
pipelines that transport crude oil across the OCS must offer "equal access" to
other potential shippers of crude. The Poseidon System is located in federal
waters in the Gulf of Mexico, and its right-of-way was granted by the federal
government. Therefore, the FERC may assert that it has jurisdiction to compel
Poseidon to grant access under the OCSLA to other shippers of crude oil upon the
satisfaction of certain conditions and to apportion the capacity of the line
among owner and non-owner shippers.
RATES. Each of our regulated pipelines (the Nautilus, Stingray, HIOS and
UTOS systems) is classified as a "natural gas company" by the NGA. Consequently,
the FERC has jurisdiction over these regulated pipelines with respect to
transportation of natural gas, rates and charges, construction of new
facilities, extension or abandonment of service and facilities, accounts and
records, depreciation and amortization policies and certain other matters. In
addition, these regulated pipelines hold certificates of public convenience and
necessity issued by the FERC authorizing their facilities, activities and
services.
Under the terms of the regulated pipelines' tariffs on file at the FERC,
the regulated pipelines may not charge or collect more than the maximum rates on
file with the FERC. FERC regulations permit natural gas pipelines to charge
maximum rates that generally allow pipelines the opportunity to (1) recover
operating expenses, (2) recover the pipeline's undepreciated investment in
property, plant and equipment ("rate base") and (3) receive an overall allowed
rate of return on the pipeline's rate base. We believe that even after the rate
base of any regulated pipeline is substantially depleted, the FERC will allow
such regulated pipeline to recover a reasonable return, whether through a
management fee or otherwise.
Each of the Nautilus, Stingray, HIOS and UTOS systems is currently
operating under agreements with their respective customers that provide for
rates that have been approved by the FERC.
On March 13, 1997, the FERC issued an order declaring Tarpon's facilities
exempt from NGA regulation under the gathering exception, thereby terminating
Tarpon's status as a "natural gas company" under the NGA. Tarpon has agreed,
however, to continue service for shippers that have not executed replacement
contracts on the terms and conditions, and at the rate reflected in, its last
effective regulated tariff for two years from the date of the order. None of the
Green Canyon, Ewing Bank, Manta Ray Offshore or Viosca Knoll systems is
currently, nor do we expect East Breaks to be, considered a "natural gas
company" under the NGA. Consequently, these companies are not subject to
extensive FERC regulation under the NGA or the Natural Gas Policy Act of 1978,
as amended (the "NGPA"), and are thus allowed to negotiate the rates and terms
of service with their respective shippers, subject to the "equal access"
requirements of the OCSLA.
The FERC has asserted its NGA rate jurisdiction over services performed
through gathering facilities owned by a natural gas company (as defined in the
NGA) when such services were performed "in connection with" transportation
services provided by such natural gas company. Whether, and to what extent, the
FERC should exercise any NGA rate jurisdiction it may be found to have over
gathering facilities owned either by natural gas companies or affiliates thereof
is subject to case-by-case review by the FERC. Based on current FERC policy and
precedent, we do not anticipate that the FERC will assert or exercise any NGA
rate jurisdiction over the Green Canyon, Ewing Bank, Manta Ray Offshore, Viosca
Knoll or East Breaks systems, so long as the services provided through such
lines are not performed "in connection with" transportation services performed
through any of the regulated pipelines.
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The FERC has generally disclaimed jurisdiction to set rates for oil
pipelines in the OCS under the Interstate Commerce Act. As a result, Poseidon,
as operator of the Poseidon system, has not filed tariffs with the FERC for the
Poseidon system.
PRODUCTION AND DEVELOPMENT. Our production and development operations are
subject to regulation at the federal and state levels. Such regulation includes
requiring permits for the drilling of wells and maintaining bonds and insurance
requirements in order to drill or operate wells, and regulating the location of
wells, the method of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilled and the plugging and abandoning of
wells. Our production and development operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units, the density of wells that may be
drilled, the levels of production, and the unitization or pooling of oil and
natural gas properties.
We presently have interests in or rights to offshore leases located in
federal waters. Federal leases are administered by the MMS. Individuals and
entities must qualify with the MMS prior to owning and operating any leasehold
or right-of-way interest in federal waters. Such qualification with the MMS
generally involves filing certain documents with the MMS and obtaining an
area-wide performance bond and, in some cases, supplemental bonds representing
security deemed necessary by the MMS in excess of the area-wide bond
requirements for facility abandonment and site clearance costs.
OPERATIONAL HAZARDS AND INSURANCE
Pipelines, platforms and other offshore assets may experience damage as a
result of an accident or other natural disaster, especially in the deeper water
regions. In addition, our production and development operations are subject to
the usual hazards incident to the drilling and production of natural gas and
crude oil, such as blowouts, cratering, explosions, uncontrollable flows of oil,
natural gas or well fluids, fires, pollution, releases of toxic gas and other
environmental hazards and risks. These hazards can cause personal injury and
loss of life, severe damage to and destruction of property and equipment,
pollution or environmental damages and suspension of operations. To mitigate the
impact of repair costs associated with such an accident or disaster, we maintain
insurance of various types that we consider to be adequate to cover our
operations. In our opinion, this insurance provides reasonable coverage for all
of our assets except for our 50.0% interest in the assets of Stingray, for which
insurance providing reasonable coverage is carried at the Stingray level. The
insurance package is subject to deductibles that we consider reasonable and not
excessive. Our insurance does not cover every potential risk associated with
operating pipelines or the drilling and production of oil and natural gas.
Consistent with insurance coverage generally available to the industry, our
insurance policies do not provide coverage for losses or liabilities relating to
pollution, except for sudden and accidental occurrences. We do, however, have
certificates of financial responsibility of not less than $35.0 million per
offshore facility and/or lease.
The occurrence of a significant event not fully insured or indemnified
against, or the failure of a party to meet its indemnification obligations,
could materially and adversely affect our operations and financial condition. We
believe that we are adequately insured for public liability and property damage
to others with respect to its operations. However, we can give no assurance that
we will be able to maintain adequate insurance in the future at rates we
consider reasonable.
INDUSTRY CONDITIONS
Profitability and cash flow in the oil and natural gas industry largely
depend on the market prices of oil and natural gas, which historically have been
seasonal, cyclical, volatile and driven by general economic developments,
governmental regulations and many other factors, including weather and political
conditions. Commodity prices for hydrocarbons were very volatile in 1998 and
continue to be in 1999, including some significant declines. These commodity
prices also declined dramatically from 1981 until the mid-1980's and increased
noticeably from the mid-1980's through the early 1990's.
Supply and demand conditions and regulatory factors have been the primary
contributors to this oil and natural gas price volatility as well as a related
restructuring of certain segments of the energy industry.
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Increases in worldwide oil production capability and decreases in energy
consumption have brought about substantial surpluses in oil supplies in recent
years. This, in turn, has resulted in substantial domestic competition between
oil and natural gas for end-use markets. Changes in government regulations
relating to the production, transportation and marketing of natural gas have
also resulted in significant changes in the historical marketing patterns of the
natural gas industry. Generally, these changes have resulted in the abandonment
by many pipelines of long-term contracts for the purchase of natural gas, the
development by natural gas producers of their own marketing programs to take
advantage of new regulations requiring pipelines to transport natural gas for
regulated fees, and the emergence of various types of marketing companies and
other aggregators of natural gas supplies.
As a result of the recent steep decline in energy commodity prices,
internal and external sources of cash have become constrained, and accordingly,
some industry participants have reduced offshore exploration and development
budgets. The future direction of these commodity prices is uncertain, as are the
long-term effects on the industry.
ENVIRONMENTAL
GENERAL. Our operations are subject to extensive federal, state and local
statutory and regulatory requirements relating to environmental affairs, health
and safety, waste management and chemical products. In recent years, these
requirements have become increasingly stringent and in certain circumstances,
they impose "strict liability" on a company, rendering it liable for
environmental damage without regard to negligence or fault on the part of such
company. To our knowledge, our operations are in substantial compliance, and are
expected to continue to comply in all material respects, with applicable
environmental laws, regulations and ordinances.
It is possible, however, that future developments, such as stricter
environmental laws, regulations or enforcement policies could affect the
handling, manufacture, use, emission or disposal of substances or wastes by us
or our pipelines. In addition, some risk of environmental costs and liabilities
is inherent in our operations and products as it is with other companies engaged
in similar or related businesses, and there can be no assurance that we will not
incur material costs and liabilities, including substantial fines and criminal
sanctions for violation of environmental laws and regulations. Furthermore, we
will likely be required to increase our expenditures during the next several
years to comply with higher industry and regulatory safety standards. However,
such expenditures cannot be accurately estimated at this time.
PIPELINES. In addition to the NGA, the NGPA and the OCSLA, several federal
and state statutes and regulations may pertain specifically to the operations of
our pipelines. The Hazardous Materials Transportation Act, 49 U.S.C. sec. 5101
et seq., as amended, regulates materials capable of posing an unreasonable risk
to health, safety and property when transported in commerce. The NGPSA and the
HLPSA authorize the development and enforcement of regulations governing
pipeline transportation of natural gas and hazardous liquids. Although federal
jurisdiction is exclusive over regulated pipelines, the statutes allow states to
impose additional requirements for intrastate lines if compatible with federal
programs. Both Texas and Louisiana have developed regulatory programs that
parallel the federal program for the transportation of natural gas by pipelines.
SOLID WASTE. The operations of our pipelines may generate or transport both
hazardous and nonhazardous solid wastes that are subject to the requirements of
the federal Resource Conservation and Recovery Act ("RCRA"), as amended, 42
U.S.C. sec. 6901 et. seq., and its regulations, and comparable state statutes
and regulations. Further, it is possible that some wastes that are currently
classified as nonhazardous, via exemption or otherwise, perhaps including wastes
currently generated during pipeline operations, may, in the future, be
designated as "hazardous wastes," which would then be subject to more rigorous
and costly treatment, storage, transportation and disposal requirements. Such
changes in the regulations may result in additional expenditures or operating
expenses by Leviathan. On August 8, 1998, the Environmental Protection Agency
("EPA") added four petroleum refining wastes to the list of RCRA hazardous
wastes. While the full impact of the rule has yet to be determined, the rule
may, as of February 1999, impose increased expenditures and operating expenses
on us or our pipelines, which may take on
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increased obligations relating to the treatment, storage, transportation and
disposal of certain petroleum refining wastes that previously were not regulated
as hazardous waste.
HAZARDOUS SUBSTANCES. The Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), 42 U.S.C. sec. 9601 et. seq., and
comparable state statutes, also known as "Superfund" laws, impose liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that cause or contribute to the release of a "hazardous
substance" into the environment. These persons include the current owner or
operator of a site, the past owner or operator of a site, and companies that
transport, dispose of, or arrange for the disposal of the hazardous substances
found at the site. CERCLA also authorizes the EPA or state agency, and in some
cases, third parties, to take actions in response to threats to the public
health or the environment and to seek to recover from the responsible classes of
persons the costs they incur. Despite the "petroleum exclusion" of Section
101(14) that currently encompasses natural gas, we may nonetheless generate or
transport "hazardous substances" within the meaning of CERCLA, or comparable
state statutes, in the course of our ordinary operations. And, certain petroleum
refining wastes that previously were not regulated as hazardous waste may now
fall within the definition of CERCLA hazardous substances. Thus, we may be
responsible under CERCLA or the state equivalents for all or part of the costs
required to cleanup sites where a release of a hazardous substance has occurred.
AIR. Our operations may be subject to the Clean Air Act ("CAA"), 42 U.S.C.
sec. 7401-7642, and comparable state statutes. The 1990 CAA amendments and
accompanying regulations, state or federal, may impose certain pollution control
requirements with respect to air emissions from operations, particularly in
instances where a company constructs a new facility or modifies an existing
facility. We may also be required to incur certain capital expenditures in the
next several years for air pollution control equipment in connection with
maintaining or obtaining operating permits and approvals addressing other air
emission-related issues. However, we do not believe our operations will be
materially adversely affected by any such requirements.
WATER. The Federal Water Pollution Control Act ("FWPCA") or Clean Water
Act, 33 U.S.C. sec. 1311 et. seq., imposes strict controls against the
unauthorized discharge of produced waters and other oil and natural gas wastes
into navigable waters. The FWPCA provides for civil and criminal penalties for
any unauthorized discharges of oil and other hazardous substances in reportable
quantities, and, along with the Oil Pollution Act of 1990 ("OPA"), 33 U.S.C.
sec.sec. 2701-2761, imposes substantial potential liability for the costs of
removal, remediation and damages. Similarly, the OPA imposes liability for the
discharge of oil into or upon navigable waters or adjoining shorelines. Among
other things, the OPA raises liability limits, narrows defenses to liability and
provides more instances in which a responsible party is subject to unlimited
liability. One provision of the OPA requires that offshore facilities establish
and maintain evidence of financial responsibility of up to $35.0 million or any
amount up to $150.0 million if the EPA determines that a greater amount is
justified based on the relative operational, environmental, human health and
other risks posed by the quantity or quality of the oil involved. State laws for
the control of water pollution also provide varying civil and criminal penalties
and liabilities in the case of an unauthorized discharge of petroleum, its
derivatives or other hazardous substances into state waters. Further, the
Coastal Zone Management Act ("CZMA"), 16 U.S.C. sec.sec. 1451-1464, authorizes
state implementation and development of programs containing management measures
for the control of nonpoint source pollution to restore and protect coastal
waters.
ENDANGERED SPECIES. The Endangered Species Act ("ESA"), 7 U.S.C. sec. 136,
seeks to ensure that activities do not jeopardize endangered or threatened plant
and animal species, nor destroy or modify the critical habitat of such species.
Under the ESA, certain exploration and production operations, as well as actions
by federal agencies or funded by federal agencies, must not significantly impair
or jeopardize the species or its habitat. The ESA provides for criminal
penalties for willful violations of this act. Other statutes which provide
protection to animal and plant species and thus may apply to our operations are
the Marine Mammal Protection Act, the Marine Protection and Sanctuaries Act, the
Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act,
and the Migratory Bird Treaty Act. The National Historic Preservation Act, 16
U.S.C. sec. 3470, may impose similar requirements.
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COMMUNICATION OF HAZARDS. The Occupational Safety and Health Act, as
amended ("OSHA"), 29 U.S.C. sec.sec. 651 et. seq., the Emergency Planning and
Community Right-to-Know Act, as amended ("EPCRA"), 42 U.S.C. sec.sec. 11001 et.
seq., and comparable state statutes require us to organize and disseminate
information to employees, state and local organizations, and the public about
the hazardous materials used in its operations and its emergency planning.
EMPLOYEES
Prior to August 1998, we and the general partner depended primarily upon
the employees and management services provided by DeepTech International Inc.
pursuant to a management agreement, although one of our subsidiaries had 10
full-time employees based in Houma, Louisiana to perform operational functions
for its natural gas pipeline and platform operations. Since El Paso Energy's
acquisition of our general partner, El Paso Energy through its subsidiaries has
provided such services under the management agreement. Accordingly, El Paso
Energy hired substantially all of the employees comprising our management team
and those employees performing the operational functions. We reimburse the
general partner for all reasonable general and administrative expenses and other
reasonable expenses incurred by the general partner and its affiliates for or on
behalf of us, including, but not limited to, amounts paid by the general partner
to El Paso Energy and its affiliates under the management agreement. In addition
to the employees provided by affiliates of El Paso Energy under the management
agreement, affiliates of El Paso Energy currently have 15 full-time employees
based in Houma, Louisiana that spend all their time performing operational
functions related to our natural gas pipeline and platform operations. As we
continue to operate more facilities, such as Stingray and the facilities under
construction, we will require more personnel.
LEGAL PROCEEDINGS
We are involved from time to time in various claims, actions, lawsuits and
regulatory matters that have arisen in the ordinary course of business,
including various rate cases and other proceedings before the FERC.
In particular, we are a defendant in a lawsuit filed by Transcontinental
Gas Pipe Line Corporation ("Transco") in the 157(th) Judicial District Court,
Harris County, Texas on August 30, 1996. Transco alleges that, pursuant to a
platform lease agreement entered into on June 28, 1994, Transco has the right to
expand its facilities and operations on the offshore platform by connecting
additional pipeline receiving and appurtenant facilities. We have denied
Transco's request to expand its facilities and operations because the lease
agreement does not provide for such expansion and because Transco's activities
will interfere with the Manta Ray Offshore system and our existing and planned
activities on the platform. Transco has requested a declaratory judgment and is
seeking damages. The case is set to be tried in November 1999. It is the opinion
of management that adequate defenses exist and that the final disposition of
this suit individually, and all of our other pending legal proceedings in the
aggregate, will not have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
Leviathan and several subsidiaries of El Paso Energy have been made
defendants in United States ex rel Grynberg v. El Paso Natural Gas Company, et
al. litigation. Generally, the complaint in this motion alleges an industry-wide
conspiracy to underreport the heating value as well as the volumes of the
natural gas produced from federal and Indian lands, thereby depriving the United
States government of royalties. The complaint remains sealed. We believe the
complaint is without merit and therefore will not have a material adverse effect
on our consolidated financial position, results of operations or cash flows.
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EL PASO ENERGY'S ACQUISITION OF OUR GENERAL PARTNER
Effective August 14, 1998, El Paso Energy completed the $422.0 million
acquisition of our general partner, which became a wholly owned indirect
subsidiary of El Paso Energy. The material terms of the acquisition and the
related transactions, as they relate to us, are as follows:
(1) El Paso Energy acquired the majority interest of Leviathan Holdings
Company, which owns 100% of our general partner, by acquiring
DeepTech International Inc. for an aggregate of $365 million, and
acquired the minority interests of Leviathan Holdings and two other
affiliates of Leviathan Holdings for an aggregate of $55.0 million.
Therefore, following those acquisitions by El Paso Energy, El Paso
Energy owned an overall 27.3% effective interest in us, comprised of
a 1.0% general partner interest, a 25.3% limited partner interest
comprised of 6,291,894 common units and a 1.0% nonmanaging
membership interest in most of our subsidiaries. Following the
closing of the acquisition of the Viosca Knoll interest in June
1999, El Paso Energy (through a subsidiary) acquired an additional
7.2% effective interest in us represented by 2,661,870 common units.
(2) On August 14, 1998, Tatham Offshore, Inc. (an affiliate of ours
through August 1998) transferred its remaining assets located in the
Gulf of Mexico to us in exchange for the 7,500 shares of Tatham
Offshore Series B 9% Senior Convertible Preferred Stock owned by us.
We acquired Tatham Offshore's right, title and interest in and to
Viosca Knoll Block 817 (subject to an existing production payment
obligation), West Delta Block 35, the platform located at Ship Shoal
Block 331 and other lease blocks not material to our current
operations. Our net cash expenditure for these transactions totaled
$0.8 million representing (a) $2.8 million of abandonment costs
relating to wells located at Ewing Bank Blocks 914 and 915 offset by
(b) $2.0 million of net cash generated from producing properties
from January 1, 1998 through August 14, 1998. In addition, we
assumed all remaining abandonment and restoration obligations
associated with the platform and leases.
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MANAGEMENT
OUR DIRECTORS AND EXECUTIVE OFFICERS
We and the general partner utilize the employees of and management services
provided by El Paso Energy and its affiliates under our management agreement. We
reimburse the general partner for reasonable general and administrative
expenses, and other reasonable expenses, incurred by the general partner and its
affiliates, for or on our behalf, including, without limitation, fees paid by
the general partner to El Paso Energy and its affiliates pursuant to our
management agreement. We also reimburse affiliates of our general partner for
costs related to insurance and operational personnel that spend all of their
time in connection with our operations.
Some of our officers and the general partner's officers and directors are
also officers and directors of El Paso Energy and its affiliates. Such officers
and directors may spend a substantial amount of time managing the business and
affairs of the general partner and El Paso Energy and its affiliates and may
face a conflict regarding the allocation of their time between our interests and
the other business interests of the general partner and El Paso Energy and its
affiliates. Mr. Sims and Mr. Lytal entered into employment agreements with
five-year terms with El Paso Energy pursuant to which they would continue to
serve as Chief Executive Officer and President, respectively, of the general
partner and us. However, pursuant to the terms of their respective employment
agreements, Messrs. Sims and Lytal have the right to terminate such agreements
upon 30 days notice and El Paso Energy has the right to terminate such
agreements under certain circumstances. The general partner may retain, acquire
and invest in businesses that compete with us, subject to certain limitations.
However, the ability of El Paso Energy and its other affiliates to retain,
acquire and invest in businesses that compete with us is not subject to any
limitations.
Certain provisions of our partnership agreement contain exculpatory
language purporting to (1) limit the liability of the general partner to us and
our unitholders and (2) modify the fiduciary duty standards to which the general
partner would otherwise be subject under Delaware law. Our partnership agreement
provides that (1) any action taken by the general partner consistent with the
standards of reasonable discretion set forth in certain definitions in our
partnership agreement will not breach any duty of the general partner to us or
to our unitholders, (2) in the absence of bad faith by the general partner, the
resolution of conflicts of interest by the general partner will not breach our
partnership agreement or any standard of care or duty and (3) the general
partner and its officers and directors may not be liable to us or to our
unitholders for certain actions or omissions which might otherwise be deemed to
be a breach of fiduciary duty under Delaware or other applicable state law.
Further, the partnership agreement requires us to indemnify the general partner
to the fullest extent permitted by law, which indemnification, in light of the
exculpatory provisions in the partnership agreement, could result in us
indemnifying the general partner for negligent acts.
DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER
The following table sets forth certain information as of June 30, 1999,
regarding our executive officers and the executive officers and directors of the
general partner who provide services to us. Each executive officer of the
general partner holds the same executive position for us. Directors are elected
annually by the general partner's sole stockholder, Leviathan Holdings Company,
and hold office until their successors are elected and qualified. Each executive
officer named in the following table has been elected to serve until his
successor is duly appointed or elected or until his earlier removal or
resignation from office.
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There is no family relationship among any of the executive officers or
directors, and other than described in this prospectus, no arrangement or
understanding exists between any executive officer and any other person pursuant
to which he was or is to be selected as an officer.
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
- ---- --- -----------
<S> <C> <C>
William A. Wise........................... 53 Director and Chairman of the Board
Grant E. Sims............................. 43 Director and Chief Executive Officer
James H. Lytal............................ 41 Director and President
H. Brent Austin........................... 44 Director and Executive Vice President
Robert G. Phillips........................ 44 Director and Executive Vice President
Keith B. Forman........................... 41 Vice President and Chief Financial Officer
D. Mark Leland............................ 37 Vice President and Controller
Michael B. Bracy.......................... 57 Director
H. Douglas Church......................... 61 Director
Malcolm Wallop............................ 66 Director
</TABLE>
WILLIAM A. WISE has served as a director and Chairman of the Board of the
general partner since August 1998, Chairman of the Board of El Paso Energy since
January 1994 and Chief Executive Officer of El Paso Energy since June 1990. Mr.
Wise served as President of El Paso Energy from January 1990 until April 1996
and from July 1998 to the present. Mr. Wise served as President and Chief
Operating Officer of El Paso Energy from April 1989 to December 1989. From March
1987 until April 1989, Mr. Wise was an Executive Vice President of El Paso
Energy and a Senior Vice President of El Paso Energy from January 1984 to
February 1987. Mr. Wise is a member of the Boards of Directors of Battle
Mountain Gold Company and Chase Bank of Texas and is Chairman of the Board of El
Paso Tennessee Pipeline Co.
GRANT E. SIMS has served as a director of the general partner since July
1995 and as our Chief Executive Officer and the Chief Executive Officer of
general partner since August 1994. Mr. Sims served as our President and
President of the general partner from March 1994 through June 1995. In addition,
Mr. Sims has served as a director and Senior Vice President of DeepTech
International Inc. since July 1993 and served as a director of Offshore Gas
Marketing, Inc., a subsidiary of DeepTech, from December 1992 to March 1994.
Prior to his employment with DeepTech, Mr. Sims spent ten years with Transco in
various capacities, most recently directing Transco's non-jurisdictional natural
gas activities.
JAMES H. LYTAL has served as a director of the general partner since July
1995 and as our President and President of the general partner since August
1994. He served as our Senior Vice President and Senior Vice President of the
general partner from August 1994 to June 1995. Prior to joining us, Mr. Lytal
was Vice President -- Business Development for American Pipeline Company from
December 1992 to August 1994. Prior thereto, Mr. Lytal served as Vice
President -- Business Development for United Gas Pipe Line Company from March
1991 to December 1992. Prior thereto, Mr. Lytal has served in various capacities
in the oil and natural gas exploration and production and natural gas pipeline
industries with Texas Oil and Gas, Inc. and American Pipeline Company from
September 1980 to March 1991.
H. BRENT AUSTIN has served as a director and an Executive Vice President of
the general partner and as our Executive Vice President since August 1998. Mr.
Austin has served as an Executive Vice President of El Paso Energy since May
1995 and as the Chief Financial Officer of El Paso Energy since April 1992. He
served as the Senior Vice President of El Paso Energy from April 1992 to May
1995. He served as the Vice President, Planning and Treasurer of Burlington
Resources Inc. from November 1990 to March 1992 and Assistant Vice President,
Planning of Burlington Resources from January 1989 to October 1990. Mr. Austin
is a member of the Board of Directors of El Paso Tennessee Pipeline Co.
ROBERT G. PHILLIPS has served as a director and an Executive Vice President
of the general partner and as our Executive Vice President since August 1998.
Mr. Phillips has served as President of El Paso Field
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Services Company since June 1997. He served as President of El Paso Energy
Resources Company from December 1996 to June 1997, President of El Paso Field
Services Company from April 1996 to December 1996 and Senior Vice President of
El Paso Energy from September 1995 to April 1996. For more than five years prior
thereto, Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc.
KEITH B. FORMAN has served as our Chief Financial Officer and Chief
Financial Officer of the general partner since January 1992 and served as a
director of the general partner from July 1992 to August 1998. Prior to joining
us, Mr. Forman served as Vice President of the Natural Gas Pipeline Group of
Manufacturers Hanover Trust Company which he joined in 1982. His account
responsibility included interstate natural gas transmission companies and
natural gas gathering companies.
D. MARK LELAND has served as our Vice President and Controller and Vice
President and Controller of the general partner since August 1998 and as Vice
President of El Paso Field Services Company since September 1997. He served as
Director of Business Development for El Paso Field Services Company from
September 1994 to September 1997. For more than five years prior thereto, Mr.
Leland served in various capacities in the finance and accounting functions of
El Paso Energy.
MICHAEL B. BRACY has served as a director of the general partner since
October 1998. From January 1993 to August 1997, Mr. Bracy served as a director,
Executive Vice President and Chief Financial Officer of NorAm Energy Corp.
(formerly Arkla, Inc.) and as Executive Vice President and Chief Financial
Officer of NorAm from December 1991 to January 1993. For seven years prior
thereto, Mr. Bracy served in various executive capacities with NorAm. From
December 1977 to October 1984, Mr. Bracy held various executive financial
positions with El Paso Energy and prior thereto, Mr. Bracy served in various
capacities with The Chase Manhattan Bank. Mr. Bracy is a member of the Board of
Directors of Itron, Inc.
H. DOUGLAS CHURCH has served as a director of the general partner since
January 1999. From January 1994 to December 1998, Mr. Church served as the
Senior Vice President, Transmission, Engineering and Environmental for a
subsidiary of, Duke Energy Corporation, Texas Eastern Transmission Company. For
thirty-two years prior thereto, Mr. Church served in various engineering and
operating capacities with Texas Eastern, Panhandle Eastern Corporation and
Transwestern Pipeline Company. Mr. Church is a past member and Chairman of the
Board of Directors of Southern Gas Association and Boys and Girls Country of
Houston, Inc.
MALCOLM WALLOP has served as a director of the general partner since August
1998 and as a director of El Paso Energy since February 1995. Mr. Wallop became
Chairman of Western Gulf Strategy Group on January 1, 1999. Since January 1996,
Mr. Wallop has served as President for Frontiers of Freedom Foundation, a
political foundation. For eighteen years prior thereto, Mr. Wallop was a member
of the United States Senate. He is a member of the Board of Directors of Hubbell
Inc. and Sheridan State Bank.
COMPENSATION OF DIRECTORS
Directors of the general partner are entitled to reimbursement for their
reasonable out-of-pocket expenses in connection with their travel to and from,
and attendance at, meetings of the Board or committees thereof. Mr. Paul
Thompson III, Mr. George L. Ball and Mr. William A. Bruckmann, III, directors of
the general partner until their resignation on August 14, 1998, were paid an
annual fee of $36,000 plus $1,000 per meeting attended. Current non-employee
directors are paid an annual fee of $30,000. Officers of the general partner and
our officers are elected by, and serve at the discretion of, the Board.
Pursuant to our former non-employee director compensation arrangements, we
were obligated to pay each non-employee director 2.5% of the general partner's
Incentive Distribution as a profit participation fee. During the year ended
December 31, 1998, we paid the Messrs. Thompson, Ball and Bruckmann a total of
$600,000 as a profit participation fee. In connection with El Paso Energy's
acquisition of Leviathan, Messrs. Thompson, Ball and Bruckmann resigned and the
compensation arrangements were terminated.
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In August 1998, we adopted the 1998 Unit Option Plan for Non-Employee
Directors to provide us with the ability to issue unit options to attract and
retain the services of knowledgeable directors. Unit options to purchase a
maximum of 100,000 common units may be issued pursuant to this plan. Under this
plan, we granted (1) 1,500 unit options to Mr. Wallop in August 1998 to acquire
an equal number of common units at $27.34375 per unit, (2) 1,500 unit options to
Mr. Bracy in October 1998 to acquire an equal number of common units at $25.00
per unit and (3) 1,500 unit options to Mr. Church in January 1999 to acquire an
equal number of common units at $20.625 per unit. Each unit option vests
immediately at the date of grant and shall expire ten years from such date, but
shall be subject to earlier termination in the event that Messrs. Wallop, Bracy
and Church cease to be a director of the general partner for any reason, in
which case the unit options expire 36 months after such date except in the case
of death, in which case the unit options expire 12 months after such date. This
plan is administered by a management committee consisting of the Chairman of the
Board and such other senior officers of the general partner or its affiliates as
the Chairman of the Board shall designate.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
We do not currently have a compensation committee or another committee
performing similar functions, and all such matters which would be considered by
such committee are acted upon by the full Board of Directors. The Board of
Directors, administers and interprets the Omnibus Plan. See
"Management -- Executive Compensation -- Omnibus Plan" beginning on page 75.
AUDIT AND CONFLICTS COMMITTEE
Currently, Messrs. Bracy, Church and Wallop, who are neither officers nor
employees of the general partner nor any of its affiliates, serve as the Audit
and Conflicts Committee of the Board of Directors of the general partner and of
us. Mr. Wallop is a director of El Paso Energy. Through August 14, 1998, Messrs.
Thompson, Ball and Bruckmann, who were neither officers nor employees of the
general partner nor any of its affiliates, served as the Audit and Conflicts
Committee.
The Audit and Conflicts Committee provides two primary services. First, it
advises the Board of Directors in matters regarding the system of internal
controls and the annual independent audit, and reviews our policies and
practices, as well as those of the general partner. Second, the Audit and
Conflicts Committee, at the request of the general partner, reviews specific
matters as to which the general partner believes there may be a conflict of
interest in order to determine if the resolution of such conflict proposed by
the general partner is fair and reasonable to us. Except as otherwise required
by the rules of the NYSE, the Audit and Conflicts Committee only reviews matters
concerning potential conflicts of interest at the request of the general
partner, which has sole discretion to determine which such matters to submit to
that committee. Any such matters approved by a majority vote of the Audit and
Conflicts Committee will be conclusively deemed (1) to be fair and reasonable to
us, (2) approved by all of our limited partners and (3) not a breach by the
general partner of any duties it may owe to us. However, it is possible that
such procedure in itself may constitute a conflict of interest.
COMPENSATION OF THE GENERAL PARTNER
The general partner receives no remuneration in connection with our
management other than: (1) distributions in respect of its general and limited
partner interests in us and its nonmanaging interest in certain of our
subsidiaries; (2) incentive distributions in respect of its general partner
interest, as provided in our partnership agreement; and (3) reimbursement for
all direct and indirect costs and expenses incurred on our behalf, all selling,
general and administrative expenses incurred by the general partner for or on
our behalf and all other expenses necessary or appropriate to the conduct of the
business of, and allocable to, us, including, but not limited to, the management
fees paid by the general partner to El Paso Energy and its affiliates under our
management agreement.
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EXECUTIVE COMPENSATION
Our executive officers (who are also executive officers of the general
partner) are compensated by El Paso Energy (and, prior to consummation of El
Paso Energy's acquisition of Leviathan, were compensated by Leviathan's parent)
and do not receive compensation from the general partner or us for their
services in such capacities with the exception of awards pursuant to the Unit
Rights Appreciation Plan and Omnibus Plan discussed below.
UNIT RIGHTS APPRECIATION PLAN
In 1995, we adopted the Unit Rights Appreciation Plan to provide us with
the ability of making awards of unit rights to certain officers and employees of
the general partner or its affiliates as an incentive for these individuals to
continue in the service of us or our affiliates. Under the Unit Rights Plan, we
granted 1.2 million unit rights to certain officers and employees of the general
partner or its affiliates that provided for the right to purchase, or realize
the appreciation of, a preference unit or a common unit, pursuant to the
provisions of the Unit Rights Plan. The Unit Rights Plan was administered by a
committee of the Board of Directors of the general partner comprised of two or
more non-employee directors. The aggregate number of rights that could have been
issued pursuant to the Unit Rights Plan could not exceed 400,000 rights per
calendar year and 4 million rights over the term of that plan, subject to
adjustment. No participant could have been granted more than 400,000 rights in
any calendar year. The exercise price covered by the rights granted pursuant to
that plan was the closing price of the preference units as reported on the NYSE
on the date on which rights were granted pursuant to that plan.
The exercise prices covered by these rights granted pursuant to this plan
ranged from $15.6875 to $21.50, the closing prices of the preference units as
reported on the NYSE on the grant date of the respective rights. As a result of
the "change of control" occurring upon the closing of El Paso Energy's
acquisition of Leviathan, the rights fully vested and the holders of those
rights elected to be paid $8.6 million, the amount equal to the difference
between the grant price of those rights and the average of the high and the low
sales price of the common units on the date of exercise. Upon the exercise of
all of the rights outstanding, that plan was terminated. We replaced that plan
with the Omnibus Plan described below.
OMNIBUS PLAN
In August 1998, we adopted the 1998 Omnibus Compensation Plan to provide us
with the ability to issue unit options to attract and retain the services of
knowledgeable officers and key management personnel. Unit options to purchase a
maximum of 3 million common units may be issued pursuant to the Omnibus Plan.
The Plan is administered by the Board. The Board interprets, prescribes, amends
and rescinds rules relating to the Omnibus Plan, selects eligible participants,
makes grants to participants who are not Section 16 insiders pursuant to the
Exchange Act, and takes all other actions necessary for the Omnibus Plan
administration, which actions shall be final and binding upon all the
participants.
In August 1998, we granted 930,000 unit options to employees of our general
partner to purchase an equal number of common units at $27.1875 per unit
pursuant to the Omnibus Plan. These unit options, none of which are exercisable,
remain outstanding as of April 30, 1999.
REPORT FROM COMPENSATION COMMITTEE REGARDING EXECUTIVE COMPENSATION
Because we do not have a compensation committee or another committee
performing similar functions, this report is presented by the full Board of
Directors. The Board of Directors is responsible for establishing appropriate
compensation goals for the knowledgeable officers and key management personnel
working for us and evaluating the performance of such officers and personnel in
meeting such goals.
The goals of the Board of Directors in administering the Omnibus Plan are
as follows:
(1) To fairly compensate the knowledgeable officers and key management
personnel working for us and our affiliates for their contributions to our
short-term and long-term performance.
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<PAGE> 81
(2) To allow us to attract, motivate and retain the management
personnel necessary to our success by providing an Omnibus Plan comparable
to that offered by companies with which we compete for such management
personnel.
The elements of the Omnibus Plan described above are implemented and
periodically reviewed and adjusted by the Board of Directors. The awards made
under the Omnibus Plan are determined based on individual performance,
experience and comparison with awards made by our industry peers and other
companies in similar industries with comparable revenue while linking such
awards to our achievement of certain financial goals.
SUMMARY COMPENSATION TABLE
The following table sets forth information concerning the annual
compensation earned by our Chief Executive Officer and each of our other four
most highly compensated executive officers whose annual salary and bonus from us
during the year ended December 31, 1998 exceeded $100,000:
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
ANNUAL COMPENSATION(2) AWARDS
-------------------------------------------- ----------------------
MARKET VALUE OTHER ANNUAL ALL OTHER
FISCAL SALARY BONUS OF UNITS COMPENSATION OPTIONS COMPENSATION
NAME/PRINCIPAL POSITION YEAR ($) ($) ISSUED ($) (#) ($)
----------------------- ------ ------ ----- ------------ ------------ ------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Grant E. Sims................ 1998 -- -- -- -- 215,000(3) --
Chief Executive Officer 1997 -- -- -- -- 125,000(4) --
1996 -- -- -- -- 90,000(4) --
James H. Lytal............... 1998 -- -- -- -- 215,000(3) --
President 1997 -- -- -- -- 125,000(4) --
1996 -- -- -- -- 90,000(4) --
Keith B. Forman.............. 1998 -- -- -- -- 215,000(3) --
Chief Financial Officer 1997 -- -- -- -- 125,000(4) --
1996 -- -- -- -- 90,000(4) --
John H. Gray(1).............. 1998 -- -- -- -- -- --
Chief Operating Officer 1997 -- -- -- -- 125,000(4) --
1996 -- -- -- -- 90,000(4) --
Donald V. Weir(1)............ 1998 -- -- -- -- -- --
Vice President 1997 -- -- -- -- -- --
1996 -- -- -- -- -- --
T. Darty Smith............... 1998 -- -- -- -- 70,000(3) --
Vice President 1997 -- -- -- -- 50,000(4) --
1996 -- -- -- -- 20,000(4) --
Bart H. Heijermans........... 1998 -- -- -- -- 40,000(3) --
Vice President 1997 -- -- -- -- -- --
1996 -- -- -- -- -- --
</TABLE>
- ------------------------------------
(1) John H. Gray, our former Chief Operating Officer, and Donald V. Weir, our
former Vice President, resigned their positions in connection with the
consummation of El Paso Energy's acquisition of our general partner on
August 14, 1998.
(2) Other than awards made under our incentive arrangements, all other
compensation was paid by El Paso Energy and/or our previous parent.
(3) Issued pursuant to the Omnibus Plan.
(4) Issued pursuant to the Unit Rights Plan.
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<PAGE> 82
OPTION GRANTS
The following table sets forth certain information concerning the unit
options granted to the named officers during the year ended December 31, 1998:
<TABLE>
<CAPTION>
POTENTIAL REALIZABLE
VALUE AT ASSUMED ANNUAL
PERCENT OF RATES OF UNIT PRICE
TOTAL APPRECIATION FOR OPTION
NUMBER OF OPTIONS TERM
COMMON UNITS GRANTED TO EXERCISE OR -----------------------
UNDERLYING EMPLOYEES IN BASE PRICE EXPIRATION 5% 10%
NAME OPTIONS GRANTED FISCAL YEAR ($/SH) DATE ($) ($)
---- --------------- ------------ ----------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Grant E. Sims........ 215,000(1) 23% $27.1875 8/14/2008 $3,676,086 $9,315,923
James H. Lytal....... 215,000(1) 23% $27.1875 8/14/2008 $3,676,086 $9,315,923
Keith B. Forman...... 215,000(1) 23% $27.1875 8/14/2008 $3,676,086 $9,315,923
T. Darty Smith....... 70,000(1) 8% $27.1875 8/14/2008 $1,196,865 $3,033,091
Bart H. Heijermans... 40,000(1) 4% $27.1875 8/14/2008 $ 683,923 $1,733,195
</TABLE>
- ------------------------------------
(1) These unit options were issued pursuant to the Omnibus Plan and are not
immediately exercisable. One half of the unit options are considered vested
and exercisable one year after at the date of grant and the remaining
one-half of the units options are considered vested and exercisable one year
after the first anniversary of the date of grant. The unit options shall
expire 10 years from such grant date, but shall be subject to earlier
termination in the event that a participant ceases employment with the
general partner for retirement or disability, in which case the unit options
expire 36 months after such date; for termination without cause, one year
after such date; for voluntary termination, three months after such date;
and death, twelve months after such date.
OPTION EXERCISES AND YEAR-END VALUE TABLE
The following table sets forth certain information concerning the unit
options held by the relevant officers at December 31, 1998 or exercised by those
officers during the year then ended:
<TABLE>
<CAPTION>
VALUE OF
UNEXERCISED
IN-THE-MONEY
OPTIONS AT FISCAL
NUMBER OF YEAR-END
SHARES ACQUIRED VALUE EXERCISABLE/ EXERCISABLE/
NAME ON EXERCISE(#) REALIZED($) UNEXERCISABLE(2) UNEXERCISABLE
- ---- --------------- ----------- ---------------- -----------------
<S> <C> <C> <C> <C>
Grant E. Sims........................ 215,000(1) $1,745,938(1) -- /215,000 -$-/$--
James H. Lytal....................... 215,000(1) 1,745,938(1) -- /215,000 --/ --
Keith B. Forman...................... 215,000(1) 1,745,938(1) -- /215,000 --/ --
T. Darty Smith....................... 70,000(1) 416,875(1) -- /70,000 --/ --
Bart H. Heijermans................... -- -- -- /40,000 --/ --
</TABLE>
- ------------------------------------
(1) As a result of the "change of control" occurring upon El Paso Energy's
acquisition of our general partner, the rights issued pursuant to the Unit
Rights Plan fully vested and the holders of the rights elected to be paid
the amount equal to the difference between the grant price of the right and
the average of the high and the low sales price of the common units on the
date of exercise.
(2) All unexercisable options in this column relate to options issued pursuant
to the Omnibus Plan.
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<PAGE> 83
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
MANAGEMENT FEES
Substantially all of the individuals who perform the day-to-day financial,
administrative, accounting and operational functions for us, as well as those
who are responsible for our direction are currently employed by El Paso Energy.
Under a management agreement between a subsidiary of El Paso Energy and our
general partner, a management fee is charged to our general partner which is
intended to approximate an allocation for the costs of resources allocated by El
Paso Energy and its affiliates in connection with operational, financial,
accounting and administrative matters. The management agreement expires on June
30, 2002, and may be terminated thereafter upon 90 days notice by either party.
Under our partnership agreement, our general partner is reimbursed for all
reasonable general and administrative expenses and other reasonable expenses
that it and its affiliates incur on our behalf, including amounts payable by our
general partner to a subsidiary of El Paso Energy under the management
agreement.
In connection with El Paso Energy's acquisition of our general partner, our
general partner amended its management agreement to provide for a monthly
management fee of $775,000. Prior to that, the management fee represented an
allocation of costs attributable to our business, primarily based on a time and
space methodology. Effective November 1, 1995, July 1, 1996 and July 1, 1997,
primarily as a result of our increased activities, the annual management fee was
45.3%, 54.0% and 52.0% of such costs. Our general partner charged us $9.3
million, $8.1 million and $6.6 million under our management agreement for the
years ended December 31, 1998, 1997 and 1996, and $4.6 million and $4.7 million
for the six months ended June 30, 1998, and 1999.
In addition, our general partner must reimburse El Paso Energy and its
affiliates for certain tax liabilities resulting from, among other things,
additional taxable income allocated to our general partner due to (1) the
issuance of additional preference units in 1994 and (2) the investment of such
proceeds in additional acquisitions or construction projects. During the years
ended December 31, 1998, 1997 and 1996, our general partner charged us $489,000,
$713,000 and approximately $1.2 million for additional taxable income allocated
to the general partner.
PLATFORM ACCESS AND TRANSPORTATION AGREEMENTS
VIOSCA KNOLL. For the years ended December 31, 1998, 1997 and 1996, we
received approximately $1.1 million, $2.0 million and $1.9 million from Tatham
Offshore as platform access and production handling fees related to our platform
located in Viosca Knoll Block 817.
For the years ended December 31, 1998, 1997 and 1996, we charged Viosca
Knoll approximately $2.4 million, $2.1 million and $249,000 for expenses and
platform access fees related to the Viosca Knoll Block 817 platform.
In addition, for the years ended December 31, 1998, 1997 and 1996, Viosca
Knoll reimbursed us $152,000, $47,000 and $254,000 for costs we incurred in
connection with the acquisition and installation of a booster compressor on our
Viosca Knoll Block 817 platform.
During the years ended December 31, 1998, 1997 and 1996, Viosca Knoll
charged us approximately $1.9 million, $3.9 million and $3.2 million for
transportation services related to transporting production from the Viosca Knoll
Block 817 lease.
GARDEN BANKS. During the years ended December 31, 1998, 1997 and 1996,
Poseidon charged us approximately $1.4 million, $2.0 million and $1.1 million
for transportation services related to transporting production from the Garden
Banks Block 72 and 117 leases.
OTHER
We have agreed to sell all of our oil and natural gas production to
Offshore Gas Marketing, Inc. a wholly owned subsidiary of El Paso Energy, on a
month to month basis. This agreement provides Offshore
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<PAGE> 84
Gas Marketing fees equal to 2.0% of the sales value of crude oil and condensate
and $0.015 per dekatherm of natural gas for selling our production. During the
years ended December 31, 1998, 1997 and 1996, our oil and natural gas sales to
Offshore Gas Marketing totaled approximately $31.2 million, $57.8 million and
$46.3 million.
We are party to a management agreement with Viosca Knoll under which we
charge Viosca Knoll a base fee of $100,000 annually in exchange for providing
financial, accounting and administrative services to Viosca Knoll. For each of
the years ended December 31, 1998, 1997 and 1996, we charged Viosca Knoll
$100,000 in accordance with this agreement.
For the years ended December 31, 1998 and 1997, we charged Manta Ray
Offshore approximately $1.3 million and $287,000 under management and operations
agreements.
In connection with El Paso Energy's acquisition of our general partner, Mr.
Grant E. Sims and Mr. James H. Lytal entered into employment agreements with
five year terms with El Paso Energy under which they would continue to serve as
our and our general partner's Chief Executive Officer and President,
respectively. However, under their respective employment agreements, Messrs.
Sims and Lytal have the right to terminate such agreements upon 30 days' advance
notice and El Paso Energy has the right to terminate these agreements under
certain circumstances.
Under our former non-employee director compensation arrangements, we were
obligated to pay each non-employee director 2.5% of the general partner's
incentive distribution as a profit participation fee. During the years ended
December 31, 1998 and 1997, we paid the three non-employee directors of
Leviathan a total of $621,000 and $313,000 as a profit participation fee. As a
result of El Paso Energy's acquisition of our general partner, the three
non-employee directors resigned and the compensation arrangements were
terminated.
We reimburse affiliates of our general partner for costs related to
insurance and operational personnel that spend all of their time in connection
with our operations. During the last four months of 1998 and the six months
ended June 30, 1999, we reimbursed $660,000 and $1.1 million to these
affiliates.
Prior to the closing of the offering of our subordinated notes, Viosca
Knoll Gathering Company was effectively owned 50.0% by us and 50.0% by El Paso
Energy (through a wholly owned subsidiary). In January 1999, we entered into an
agreement to acquire an additional 49.0% interest in Viosca Knoll from El Paso
Energy, which would result in us owning 99.0% of Viosca Knoll with an option to
purchase the remaining 1.0% interest. In exchange for El Paso Energy's
contribution of its Viosca Knoll interest, we paid El Paso Energy $79.7 million
for the 49.0% interest, comprised of $19.9 in cash and $59.8 million in common
units. The acquisition of the Viosca Knoll interest closed on June 1, 1999.
Following the closing of the Viosca Knoll transaction and prior to this
offering, El Paso Energy's effective ownership interest in us was 34.5%. In
addition, at the closing of the Viosca Knoll transaction, El Paso Energy
contributed to Viosca Knoll approximately $33.4 million in cash, which equaled
50.0% of the principal amount outstanding under Viosca Knoll's credit facility,
and we thereafter repaid and terminated that credit facility.
In October 1998, we purchased a 100% working interest in the Ewing Bank 958
Unit from a wholly owned, indirect subsidiary of El Paso Energy for $12.2
million. For a more detailed description of the Ewing Bank 958 Unit, see
"--Business and Properties--Recent Developments, Acquisitions and New
Projects--Ewing Bank 958 Unit."
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<PAGE> 85
PRINCIPAL UNITHOLDERS
The following table sets forth, as of August 1, 1999, the beneficial
ownership of our outstanding equity securities, by (1) each person who we know
to beneficially own more than 5.0% of our outstanding units, (2) each director
of the general partner and (3) all directors and executive officers of the
general partner as a group.
<TABLE>
<CAPTION>
COMMON UNITS PREFERENCE UNITS
------------------ -----------------
BENEFICIAL OWNER NUMBER PERCENT NUMBER PERCENT
- ---------------- ------ ------- ------ -------
<S> <C> <C> <C> <C>
El Paso Energy(1)...................................... (1) (1) -- --
Grant E. Sims.......................................... 33,000(2) * -- --
James H. Lytal......................................... 6,050(3) * -- --
Keith B. Forman........................................ 1,000 * -- --
Robert G. Phillips..................................... 1,000 * -- --
William A. Wise........................................ 9,670(4) * -- --
H. Brent Austin........................................ 1,000 * -- --
D. Mark Leland......................................... -- -- -- --
Michael B. Bracy....................................... 6,500(5) * -- --
H. Douglas Church...................................... 1,500(5) * -- --
Malcolm Wallop......................................... 1,500(5) * -- --
Executive officers and directors of Leviathan as a
group (10 persons)................................... 61,220 * -- --
</TABLE>
- ------------------------------------
* Less than 1%.
(1) El Paso Energy beneficially owns all of the outstanding capital stock of our
general partner, the general partner of Leviathan. The address for our
general partner and El Paso Energy is El Paso Energy Building, 1001
Louisiana Street, Houston, Texas 77002. El Paso Energy indirectly owns all
of the general partner's outstanding common stock, par value $0.10 per
share. The general partner has no other class of capital stock outstanding.
As of August 1, 1999, our general partner, through its ownership of
6,291,894 common units, its 1.0% general partner interest and its
approximate 1.0% nonmanaging interest in certain of our subsidiaries,
effectively owned a 27.3% interest in us. Another subsidiary of El Paso
Energy owns 2,661,870 common units. As a result, El Paso Energy effectively
owns a 34.5% interest in us.
(2) Mr. Sims disclaims beneficial ownership of 2,000 common units held in trust
for his 18 year old son.
(3) Mr. Lytal may be deemed to be the beneficial owner of 34 common units owned
by Mr. Lytal's son, a minor.
(4) This number excludes 3,625 units owned by Mr. Wise's children, for which he
disclaims beneficial ownership.
(5) Includes the option to acquire 1,500 common units pursuant to the 1998 Unit
Option Plan for Non-Employee Directors. See "Management -- Compensation of
Directors" beginning on page 73.
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<PAGE> 86
DESCRIPTION OF COMMON UNITS
RIGHTS TO DISTRIBUTIONS
GENERAL. Our limited partner interests (common units and preference units)
are equity securities entitled (1) to participate in distributions of available
cash that may be made from time to time and (2) in the event we liquidate or
wind-up, to share in any of our assets remaining after satisfaction of our
liabilities. Except to the extent our general partner has earned the right to
receive any incentive distributions, we will distribute 98% of our available
cash constituting cash from operations to our limited partners in respect of
their common units and preference units and 2% of such available cash to our
general partner in respect of its 1% general partner interest and its 1%
non-managing member interest. Our general partner will become entitled, as an
incentive, to a greater share of the distributions of available cash
constituting cash from operations to the extent that available cash exceeds
specified target levels that are above $0.275 per unit per quarter, as further
described below.
Our partnership agreement requires us to distribute all of our "available
cash," as such term is defined in our partnership agreement. Generally,
"available cash" means, for the applicable quarter, all cash receipts for such
quarter and any reductions in reserves established in prior quarters less all
cash disbursements made in such quarter and additions to reserves, as determined
by our general partner. Our partnership agreement characterizes available cash
into two categories--"cash from operations" and "cash from interim capital
contributions. This distinction affects the amounts distributed to the
unitholders relative to the general partner and the priority of distributions to
preference unitholders relative to common unitholders. "Cash from operations,"
which is determined on a cumulative basis, generally refers to all cash
generated by the operations of our business (excluding any cash from interim
capital transactions), after deducting related cash operating expenditures, cash
debt service payments, cash capital expenditures, reserves and certain other
items. "Cash from interim capital transactions" will, generally, be generated
only by (1) borrowings and sales of debt securities by us (other than for
working capital purposes and other than for goods or services purchased on open
account in the ordinary course of business), (2) sales of equity interests in
Leviathan for cash and (3) sales or other voluntary or involuntary dispositions
of any of our assets for cash (other than inventory, accounts receivable and
other current assets and assets disposed of in the ordinary course of business).
Amounts of cash distributed by us on any date from any source will be
treated as a distribution of cash from operations, until the sum of all amounts
so distributed to the unitholders and to the general partner (including any
incentive distributions) equals the aggregate amount of all cash from operations
from February 19, 1993 through the end of the calendar quarter prior to such
distribution. Any amount of such cash (irrespective of its source) distributed
on such date which, together with prior distributions of cash from operations,
is in excess of the aggregate amount of all cash from operations from February
19, 1993 through the end of the calendar quarter prior to such distribution will
be deemed to constitute cash from interim capital transactions and will be
distributed accordingly. If cash that is deemed to constitute cash from interim
capital transactions is distributed in respect of each preference unit in an
aggregate amount per preference unit equal to the unrecovered capital with
respect thereto, the distinction between cash from operations and cash from
interim capital transactions will cease, and all cash will be distributed as
cash from operations. Because our general partner has no present plans to cause
us to use the proceeds from interim capital transactions to pay distributions,
our general partner does not currently anticipate that there will be any
significant amounts of cash that are deemed to constitute cash from interim
capital transactions distributed to the unitholders during the next 18 months.
Capital expenditures that our general partner determines are necessary or
desirable to maintain our facilities and operations (as distinguished from
capital expenditures made to expand the capacity of such facilities or make
strategic acquisitions) will reduce the amount of cash from operations.
Therefore, if our general partner were to determine that substantial capital
expenditures were necessary or desirable to maintain our facilities, the amount
of cash distributions that are deemed to constitute cash from operations would
decrease and, if such expenditures were subsequently refinanced and all or a
portion of the proceeds
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<PAGE> 87
distributed to unitholders, the amount of cash distributions deemed to
constitute cash from interim capital transactions might increase.
QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH. Our partnership agreement
requires us to distribute available cash for each calendar quarter within 45
days after the end of such quarter.
PARTICIPATION IN DISTRIBUTIONS. The holders of our common units are
entitled to fully participate in quarterly distributions of available cash
constituting cash from operations, subject to the right of our general partner
to receive the incentive distributions described below, the right of holders of
our preference units to receive minimum quarterly distributions and any
arrearages, and the right of holders of any securities we issue after this
offering to receive any priority distributions attributable to such securities.
The holders of our preference units do not have the right to fully participate
in distributions of available cash constituting cash from operations. They do
not participate in such distributions in excess of the minimum quarterly
distribution amount plus arrearages, if any.
SENIORITY. The common unit distribution rights with respect to available
cash constituting cash from operations (1) are subordinate to the right of
preference units to receive the minimum quarterly distribution amount (including
arrearages) and (2) until the common units receive an amount equal to the
minimum quarterly distribution amount (excluding arrearages), are senior to the
right of any other unit to receive a share of distributions of available cash
constituting cash from operations.
The holders of our preference units are entitled to receive minimum
distributions of available cash constituting cash from operations, for each
quarter of $0.275 per preference unit, aggregating $1.10 per preference unit on
an annualized basis. Such rights are cumulative, and arrearages will accrue.
After the holders of our preference units have received distributions of
available cash constituting cash from operations, during any relevant quarter
equal to the minimum quarterly distribution amount plus any arrearages, but
before any other units may participate in distributions of such available cash
during such quarter, the holders of our common units are entitled to receive
during such quarter distributions of such available cash, if any, in an amount
up to the minimum quarterly distribution amount. However, our common units do
not have cumulative distribution participation rights, and no arrearages will
accrue.
After our preference unit holders and common unitholders are paid the
minimum quarterly distribution amount and any arrearages, holders of our common
units are entitled to fully participate in quarterly distributions of available
cash, subject to the right of our general partner to receive the incentive
distributions described below and the rights of holders of any securities we may
issue in the future.
In the future, we may issue unlimited amounts of additional securities that
would participate in, or have preferences with respect to, distributions of
available cash constituting cash from operations, whether up to or in excess of
the minimum quarterly distribution amount.
The minimum quarterly distribution and the specified target levels relating
to incentive distributions may be adjusted under certain circumstances in
accordance with our partnership agreement.
DISTRIBUTION OF CASH FROM OPERATIONS, UP TO THE MINIMUM QUARTERLY
DISTRIBUTION, ON ALL UNITS. Available cash constituting cash from operations in
respect of any calendar quarter will be distributed in the following manner:
first, 98% will be distributed to the preference unitholders, pro
rata, and 2% will be distributed to the general partner until there has
been distributed in respect of each preference unit an amount equal to
the minimum quarterly distribution for such quarter;
second, 98% will be distributed to the preference unitholders, pro
rata, and 2% will be distributed to the general partner until there has
been distributed in respect of each preference unit an amount equal to
any cumulative arrearages in the minimum quarterly distribution on each
preference unit with respect to any prior quarter;
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<PAGE> 88
third, 98% will be distributed to the common unitholders, pro rata,
and 2% will be distributed to the general partner until there has been
distributed in respect of each common unit an amount equal to the
minimum quarterly distribution for such quarter; and
thereafter, in the manner described under "--Incentive
Distributions" below.
Notwithstanding the foregoing, the minimum quarterly distribution is subject to
adjustment as described below.
INCENTIVE DISTRIBUTIONS. Subject to the payment of incentive distributions
to the general partner if certain target levels of distributions of available
cash constituting cash from operations to preference and common unitholders are
achieved, distributions of such available cash are effectively made 98% to the
limited partners and 2% to the general partner. As an incentive, in respect of
its 2% interest, the general partner's share of such quarterly cash
distributions in excess of $0.325 per common unit and less than or equal to
$0.375 per common unit will increase to 15%. For such quarterly cash
distributions over $0.375 per common unit but no more than $0.425 per common
unit, the general partner will receive 25% of such incremental amount, and for
all quarterly cash distributions in excess of $0.425 per unit, the 1% general
partner interest will receive 50% of the incremental amount. We paid the general
partner incentive distributions totaling $11.1 million for the year ended
December 31, 1998 and $5.6 million for the six months ended June 30, 1999.
For any calendar quarter with respect to which available cash constituting
cash from operations is distributed in respect of both the preference units and
the common units in an amount equal to the minimum quarterly distribution of
$0.275 per unit, plus any preference unit arrearages, then any additional
available cash constituting cash from operations will be allocated between the
general partner and the common unitholders at differing percentage rates, which
increase the share of such additional available cash allocable to the general
partner after common unitholders have received allocations of any such
additional available cash constituting cash from operations between the common
unitholders and the general partner up to the various target distribution level.
The following table illustrates the percentage allocation of distributions
of available cash among the unitholders and our general partner up to the
various target distribution levels.
<TABLE>
<CAPTION>
PERCENT OF MARGINAL
QUARTERLY AVAILABLE CASH DISTRIBUTED TO
DISTRIBUTION -----------------------------
AMOUNT PER COMMON
UNIT UP TO UNITHOLDERS GENERAL PARTNER
------------ ----------- ---------------
<S> <C> <C> <C>
Minimum Quarterly Distribution.................... $0.275 98% 2%
First Target Distribution......................... 0.325 98% 2%
Second Target Distribution........................ 0.375 85% 15%
Third Target Distribution......................... 0.425 75% 25%
Thereafter........................................ -- 50% 50%
</TABLE>
DISTRIBUTIONS OF CASH FROM INTERIM CAPITAL TRANSACTIONS. Distributions on
any date by us of available cash constituting cash from interim capital
transactions will be distributed 98% to preference and common unitholders, pro
rata, and 2% to the general partner until a hypothetical holder of a preference
unit acquired on February 19, 1993 has received with respect to such preference
unit distributions of available cash constituting cash from interim capital
transactions in an amount equal to such preference unit's unrecovered capital
(being $10.25 per preference unit less any amounts previously distributed as
cash from interim capital transactions) plus accrued arrearages, if any.
Thereafter, distributions of available cash that constitute cash from interim
capital transactions will be distributed as if they were cash from operations,
and because the minimum quarterly distribution and first, second and third
target distribution levels will have been reduced to zero as described below,
the general partner's share of distributions of available cash will increase, in
general, to 50% of all distributions of available cash.
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<PAGE> 89
After May 5, 2000, any preference units that have not either been redeemed
or converted into common units and that have received distributions of cash from
interim capital transactions equal to their unrecovered capital plus accrued
arrearages, if any, (1) will receive no further distributions, (2) will be
treated as if they had been redeemed and (3) will cease to be outstanding for
all purposes.
Distributions of cash from interim capital transactions will not reduce the
minimum quarterly distribution in the quarter in which they are distributed.
ADJUSTMENT OF THE MINIMUM QUARTERLY DISTRIBUTION AND TARGET DISTRIBUTION
LEVELS. The minimum quarterly distribution, unrecovered capital per unit and the
first, second and third target distribution levels will be proportionately
adjusted upward or downward, as appropriate, in the event of any combination or
subdivision of preference units (whether effected by a distribution payable in
preference units or otherwise) but not by reason of the issuance of additional
preference units for cash or property. For example, in the event of a
two-for-one split of the preference units (assuming no prior adjustments), then
the minimum quarterly distribution, unrecovered capital for a unit and the
first, second and third target distribution levels would each be reduced to 50%
of its initial level. In addition, if unrecovered capital is reduced as a result
of a distribution of available cash constituting cash from interim capital
transactions, the minimum quarterly distribution and the first, second and third
target distribution levels will be adjusted downward proportionately, by
multiplying each such amount, as the same may have been previously adjusted, by
a fraction, the numerator of which is the unrecovered capital immediately after
giving effect to such distribution and the denominator of which is the
unrecovered capital immediately prior to such distribution. "Unrecovered
capital" means, generally, the amount by which $10.25 per preference unit
exceeds the aggregate distributions of Cash from Interim Capital Transactions
with respect to such unit, as adjusted. For example, the initial unrecovered
capital is $10.25 per unit (which was the initial public offering price per
preference unit, as adjusted for a two-for-one split); if cash from interim
capital transactions of $7.50 per unit is distributed to unitholders (assuming
no prior adjustments), then the amount of the minimum quarterly distribution,
and of each of the target distribution levels, would be reduced to 26.8% of its
initial level. If and when the unrecovered capital is zero, the minimum
quarterly distribution and the first, second and third target distribution
levels each will have been reduced to zero, and the general partner's share of
distributions of available cash will increase, in general, to 50% of all
distributions of available cash.
The minimum quarterly distribution and the first, second and third target
distribution levels may also be adjusted if legislation is enacted or the
interpretation or existing legislation is modified which causes us to become
taxable as a corporation or otherwise subjects Leviathan to taxation as an
entity for federal income tax purposes. In such event, the minimum quarterly
distribution and the first, second and third target distribution levels for each
quarter thereafter would be reduced to an amount equal to the product of (1)
each of the minimum quarterly distribution and the first, second and third
target distribution levels multiplied by (2) one minus the sum of (a) the
estimated effective federal income tax rate to which Leviathan is subject as an
entity plus (b) the estimated effective overall state and local income tax rate
to which Leviathan is subject as an entity for the taxable year in which such
quarter occurs. For example, if we were to become taxable as an entity for
federal income tax purposes and we became subject to a combined estimated
effective federal, state and local income tax rate of 38%, then the minimum
quarterly distribution, and each of the target distribution levels, would be
reduced to 62% of the amount thereof immediately prior to such adjustment.
DISTRIBUTION OF CASH UPON LIQUIDATION. Following the commencement of our
liquidation, our assets will be sold or otherwise disposed of, and the partners'
capital account balances will be adjusted to reflect any resulting gain or loss.
The proceeds of such liquidation will, first, be applied to the payment of our
creditors in the order of priority provided in the partnership agreement and by
law, and thereafter, be distributed to the unitholders and our general partner
in accordance with their respective capital account balances, as so adjusted.
Partners are entitled to liquidation distributions in accordance with
capital account balances. The allocations of gain or loss at the time of
liquidation are intended to entitle the holders of outstanding
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preference units to a preference over the holders of outstanding common units
upon our liquidation, to the extent of their Unrecovered Capital and any
arrearages. However, you cannot be sure that gain or loss will be sufficient to
achieve this result. Preference unitholders will not be entitled to share with
the general partner and common unitholders in our assets in excess of such
Unrecovered Capital and arrearages. The manner of such adjustment is as provided
in the partnership agreement. Any gain (or unrealized gain attributable to
assets distributed in kind) will be allocated to the partners as follows:
- first, to the general partner and the holders of units which have
negative balances in their capital accounts to the extent of and in
proportion to such negative balance;
- second, 98% to the preference unitholders and 2% to the general partner,
until the capital account for each preference unit is equal to the sum of
the Unrecovered Capital in respect of such preference unit plus any
cumulative arrearages then existing in the payment of the minimum
quarterly distribution on such preference unit;
- third, 98% to the common unitholders and 2% to the general partner until
the capital account for each common unit is equal to the Unrecovered
Capital in respect of such common unit;
- fourth, 98% to all unitholders (or, if liquidation occurs after the
second anniversary of the preference unit conversion, to all common
unitholders) and 2% to the general partner until there has been allocated
under this clause fourth an amount per unit equal to (a) the excess of
the first target distribution per unit over the minimum quarterly
distribution per unit for each quarter of our existence, less (b) the
amount per unit of any distributions of available cash constituting cash
from operations in excess of the minimum quarterly distribution per unit
which was distributed 98% to the Common Unitholders and 2% to the general
partner for any quarter of our existence;
- fifth, 85% to all unitholders (or, if liquidation occurs after the second
anniversary of the preference unit conversion, to all common unitholders)
and 15% to the general partner until there has been allocated under this
clause fifth an amount per unit equal to (a) the excess of the second
target distribution per unit over the first target distribution per unit
for each quarter of our existence, less (b) the amount per unit of any
distributions of available cash constituting cash from operations in
excess of the first target distribution per unit which was distributed
85% to the common unitholders and 15% to the general partner for any
quarter of our existence;
- sixth, 75% to all unitholders (or, if liquidation occurs after the second
anniversary of the preference unit conversion, to all common unitholders)
and 25% to the general partner until there has been allocated under this
clause sixth an amount per unit equal to (a) the excess of the third
target distribution per unit over the second target distribution per unit
for each quarter of our existence, less (b) the amount per unit of any
distributions of available cash constituting cash from operations in
excess of the second target distribution per unit which was distributed
75% to the Common Unitholders and 25% to the general partner for any
quarter of our existence; and
- thereafter, 50% to all unitholders (or, if liquidation occurs after the
second anniversary of the preference unit conversion, to all common
unitholders) and 50% to the general partner.
Any loss or unrealized loss will be allocated to the partners: first, in
proportion to the positive balances of the preference unitholders' capital
accounts until the preference unitholders' capital account balances are reduced
to the amount of their Unrecovered Capital plus any arrearages; second, in
proportion to the positive balances in the general partner's and the common
unitholders' capital accounts until the common unitholders' capital accounts are
reduced to zero; third, in proportion to the positive balances in the general
partners' and the preference unitholders' capital accounts until the preference
unitholders' capital accounts are reduced to zero; and thereafter, to the
general partner.
LIMITED CALL RIGHT
If, at any time, non-affiliates of our general partner own 15% or less of
the issued and outstanding units of any class (including common units), then our
general partner may call, or assign to us or its
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affiliates our right to call, such remaining publicly-held units at a purchase
price equal to the greater of (1) the highest cash price paid by our general
partner or its affiliates for any unit purchased within the 90 days preceding
the date our general partner mails notice of the election to call the common
units or (2) the average of the last reported sales price per common unit over
the 20 trading days preceding the date five days before the general partner
mails such notice.
VOTING RIGHTS
Our general partner manages and operates our business. Unlike the holders
of common stock in a corporation, you will have only limited voting rights on
matters affecting our business. You will have no right to elect our general
partner on an annual or other continuing basis. Our general partner may not be
removed except pursuant to the vote of the holders of at least 55.0% of our
outstanding units, including units owned by the general partner and its
affiliates. And to the extent our limited partners do have the right to vote on
a particular matter, our general partner and its affiliates will be able to
exert substantial influence over such vote because of their effective 30.3%
ownership of us. You are entitled to vote only on the following matters:
- a merger or consolidation involving us;
- the sale, exchange or other disposition of all or substantially all of
our assets;
- our conversion into a corporation for tax purposes;
- the transfer of all of our general partner interest (but not the sale of
the general partner);
- the election of any successor general partner upon the current general
partner's withdrawal;
- the removal of our general partner;
- our continuation upon an event of dissolution; and
- certain amendments to our partnership agreement.
In addition, unitholders of record will be entitled to notice of, and to
vote at, meetings of our limited partners and to act with respect to matters as
to which approvals may be solicited. The partnership agreement provides that
units held in nominee or street name account will be voted by the broker (or
other nominee) pursuant to the instruction of the beneficial owner unless the
arrangement between the beneficial owner and his nominee provides otherwise.
PREEMPTIVE AND DISSENTER'S APPRAISAL RIGHTS
Holders of units do not have preemptive rights and do not have dissenters'
rights of appraisal under the partnership agreement or applicable Delaware law
in the event of a merger or consolidation involving us or a sale of
substantially all of our assets.
TRANSFER AGENT AND REGISTRAR
DUTIES. ChaseMellon Shareholder Services acts as the registrar and transfer
agent for the preference and common units and receives a fee from us for serving
in such capacities. All fees charged by the transfer agent for transfers and
withdrawals of units are borne by us and not by the unitholders, except that
fees similar to those customarily paid by stockholders for surety bond premiums
to replace lost or stolen certificates, taxes or other governmental charges,
special charges for services requested by a unitholder and other similar fees or
charges are borne by the affected unitholder. There is no charge to unitholders
for disbursements of our distributions of available cash. We indemnify the
transfer agent and its agents from certain liabilities.
RESIGNATION OR REMOVAL. The transfer agent may at any time resign, by
notice to us, or be removed by us, such resignation or removal to become
effective upon the appointment by our general partner of a successor transfer
agent and registrar and its acceptance of such appointment. If no successor has
been
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appointed and has accepted such appointment with 30 days after notice of such
resignation or removal, our general partner is authorized to act as the transfer
agent and registrar until a successor is appointed.
TRANSFER OF UNITS
Until a unit has been transferred on our books, we and the transfer agent
may treat the record holder thereof as the absolute owner for all purposes,
notwithstanding any notice to the contrary or any notation or other writing on
the certificate representing such unit, except as otherwise required by law. Any
transfer of a unit will not be recorded by the transfer agent or recognized by
us unless certificates representing those units are surrendered. When acquiring
units, the transferee of such units:
- is an assignee until admitted as a substituted limited partner;
- automatically requests admission as a substituted limited partner;
- agrees to be bound by the terms and conditions of, and executes, our
partnership agreement;
- represents that such transferee has the capacity and authority to enter
into our partnership agreement;
- grants powers of attorney to our general partner and any liquidator of
us;
- makes the consents and waivers contained in our partnership agreement;
and
- certifies that such transferee is an eligible U.S. citizen as required by
the FERC.
An assignee will become a limited partner in respect of the transferred
units upon the consent of our general partner and the recordation of the name of
the assignee on our books and records. Such consent may be withheld in the sole
discretion of our general partner. Our units are securities and are transferable
according to the laws governing transfers of securities.
In addition to other rights acquired upon transfer, the transferor gives
the transferee the right to request admission as a substituted limited partner
in respect of the transferred units. A purchaser or transferee of units who does
not become a limited partner obtains only (1) the right to assign the units to a
purchaser or other transferee and (2) the right to transfer the right to seek
admission as a substituted limited partner with respect to the transferred
units. Thus, a purchaser or transferee of units who does not meet the
requirements of limited partner admission will not be the record holder of such
units, will not receive cash distributions unless the units are held in a
nominee or street name account and the nominee or broker has ensured that such
transferee satisfies such requirements of admission with respect to such units
and may not receive certain federal income tax information or reports furnished
to unitholders of record.
LIQUIDATION RIGHTS
Following the commencement of our liquidation, assets will be sold or
otherwise disposed of, and the partners' capital account balances will be
adjusted to reflect any resulting gain or loss. The manner of such adjustment is
as provided in our partnership agreement. The proceeds of any liquidation will,
first, be applied to the payment of our creditors in the order of priority
provided in our partnership agreement and by law, and thereafter, be distributed
to the unitholders and our general partner in accordance with their respective
capital account balances, as so adjusted.
Partners are entitled to liquidation distributions in accordance with
capital account balances. The allocations of gain or loss at the time of
liquidation are intended to entitle the holders of outstanding preference units
to a preference over the holders of outstanding common units upon our
liquidation, to the extent of any unrecovered capital (as defined in our
partnership agreement), and any arrearages, applicable thereto. However, no
assurance can be given that gain or loss will be sufficient to achieve this
result. Further, preference unitholders are not entitled to share with our
general partner and other unitholders in
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our assets in excess of the unrecovered capital and arrearages. Any gain (or
unrealized gain attributable to assets distributed in kind) will be allocated to
our partners as follows:
first, to the general partner and the holders of units which have
negative balances in their capital accounts to the extent of and in
proportion to such negative balance;
second, 98% to the preference unitholders and 2% to the general
partner, until the capital account for each preference unit is equal to
the sum of the unrecovered capital in respect of such preference unit
plus any cumulative arrearages then existing in the payment of the
minimum quarterly distribution on such preference unit.
third, 98% to the common unitholders and 2% to the general partner
until the capital account for each common unit is equal to the
unrecovered capital in respect of such common unit;
fourth, 98% to all unitholders (or, if liquidation occurs after
August, 2000, to all common unitholders) and 2% to our general partner
until there has been allocated under this clause fourth an amount per
unit equal to (a) the excess of the first target distribution per unit
over the minimum quarterly distribution per unit for each quarter of our
existence, less (b) the amount per unit of any distributions of
available cash constituting "cash from operations" (as defined in our
partnership agreement) in excess of the minimum quarterly distribution
per unit which was distributed 98% to our common unitholders and 2% to
our general partner for any quarter of our existence;
fifth, 85% to all unitholders (or, if liquidation occurs after
August, 2000, to all common unitholders) and 15% to our general partner
until there has been allocated under this clause fifth an amount per
unit equal to (a) the excess of the second target distribution per unit
over the first target distribution per unit for each quarter of our
existence, less (b) the amount per unit of any distributions of
available cash constituting cash from operations in excess of the first
target distribution per unit which was distributed 85% to our common
unitholders and 15% to our general partner for any quarter of our
existence;
sixth, 75% to all unitholders (or, if liquidation occurs after
August 2000, to all common unitholders) and 25% to our general partner
until there has been allocated under this clause sixth an amount per
unit equal to (a) the excess of the third target distribution per unit
over the second target distribution per unit for each quarter our
existence, less (b) the amount per unit of any distributions of
available cash constituting cash from operations in excess of the second
target distribution per unit which was distributed 75% to the common
unitholders and 25% to the general partner for any quarter of our
existence; and
thereafter, 50% to all unitholders (or, if liquidation occurs after
August 2000, to all common unitholders) and 50% to our general partner.
Any loss or unrealized loss will be allocated to the partners: first, in
proportion to the positive balances of the preference unitholders' capital
accounts until the preference unitholders' capital account balances are reduced
to the amount of their unrecovered capital plus any arrearages; second, in
proportion to the positive balances in our general partner's and the common
unitholders' capital accounts until the common unitholders' capital account
balances are reduced to zero; third, in proportion to the positive balances in
our general partner's and the preference unitholders' capital accounts until the
preference unitholders' capital accounts are reduced to zero; and thereafter, to
the general partner.
FURTHER ASSESSMENTS
Generally, limited partners will not be liable for assessments in addition
to your initial capital investment in their units. Under certain circumstances,
however, limited partners may be required to repay us amounts wrongfully
returned or distributed to such limited partners. Under Delaware law, a limited
partnership may not make a distribution to a partner to the extent that at the
time of the distribution, after
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giving effect to the distribution, all liabilities of the partnership, other
than liabilities to partners on account of their partnership interests and
nonrecourse liabilities, exceed the fair value of the assets of the limited
partnership. Delaware law provides that a limited partner who receives such a
distribution and knew at the time of the distribution that the distribution
violated the law will be liable to the limited partnership for the amount of the
distribution for three years from the date of the distribution. Under Delaware
law, an assignee who becomes a substitute limited partner of a limited
partnership is liable for the obligations of his assignor to make contributions
to the partnership, except the assignee is not obligated for liabilities that
were unknown to him at the time he became a limited partner and that could not
be ascertained from the partnership agreement.
If it were determined under Delaware law that certain actions which the
limited partners may take under our partnership agreement constituted "control"
of our business, then our limited partners could be held personally liable for
our obligations to the same extent as our general partner.
MODIFICATION OF RIGHTS
In general, amendments which would enlarge the obligations of the limited
partners or the general partner require the consent of the limited partner or
general partner, as applicable. Notwithstanding the foregoing, our partnership
agreement permits our general partner to make certain amendments to our
partnership agreement without the approval of any limited partner, including,
subject to certain limitations, (1) an amendment that in the sole discretion of
our general partner is necessary or desirable in connection with the
authorization of additional preference units or other equity securities, (2) any
amendment made, the effect of which is to separate into a separate security,
separate and apart from the units, the right of preference unitholders to
receive any arrearage, and (3) several other amendments expressly permitted in
our partnership agreement to be made by our general partner acting alone.
In addition, our general partner may make amendments to our partnership
agreement without the approval of any limited partner if such amendments do not
adversely affect the limited partners in any material respect, or are required
by law or by our partnership agreement.
RELATIONSHIP TO PREFERENCE UNITS
As of August 25, 1999, there were 291,299 preference units outstanding.
Preference units have certain rights which are superior to those of common
units. These rights include:
- the right to receive a cumulative minimum quarterly distribution of
available cash of $0.275 (plus any arrearages) per preference unit before
the common units may receive any quarterly distribution; and
- a liquidation preference of the unrecovered capital per preference
unit--that is, if we are liquidated, each preference unit must receive a
liquidating distribution equal to its unrecovered capital (plus any
arrearages on the minimum quarterly distributions) before the common
units may receive any liquidating distribution.
RELATIONSHIP TO OTHER UNITS
As of August 25, 1999, there were 26,737,465 common units outstanding.
Common units have certain rights which are superior to those of other units that
may be issued in the future. These rights include:
- the right to receive a cumulative minimum quarterly distribution of
available cash of $0.275 (plus any arrearages) per common unit before the
other units may receive any quarterly distribution; and
- a liquidation preference of the unrecovered capital per common unit--that
is, if we are liquidated, each common unit must receive a liquidating
distribution equal to its unrecovered capital (plus any arrearages on the
minimum quarterly distributions) before the other units may receive any
liquidating distribution.
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CERTAIN OTHER PARTNERSHIP AGREEMENT PROVISIONS
The following paragraphs are a summary of certain provisions of our
partnership agreement. The following discussion is qualified in its entirety by
reference to our partnership agreement.
PURPOSE
Our stated purposes under our partnership agreement are to serve as the
managing member of our subsidiaries and to engage in any business activity
permitted under Delaware law. Our general partner is generally authorized to
perform all acts deemed necessary to carry out these purposes and to conduct our
business. Our partnership existence will continue until December 31, 2043,
unless sooner dissolved pursuant to the terms of our partnership agreement.
AUTHORITY OF OUR GENERAL PARTNER
Our general partner has a power of attorney to take certain actions,
including the execution and filing of documents, on our behalf and with respect
to our partnership agreement. However, our partnership agreement limits the
authority of our general partner as follows:
- Without the prior approval of holders of at least a majority of our
units, our general partner may not, among other things, (a) sell or
exchange all or substantially all of our assets (whether in a single
transaction or a series of related transactions) or (b) approve on our
behalf the sale, exchange or other disposition of all or substantially
all of our assets; however, we may mortgage, pledge, hypothecate or grant
a security interest in all or substantially all of our assets without
such approval;
- With certain exceptions generally described below under "--Amendment of
Partnership Agreement," an amendment to a provision of our partnership
agreement generally requires the approval of the holders of at least
66 2/3% of the outstanding units;
- With certain exceptions described below, any amendment that would
materially and adversely affect the rights and preference of any type or
class of partnership interests in relation to other types or classes of
partnership interests will require the approval of the holders of at
least a majority of such type or class of partnership interest (excluding
those held by our general partner and its affiliates); and
- In general, our general partner may not take any action, or refuse to
take any reasonable action, the effect of which would be to cause us to
be taxable as a corporation or to be treated as an association taxable as
a corporation for federal income tax purposes, without the consent of the
holders of at least 66 2/3% of the outstanding units, including the vote
of the holders of a majority of the preference units (other than
preference units held by our general partner and its affiliates).
WITHDRAWAL OR REMOVAL OF OUR GENERAL PARTNER
Our general partner has agreed not to voluntarily withdraw the general
partner on or prior to December 31, 2002 (with limited exceptions described
below) without the approval of at least a majority of the remaining outstanding
units and an opinion of counsel that (following the selection of a successor)
its withdrawal would not result in the loss of limited liability or cause us to
be taxed as an entity for federal income tax purposes. However, our general
partner may withdraw without such approval of the unitholders, upon 90 days'
notice, if more than 50.0% of the outstanding preference units are held or
controlled by one person and its affiliates other than the withdrawing general
partner and its affiliates.
After December 31, 2002, our general partner may withdraw by giving 90
days' written notice. If an appropriate opinion of counsel cannot be obtained,
we would be dissolved as a result of such withdrawal.
Our general partner may not be removed, with or without cause, as general
partner except upon approval by the affirmative vote of the holders of not less
than 55.0% of the outstanding units, subject to the satisfaction of certain
conditions.
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In the event of withdrawal of our general partner where such withdrawal
violates our partnership agreement or removal of our general partner for
"cause," a successor general partner will have the option to acquire the general
partner interest of the departing general partner (the "Departing Partner") and,
if requested by the Departing Partner, its nonmanaging member interests in our
subsidiaries, for a fair market value cash payment. Under all other
circumstances where our general partner withdraws or is removed by our limited
partners, the Departing Partner will have the option to require the successor
general partner to acquire the general partner and nonmanaging member interests
of the Departing Partner for a fair market value cash payment.
Our general partner may transfer all, but not less than all, of its general
partner interest and its nonmanaging interests in our subsidiaries without the
approval of our limited partners (1) to an affiliate of our general partner or
(2) upon its merger or consolidation into another entity or the transfer of all
or substantially all of its assets to another entity. In the case of any other
transfer, in addition to the foregoing requirements, the approval of the holders
of at least a majority of the outstanding units is required, excluding for
purposes of such determination units held by our general partner and its
affiliates. However, no approval of the unitholders is required for transfers of
the stock or other securities representing equity interest in our general
partner.
REDEMPTION AND LIMITED CALL RIGHT
After approximately August 2000, any or all of the outstanding preference
units may be redeemed at any time at our option, exercised in the sole
discretion of our general partner, upon at least 30 but not more than 60 days'
notice. If, after giving effect to an anticipated redemption, fewer than
1,000,000 preference units would be held by persons other than our general
partner and its affiliates, we must redeem all such preference units if we
redeem any preference units. The redemption price for each preference unit would
be the amount of the "unrecovered capital," which is $10.25 as of the date of
this prospectus. Unrecovered capital is more particularly defined in our
partnership agreement, but generally is the difference between $10.25 less the
amount of available cash from interim capital transactions that has been
distributed to a hypothetical preference unit issued on February 19, 1993.
If, at any time, non-affiliates of our general partner own 15% or less of
the issued and outstanding units of any class (including common units), then our
general partner may call, or assign to us or its affiliates our right to call,
such remaining publicly-held units at a purchase price equal to the greater of
(1) the highest cash price paid by our general partner or its affiliates for any
unit purchased within the 90 days preceding the date our general partner mails
notice of the election to call the common units or (2) the average of the last
reported sales price per common unit over the 20 trading days preceding the date
five days before the general partner mails such notice.
AMENDMENT OF PARTNERSHIP AGREEMENT
Amendments to our partnership agreement may be proposed only by our general
partner. Proposed amendments (other than those described below) must be approved
by holders of at least 66 2/3% of the outstanding units, except (1) that any
amendment that would have a disproportionate material adverse effect on a class
of units will require the approval of the holders of at least a majority of the
outstanding units (excluding those held by the general partner and its
affiliates) of the class so affected or (2) as otherwise provided in our
partnership agreement. No provision of our partnership agreement that
establishes a percentage of outstanding units required to take any action may be
amended or otherwise modified to reduce such voting requirement without the
approval of the holders of that percentage of outstanding units constituting the
voting requirement sought to be amended.
In general, amendments which would enlarge the obligations of any type or
class of our limited partners or our general partner require the consent of such
limited partners or general partner, as applicable. Notwithstanding the
foregoing, our partnership agreement permits our general partner to make certain
amendments to our partnership agreement without the approval of any limited
partner, including, subject to certain limitations, (1) an amendment that in the
sole discretion of our general partner is
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necessary or desirable in connection with the authorization of additional
preference units or other equity securities, (2) any amendment made, the effect
of which is to separate into a separate security, separate and apart from the
units, the right of preference unitholders to receive any arrearage, and (3)
several other amendments expressly permitted in our partnership agreement to be
made by our general partner acting alone.
In addition, our general partner may make amendments to our partnership
agreement without the approval of any limited partner if such amendments do not
adversely affect the limited partners in any material respect, or are required
by law or by our partnership agreement.
No other amendments to our partnership agreement will become effective
without the approval of at least 95.0% of the units unless we obtain an opinion
of counsel to the effect that such amendment will not cause us to be taxable as
a corporation or otherwise taxed as an entity for federal income tax purposes
and will not affect the limited liability of any limited partner or any member
of our subsidiaries.
MEETINGS; VOTING
Record holders of units on the record date set pursuant to our partnership
agreement will be entitled to notice of, and to vote at, meetings of limited
partners. Meetings of our limited partners may only be called by our general
partner or, with respect to meetings called to remove our general partner, by
limited partners owning 55% or more of the outstanding units.
Representation in person or by proxy of two-thirds (or a majority, if that
is the vote required to take action at the meeting in question) of the
outstanding units of the class for which a meeting is to be held will constitute
a quorum at a meeting of limited partners. Except for (a) a proposal for removal
or withdrawal of our general partner, (b) the sale of all or substantially all
of our assets or (c) certain amendments to our partnership agreement described
above, substantially all matters submitted for a vote are determined by the
affirmative vote, in person or by proxy, of holders of at least a majority of
the outstanding units.
Each record holder of a unit has one vote per unit, according to his
percentage interest in us. However, our partnership agreement does not restrict
our general partner from issuing units having special or superior voting rights.
INDEMNIFICATION
Our partnership agreement provides that we:
- will indemnify our general partner, any Departing Partner and any person
who is or was an officer, director or other representative of our general
partner, any Departing Partner or us, to the fullest extent permitted by
law, and
- may indemnify, to the fullest extent permitted by law, (a) any person who
is or was an affiliate of our general partner, any Departing Partner or
us, (b) any person who is or was an employee, partner, agent or trustee
of our general partner, any Departing Partner, us or any such affiliate,
or (c) any person who is or was serving at our request as an officer,
director, employee, partner, member, agent or other representative of
another corporation, partnership, joint venture, trust, committee or
other enterprise;
(each, as well as any employee, partner, agent or other representative of our
general partner, any Departing Partner, us or any of their affiliates, an
"Indemnitee") from and against any and all claims, damages, expenses and fines,
whether civil, criminal, administrative or investigative, in which any
Indemnitee may be involved, or is threatened to be involved, as a party or
otherwise, by reason of its status as (1) our general partner, Departing
Partner, us or an affiliate of either, (2) an officer, director, employee,
partner, agent, trustee or other representative of our general partner, any
Departing Partner, us or any of their affiliates or (3) a person serving at our
request in any other entity in a similar capacity. Indemnification will be
conditioned on the determination that, in each case, the Indemnitee acted in
good
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faith, in a manner which such Indemnitee believed to be in, or not opposed to,
our best interests and, with respect to any criminal proceeding, had no
reasonable cause to believe its conduct was unlawful.
The above indemnification may result in indemnification of Indemnitees for
negligent acts, and may include indemnification for liabilities under the
Securities Act. We have been advised that, in the opinion of the Securities and
Exchange Commission, such indemnification is against public policy as expressed
in the Securities Act and is, therefore, unenforceable. Any indemnification
under these provisions will be only out of our assets. We are authorized to
purchase (or to reimburse our general partner or its affiliates for the cost of)
insurance against liabilities asserted against and expenses incurred by such
persons in connection with our activities, whether or not we would have the
power to indemnify such person against such liabilities under the provisions
described above.
GENERAL PARTNER EXPENSES
Our general partner will be reimbursed for its direct and indirect expenses
incurred on our behalf on a monthly or other appropriate basis as provided for
in our partnership agreement, including, without limitation, expenses allocated
to the general partner by its affiliates and payments made by our general
partner to El Paso Energy and its affiliates pursuant to the management
agreement.
CONVERSION OF PREFERENCE UNITS INTO COMMON UNITS.
From May 14, 1999 until August 12, 1999, the holders of our 1,016,906
outstanding preference units had the right to convert their preference units
into an equal number of common units. Holders of 725,607 preference units
elected to convert, and holders of 291,299 preference units elected not to
convert. This was the second conversion opportunity that we offered to holders
of preference units. The third and final conversion option period will occur
during substantially the same period in 2000.
During the first and second conversion opportunities, which occurred in
1998 and 1999, the holders of 17,783,701 preference units, representing
approximately 98.0% of the preference units issued by us, converted their
preference units into common units. As a result of that conversion, the common
units then (including the 8,953,764 common units held by our general partner and
its affiliates) have become the primary listed security on the NYSE under the
symbol "LEV". A total of 291,299 preference units remain outstanding and now
trade as our secondary listed security on the NYSE under the symbol "LEV.P".
LIMITED LIABILITY
Assuming that a limited partner does not take part in the control of our
business, and that he otherwise acts in conformity with the provisions of our
partnership agreement, his liability under Delaware law will be limited, subject
to certain possible exceptions, generally to the amount of capital he is
obligated to contribute to us in respect of his units plus his share of any of
our undistributed profits and assets.
TERMINATION, DISSOLUTION AND LIQUIDATION
Our partnership existence will continue until December 31, 2043, unless
sooner terminated pursuant to our partnership agreement. We will be dissolved
upon (a) the election of our general partner, if approved by the holders of at
least 66 2/3% of the outstanding units, (b) the sale, exchange or other
disposition of all or substantially all of our assets and properties, (c)
bankruptcy or dissolution of our general partner or (d) withdrawal or removal of
our general partner or any other event that results in its ceasing to be our
general partner (other than by reason of transfer in accordance with our
partnership agreement or withdrawal or removal following approval of a
successor). Notwithstanding the foregoing, we will not be dissolved if within 90
days after such event our partners agree in writing to continue our business and
to the appointment, effective as of the date of such event, of a successor
general partner.
Upon a dissolution pursuant to clause (c) or (d) above, the holders of at
least 66 2/3% of the outstanding units may also elect, within certain time
limitations, to reconstitute and continue our business on the same terms and
conditions set forth in our partnership agreement by forming a new limited
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partnership on terms identical to those set forth in our partnership agreement
and having as a general partner an entity approved by the holders of at least
66 2/3% of the outstanding units, subject to our receipt of an opinion of
counsel that such reconstitution, continuation and approval will not result in
the loss of the limited liability of unitholders or cause us, the reconstituted
limited partnership or our subsidiaries to be taxable as a corporation or
otherwise subject to taxation as an entity for federal income tax purposes.
Upon our dissolution, unless we are reconstituted and continue as a new
limited partnership, a liquidator will liquidate our assets and apply the
proceeds of the liquidation in the order of priority set forth in our
partnership agreement. The liquidator may defer liquidation or distribution of
our assets and/or distribute assets to partners in kind if it determines that a
sale or other disposition of our assets would be unsuitable.
OTHER UNITHOLDER RIGHTS AND OBLIGATIONS
In addition to the information above, you will find other rights and
obligations arising under our partnership agreement described in this prospectus
in the sections entitled "The Offering" beginning on page 7 and "Description of
Common Units" beginning on page 81.
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INCOME TAX CONSIDERATIONS
The tax consequences to you of an investment in common units will depend in
part on your own tax circumstances. You should therefore consult your own tax
advisor about the federal, state, local and foreign tax consequences to you of
an investment in common units.
This section is a summary of material tax considerations that may be
relevant to prospective unitholders and, to the extent set forth below under
"--Legal Opinions and Advice," expresses the opinion of Akin, Gump, Strauss,
Hauer & Feld, L.L.P., counsel to us and our general partner, insofar as it
relates to matters of law and legal conclusions. This section is based upon
current provisions of the Internal Revenue Code of 1986, as amended (the
"Code"), existing and proposed regulations thereunder and current administrative
rulings and court decisions, all of which are subject to change, possibly
retroactively. Subsequent changes in such authorities may cause the tax
consequences to vary substantially from the consequences described below.
No attempt has been made in the following discussion to comment on all
federal income tax matters affecting us or you. Moreover, the discussion focuses
on unitholders who are individual citizens or residents of the U.S. and has only
limited application to corporations, estates, trusts, non-resident aliens or
other unitholders subject to specialized tax treatment (such as tax-exempt
institutions, foreign persons, individual retirement accounts, REITs or mutual
funds). Accordingly, you should consult, and should depend on, your own tax
advisor in analyzing the federal, state, local and foreign tax consequences
peculiar to you of the ownership or disposition of units.
LEGAL OPINIONS AND ADVICE
Our counsel is of the opinion that, based on the accuracy of the
representations and subject to the qualifications set forth in the detailed
discussion that follows, for federal income tax purposes (1) we will be treated
as a partnership, and (2) owners of units (with certain exceptions, as described
in "--Limited Partner Status" below) will be treated as our partners. In
addition, all statements as to matters of law and legal conclusions contained in
this section, unless otherwise noted, reflect the opinion of our counsel.
We have not requested and will not request a ruling from the IRS, and the
IRS has made no determination, with respect to the foregoing issues or any other
matter affecting us or you. An opinion of counsel represents only that counsel's
best legal judgment and does not bind the IRS or the courts. Thus, no assurance
can be provided that, if contested by the IRS, a court would agree with the
opinions and statements set forth herein. Any such contest with the IRS may
materially and adversely impact the market for our units and the prices at which
they trade. In addition, the costs of any contest with the IRS will be borne
directly or indirectly by the unitholders and our general partner. Furthermore,
no assurance can be given that our treatment or the treatment of an investment
in us will not be significantly modified by future legislative or administrative
changes or court decisions. Any such modification may or may not be
retroactively applied.
For the reasons hereinafter described, our counsel has not rendered an
opinion with respect to the following specific federal income tax issues:
(1) the treatment of a unitholder whose units are loaned to a short seller
to cover a short sale of units (see "--Tax Treatment of
Operations--Treatment of Short Sales"),
(2) whether a unitholder acquiring units in separate transactions must
maintain a single aggregate adjusted tax basis in his units (see
"--Disposition of Units--Recognition of Gain or Loss"),
(3) whether our monthly convention for allocating taxable income and losses
is permitted by existing Treasury Regulations (see "--Disposition of
Units--Allocations Between Transferors and Transferees"), and;
(4) whether our method for depreciating Section 743 adjustments is
sustainable (see "--Tax Treatment of Operations--Section 754
Election").
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TAX RATES
The top effective income tax rate for individuals for 1999 is 39.6%. In
general, net capital gains of an individual are subject to a maximum 20% tax
rate if the asset giving rise to gain was held for more than 12 months at the
time of disposition.
PARTNERSHIP STATUS
A partnership is not a taxable entity and incurs no federal income tax
liability. Instead, each partner of a partnership is required to take into
account his allocable share of items of income, gain, loss and deduction of the
partnership in computing his federal income tax liability, regardless of whether
cash distributions are made. Distributions by a partnership to a partner are
generally not taxable unless the amount of cash distributed is in excess of the
partner's adjusted basis in his partnership interest immediately before the
distribution.
We have not requested and will not request a ruling from the IRS, and the
IRS has made no determination, as to our status as a partnership for federal
income tax purposes. Instead we have relied on the opinion of our counsel that,
based upon the Code, the regulations thereunder, published revenue rulings and
court decisions, we will be classified as a partnership for federal income tax
purposes.
In rendering its opinion, our counsel has relied on certain factual
representations made by us and our general partner. Such factual matters are as
follows:
- We will not elect to be treated as an association or corporation;
- We will be operated in accordance with (1) all applicable partnership
statutes, (2) our partnership agreement, and (3) the description thereof
in this prospectus;
- For each taxable year, more than 90% of our gross income will be income
from sources that our counsel has opined or may opine is "qualifying
income" within the meaning of Section 7704(d) of the Code;
- Each futures contract entered into by us for the purchase or sale of
natural gas or crude oil will be identified as a hedging transaction
pursuant to Treasury Regulation Section 1.1221-2(e)(1); and
- Gain or loss resulting from our future transactions will be treated as an
adjustment in the computation of cost of goods sold with respect to sales
of crude oil for federal income tax purposes.
- Prior to January 1, 1997 our general partner had at all times while
acting as our general partner either (i) in the aggregate as a general
and limited partner at least a 20% interest in the capital and 19% of our
outstanding units and will be acting for its own account and not as a
mere agent of the limited partners, or (ii) assets (excluding any
interest in, or notes or receivables due from, us or our operating
subsidiaries), the fair market value of which exceeds its liabilities by
the amount of at least 5% of the fair market value of all partnership
interests outstanding immediately after the initial public offering of
preference units, plus 5% of any additional net capital contributions to
us made after the initial public offering.
- Prior to January 1, 1992, except as otherwise required by Section 704 of
the code, our general partner had an interest in each material item of
our and our operating subsidiaries' income, gain, loss, deduction and
credit equal to at least 1% at all times during our existence and the
existence of our operating companies.
- Prior to January 1, 1992 our general partner has acted independently of
our limited partners.
Section 7704 of the Code provides that publicly-traded partnerships will,
as a general rule, be taxed as corporations. However, an exception (the
"Qualifying Income Exception") exists with respect to publicly-traded
partnerships of which 90% or more of the gross income for every taxable year
consists of "qualifying income." Qualifying income includes income and gains
derived from the transportation and
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marketing, processing, production and development of, and exploration for,
natural gas and crude oil, among other activities. Other types of qualifying
income include interest (from other than a financial business), dividends, gains
from the sale of real property and gains from the sale or other disposition of
capital assets held for the production of income that otherwise constitutes
qualifying income. Based upon our representations and the representations of our
general partner and a review of the applicable legal authorities, our counsel is
of the opinion that at least 90% of our gross income will constitute qualifying
income. We estimate that less than 5.0% of our gross income for each taxable
year will not constitute qualifying income.
If we fail to meet the Qualifying Income Exception (other than a failure
which is determined by the IRS to be inadvertent and which is cured within a
reasonable time after discovery), we will be treated as if we had transferred
all of our assets (subject to liabilities) to a newly formed corporation (on the
first day of the year in which we fail to meet the Qualifying Income Exception)
in return for stock in that corporation, and then distributed that stock to our
partners in liquidation of their interests in us. This contribution and
liquidation should be tax-free to us and unitholders, so long as we, at that
time, do not have liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal income tax
purposes.
If we were taxable as a corporation in any taxable year, either as a result
of a failure to meet the Qualifying Income Exception or otherwise, our items of
income, gain, loss and deduction would be reflected only on our tax return
rather than being passed through to the unitholders, and our net income would be
taxed to us at corporate rates. In addition, any distribution made to a
unitholder would be treated as either taxable dividend income (to the extent of
our current or accumulated earnings and profits) or (in the absence of earnings
and profits) a nontaxable return of capital (to the extent of the unitholder's
tax basis in his units) or taxable capital gain (after the unitholder's tax
basis in his units is reduced to zero). Accordingly, taxation as a corporation
would result in a material reduction in a unitholder's cash flow and after-tax
return and thus would likely result in a substantial reduction of the value of
the units.
The discussion below is based on the assumption that we will be classified
as a partnership for federal income tax purposes.
LIMITED PARTNER STATUS
Unitholders who have become our limited partners will be treated as our
partners for federal income tax purposes. Our counsel is also of the opinion
that (a) assignees who have executed and delivered transfer applications and are
awaiting admission as limited partners and (b) unitholders whose units are held
in street name or by a nominee and who have the right to direct the nominee in
the exercise of all substantive rights attendant to the ownership of their units
will be treated as our partners for federal income tax purposes. As there is no
direct authority addressing assignees of units who are entitled to execute and
deliver transfer applications and thereby become entitled to direct the exercise
of attendant rights, but who fail to execute and deliver transfer applications,
our counsel's opinion does not extend to these persons. Furthermore, a purchaser
or other transferee of units who does not execute and deliver a transfer
application may not receive certain federal income tax information or reports
furnished to record holders of units unless the units are held in a nominee or
street name account and the nominee or broker has executed and delivered a
transfer application with respect to such units.
A beneficial owner of units whose units have been transferred to a short
seller to complete a short sale would appear to lose his status as a partner
with respect to such units for federal income tax purposes. See "--Tax Treatment
of Operations--Treatment of Short Sales."
Income, gain, deductions or losses would not appear to be reportable by a
unitholder who is not a partner for federal income tax purposes, and any cash
distributions received by such a unitholder would therefore be fully taxable as
ordinary income. These holders should consult their own tax advisors with
respect to their status as our partners for federal income tax purposes.
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TAX CONSEQUENCES OF UNIT OWNERSHIP
FLOW-THROUGH OF TAXABLE INCOME
We will pay no federal income tax. Instead, each unitholder will be
required to report on his income tax return his allocable share of our income,
gains, losses and deductions without regard to whether corresponding cash
distributions are received by him. Consequently, we may allocate income to a
unitholder even if he has not received a cash distribution. Each unitholder will
be required to include in income his allocable share of our income, gain, loss
and deduction for our taxable year ending with or within the taxable year of the
unitholder.
TREATMENT OF PARTNERSHIP DISTRIBUTIONS
Distributions by us to a unitholder generally will not be taxable to him
for federal income tax purposes to the extent of his tax basis in his units
immediately before the distribution.
Cash distributions in excess of a unitholder's tax basis generally will be
considered to be gain from the sale or exchange of the units, taxable in
accordance with the rules described under "--Disposition of Units" below. Any
reduction in a unitholder's share of our liabilities for which no partner,
including the general partner, bears the economic risk of loss ("nonrecourse
liabilities") will be treated as a distribution of cash to that unitholder. To
the extent that our distributions cause a unitholder's "at risk" amount to be
less than zero at the end of any taxable year, he must recapture any losses
deducted in previous years. See "--Limitations on Deductibility of Partnership
Losses."
A decrease in a unitholder's percentage interest in us because of our
issuance of additional units will decrease his share of our nonrecourse
liabilities and, thus will result in a corresponding deemed distribution of
cash. A non-pro rata distribution of money or property may result in ordinary
income to a unitholder, regardless of his tax basis in his units, if the
distribution reduces his share of our "unrealized receivables" (including
depreciation recapture) and/or substantially appreciated "inventory items" (both
as defined in Section 751 of the Code) (collectively, "Section 751 Assets"). To
that extent, he will be treated as having been distributed his proportionate
share of the Section 751 Assets and having exchanged those assets with us in
return for the non-pro rata portion of the actual distribution made to him. This
latter deemed exchange will generally result in the unitholder's realization of
ordinary income under Section 751(b) of the Code. This income will equal the
excess of (1) the non-pro rata portion of the distribution over (2) the
unitholder's tax basis for the share of the Section 751 Assets deemed
relinquished in the exchange.
RATIO OF TAXABLE INCOME TO DISTRIBUTIONS
We estimate that a purchaser of units in this offering who owns those units
from the date of the closing of this offering through December 31, 2001 will be
allocated, on a cumulative basis, an amount of federal taxable income for such
period that will be approximately 30% of the cash distributed with respect to
that period. We further estimate that for taxable years after the taxable year
ending December 31, 2001 the taxable income allocable to those unitholders may
constitute a significantly higher percentage of cash distributed to them. The
foregoing estimates are based upon the assumption that gross income from
operations will approximate the amount required to make the minimum quarterly
distribution with respect to all units and other assumptions with respect to
capital expenditures, cash flow and anticipated cash distributions. These
estimates and assumptions are subject to, among other things, numerous business,
economic, regulatory, competitive and political uncertainties beyond our
control. Further, the estimates are based on current tax law and certain tax
reporting positions that we have adopted and with which the IRS could disagree.
Accordingly, you cannot be sure that the estimates will prove to be correct. The
actual percentage could be higher or lower, and any such differences could be
material and could materially affect the value of the units.
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BASIS OF UNITS
A unitholder's initial tax basis for his units will be the amount he paid
for the units plus his share of our nonrecourse liabilities. That basis will be
increased by his share of our income and by any increases in his share of our
nonrecourse liabilities. That basis will be decreased (but not below zero) by
distributions from us to him, by his share of our losses, by any decrease in his
share of our nonrecourse liabilities and by his share of our expenditures that
are not deductible in computing its taxable income and are not required to be
capitalized. A limited partner will have no share of our debt which is recourse
to the general partner, but will have a share, generally based on his share of
profits, of our nonrecourse liabilities. See "--Disposition of
Units--Recognition of Gain or Loss."
LIMITATIONS ON DEDUCTIBILITY OF PARTNERSHIP LOSSES
The deduction by a unitholder of his share of our losses will be limited to
the tax basis in his units and, in the case of an individual unitholder or a
corporate unitholder (if more than 50% of the value of its stock is owned
directly or indirectly by five or fewer individuals or certain tax-exempt
organizations), to the amount for which the unitholder is considered to be "at
risk" with respect to our activities, if that is less than his tax basis. A
unitholder must recapture losses deducted in previous years to the extent that
our distributions cause his at risk amount to be less than zero at the end of
any taxable year. Losses disallowed to a unitholder or recaptured as a result of
these limitations will carry forward and will be allowable to the extent that
his tax basis or at risk amount (whichever is the limiting factor) is
subsequently increased. Upon the taxable disposition of a unit, any gain
recognized by a unitholder can be offset by losses that were previously
suspended by the at risk limitation but may not be offset by losses suspended by
the basis limitation. Any excess loss (above such gain) previously suspended by
the at risk or basis limitations is no longer utilizable.
In general, a unitholder will be at risk to the extent of the tax basis of
his units, excluding any portion of that basis attributable to his share of our
nonrecourse liabilities, reduced by any amount of money he borrows to acquire or
hold his units if the lender of such borrowed funds owns an interest in us, is
related to such a person or can look only to units for repayment. A unitholder's
at risk amount will increase or decrease as the tax basis of his units increases
or decreases (other than tax basis increases or decreases attributable to
increases or decreases in his share of our nonrecourse liabilities).
The passive loss limitations generally provide that individuals, estates,
trusts and certain closely-held corporations and personal service corporations
can deduct losses from passive activities (generally, activities in which the
taxpayer does not materially participate) only to the extent of the taxpayer's
income from those passive activities. The passive loss limitations are applied
separately with respect to each publicly-traded partnership. Consequently, any
passive losses generated by us will only be available to offset future income
generated by us and will not be available to offset income from other passive
activities or investments (including other publicly-traded partnerships) or
salary or active business income. Passive losses which are not deductible
because they exceed a unitholder's income generated by us may be deducted in
full when he disposes of his entire investment in us in a fully taxable
transaction to an unrelated party. The passive activity loss rules are applied
after other applicable limitations on deductions such as the at risk rules and
the basis limitation.
A unitholder's share of our net income may be offset by any suspended
passive losses from us, but it may not be offset by any other current or
carryover losses from other passive activities, including those attributable to
other publicly-traded partnerships. The IRS has announced that Treasury
Regulations will be issued which characterize net passive income from a
publicly-traded partnership as investment income for purposes of the limitations
on the deductibility of investment interest.
LIMITATIONS ON INTEREST DEDUCTIONS
The deductibility of a non-corporate taxpayer's "investment interest
expense" is generally limited to the amount of such taxpayer's "net investment
income." As noted, a unitholder's net passive income from us will be treated as
investment income for this purpose. In addition, a unitholder's share of our
portfolio
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income will be treated as investment income. Investment interest expense
includes (1) interest on indebtedness properly allocable to property held for
investment, (2) our interest expense attributed to portfolio income, and (3) the
portion of interest expense incurred to purchase or carry an interest in a
passive activity to the extent attributable to portfolio income. The computation
of a unitholder's investment interest expense will take into account interest on
any margin account borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held for investment
and amounts treated as portfolio income pursuant to the passive loss rules less
deductible expenses (other than interest) directly connected with the production
of investment income, but generally does not include gains attributable to the
disposition of property held for investment.
ALLOCATION OF PARTNERSHIP INCOME, GAIN, LOSS AND DEDUCTION
In general, if we have a net profit, items of income, gain, loss and
deduction will be allocated among the general partner and the unitholders in
accordance with their respective percentage interests in us. At any time that
distributions are made to the preference units and not to the common units, or
that incentive distributions are made to our general partner, gross income will
be allocated to the recipients to the extent of such distribution. If we have a
net loss, items of income, gain, loss and deduction will generally be allocated
first, to our general partner and the unitholders in accordance with their
respective percentage interests to the extent of their positive capital accounts
(as maintained under the partnership agreement) and, second, to our general
partner.
As required by Section 704(c) of the Code and as permitted by Regulations
thereunder, certain items of our income, deduction, gain and loss will be
allocated to account for the difference between the tax basis and fair market
value of property contributed to us by our general partner or others
("Contributed Property"). The effect of these allocations to a unitholder will
be essentially the same as if the tax basis of the Contributed Property were
equal to its fair market value at the time of contribution. In addition, certain
items of recapture income will be allocated to the extent possible to the
partner allocated the deduction giving rise to the treatment of such gain as
recapture income in order to minimize the recognition of ordinary income by some
unitholders. Finally, although we do not expect that our operations will result
in the creation of negative capital accounts, if negative capital accounts
nevertheless result, items of our income and gain will be allocated in an amount
and manner sufficient to eliminate the negative balance as quickly as possible.
Regulations provide that an allocation of items of partnership income,
gain, loss or deduction, other than an allocation required by Section 704(c) of
the Code to eliminate the difference between a partner's "book" capital account
(credited with the fair market value of Contributed Property) and "tax" capital
account (credited with the tax basis of Contributed Property) (the "Book-Tax
Disparity"), will generally be given effect for federal income tax purposes in
determining a partner's distributive share of an item of income, gain, loss or
deduction only if the allocation has substantial economic effect. In any other
case, a partner's distributive share of an item will be determined on the basis
of the partner's interest in the partnership, which will be determined by taking
into account all the facts and circumstances, including the partners' relative
contributions to the partnership, the interests of the partners in economic
profits and losses, the interest of the partners in cash flow and other
nonliquidating distributions and rights of the partners to distributions of
capital upon liquidation.
Our counsel is of the opinion that allocations under our partnership
agreement will be given effect for federal income tax purposes in determining a
unitholder's distributive share of an item of income, gain, loss or deduction.
TAX TREATMENT OF OPERATIONS
ACCOUNTING METHOD AND TAXABLE YEAR
We use the year ending December 31 as our taxable year and have adopted the
accrual method of accounting for federal income tax purposes. Each unitholder
will be required to include in income his allocable share of partnership income,
gain, loss and deduction for our taxable year ending within or with
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the taxable year of the unitholder. In addition, a unitholder who has a taxable
year ending on a date other than December 31 and who disposes of all of his
units following the close of our taxable year but before the close of his
taxable year must include his allocable share of our income, gain, loss and
deduction in income for his taxable year with the result that he will be
required to report in income for his taxable year his distributive share of more
than one year of our income, gain, loss and deduction. See "--Disposition of
Units--Allocations Between Transferors and Transferees."
INITIAL TAX BASIS, DEPRECIATION AND AMORTIZATION
The tax basis of our various assets will be used for purposes of computing
depreciation and cost recovery deductions and, ultimately, gain or loss on the
disposition of such assets. Our assets initially have an aggregate tax basis
equal to the consideration we paid for such assets or, with respect to assets we
acquired upon our formation or by contribution, the tax basis of the assets in
the possession of our general partner or other contributor immediately prior to
our formation. The federal income tax burden associated with the difference
between the fair market value of property contributed by our general partner or
other contributor and the tax basis established for such property will be borne
by our general partner or other contributor. See "--Allocation of Partnership
Income, Gain, Loss and Deduction."
To the extent allowable, we may elect to use the depletion, depreciation
and cost recovery methods that will result in the largest deductions in our
early years. We are not be entitled to any amortization deductions with respect
to any goodwill conveyed to us on formation. Property subsequently acquired or
constructed by us may be depreciated using accelerated methods permitted by the
Code.
If we dispose of depreciable property by sale, foreclosure or otherwise,
all or a portion of any gain (determined by reference to the amount of
depreciation previously deducted and the nature of the property) may be subject
to the recapture rules and taxed as ordinary income rather than capital gain.
Similarly, a partner who has taken cost recovery or depreciation deductions with
respect to our property may be required to recapture such deductions as ordinary
income upon a sale of his units. See "--Allocation of Partnership Income, Gain,
Loss and Deduction" and "--Disposition of Units--Recognition of Gain or Loss."
The costs incurred in promoting the issuance of units (i.e. syndication
expenses) must be capitalized and cannot be deducted currently, ratably or upon
our termination. There are uncertainties regarding the classification of costs
as organization expenses, which may be amortized, and as syndication expenses,
which may not be amortized. Under recently adopted regulations, underwriting
discounts and commissions would be treated as a syndication cost.
SECTION 754 ELECTION
We have made the election permitted by Section 754 of the Code. That
election is irrevocable without the consent of the IRS. The election will
generally permit us to adjust a unit purchaser's (other than a unit purchaser
that purchases units directly from us) tax basis in our assets ("inside basis")
pursuant to Section 743(b) of the Code to reflect his purchase price. The
Section 743(b) adjustment belongs to the purchaser and not to other partners.
(For purposes of this discussion, a partner's inside basis in our assets will be
considered to have two components: (1) his share of our tax basis in such assets
("common basis") and (2) his Section 743(b) adjustment to that basis.)
If a partnership elects the remedial allocation method with respect to an
item of partnership property (which we may do with respect to certain assets),
proposed Treasury regulations under Section 743 of the Code require that the
portion of any Section 743(b) adjustment that is attributable to Section 704(c)
built in gain must be depreciated over the remaining cost recovery period for
the Section 704(c) built in gain. Nevertheless, the proposed regulations under
Section 197 indicate that the Section 743(b) adjustment attributable to an
amortizable Section 197 intangible should be treated as a newly-acquired asset
placed in service in the month when the purchaser acquires the unit. Under
Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment
attributable to property subject to depreciation under Section 167 of the Code
rather than cost recovery deductions under Section 168 is
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generally required to be depreciated using either the straight-line method or
the 150% declining balance method. Although the proposed regulations under
Section 743 will likely eliminate many of the problems if finalized in their
current form, the depreciation and amortization methods and useful lives
associated with the Section 743(b) adjustment may differ from the methods and
useful lives generally used to depreciate the common basis in such properties.
Pursuant to our partnership agreement, we are authorized to adopt a convention
to preserve the uniformity of units even if that convention is not consistent
with Treasury Regulation Section 1.167(c)-1(a)(6) and Proposed Treasury
Regulation Section 1.197-2(g)(3). See "--Uniformity of Units."
Although our counsel is unable to opine as to the validity of such an
approach, we intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of Contributed Property (to
the extent of any unamortized Book-Tax Disparity) using a rate of depreciation
or amortization derived from the depreciation or amortization method and useful
life applied to the common basis of such property, or treat that portion as
non-amortizable to the extent attributable to property the common basis of which
is not amortizable. This method is consistent with the proposed regulations
under Section 743 but is arguably inconsistent with Treasury Regulation Section
1.167(c)-1(a)(6) and Proposed Treasury Regulation Section 1.197-2(g)(3) (neither
of which is expected to directly apply to a material portion of our assets). To
the extent such Section 743(b) adjustment is attributable to appreciation in
value in excess of the unamortized Book-Tax Disparity, we will apply the rules
described in the Regulations and legislative history. If we determine that such
position cannot reasonably be taken, we may adopt a depreciation or amortization
convention under which all purchasers acquiring units in the same month would
receive depreciation or amortization, whether attributable to common basis or
Section 743(b) adjustment, based upon the same applicable rate as if they had
purchased a direct interest in our assets. Such an aggregate approach may result
in lower annual depreciation or amortization deductions than would otherwise be
allowable to certain unitholders. See "--Uniformity of Units."
The allocation of the Section 743(b) adjustment must be made in accordance
with the Code. The IRS may seek to reallocate some or all of any Section 743(b)
adjustment not so allocated by us to goodwill which, as an intangible asset,
would be amortizable over a longer period of time than some of our tangible
assets.
A Section 754 election is advantageous if the transferee's tax basis in his
units is higher than such units' share of the aggregate tax basis of our assets
immediately prior to the transfer. In such a case, as a result of the election,
the transferee would have a higher tax basis in his share of our assets for
purposes of calculating, among other items, his depreciation and depletion
deductions and his share of any gain or loss on a sale of our assets.
Conversely, a Section 754 election is disadvantageous if the transferee's tax
basis in such units is lower than such unit's share of the aggregate tax basis
of our assets immediately prior to the transfer. Thus, the fair market value of
the units may be affected either favorably or adversely by the election.
The calculations involved in the Section 754 election are complex and will
be made by us on the basis of certain assumptions as to the value of our assets
and other matters. There is no assurance that the determinations made by us will
not be successfully challenged by the IRS and that the deductions resulting from
them will not be reduced or disallowed altogether. Should the IRS require a
different basis adjustment to be made, and should, in our opinion, the expense
of compliance exceed the benefit of the election, we may seek permission from
the IRS to revoke our Section 754 election. If such permission is granted, a
subsequent purchaser of units may be allocated more income than he would have
been allocated had the election not been revoked.
ALTERNATIVE MINIMUM TAX
Each unitholder will be required to take into account his distributive
share of any items of our income, gain, deduction or loss for purposes of the
alternative minimum tax. The current minimum tax rate for noncorporate taxpayers
is 26% on the first $175,000 of alternative minimum taxable income in
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excess of the exemption amount and 28% on any additional alternative minimum
taxable income. Prospective unitholders should consult with their tax advisors
as to the impact of an investment in units on their liability for the
alternative minimum tax.
VALUATION OF PARTNERSHIP PROPERTY AND BASIS OF PROPERTIES
The federal income tax consequences of the ownership and disposition of
units will depend in part on our estimates of the relative fair market values of
our assets. Although we may from time to time consult with professional
appraisers with respect to valuation matters, many of the relative fair market
value estimates will be made by us. These estimates are subject to challenge and
will not be binding on the IRS or the courts. If the estimates of fair market
value are subsequently found to be incorrect, the character and amount of items
of income, gain, loss or deductions previously reported by unitholders might
change, and unitholders might be required to adjust their tax liability for
prior years.
TREATMENT OF SHORT SALES
A unitholder whose units are loaned to a "short seller" to cover a short
sale of units may be considered as having disposed of ownership of those units.
If so, he would no longer be a partner with respect to those units during the
period of the loan and may recognize gain or loss from the disposition. As a
result, during this period, any of our income, gain, deduction or loss with
respect to those units would not be reportable by the unitholder, any cash
distributions received by the unitholder with respect to those units would be
fully taxable and all of such distributions would appear to be treated as
ordinary income. Unitholders desiring to assure their status as partners and
avoid the risk of gain recognition should modify any applicable brokerage
account agreements to prohibit their brokers from borrowing their units. The IRS
has announced that it is actively studying issues relating to the tax treatment
of short sales of partnership interests. See also "--Disposition of
Units--Recognition of Gain or Loss."
DISPOSITION OF UNITS
RECOGNITION OF GAIN OR LOSS
Gain or loss will be recognized on a sale of units equal to the difference
between the amount realized and the unitholder's tax basis for the units sold. A
unitholder's amount realized will be measured by the sum of the cash or the fair
market value of other property received plus his share of our nonrecourse
liabilities. Because the amount realized includes a unitholder's share of our
nonrecourse liabilities, the gain recognized on the sale of units could result
in a tax liability in excess of any cash received from such sale.
Prior distributions by us in excess of cumulative net taxable income in
respect of a unit which decreased a unitholder's tax basis in such unit will, in
effect, become taxable income if the unit is sold at a price greater than the
unitholder's tax basis in such unit, even if the price is less than his original
cost.
Should the IRS successfully contest the convention used by us to amortize
only a portion of the Section 743(b) adjustment (described under "--Tax
Treatment of Operations--Section 754 Election") attributable to an amortizable
Section 197 intangible after a sale by our general partner of units, a
unitholder could realize additional gain from the sale of units than had such
convention been respected. In that case, the unitholder may have been entitled
to additional deductions against income in prior years but may be unable to
claim them, with the result to him of greater overall taxable income than
appropriate. Our counsel is unable to opine as to the validity of the convention
but believes such a contest by the IRS to be unlikely because a successful
contest could result in substantial additional deductions to other unitholders.
Gain or loss recognized by a unitholder (other than a "dealer" in units) on
the sale or exchange of a unit held for more than one year will generally be
taxable as capital gain or loss. Capital gain recognized on the sale of units
held for more than 12 months will generally be taxed at a maximum rate of 20%. A
portion of this gain or loss (which could be substantial), however, will be
separately computed and taxed as ordinary income or loss under Section 751 of
the Code to the extent attributable to assets giving rise to
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depreciation recapture or other "unrealized receivables" or to "inventory items"
owned by us. The term "unrealized receivables" includes potential recapture
items, including depreciation recapture. Ordinary income attributable to
unrealized receivables, inventory items and depreciation recapture may exceed
net taxable gain realized upon the sale of the unit and may be recognized even
if there is a net taxable loss realized on the sale of the unit. Thus, a
unitholder may recognize both ordinary income and a capital loss upon a
disposition of units. Net capital loss may offset no more than $3,000 of
ordinary income in the case of individuals and may only be used to offset
capital gain in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in
separate transactions must combine those interests and maintain a single
adjusted tax basis. Upon a sale or other disposition of less than all of such
interests, a portion of that tax basis must be allocated to the interests sold
using an "equitable apportionment" method. The ruling is unclear as to how the
holding period of these interests is determined once they are combined. If this
ruling is applicable to the holders of units, a unitholder will be unable to
select high or low basis units to sell as would be the case with corporate
stock. It is not clear whether the ruling applies to us because, similar to
corporate stock, interests in us are evidenced by separate certificates.
Accordingly, our counsel is unable to opine as to the effect such ruling will
have on the unitholders. A unitholder considering the purchase of additional
units or a sale of units purchased in separate transactions should consult his
own tax advisor as to the possible consequences of that ruling.
Some provisions of the Code affect the taxation of certain financial
products and securities, including partnership interests, by treating a taxpayer
as having sold an "appreciated" partnership interest (one in which gain would be
recognized if it were sold, assigned or terminated at its fair market value) if
the taxpayer or related persons enters into a short sale, an offsetting notional
principal contract or a futures or forward contract with respect to the
partnership interest or substantially identical property. Moreover, if a
taxpayer has previously entered into a short sale, an offsetting notional
principal contract or a futures or forward contract with respect to the
partnership interest, the taxpayer will be treated as having sold such position
if the taxpayer or related person then acquires the partnership interest or
substantially identical property. The Secretary of Treasury is also authorized
to issue regulations that treat a taxpayer that enters into transactions or
positions that have substantially the same effect as the preceding transactions
as having constructively sold the financial position.
ALLOCATIONS BETWEEN TRANSFERORS AND TRANSFEREES
In general, our taxable income and losses will be determined annually, will
be prorated on a monthly basis and will be subsequently apportioned among the
unitholders in proportion to the number of units owned by each of them as of the
opening of the NYSE on the first business day of the month (the "Allocation
Date"). However, gain or loss realized on a sale or other disposition of our
assets other than in the ordinary course of business will be allocated among the
unitholders on the Allocation Date in the month in which that gain or loss is
recognized. As a result, a unitholder transferring units may be allocated
income, gain, loss and deduction accrued after the date of transfer.
The use of this method may not be permitted under existing Treasury
Regulations. Accordingly, our counsel is unable to opine on the validity of this
method of allocating income and deductions between the transferors and the
transferees of units. If this method is not allowed under the Treasury
Regulations (or only applies to transfers of less than all of the unitholder's
interest), our taxable income or losses might be reallocated among the
unitholders. We are authorized to revise our method of allocation between
transferors and transferees (as well as among partners whose interests otherwise
vary during a taxable period) to conform to a method permitted under future
Treasury Regulations.
A unitholder who owns units at any time during a quarter and who disposes
of those units prior to the record date set for a cash distribution with respect
to such quarter will be allocated items of our income, gain, loss and deductions
attributable to such quarter but will not be entitled to receive that cash
distribution.
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NOTIFICATION REQUIREMENTS
A unitholder who sells or exchanges units is required to notify us in
writing of that sale or exchange within 30 days after the sale or exchange and
in any event by no later than January 15 of the year following the calendar year
in which the sale or exchange occurred. We are required to notify the IRS of
that transaction and to furnish certain information to the transferor and
transferee. However, these reporting requirements do not apply with respect to a
sale by an individual who is a citizen of the U.S. and who effects the sale or
exchange through a broker. Additionally, a transferor and a transferee of a unit
will be required to furnish statements to the IRS, filed with their income tax
returns for the taxable year in which the sale or exchange occurred, that set
forth the amount of the consideration received for the unit that is allocated to
goodwill or going concern value of ours. Failure to satisfy these reporting
obligations may lead to the imposition of substantial penalties.
CONSTRUCTIVE TERMINATION
We will be considered to have been terminated if there is a sale or
exchange of 50% or more of the total interests in our capital and profits within
a 12-month period. Our termination will result in the closing of our taxable
year for all unitholders. In the case of a unitholder reporting on a taxable
year other than a fiscal year ending December 31, the closing of our taxable
year may result in more than 12 months' taxable income or the inability to
include our results in his taxable income for the year of termination. New tax
elections required to be made by us, including a new election under Section 754
of the Code, must be made subsequent to a termination, and a termination could
result in a deferral of our deductions for depreciation. A termination could
also result in penalties if we were unable to determine that the termination had
occurred. Moreover, a termination might either accelerate the application of, or
subject us to, any tax legislation enacted prior to the termination.
ENTITY-LEVEL COLLECTIONS
If we are required or elect under applicable law to pay any federal, state
or local income tax on behalf of any unitholder or our general partner or any
former unitholder, we are authorized to pay those taxes from our funds. Such
payment, if made, will be treated as a distribution of cash to the partner on
whose behalf the payment was made. If the payment is made on behalf of a person
whose identity cannot be determined, we are authorized to treat the payment as a
distribution to current unitholders. We are authorized to amend our partnership
agreement in the manner necessary to maintain uniformity of intrinsic tax
characteristics of units and to adjust subsequent distributions, so that after
giving effect to such distributions, the priority and characterization of
distributions otherwise applicable under the partnership agreement is maintained
as nearly as is practicable. Payments by us as described above could give rise
to an overpayment of tax on behalf of an individual partner in which event the
partner could file a claim for credit or refund.
UNIFORMITY OF UNITS
Because we cannot match transferors and transferees of units, we must
maintain uniformity of the economic and tax characteristics of the units to a
purchaser of such units. In the absence of uniformity, compliance with a number
of federal income tax requirements, both statutory and regulatory, could be
substantially diminished. A lack of uniformity can result from a literal
application of Treasury Regulation Section 1.167(c)-1(a)(6) and Proposed
Treasury Regulation Section 1.197-2(g)(3). Any non-uniformity could have a
negative impact on the value of the units. See "--Tax Treatment of
Operations--Section 754 Election."
We intend to depreciate the portion of a Section 743(b) adjustment
attributable to unrealized appreciation in the value of contributed property or
adjusted property (to the extent of any unamortized Book-Tax Disparity) using a
rate of depreciation or amortization derived from the depreciation or
amortization method and useful life applied to the common basis of such
property, or treat that portion as nonamortizable, to the extent attributable to
property the common basis of which is not amortizable,
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consistent with the proposed regulations under Section 743 but despite its
inconsistency with Treasury Regulation Section 1.167(c)-1(a)(6) and Proposed
Treasury Regulation Section 1.197- 2(g)(3) (neither of which is expected to
directly apply to a material portion of our assets). See "--Tax Treatment of
Operations--Section 754 Election." To the extent such Section 743(b) adjustment
is attributable to appreciation in value in excess of the unamortized Book-Tax
Disparity, we will apply the rules described in the Regulations and legislative
history. If we determine that such a position cannot reasonably be taken, we may
adopt a depreciation and amortization convention under which all purchasers
acquiring units in the same month would receive depreciation and amortization
deductions, whether attributable to common basis or Section 743(b) basis, based
upon the same applicable rate as if they had purchased a direct interest in our
property. If such an aggregate approach is adopted, it may result in lower
annual depreciation and amortization deductions than would otherwise be
allowable to certain unitholders and risk the loss of depreciation and
amortization deductions not taken in the year that such deductions are otherwise
allowable. We will not adopt this convention if we determine that the loss of
depreciation and amortization deductions will have a material adverse effect on
the unitholders. If we choose not to utilize this aggregate method, we may use
any other reasonable depreciation and amortization convention to preserve the
uniformity of the intrinsic tax characteristics of any units that would not have
a material adverse effect on the unitholders. The IRS may challenge any method
of depreciating the Section 743(b) adjustment described in this paragraph. If
such a challenge were sustained, the uniformity of units might be affected, and
the gain from the sale of units might be increased without the benefit of
additional deductions. See "--Disposition of Units--Recognition of Gain or
Loss."
TAX EXEMPT ORGANIZATIONS AND CERTAIN OTHER INVESTORS
Ownership of units by employee benefit plans, other tax-exempt
organizations, nonresident aliens, foreign corporations, other foreign persons
and regulated investment companies raises issues unique to such persons and, as
described below, may have substantially adverse tax consequences. Employee
benefit plans and most other organizations exempt from federal income tax
(including individual retirement accounts ("IRAs") and other retirement plans)
are subject to federal income tax on unrelated business taxable income.
Virtually all of the taxable income derived by such an organization from the
ownership of a unit will be unrelated business taxable income and thus will be
taxable to such a unitholder.
A regulated investment partnership or "mutual fund" is required to derive
90% or more of its gross income from interest, dividends, gains from the sale of
stocks or securities or foreign currency or certain related sources. We do not
anticipate that any significant amount of our gross income will include that
type of income.
Non-resident aliens and foreign corporations, trusts or estates which hold
units will be considered to be engaged in business in the U.S. on account of
ownership of units. As a consequence they will be required to file federal tax
returns in respect of their share of our income, gain, loss or deduction and pay
federal income tax at regular rates on any net income or gain. Generally, a
partnership is required to deduct withholding tax on the portion of the
partnership's income which is effectively connected with the conduct of a U.S.
trade or business and which is allocable to the foreign partners, regardless of
whether any actual distributions have been made to such partners. However, under
rules applicable to publicly-traded partnerships, we will withhold (currently at
the rate of 39.6%) on actual cash distributions made quarterly to foreign
unitholders. Each foreign unitholder must obtain a taxpayer identification
number from the IRS and submit that number to the Transfer Agent on a Form W-8
in order to obtain credit for the taxes withheld. A change in applicable law may
require us to change these procedures.
Because a foreign corporation which owns units will be treated as engaged
in a U.S. trade or business, such a corporation may be subject to U.S. branch
profits tax at a rate of 30%, in addition to regular federal income tax, on its
allocable share of our income and gain (as adjusted for changes in the foreign
corporation's "U.S. net equity") which are effectively connected with the
conduct of a U.S. trade or business. That tax may be reduced or eliminated by an
income tax treaty between the U.S. and the country with respect to which the
foreign corporate unitholder is a "qualified resident." In addition, such a
unitholder is subject to special information reporting requirements under
Section 6038C of the Code.
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Under a ruling of the IRS a foreign unitholder who sells or otherwise
disposes of a unit will be subject to federal income tax on gain realized on the
disposition of the unit to the extent that the gain is effectively connected
with a U.S. trade or business of the foreign unitholder. Apart from the
application of ruling, a foreign unitholder will not be taxed or subject to
withholding upon the disposition of a unit if that foreign unitholder has held
less than 5% in value of the units during the five-year period ending on the
date of the disposition and if the units are regularly traded on an established
securities market at the time of the disposition.
ADMINISTRATIVE MATTERS
PARTNERSHIP INFORMATION RETURNS AND AUDIT PROCEDURES
We intend to furnish to each unitholder, within 90 days after the close of
each calendar year, certain tax information, including a substitute Schedule
K-1, which sets forth each unitholder's share of our income, gain, loss and
deduction for our preceding taxable year. In preparing this information, which
will generally not be reviewed by counsel, we will use various accounting and
reporting conventions, some of which have been mentioned in the previous
discussion, to determine the unitholder's share of income, gain, loss and
deduction. There is no assurance that any of those conventions will yield a
result which conforms to the requirements of the Code, regulations or
administrative interpretations of the IRS. We cannot assure prospective
unitholders that the IRS will not successfully contend in court that such
accounting and reporting conventions are impermissible. Any such challenge by
the IRS could negatively affect the value of the units.
The federal income tax information returns filed by us may be audited by
the IRS. Adjustments resulting from any such audit may require each unitholder
to adjust a prior year's tax liability, and possibly may result in an audit of
the unitholder's own return. Any audit of a unitholder's return could result in
adjustments of non-partnership as well as partnership items.
Partnerships generally are treated as separate entities for purposes of
federal tax audits, judicial review of administrative adjustments by the IRS and
tax settlement proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership proceeding rather than
in separate proceedings with the partners. The Code provides for one partner to
be designated as the "Tax Matters Partner" for these purposes. Our partnership
agreement appoints our general partner as our Tax Matters Partner.
The Tax Matters Partner has made and will make certain elections on our
behalf and on behalf of the unitholders and can extend the statute of
limitations for assessment of tax deficiencies against unitholders with respect
to our items. The Tax Matters Partner may bind a unitholder with less than a 1%
profits interest in us to a settlement with the IRS unless that unitholder
elects, by filing a statement with the IRS, not to give such authority to the
Tax Matters Partner. The Tax Matters Partner may seek judicial review (by which
all the unitholders are bound) of a final partnership administrative adjustment
and, if the Tax Matters Partner fails to seek judicial review, such review may
be sought by any unitholder having at least a 1% interest in our profits and by
the unitholders having in the aggregate at least a 5% profits interest. However,
only one action for judicial review will go forward, and each unitholder with an
interest in the outcome may participate. However, if we elect to be treated as a
large partnership, a partner will not have the right to participate in
settlement conferences with the IRS or to seek a refund.
A unitholder must file a statement with the IRS identifying the treatment
of any item on his federal income tax return that is not consistent with the
treatment of the item on our return. Intentional or negligent disregard of the
consistency requirement may subject a unitholder to substantial penalties.
However, if we elect to be treated as a large partnership, our partners would be
required to treat all of our items in a manner consistent with our return.
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NOMINEE REPORTING
Persons who hold an interest in us as a nominee for another person are
required to furnish to us (a) the name, address and taxpayer identification
number of the beneficial owner and the nominee; (b) whether the beneficial owner
is (1) a person that is not a U.S. person, (2) a foreign government, an
international organization or any wholly-owned agency or instrumentality of
either of the foregoing, or (3) a tax-exempt entity; (c) the amount and
description of units held, acquired or transferred for the beneficial owner; and
(d) certain information including the dates of acquisitions and transfers, means
of acquisitions and transfers, and acquisition cost for purchases, as well as
the amount of net proceeds from sales. Brokers and financial institutions are
required to furnish additional information, including whether they are U.S.
persons and certain information on units they acquire, hold or transfer for
their own account. A penalty of $50 per failure (up to a maximum of $100,000 per
calendar year) is imposed by the Code for failure to report such information to
us. The nominee is required to supply the beneficial owner of the units with the
information furnished to us.
REGISTRATION AS A TAX SHELTER
The Code requires that "tax shelters" be registered with the Secretary of
the Treasury. The temporary Treasury Regulations interpreting the tax shelter
registration provisions of the Code are extremely broad. It is arguable that we
are not subject to the registration requirement on the basis that we will not
constitute a tax shelter. However, our general partner, as our principal
organizer, has registered us as a tax shelter with the Secretary of the Treasury
in the absence of assurance that we will not be subject to tax shelter
registration and in light of the substantial penalties which might be imposed if
registration is required and not undertaken. ISSUANCE OF THE REGISTRATION NUMBER
DOES NOT INDICATE THAT AN INVESTMENT IN THE PARTNERSHIP OR THE CLAIMED TAX
BENEFITS HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS. The IRS has issued
the following shelter registration number to us: 93084000079. We must furnish
the registration number to the unitholders, and a unitholder who sells or
otherwise transfers a unit in a subsequent transaction must furnish the
registration number to the transferee. The penalty for failure of the transferor
of a unit to furnish the registration number to the transferee is $100 for each
such failure. The unitholders must disclose our tax shelter registration number
on Form 8271 to be attached to the tax return on which any deduction, loss or
other benefit generated by us is claimed or income of ours is included. A
unitholder who fails to disclose the tax shelter registration number on his
return, without reasonable cause for that failure, will be subject to a $250
penalty for each failure. Any penalties discussed herein are not deductible for
federal income tax purposes.
ACCURACY-RELATED PENALTIES
An additional tax equal to 20% of the amount of any portion of an
underpayment of tax which is attributable to one or more of certain listed
causes, including negligence or disregard of rules or regulations, substantial
understatements of income tax and substantial valuation misstatements, is
imposed by the Code. No penalty will be imposed, however, with respect to any
portion of an underpayment if it is shown that there was a reasonable cause for
that portion and that the taxpayer acted in good faith with respect to that
portion.
A substantial understatement of income tax in any taxable year exists if
the amount of the understatement exceeds the greater of 10% of the tax required
to be shown on the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to penalty generally is
reduced if any portion is attributable to a position adopted on the return (1)
with respect to which there is, or was, "substantial authority" or (2) as to
which there is a reasonable basis and the pertinent facts of such position are
disclosed on the return. Certain more stringent rules apply to "tax shelters," a
term that in this context does not appear to include us. If any item of our
income, gain, loss or deduction included in the distributive shares of
unitholders might result in such an "understatement" of income for which no
"substantial authority" exists, we must disclose the pertinent facts on its
return. In
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addition, we will make a reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns to avoid liability for
this penalty.
A substantial valuation misstatement exists if the value of any property
(or the adjusted basis of any property) claimed on a tax return is 200% or more
of the amount determined to be the correct amount of such valuation or adjusted
basis. No penalty is imposed unless the portion of the underpayment attributable
to a substantial valuation misstatement exceeds $5,000 ($10,000 for most
corporations). If the valuation claimed on a return is 400% or more than the
correct valuation, the penalty imposed increases to 40%.
STATE, LOCAL AND OTHER TAX CONSIDERATIONS
In addition to federal income taxes, unitholders will be subject to other
taxes, such as state and local income taxes, unincorporated business taxes, and
estate, inheritance or intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property. Although an analysis of
those various taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us. We will own property
and conduct business in Texas and Louisiana; among other places. Of those, only
Texas does not currently impose a personal income tax. A unitholder will be
required to file state income tax returns and to pay state income taxes in some
or all of the states in which we do business or own property and may be subject
to penalties for failure to comply with those requirements. In certain states,
tax losses may not produce a tax benefit in the year incurred (if, for example,
we have no income from sources within that state) and also may not be available
to offset income in subsequent taxable years. Some of the states may require us,
or we may elect, to withhold a percentage of income from amounts to be
distributed to a unitholder who is not a resident of the state. Withholding, the
amount of which may be greater or less than a particular unitholder's income tax
liability to the state, generally does not relieve the non-resident unitholder
from the obligation to file an income tax return. Amounts withheld may be
treated as if distributed to unitholders for purposes of determining the amounts
distributed by us. See "--Disposition of Units--Entity-Level Collections." Based
on current law and its estimate of our future operations, our general partner
anticipates that any amounts required to be withheld will not be material.
It is the responsibility of each unitholder to investigate the legal and
tax consequences, under the laws of pertinent states and localities, of his
investment in us. Accordingly, each prospective unitholder should consult, and
must depend upon, his own tax counsel or other advisor with regard to those
matters. Further, it is the responsibility of each unitholder to file all state
and local, as well as U.S. federal, tax returns that may be required of such
unitholder. Our counsel has not rendered an opinion on the state or local tax
consequences of an investment in us.
109
<PAGE> 115
UNDERWRITING
Subject to the terms and conditions stated in the underwriting agreement
dated the date hereof, each underwriter named below has severally agreed to
purchase, and Leviathan has agreed to sell to such underwriter, the number of
common units set forth opposite the name of such underwriter.
<TABLE>
<CAPTION>
NUMBER OF
NAME COMMON UNITS
- ---- ------------
<S> <C>
Salomon Smith Barney Inc....................................
Goldman, Sachs & Co. .......................................
PaineWebber Incorporated....................................
Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated..............................................
First Union Capital Markets Corp............................
---------
Total............................................. 4,000,000
=========
</TABLE>
The underwriting agreement provides that the obligations of the several
underwriters to purchase the units included in this offering are subject to
approval of certain legal matters by counsel and to certain other conditions.
The underwriters are obligated to purchase all the common units (other than
those covered by the over-allotment option described below) if they purchase any
of the common units.
The underwriters, for whom Salomon Smith Barney Inc., Goldman, Sachs & Co.,
PaineWebber Incorporated, Dain Rauscher Wessels, a division of Dain Rauscher
Incorporated and First Union Capital Markets Corp. are acting as
representatives, propose to offer some of the common units directly to the
public at the public offering price set forth on the cover page of this
prospectus and some of the units to certain dealers at the public offering price
less a concession not in excess of $ per common unit. The underwriters may
allow, and such dealers may reallow, a concession not in excess of $ per
common unit on sales to certain other dealers. If all of the common units are
not sold at the initial offering price, the representatives may change the
public offering price and the other selling terms.
Leviathan has granted to the underwriters an option, exercisable for 30
days from the date of this prospectus, to purchase up to 600,000 additional
common units at the public offering price less the underwriting discount. The
underwriters may exercise such option solely for the purpose of covering
over-allotments, if any, in connection with this offering. To the extent such
option is exercised, each underwriter will be obligated, subject to certain
conditions, to purchase a number of additional common units approximately
proportionate to such underwriter's initial purchase commitment.
Leviathan, its general partner and EPEC Deepwater Gathering Company, a
wholly owned subsidiary of El Paso, have agreed that, for a period of 180 days
from the date of this prospectus, they will not, without the prior written
consent of Salomon Smith Barney Inc., dispose of or hedge any common units of
Leviathan or any securities convertible into or exchangeable for common units.
The foregoing restriction shall not prohibit Leviathan's general partner or EPEC
Deepwater from transferring common units owned by such person to a limited
liability company of which such transferror is the sole member and pledging the
member interests of such limited liability company to secure advances to El Paso
Energy by Trinity River Associates, L.L.C., a limited liability company of which
El Paso Energy is the managing member, as contemplated by an operating agreement
between El Paso Energy and the other investors in Trinity River. Salomon Smith
Barney Inc. in its sole discretion may release any of the securities subject to
these lock-up agreements at any time without notice.
The common units are listed on the New York Stock Exchange under the symbol
"LEV".
110
<PAGE> 116
The following table shows the underwriting discounts and commissions to be
paid to the underwriters by Leviathan in connection with this offering. These
amounts are shown assuming both no exercise and full exercise of the
underwriters' option to purchase additional common units.
<TABLE>
<CAPTION>
PAID BY LEVIATHAN
---------------------------
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per unit................................................. $ $
Total.................................................... $ $
</TABLE>
In connection with the offering, Salomon Smith Barney Inc., on behalf of
the underwriters, may purchase and sell the common units in the open market.
These transactions may include over-allotment, syndicate covering transactions
and stabilizing transactions. Over-allotment involves syndicate sales of common
units in excess of the number of common units to be purchased by the
underwriters in the offering, which creates a syndicate short position.
Syndicate covering transactions involve purchases of the common units in the
open market after the distribution has been completed in order to cover
syndicate short positions. Stabilizing transactions consist of certain bids or
purchases of common units made for the purpose of preventing or retarding a
decline in the market price of the common units while the offering is in
progress.
The underwriters also may impose a penalty bid. Penalty bids permit the
underwriters to reclaim a selling concession from a syndicate member when
Salomon Smith Barney Inc., in covering syndicate short positions or making
stabilizing purchases, repurchases common units originally sold by that
syndicate member.
Any of these activities may cause the price of the common units to be
higher than the price that otherwise would exist in the open market in the
absence of such transactions. These transactions may be effected on the New York
Stock Exchange or in the over-the-counter market, or otherwise and, if
commenced, may be discontinued at any time.
Leviathan estimates that its portion of the total expenses of this offering
will be $8.4 million.
The representatives have performed certain investment banking and advisory
services for Leviathan from time to time for which they have received customary
fees and expenses. The representatives may, from time to time, engage in
transactions with and perform services for Leviathan in the ordinary course of
their business.
Leviathan has agreed to indemnify the underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, or to
contribute to payments the underwriters may be required to make in respect of
any of those liabilities.
LEGAL MATTERS
Certain legal matters with respect to the legality of the common units
being offered and certain tax matters will be passed upon for us by Akin, Gump,
Strauss, Hauer & Feld, L.L.P., Houston, Texas. Certain legal matters with
respect to the legality of the common units being offered will be passed upon
for the underwriters by Andrews & Kurth L.L.P., Houston, Texas.
111
<PAGE> 117
EXPERTS
The consolidated financial statements of Leviathan Gas Pipeline Partners,
L.P. and its subsidiaries as of December 31, 1998 and 1997 and for each of the
three years in the period ended December 31, 1998 included in this Registration
Statement have been so included in reliance on the report of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts in auditing and accounting.
The financial statements of Viosca Knoll Gathering Company as of December
31, 1998 and 1997 and for each of the three years in the period ended December
31, 1998 included in this Registration Statement have been so included in
reliance on the report of PricewaterhouseCoopers LLP, independent accountants,
given on the authority of said firm as experts in auditing and accounting.
The statements of financial position of High Island Offshore System, L.L.C.
as of December 31, 1998 and 1997 and the related statements of income, members'
equity, and cash flows for each of the three years in the period ended December
31, 1998 included in this Registration Statement have been so included in
reliance on the report of Deloitte & Touche LLP, independent auditors, given
upon the authority of said firm as experts in auditing and accounting.
The financial statements of Poseidon Oil Pipeline Company, L.L.C. as of
December 31, 1998 and 1997 and for the years ended December 31, 1998 and 1997
and for the period from inception (February 14, 1996) through December 31, 1996
included in this Registration Statement have been so included in reliance on the
report of Arthur Andersen LLP, independent public accountants, given on the
authority of said firm as experts in auditing and accounting.
The consolidated financial statements of Neptune Pipeline Company, L.L.C.
as of December 31, 1998 and 1997 and for the years then ended included in this
Registration Statement have been so included in reliance on the report of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts in auditing and accounting.
The balance sheet of Leviathan Finance Corporation as of April 30, 1999
included in this Registration Statement has been so included in reliance on the
report of PricewaterhouseCoopers LLP, independent accountants, given on the
authority of said firm as experts in auditing and accounting.
The balance sheet of Leviathan Gas Pipeline Company as of December 31, 1998
included in this Registration Statement has been so included in reliance on the
report of PricewaterhouseCoopers LLP, independent accountants, given on the
authority of said firm as experts in auditing and accounting.
The information derived from the report of Netherland, Sewell & Associates,
Inc., independent petroleum engineers, with respect to estimated oil and natural
gas reserves of Leviathan Gas Pipeline Partners, L.P. and its subsidiaries
included in this Registration Statement have been so included in reliance upon
the authority of said firm as experts with respect to such matters contained in
their report.
112
<PAGE> 118
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
GLOSSARY TO CERTAIN FINANCIAL STATEMENTS.................... F-3
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
PRO FORMA:
Unaudited Pro Forma Condensed Consolidated Financial
Statements............................................. F-4
Unaudited Pro Forma Condensed Consolidated Balance Sheet
as of June 30, 1999.................................... F-6
Unaudited Pro Forma Condensed Consolidated Statement of
Operations for the Six Months Ended June 30, 1999...... F-7
Unaudited Pro Forma Condensed Consolidated Statement of
Operations for the Year Ended December 31, 1998........ F-8
Notes to Unaudited Pro Forma Condensed Consolidated
Financial Statements................................... F-9
HISTORICAL:
Condensed Consolidated Statements of Income for the
Quarter and Six Months Ended June 30, 1999 and 1998
(unaudited)............................................ F-12
Condensed Consolidated Balance Sheets as of June 30, 1999
(unaudited) and December 31, 1998...................... F-13
Condensed Consolidated Statements of Cash Flows for the
Six Months Ended June 30, 1999 and 1998 (unaudited).... F-14
Condensed Consolidated Statement of Partners' Capital for
the Six Months Ended June 30, 1999 (unaudited)......... F-15
Notes to Condensed Consolidated Financial Statements
(unaudited)............................................ F-16
Report of Independent Accountants......................... F-28
Consolidated Balance Sheet as of December 31, 1998 and
1997................................................... F-29
Consolidated Statement of Operations for the Years Ended
December 31, 1998, 1997 and 1996....................... F-30
Consolidated Statement of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996....................... F-31
Consolidated Statement of Partners' Capital for the Years
Ended December 31, 1996, 1997 and 1998................. F-32
Notes to Consolidated Financial Statements................ F-33
LEVIATHAN FINANCE CORPORATION
Report of Independent Accountants......................... F-60
Balance Sheet as of April 30, 1999........................ F-61
Note to Balance Sheet..................................... F-62
VIOSCA KNOLL GATHERING COMPANY
Report of Independent Accountants......................... F-63
Balance Sheet as of June 30, 1999 (unaudited) and December
31, 1998 and 1997...................................... F-64
Statement of Operations for the Six Months Ended June 30,
1999 and 1998 (unaudited) and for the Years Ended
December 31, 1998, 1997 and 1996....................... F-65
Statement of Cash Flows for the Six Months Ended June 30,
1999 and 1998 (unaudited) and for the Years Ended
December 31, 1998, 1997 and 1996....................... F-66
Statement of Partners' Capital for the Years Ended
December 31, 1996, 1997 and 1998 and for the Six Months
Ended June 30, 1999 (unaudited)........................ F-67
Notes to Financial Statements............................. F-68
</TABLE>
F-1
<PAGE> 119
INDEX TO FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
Independent Auditors' Report.............................. F-73
Statements of Financial Position as of June 30, 1999
(unaudited) and December 31, 1998
and 1997............................................... F-74
Statements of Income and Statements of Members' Equity for
the Six Months Ended June 30, 1999 and 1998 (unaudited)
and for the Years Ended December 31, 1998, 1997 and
1996................................................... F-75
Statements of Cash Flows for the Six Months Ended June 30,
1999 and 1998 (unaudited) and for the Years Ended
December 31, 1998, 1997 and 1996....................... F-76
Notes to the Financial Statements for the Years Ended
December 31, 1998, 1997 and 1996....................... F-77
POSEIDON OIL PIPELINE COMPANY, L.L.C.
Report of Independent Public Accountants.................. F-80
Balance Sheets -- December 31, 1998 and 1997.............. F-81
Statements of Income for the Six Months Ended June 30,
1999 and 1998 (unaudited) and for the Years Ended
December 31, 1998 and 1997 and for the Period from
Inception (February 14, 1996) through December 31,
1996................................................... F-82
Statements of Members' Equity for the Years Ended December
31, 1998 and 1997 and for the Period from Inception
(February 14, 1996) through December 31, 1996.......... F-83
Statements of Cash Flows for the Years Ended December 31,
1998 and 1997 and for the Period from Inception
(February 14, 1996) through December 31, 1996.......... F-84
Notes to Financial Statements -- December 31, 1998, 1997
and 1996............................................... F-85
NEPTUNE PIPELINE COMPANY, L.L.C.
Report of Independent Accountants......................... F-89
Consolidated Balance Sheet as of December 31, 1998 and
1997................................................... F-90
Consolidated Statement of Income for the Years Ended
December 31, 1998 and 1997............................. F-91
Consolidated Statement of Cash Flows for the Years Ended
December 31, 1998 and 1997............................. F-92
Statement of Members' Capital as of December 31, 1998 and
1997................................................... F-93
Notes to Consolidated Financial Statements -- December 31,
1998................................................... F-94
LEVIATHAN GAS PIPELINE COMPANY
Report of Independent Accountants......................... F-99
Balance Sheet as of December 31, 1998..................... F-100
Notes to Balance Sheet.................................... F-101
</TABLE>
F-2
<PAGE> 120
GLOSSARY
The following abbreviations, acronyms or defined terms used in certain
financial statements are defined below:
Bcf........................ Billion cubic feet
East Breaks................ East Breaks Gathering Company, L.L.C., a Delaware
limited liability company and wholly owned
subsidiary of Western Gulf
El Paso Energy............. El Paso Energy Corporation, a Delaware corporation
and the indirect parent of the General Partner
EPFS....................... El Paso Field Services Company, a Delaware
corporation and a wholly owned subsidiary of El Paso
Energy
Equity Investees........... Collectively refers to Stingray, West Cameron Dehy,
POPCO, Manta Ray Offshore, Nautilus, HIOS, UTOS and
prior to June 1, 1999, Viosca Knoll
General Partner............ Leviathan Gas Pipeline Company, a Delaware
corporation and wholly owned indirect subsidiary of
El Paso Energy
Green Canyon............... Green Canyon Pipe Line Company, L.L.C., a Delaware
limited liability company and wholly owned
subsidiary of Leviathan
Gulf....................... Gulf of Mexico
HIOS....................... High Island Offshore System, L.L.C., a Delaware
limited liability company and wholly owned
subsidiary of Western Gulf
Leviathan.................. Leviathan Gas Pipeline Partners, L.P., a publicly
held Delaware master limited partnership, and its
subsidiaries, unless the context otherwise requires
Manta Ray Offshore......... Manta Ray Offshore Gathering Company, L.L.C., a
Delaware limited liability company and owned by
Neptune and Ocean Breeze
Mcf........................ Thousand cubic feet
MMcf....................... Million cubic feet
MMbtu...................... Million British thermal units
Nautilus................... Nautilus Pipeline Company, L.L.C., a Delaware
limited liability company and owned by Neptune and
Ocean Breeze
Neptune.................... Neptune Pipeline Company, L.L.C., a Delaware limited
liability company in which Leviathan owns a 25.67%
member interest
Ocean Breeze............... Ocean Breeze Pipeline Company, L.L.C., a Delaware
limited liability company in which Leviathan owns a
25.67% member interest
NYMEX...................... New York Mercantile Exchange
POPCO...................... Poseidon Oil Pipeline Company, L.L.C., a Delaware
limited liability company in which Leviathan owns a
36% member interest
Stingray................... Stingray Pipeline Company, L.L.C., a Delaware
limited liability company in which Leviathan owns a
50% member interest
Tarpon..................... Tarpon Transmission Company, a Texas corporation and
wholly owned subsidiary of Leviathan
UTOS....................... U-T Offshore System, a Delaware partnership in which
Leviathan collectively owns a 66.67% member interest
West Cameron Dehy.......... West Cameron Dehydration Company, L.L.C., a Delaware
limited liability company in which Leviathan owns a
50% member interest
Western Gulf............... Western Gulf Holdings, L.L.C., a Delaware limited
liability company in which Leviathan collectively
owns a 60% member interest
Viosca Knoll............... Viosca Knoll Gathering Company, a Delaware general
partnership in which Leviathan owns a 99%
partnership interest
F-3
<PAGE> 121
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
The unaudited pro forma condensed consolidated financial statements as of
and for the six months ended June 30, 1999 and for the year ended December 31,
1998 have been prepared based on the historical consolidated balance sheet and
statements of operations of Leviathan Gas Pipeline Partners, L.P. and its
subsidiaries ("Leviathan"). The historical balance sheet and statements of
operations were adjusted to give effect to the transactions identified below
(the "Transactions"). The historical balance sheet was adjusted to give effect
to the Transactions described in (4) below as if they had occurred on June 30,
1999. The effect of the Transactions described in (1), (2) and (3) are included
in Leviathan's historical results as of June 30, 1999. The historical statement
of operations for the six months ended June 30, 1999 and for the year ended
December 31, 1998 were adjusted to give effect to the Transactions as if the
Transactions had occurred on January 1, 1998.
Leviathan, a publicly held Delaware master limited partnership, is
primarily engaged in the gathering and transportation and production of natural
gas and crude oil in the Gulf of Mexico (the "Gulf"). Through its subsidiaries
and joint ventures, Leviathan owns interests in certain significant assets,
including (i) nine (eight existing and one under construction) natural gas
pipelines, (ii) two (one existing and one under construction) crude oil pipeline
systems, (iii) six strategically-located multi-purpose platforms, (iv) a
dehydration facility, (v) four producing oil and natural gas properties and (vi)
a 100% working interest in a non-producing oil and natural gas unit comprised of
Ewing Bank Blocks 958, 959, 1002 and 1003.
The unaudited pro forma financial information gives effect to the following
Transactions:
(1) In May 1999, Leviathan sold $175 million of Senior Subordinated Notes
due May 2009 (the "Subordinated Notes"). Proceeds from the Subordinated Notes
were used (a) to fund the cash portion of the acquisition of the additional
interest in Viosca Knoll Gathering Company ("Viosca Knoll") as described in (2)
below, (b) to repay outstanding principal under Viosca Knoll's credit facility
discussed in (2) below, (c) to reduce the balance outstanding on Leviathan's
$375 million credit facility, as amended and restated, (the "Credit Facility")
and (d) to pay fees and expenses incurred in connection with the sale of the
Subordinated Notes and the Credit Facility.
(2) On January 21, 1999, Leviathan entered into a Contribution Agreement
with El Paso Field Services Company ("El Paso"), to acquire all of El Paso's
interest in Viosca Knoll, other than a 1% interest in profits and capital in
Viosca Knoll. At the time the Contribution Agreement was executed, Leviathan and
El Paso each beneficially owned a 50% interest in Viosca Knoll. On June 1, 1999
(the "Closing Date"), Leviathan and El Paso consummated the Viosca Knoll
transactions. In connection therewith, (i) a subsidiary of El Paso contributed
to Viosca Knoll $33,350,000 (the "Capital Contribution"), which amount was equal
to 50% of the amount then outstanding under Viosca Knoll's credit facility, (ii)
a subsidiary of Leviathan acquired a 49% interest in Viosca Knoll from a
subsidiary of El Paso in exchange for the cash payment of $19,930,750 and the
issuance of 2,661,870 Common Units, and (iii) as required by Leviathan's Amended
and Restated Agreement of Limited Partnership, Leviathan Gas Pipeline Company,
Leviathan's general partner, contributed $603,962 to Leviathan in order to
maintain its 1% capital account balance. Concurrently with the closing of the
Viosca Knoll transactions, Leviathan also contributed $33,350,000 to Viosca
Knoll. These funds and the Capital Contribution were used to repay and terminate
Viosca Knoll's credit facility. Furthermore, effective on the Closing Date,
Leviathan began consolidating the accounts and operations of Viosca Knoll.
(3) On June 30, 1999, Leviathan acquired (i) all of the outstanding stock
of Natoco, Inc., which owns a 20% member interest in Western Gulf Holdings,
L.L.C. ("Western Gulf"), which in turn owns 100% of High Island Offshore System,
L.L.C. ("HIOS") and East Breaks Gathering Company, L.L.C. ("East Breaks"), and
Naloco, Inc. (Del.), which owns a 33 1/3% interest in U-T Offshore System
("UTOS") and (ii) various ownership interests in certain lateral pipelines
located in the Gulf from
F-4
<PAGE> 122
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS -- (CONTINUED)
Natural Gas Pipeline Company of America ("NGPL"), a subsidiary of KN Energy,
Inc. (collectively the "HIOS/UTOS Transactions"). The East Breaks system is
currently under construction and will initially consist of 85 miles of pipeline,
with a design capacity of over 400 million cubic feet of natural gas per day,
and related facilities connecting the Diana/Hoover prospects developed by Exxon
Company USA and BP Amoco plc in Alaminos Canyon Block 25 in the Gulf, with the
HIOS system. The new pipeline and related facilities are anticipated to be in
service in late 2000. The UTOS system transports natural gas from the terminus
of the HIOS system to the Johnson Bayou facility in southern Louisiana with
access to one intrastate and four interstate pipelines. Additionally, Stingray
Pipeline Company, L.L.C., which is owned 50% by each of Leviathan and NGPL,
purchased from NGPL certain offshore laterals that connect to the Stingray
pipeline for approximately $5 million. After a transition period that could end
as soon as October 1, 1999, but not later than January 1, 2000, Leviathan will
assume NGPL's role as operator of the Stingray pipeline, the Stingray Onshore
Separation Facility, the West Cameron Dehydration Facility and certain other
lateral pipelines (the "Related Facilities"). Leviathan financed this
acquisition with funds from the Credit Facility.
(4) The issuance of 4,000,000 common units of Leviathan (the "Offering")
and the required capital contribution by Leviathan's general partner in order to
maintain its 1% capital account balance. Proceeds from the Offering and the
general partner capital contribution will be used to pay fees and expenses
incurred in connection with the Offering and to reduce the principal balance
outstanding under the Credit Facility.
The unaudited pro forma condensed consolidated financial statements are not
necessarily indicative of Leviathan's consolidated financial condition or
results of operations that might have occurred had the Transactions been
completed at the beginning of the period or as of the dates specified, and do
not purport to indicate Leviathan's consolidated financial condition or results
of operations for any future period or at any future date. The unaudited pro
forma condensed consolidated statements should be read in the context of the
related historical consolidated financial statements and notes thereto appearing
elsewhere in this prospectus.
F-5
<PAGE> 123
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
JUNE 30, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
PRO FORMA
HISTORICAL FINANCING
LEVIATHAN ADJUSTMENTS PRO FORMA
---------- ----------- ---------
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents............................ $ 3,301 $100,000(a) $ 3,301
(8,400)(a)
925(b)
(92,525)(c)
Accounts receivable.................................. 9,180 -- 9,180
Other current assets................................. 344 -- 344
-------- -------- --------
Total current assets......................... 12,825 -- 12,825
-------- -------- --------
Property and equipment, net............................ 381,210 381,210
Equity investments..................................... 219,732 219,732
Other noncurrent assets................................ 12,146 12,146
-------- -------- --------
Total assets................................. $625,913 $ -- $625,913
======== ======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities............. $ 12,475 $ -- $ 12,475
-------- -------- --------
Total current liabilities.................... 12,475 -- 12,475
Notes payable.......................................... 306,500 (92,525)(c) 213,975
Long-term debt......................................... 175,000 175,000
Other noncurrent liabilities........................... 12,151 -- 12,151
-------- -------- --------
Total liabilities............................ 506,126 (92,525) 413,601
-------- -------- --------
Minorities interests................................... (249) -- (249)
-------- -------- --------
Partners' capital:
Preference unitholders............................... 6,923 -- 6,923
Common unitholders................................... 132,345 100,000(a) 223,945
(8,400)(a)
General partner...................................... (19,232) 925(b) (18,307)
-------- -------- --------
120,036 92,525 212,561
-------- -------- --------
Total liabilities and partners' capital...... $625,913 $ -- $625,913
======== ======== ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-6
<PAGE> 124
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1999
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
PRO FORMA ACQUISITION
PRO FORMA HISTORICAL ADJUSTMENTS
HISTORICAL FINANCING VIOSCA -------------------------
LEVIATHAN ADJUSTMENTS KNOLL VIOSCA KNOLL HIOS/UTOS PRO FORMA
---------- ----------- ---------- ------------ --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Revenue:
Oil and natural gas sales........ $ 15,100 $ -- $ 49 $ (8)(f) $ -- $ 15,141
Gathering, transportation and
platform services.............. 10,798 -- 14,743 (2,446)(f) 645(l) 23,740
Equity in earnings............... 19,953 -- -- (3,860)(g) 1,040(m) 17,404
166(m)
105(n)
-------- -------- ------- ------- ------ --------
45,851 -- 14,792 (6,314) 1,956 56,285
-------- -------- ------- ------- ------ --------
Costs and expenses:
Operating expenses............... 5,025 -- 1,129 (268)(f) 175(l) 6,061
Depreciation, depletion and
amortization................... 13,727 -- 2,191 637(h) 198(l) 16,315
(438)(f)
General and administrative
expenses and management fee.... 5,909 -- 71 (8)(f) -- 5,972
-------- -------- ------- ------- ------ --------
24,661 -- 3,391 (77) 373 28,348
-------- -------- ------- ------- ------ --------
Operating income................... 21,190 -- 11,401 (6,237) 1,583 27,937
Interest and other income.......... 268 -- 33 (2)(f) 500(o) 799
Interest and other financing
costs............................ (13,868) 13,868(a) (1,973) 1,973(i) -- (17,336)
(9,078)(b)
(294)(b)
(7,964)(c)
Minority interests in (income)
loss............................. (80) 35(d) -- 17(f) (21)(p) (216)
(167)(j)
-------- -------- ------- ------- ------ --------
Income before income taxes......... 7,510 (3,433) 9,461 (4,416) 2,062 11,184
Income tax benefit................. 177 -- -- -- -- 177
-------- -------- ------- ------- ------ --------
Net income......................... $ 7,687 $ (3,433) $ 9,461 $(4,416) $2,062 $ 11,361
======== ======== ======= ======= ====== ========
Weighted average number units
outstanding...................... 24,808 4,000(e) 2,221(k) 31,029
======== ======== ======= ========
Basic and diluted net income per
unit............................. $ 0.25 $ 0.30
======== ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-7
<PAGE> 125
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
PRO FORMA ACQUISITION
PRO FORMA HISTORICAL ADJUSTMENTS
HISTORICAL FINANCING VIOSCA -------------------------
LEVIATHAN ADJUSTMENTS KNOLL VIOSCA KNOLL HIOS/UTOS PRO FORMA
---------- ----------- ---------- ------------ --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Revenue:
Oil and natural gas sales............. $ 31,411 $ -- $ 528 $ -- $ -- $ 31,939
Gathering, transportation and platform
services............................ 17,320 -- 28,806 -- 1,289(l) 47,415
Equity in earnings.................... 26,724 -- -- (9,113)(g) 2,679(m) 21,048
548(m)
210(n)
-------- -------- ------- -------- ------ --------
75,455 -- 29,334 (9,113) 4,726 100,402
-------- -------- ------- -------- ------ --------
Costs and expenses:
Operating expenses.................... 11,369 -- 2,877 -- 349(l) 14,595
Depreciation, depletion and
amortization........................ 29,267 -- 3,860 1,274(h) 396(l) 34,797
Impairment, abandonment and other..... (1,131) -- -- -- -- (1,131)
General and administrative expenses
and management fee.................. 16,189 -- 154 -- -- 16,343
-------- -------- ------- -------- ------ --------
55,694 -- 6,891 1,274 745 64,604
-------- -------- ------- -------- ------ --------
Operating income........................ 19,761 -- 22,443 (10,387) 3,981 35,798
Interest and other income............... 771 -- 50 -- 1,000(o) 1,821
Interest and other financing costs...... (20,242) 20,242(a) (4,267) 4,267(i) -- (29,212)
(18,156)(b)
(589)(b)
(10,467)(c)
Minority interests in (income) loss..... (15) 91(d) -- (347)(j) (50)(p) (321)
-------- -------- ------- -------- ------ --------
Income before income taxes.............. 275 (8,879) 18,226 (6,467) 4,931 8,086
Income tax benefit...................... 471 -- -- -- -- 471
-------- -------- ------- -------- ------ --------
Net income.............................. $ 746 $ (8,879) $18,226 $ (6,467) $4,931 $ 8,557
======== ======== ======= ======== ====== ========
Weighted average number units
outstanding........................... 24,367 4,000(e) 2,662(k) 31,029
======== ======== ======== ========
Basic and diluted net income per unit... $ 0.02 $ 0.22
======== ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-8
<PAGE> 126
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
The unaudited pro forma condensed consolidated financial statements have
been prepared to reflect the Transactions described on pages F-4 and F-5 and the
application of the adjustments to the historical amounts as described below:
BALANCE SHEET
(a)To record the proceeds from the Offering ($100.0 million) and the
payment of fees and expenses related to the Offering ($8.4 million).
(b)To record the capital contribution (1.0%) by Leviathan's general partner
described in Transaction (4).
(c)To reduce the principal balance outstanding under the Credit Facility
using the net proceeds from the Offering and the general partner's
capital contribution calculated as follows (in thousands):
<TABLE>
<CAPTION>
<S> <C>
Proceeds from the Offering........................ $100,000
Fees and expenses related to the Offering......... (8,400)
General partner capital contribution.............. 925
--------
Net proceeds used to reduce Credit Facility....... $ 92,525
========
</TABLE>
STATEMENT OF OPERATIONS
(a)To reverse Leviathan's historical interest expense.
(b)To record (i) interest expense on the Subordinated Notes at a rate of
10 3/8% per annum and (ii) amortization of debt issue costs related to
the Subordinated Notes ($5.9 million) over ten years.
(c)To record interest expense and amortization of debt issue costs related
to the amended and restated Credit Facility calculated as follows (in
thousands):
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1999 1ST QUARTER 2ND QUARTER TOTAL
- ------------------------------ ----------- ----------- -------
<S> <C> <C> <C>
Credit Facility interest expense:
Outstanding balance at beginning of quarter....... $184,554 $201,554
Quarterly borrowings.............................. 17,000 12,421
-------- --------
Outstanding balance at end of quarter............. $201,554 $213,975
Average outstanding balance....................... $193,054 $207,764
Assumed average interest rate..................... 7.5% 7.5%
Assumed quarterly interest expense................ $ 3,620 $ 3,896 $ 7,516
Less capitalized interest...................................................... (755)
Commitment fees and other...................................................... 82
1,121see(x)
Amortization of debt issue costs............................................... below
-------
Adjusted interest expense...................................................... $ 7,964
=======
Credit Facility debt issue costs:
Balance of debt issue costs as of January 1,
1998........................................... $ 3,749
Amendment and restatement fees.................... 2,975
--------
6,724
Life of Credit Facility........................... 3 years
Debt issue cost amortization for six months....... $ 1,121(x)
========
</TABLE>
F-9
<PAGE> 127
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998 1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER TOTAL
- ---------------------------- ----------- ----------- ----------- ----------- -------
<S> <C> <C> <C> <C> <C>
Credit Facility interest
expense:
Outstanding balance as of
January 1, 1998.......... $ 238,000
Net reduction of Credit
Facility(1).............. (153,446)
---------
Outstanding balance at
beginning of quarter..... 84,554 $ 97,554 $116,554 $137,554
Quarterly borrowings........ 13,000 19,000 21,000 47,000
--------- -------- -------- --------
Outstanding balance at end
of quarter............... $ 97,554 $116,554 $137,554 $184,554
Average outstanding
balance.................. $ 91,054 $107,054 $127,054 $161,054
Assumed average interest
rate..................... 7.5% 7.5% 7.5% 7.5%
Assumed quarterly interest
expense.................. $ 1,708 $ 2,007 $ 2,382 $ 3,020 $ 9,117
Less capitalized interest............................................................. (1,066)
Commitment fees....................................................................... 175
2,241see(y)
Amortization of debt issue costs...................................................... below
-------
Adjusted interest expense............................................................. $10,467
=======
Credit Facility debt issue
costs:
Balance of debt issue costs
as of January 1, 1998.... $ 3,749
Amendment and restatement
fees..................... 2,975
---------
6,724
Life of Credit Facility..... 3 years
---------
Annual debt issue cost
amortization............. $ 2,241(y)
=========
</TABLE>
- ---------------
(1) The net reduction of the Credit Facility on January 1, 1998 is
calculated as follows (in thousands):
<TABLE>
<S> <C>
Proceeds from the Subordinated Notes........................ $175,000
Proceeds from the Offering.................................. 100,000
Capital contribution by the general partner................. 925
Fees and expenses related to sale of the Subordinated
Notes..................................................... (5,885)
Fees and expenses related to the Offering................... (8,400)
Cash portion of the acquisition of the additional Viosca
Knoll interest............................................ (20,741)
Repayment and cancellation of Viosca Knoll's credit
facility.................................................. (33,350)
Fees and expenses associated with the amended and restated
Credit Facility........................................... (2,975)
Consummate the HIOS/UTOS Transactions....................... (51,128)
--------
Net reduction of the Credit Facility...................... $153,446
========
</TABLE>
(d)To record the minority interest in expense for the approximate 1.0%
minority interest ownership in certain of Leviathan's subsidiaries.
F-10
<PAGE> 128
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(e)To adjust weighted average units outstanding for the 4,000,000 common
units issued in connection with the Offering.
(f)To reverse the June 1999 results of operations of Viosca Knoll which are
included in Leviathan's historical results of operations as Leviathan
began consolidating Viosca Knoll on June 1, 1999.
(g)To reverse Leviathan's historical equity in earnings of Viosca Knoll.
(h)To record depreciation expense associated with the allocation of the
excess purchase price to Viosca Knoll's property and equipment. Such
equipment will be depreciated on a straight-line basis over the
remaining useful lives of the assets which approximate 25 years.
(i)To reverse interest expense related to Viosca Knoll's credit facility
which was repaid with the proceeds from the Capital Contribution and the
Subordinated Notes.
(j)To adjust minority interest in income for the approximate 1.0% minority
interest ownership in certain of Leviathan's subsidiaries and the 1.0%
minority interest ownership in Viosca Knoll.
(k)To adjust weighted average units outstanding for the 2,661,870 common
units issued at the Closing Date.
(l)To record transportation revenue, operating expenses and depreciation
related to certain pipeline laterals acquired. The pipeline laterals
will be depreciated on a straight-line basis over their estimated
remaining useful lives of 5 years.
(m)To record Leviathan's additional equity in earnings of HIOS and UTOS
calculated as follows (in thousands). Since Leviathan's control of its
investments in HIOS and UTOS is expected to be temporary, Leviathan will
continue to use the equity method to account for these investments.
<TABLE>
<CAPTION>
SIX MONTHS
ENDED JUNE 30, YEAR ENDED
1999 DECEMBER 31, 1998
--------------- -----------------
HIOS UTOS HIOS UTOS
------ ----- ------- ------
<S> <C> <C> <C> <C>
Net investee earnings...................... $8,498 $798 $19,983 $2,247
Additional ownership interest.............. 20% 33.3% 20% 33.3%
------ ----- ------- ------
1,700 266 3,997 748
Adjustment:
Depreciation(1).......................... (659) (100) (1,318) (200)
------ ----- ------- ------
Equity in earnings......................... $1,041 $166 $ 2,679 $ 548
====== ===== ======= ======
</TABLE>
- ---------------
(1) Results from purchase price adjustments made in accordance with
Accounting Principles Board Opinion No. 16, "Business
Combinations." The purchase price of the HIOS/UTOS Transactions
exceeded the fair value of net assets acquired by approximately
$45.5 million. The excess cost has been preliminarily assigned to
property and equipment and will be amortized on a straight-line
basis over an estimated remaining life of 30 years.
(n)To record additional equity in earnings of Stingray calculated as 50% of
the net earnings related to certain laterals acquired by Stingray in
connection with the HIOS/UTOS Transactions.
(o)To record the management fee related to Leviathan's operation of the
Related Facilities.
(p)To adjust minority interest in income for the approximate 1.0% minority
interest ownership in certain of Leviathan's subsidiaries.
F-11
<PAGE> 129
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
QUARTER SIX MONTHS
ENDED JUNE 30, ENDED JUNE 30,
----------------- ------------------
1999 1998 1999 1998
------- ------- -------- -------
<S> <C> <C> <C> <C>
Revenue............................................... $23,972 $18,373 $ 45,851 $36,087
------- ------- -------- -------
Costs and expenses....................................
Operating expenses.................................. 2,431 2,708 5,025 5,546
Depreciation, depletion and amortization............ 7,009 6,978 13,727 14,845
General and administrative expenses and management
fee.............................................. 2,779 2,554 5,909 7,503
------- ------- -------- -------
12,219 12,240 24,661 27,894
------- ------- -------- -------
Operating income...................................... 11,753 6,133 21,190 8,193
Interest income and other............................. 165 73 268 157
Interest and other financing costs.................... (7,766) (4,707) (13,868) (8,429)
Minority interest in income........................... (43) (16) (80) (3)
------- ------- -------- -------
Income (loss) before income taxes..................... 4,109 1,483 7,510 (82)
Income tax benefit.................................... 79 27 177 168
------- ------- -------- -------
Net income............................................ $ 4,188 $ 1,510 $ 7,687 $ 86
======= ======= ======== =======
Weighted average number of units outstanding.......... 25,244 24,367 24,808 24,367
======= ======= ======== =======
Basic and diluted net income per unit................. $ 0.13 $ 0.05 $ 0.25 $ 0.00
======= ======= ======== =======
</TABLE>
The accompanying Notes are an integral part of these Condensed Consolidated
Financial Statements.
F-12
<PAGE> 130
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
----------- ------------
(UNAUDITED)
<S> <C> <C>
Current assets
Cash and cash equivalents................................. $ 3,301 $ 3,108
Accounts receivable....................................... 9,180 8,588
Other current assets...................................... 344 247
-------- --------
Total current assets.............................. 12,825 11,943
-------- --------
Equity investments (Notes 2 and 3).......................... 219,732 186,079
Property and equipment, net (Notes 2 and 4)................. 381,210 241,992
Other noncurrent assets..................................... 12,146 2,712
-------- --------
Total assets...................................... $625,913 $442,726
======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities
Accounts payable and accrued liabilities.................. $ 12,475 $ 11,167
Notes payable (Note 6).................................... -- 338,000
-------- --------
Total current liabilities......................... 12,475 349,167
Notes payable (Note 6)...................................... 306,500 --
Long-term debt (Note 6)..................................... 175,000 --
Other noncurrent liabilities................................ 12,151 11,661
-------- --------
Total liabilities................................. 506,126 360,828
Commitments and contingencies
Minority interest........................................... (249) (998)
Partners' capital (Note 2).................................. 120,036 82,896
-------- --------
Total liabilities and partners' capital........... $625,913 $442,726
======== ========
</TABLE>
The accompanying Notes are an integral part of these Condensed Consolidated
Financial Statements.
F-13
<PAGE> 131
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED JUNE 30,
--------------------
1999 1998
--------- --------
<S> <C> <C>
Cash flows from operating activities
Net income................................................ $ 7,687 $ 86
Adjustments to reconcile net income to net cash provided
by operating activities................................
Depreciation, depletion and amortization............... 13,727 14,845
Distributions from equity investees.................... 24,108 13,298
Equity in earnings..................................... (19,953) (12,571)
Other noncash items.................................... 721 509
Working capital changes, net of effects of acquisitions... (2,650) (3,283)
--------- --------
Net cash provided by operating activities......... 23,640 12,884
--------- --------
Cash flows from investing activities
Additions to pipelines, platforms and facilities.......... (14,260) (12,283)
Investments in equity investees........................... (4,393) (4,543)
Acquisition of additional interests in equity investees,
net of cash received................................... (51,128) --
Net cash flow impact of acquisition of Viosca Knoll....... (19,856) --
Development of oil and natural gas properties............. (3,181) (2,540)
--------- --------
Net cash used in investing activities............. (92,818) (19,366)
--------- --------
Cash flows from financing activities
Proceeds from notes payable............................... 95,500 50,000
Long-term debt issuance................................... 175,000 --
Repayments of notes payable............................... (160,350) (18,000)
Debt issuance costs....................................... (10,126) --
Distributions to partners................................. (31,256) (30,806)
General Partner's contribution............................ 603 --
--------- --------
Net cash provided by financing activities......... 69,371 1,194
--------- --------
Increase (decrease) in cash and cash equivalents............ 193 (5,288)
Cash and cash equivalents
Beginning of period....................................... 3,108 6,430
--------- --------
End of period............................................. $ 3,301 $ 1,142
========= ========
</TABLE>
Non-cash Investing Activities: See Note 2 for discussion.
The accompanying Notes are an integral part of these Condensed Consolidated
Financial Statements.
F-14
<PAGE> 132
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(IN THOUSANDS)
<TABLE>
<CAPTION>
PREFERENCE PREFERENCE COMMON COMMON GENERAL
UNITS UNITHOLDERS UNITS UNITHOLDERS PARTNER(A) TOTAL
---------- ----------- ------ ----------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Partners' capital at December
31, 1998.................... 1,017 $7,351 23,350 $ 90,972 $(15,427) $ 82,896
Net income for the six months
ended June 30, 1999
(unaudited)................. -- 131 -- 6,098 1,458 7,687
Issuance of Common Units for
acquisition of additional
interest in Viosca Knoll
(unaudited)................. -- -- 2,662 59,792 -- 59,792
General Partner contribution
related to issuance of
Common Units (unaudited).... -- -- -- -- 603 603
Cash distributions
(unaudited)................. -- (559) -- (24,517) (5,866) (30,942)
----- ------ ------ -------- -------- --------
Partners' capital at June 30,
1999 (unaudited)............ 1,017 $6,923 26,012 $132,345 $(19,232)(b) $120,036
===== ====== ====== ======== ======== ========
</TABLE>
- ---------------
(a) Leviathan Gas Pipeline Company owns a 1% general partner interest in
Leviathan.
(b) Pursuant to the terms of Leviathan's partnership agreement, no partner shall
have any obligation to restore any negative balance in its capital account
upon liquidation of Leviathan. Therefore, any net gains from the dissolution
of Leviathan's assets would be allocated first to any then-outstanding
deficit capital account balance before any of the remaining net proceeds
would be distributed to the partners in accordance with their ownership
percentages.
The accompanying Notes are an integral part of these Condensed Consolidated
Financial Statements.
F-15
<PAGE> 133
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE 1 -- ORGANIZATION AND BASIS OF PRESENTATION:
Leviathan is a provider of integrated energy services, including natural
gas and oil gathering, transportation, midstream and other related services in
the Gulf. Through its subsidiaries and joint ventures, Leviathan owns interests
in significant assets, including (i) nine (eight existing and one under
construction) natural gas pipelines (the "Gas Pipelines"), (ii) two (one
existing and one under construction) oil pipeline systems, (iii) six
strategically-located multi-purpose platforms, (iv) production handling and
dehydration facilities, (v) four producing oil and natural gas properties and
(vi) a non-producing oil and natural gas property, the Ewing Bank 958 Unit,
comprised of Ewing Bank Blocks 958, 959, 1002 and 1003, formerly referred to as
the Sunday Silence property. The General Partner performs all management and
operational functions for Leviathan and its subsidiaries.
As of June 30, 1999, Leviathan had 26,011,858 Common Units and 1,016,906
Preference Units outstanding. The public owns limited partner interests
representing an effective 65.5% interest in Leviathan, comprised of 1,016,906
Preference Units and 17,058,094 Common Units. El Paso Energy, through its
subsidiaries, owns an effective 34.5% economic interest in Leviathan, comprised
of a 32.5% limited partner interest in the form of 8,953,764 Common Units, its
1% general partner interest in Leviathan and its approximate 1% nonmanaging
member interest in certain subsidiaries of Leviathan.
The 1998 Annual Report on Form 10-K for Leviathan includes a summary of
significant accounting policies and other disclosures and should be read in
conjunction with this Quarterly Report on Form 10-Q. The condensed consolidated
financial statements at June 30, 1999, and for the quarters and six months ended
June 30, 1999 and 1998 are unaudited. The condensed consolidated balance sheet
at December 31, 1998 is derived from audited consolidated financial statements
at that date. These financial statements do not include all disclosures required
by generally accepted accounting principles, but have been prepared pursuant to
the rules and regulations of the United States Securities and Exchange
Commission. In the opinion of management, all material adjustments necessary to
present fairly the consolidated financial position and results of operations for
such periods have been included. All such adjustments are of a normal recurring
nature. Results of operations for any interim period are not necessarily
indicative of the results of operations for the entire year due to the seasonal
nature of Leviathan's businesses.
NOTE 2 -- ACQUISITIONS:
Viosca Knoll
In January 1999, Leviathan entered into a Contribution Agreement with EPFS
to acquire all of EPFS's interest in Viosca Knoll other than a 1% interest in
profits and capital of Viosca Knoll. At the time the Contribution Agreement was
executed, Leviathan and EPFS each beneficially owned a 50% interest in Viosca
Knoll, which was formed in 1994 to construct, own and operate an unregulated
gathering system designed to serve the Main Pass, Mississippi Canyon and Viosca
Knoll areas of the Gulf. The Viosca Knoll system is comprised of (i) an
approximately 94 mile, 20-inch diameter pipeline from a platform in Main Pass
Block 252 owned by Shell Offshore, Inc. to a pipeline owned by Tennessee Gas
Pipeline Company at South Pass Block 55 and (ii) a six mile 16-inch diameter
pipeline from an interconnection with the 20-inch diameter pipeline at
Leviathan's Viosca Knoll Block 817 platform to a pipeline owned by Southern
Natural Gas Company at Main Pass Block 289.
Leviathan and EPFS closed the Viosca Knoll acquisition on June 1, 1999. In
connection therewith, (i) EPFS contributed to Viosca Knoll $33.4 million, which
amount was equal to 50% of the amount then outstanding under Viosca Knoll's
credit facility, (ii) a subsidiary of EPFS transferred a 49% interest in Viosca
Knoll to Leviathan, (iii) Leviathan paid to a subsidiary of EPFS $19.9 million
and issued to that subsidiary 2,661,870 Common Units, (iv) Leviathan paid other
closing costs of $0.8 million and (v) as
F-16
<PAGE> 134
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
required by Leviathan's Amended and Restated Agreement of Limited Partnership,
the General Partner contributed $0.6 million to Leviathan in order to maintain
its 1% capital account balance. In addition, during the six months commencing on
June 1, 2000, Leviathan has an option to acquire the remaining 1% interest in
profits and capital of Viosca Knoll for a cash payment equal to the sum of $1.6
million plus the amount of additional distributions (paid, payable or in
arrears) which would have been paid, accrued or been in arrears had Leviathan
acquired the remaining 1% of Viosca Knoll on June 1, 1999, by issuing additional
Common Units in lieu of a cash payment of $1.7 million. Leviathan used the
equity method of accounting for its 50% interest in Viosca Knoll through May 31,
1999. As a result of its acquisition of an additional 49% interest in Viosca
Knoll, Leviathan began consolidating Viosca Knoll as of June 1, 1999. The
acquisition of Viosca Knoll was accounted for as a purchase and the purchase
price was assigned to the assets and liabilities acquired based upon the
estimated fair value of those assets and liabilities as of the acquisition date.
The fair value of allocations are preliminary and may be revised after the
completion of an independent appraisal.
<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
Fair value of assets acquired.......................... $ 83,061
Cash acquired.......................................... 434
Fair value of liabilities assumed...................... (2,962)
--------
Total purchase price......................... 80,533
Issuance of common units............................... (59,792)
--------
Net cash paid................................ $ 20,741
========
</TABLE>
The following selected unaudited pro forma information represents
Leviathan's consolidated results of operations on a pro forma basis for the six
month periods ended June 30, 1999 and 1998, assuming the Viosca Knoll
acquisition had occurred on January 1, 1998:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
---------------------
1999 1998
--------- ---------
(IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)
<S> <C> <C>
Revenue..................................................... $54,330 $46,021
Operating income............................................ $26,355 $14,334
Net income.................................................. $ 9,650 $ 3,005
Basic and diluted net income per unit....................... $ 0.29 $ 0.09
</TABLE>
HIOS/UTOS
On June 30, 1999, subsidiaries of Leviathan acquired from Natural Gas
Pipeline Company of America ("NGPL"), a subsidiary of KN Energy, Inc., for total
consideration of approximately $51 million, net of cash received, (i) all of the
outstanding stock of two of NGPL's wholly-owned subsidiaries, Natoco, Inc.
("Natoco"), which owns a 20% member interest in Western Gulf, which in turn owns
100% of each of HIOS and East Breaks, and Naloco, Inc. (Del.) ("Naloco"), which
owns a 33.33% interest in UTOS, and (ii) NGPL's ownership interest in certain
lateral pipelines located in the Gulf. In addition, Leviathan will assume NGPL's
role as operator of Stingray, the Stingray Offshore Separation Facility and West
Cameron Dehydration Facility. Leviathan financed this acquisition with funds
borrowed under its $375 million revolving credit facility discussed in Note 6.
The purchase price exceeded the fair market value of net assets acquired by
approximately $48 million. This excess cost has been preliminary assigned to
property and equipment and is to be amortized on a straight line basis over 30
years. After giving effect to the acquisition, Leviathan owns a 60% interest in
Western Gulf, and thus an effective 60% interest in each of HIOS and East Breaks
and a 66.67% interest in UTOS. Since Leviathan's control is
F-17
<PAGE> 135
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
expected to be temporary, these investments will continue to be accounted for
under the equity method of accounting.
Western Gulf was formed in December 1998 by Leviathan, NGPL and ANR
Pipeline Company ("ANR") as a holding company for HIOS and East Breaks. HIOS
consists of approximately 204 miles of pipeline comprised of three supply
laterals, the West, Central and East Laterals, that connect to a 42-inch
diameter mainline. The HIOS system was placed in service in 1977 and is used to
gather and transport natural gas produced from fields located in the Galveston,
Garden Banks, High Island, West Cameron and East Breaks areas of the Gulf to a
junction platform owned by HIOS located in West Cameron Block 167. The total
capacity of the HIOS system is approximately 1.8 Bcf of natural gas per day. ANR
operates the HIOS system. The East Breaks system is currently under
construction, with a design capacity of over 400 Mcf of natural gas per day, and
will initially consist of 85 miles of an 18 to 20-inch pipeline and related
facilities connecting the Diana/Hoover prospects developed by Exxon Company USA
("Exxon") and BP Amoco plc ("BP Amoco") in Alaminos Canyon Block 25, with the
HIOS system. The majority of the construction of the East Breaks system will
occur in 1999 and the system is anticipated to be in service by mid-2000 at an
estimated cost of approximately $90 million.
Prior to June 30, 1999, UTOS was owned equally by Leviathan, NGPL and ANR.
The UTOS system was placed in service in 1978 and consists of approximately 30
miles of 42-inch diameter pipeline extending from a point of interconnection
with HIOS at West Cameron Block 167 to the Johnson Bayou processing facility in
southern Louisiana. The UTOS system transports natural gas from the terminus of
the HIOS system at West Cameron Block 167 to the Johnson Bayou facility, where
it interconnects with one intrastate and four interstate pipeline systems. UTOS
also owns the Johnson Bayou facility, which provides primarily natural gas and
liquids separation and natural gas dehydration for natural gas transported on
the HIOS and UTOS systems. ANR operates the UTOS system.
The following selected unaudited pro forma information represents
Leviathan's consolidated results of operations on a pro forma basis for the six
month periods ended June 30, 1999 and 1998, assuming the HIOS/UTOS acquisition,
the acquisition of certain lateral pipelines and the effects of becoming the
operator of Stingray had occurred on January 1, 1998.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
--------------------
1999 1998
-------- --------
(IN THOUSANDS EXCEPT
PER UNIT AMOUNTS)
<S> <C> <C>
Revenue..................................................... $47,755 $38,485
Operating income............................................ $22,896 $10,392
Net income (loss)........................................... $ 6,882 $ (230)
Basic and diluted net income (loss) per unit................ $ 0.23 $ (0.01)
</TABLE>
NOTE 3 -- EQUITY INVESTMENTS:
Leviathan's ownership interest in each of the Equity Investees is included
in the summarized financial information that follows:
F-18
<PAGE> 136
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMMARIZED HISTORICAL OPERATING RESULTS
SIX MONTHS ENDED JUNE 30, 1999
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
WEST
VIOSCA CAMERON MANTA RAY
HIOS(A) UTOS(A) KNOLL(B) STINGRAY DEHY POPCO OFFSHORE(C) NAUTILUS(C) TOTAL
------- ------- -------- -------- ------- ------- ----------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenue...... $19,350 $2,119 $12,338 $ 9,068 $1,475 $36,217 $ 7,780 $ 4,453
Other income........... 118 33 31 1,105 13 191 1,144 (123)
Operating expenses..... (8,649) (1,074) (925) (5,569) (142) (3,814) (1,997) (698)
Depreciation........... (2,321) (280) (1,752) (3,800) (8) (2,301) (2,523) (2,964)
Interest expense....... -- -- (1,973) (858) -- (4,220) (18) (182)
------- ------- ------- ------- ------ ------- ------- -------
Net earnings (loss).... 8,498 798 7,719 (54) 1,338 26,073 4,386 486
Ownership percentage... 40% 33.3% 50% 50% 50% 36% 25.67% 25.67%
------- ------- ------- ------- ------ ------- ------- -------
3,399 266 3,860 (27) 669 9,386 1,126 125
Adjustments:
Depreciation(d)...... 354 17 -- 400 -- (60) (174) --
Contract
amortization(d).... (53) -- -- -- -- -- -- --
Other................ (2) 3 -- 721(e) -- -- -- (57)
------- ------- ------- ------- ------ ------- ------- -------
Equity in earnings..... $3,698 $ 286 $ 3,860 $ 1,094 $ 669 $ 9,326 $ 952 $ 68 $19,953
======= ======= ======= ======= ====== ======= ======= ======= =======
Distributions(f)....... $4,200 $ 333 $ 6,350 $ 2,501 $ 550 $ 7,463 $ 1,954 $ 757 $24,108
======= ======= ======= ======= ====== ======= ======= ======= =======
</TABLE>
- ---------------
(a) As a result of restructuring the joint venture arrangement in December
1998, the partners of HIOS, (i) created a holding company, Western Gulf,
(ii) converted the HIOS Delaware partnership into a limited liability
company and (iii) formed East Breaks. HIOS owns a regulated natural gas
system, and East Breaks is currently constructing an unregulated natural
gas system. Leviathan believes the disclosure of separate financial data
for HIOS and East Breaks is more meaningful than the consolidated results
of Western Gulf. East Breaks has had only construction activity since its
inception. On June 30, 1999, Leviathan acquired additional interests in
HIOS, East Breaks and UTOS (see Note 2). As a result of the additional
interests acquired, Leviathan owns an effective 60% interest in each of
HIOS and East Breaks and a 66.7% interest in UTOS.
(b) The information presented for Viosca Knoll as an equity investment is
through May 31, 1999. On June 1, 1999, Leviathan began consolidating the
results of Viosca Knoll as a result of acquiring an additional 49% interest
in Viosca Knoll (see Note 2).
(c) Leviathan owns a 25.67% interest in each of Neptune and Ocean Breeze, which
together own 100% of the member interests in each of Manta Ray Offshore,
which owns an unregulated natural gas system, and Nautilus, which owns a
regulated natural gas system. Leviathan believes the disclosure of separate
financial data for Manta Ray Offshore and Nautilus is more meaningful than
the consolidated results of Neptune and Ocean Breeze.
(d) Adjustments result from purchase price adjustments made in accordance with
Accounting Principles Board ("APB") Opinion No. 16, "Business
Combinations."
(e) Adjustments primarily resulting from changes in prior period estimates of
reserves for uncollectible revenue.
(f) Future distributions are at the discretion of the Equity Investees'
management committees and could further be restricted by the terms of the
Equity Investees' respective credit agreements.
F-19
<PAGE> 137
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMMARIZED HISTORICAL OPERATING RESULTS
SIX MONTHS ENDED JUNE 30, 1998
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
WEST
VIOSCA CAMERON MANTA RAY
HIOS UTOS KNOLL STINGRAY DEHY POPCO OFFSHORE(A) NAUTILUS(A) TOTAL
------- ------- ------- -------- ------- ------- ----------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenue......... $21,730 $ 2,384 $14,746 $11,620 $1,191 $19,517 $ 5,234 $ 1,289
Other income.............. 134 57 23 434 2 145 184 17
Operating expenses........ (8,632) (1,260) (1,263) (7,611) (84) (1,960) (1,533) (678)
Depreciation.............. (2,384) (279) (1,893) (3,489) (7) (4,392) (2,129) (2,890)
Interest expense.......... -- -- (1,989) (1,069) -- (4,396) -- (12)
------- ------- ------- ------- ------ ------- ------- -------
Net earnings (loss)....... 10,848 902 9,624 (115) 1,102 8,914 1,756 (2,274)
Ownership percentage...... 40% 33.3% 50% 50% 50% 36% 25.67% 25.67%
------- ------- ------- ------- ------ ------- ------- -------
4,339 301 4,812 (58) 551 3,209 451 (584)
Adjustments:
Depreciation(b)......... 379 16 -- 406 -- -- (174) --
Contract
amortization(b)....... (53) -- -- (122) -- -- -- --
Other................... (69) 16 -- (24) -- (60) -- (765)(c)
------- ------- ------- ------- ------ ------- ------- -------
Equity in earnings
(loss)................ $ 4,596 $ 333 $ 4,812 $ 202 $ 551 $ 3,149 $ 277 $(1,349) $12,571
======= ======= ======= ======= ====== ======= ======= ======= =======
Distributions........... $ 5,240 $ 333 $ 5,800 $ 1,000 $ 425 $ -- $ 500 $ -- $13,298
======= ======= ======= ======= ====== ======= ======= ======= =======
</TABLE>
- ---------------
(a) Leviathan owns a 25.67% interest in each of Neptune and Ocean Breeze, which
together own 100% of the member interests in each of Manta Ray Offshore,
which owns an unregulated natural gas system, and Nautilus, which owns a
regulated natural gas system. Leviathan believes the disclosure of separate
financial data for Manta Ray Offshore and Nautilus is more meaningful than
the consolidated results of Neptune and Ocean Breeze.
(b) Adjustments result from purchase price adjustments made in accordance with
APB Opinion No. 16.
(c) Primarily relates to a revision of the allowance for funds used during
construction ("AFUDC") which represents the estimated costs, during the
construction period, of funds used for construction purposes.
NOTE 4 -- PROPERTY AND EQUIPMENT:
Property and equipment consist of the following (in thousands):
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
----------- ------------
(UNAUDITED)
<S> <C> <C>
Property and equipment, at cost
Pipelines................................................. $ 79,313 $ 64,464
Platforms and facilities.................................. 271,049 123,912
Oil and natural gas properties, at cost, using successful
efforts method......................................... 155,931 152,750
-------- --------
506,293 341,126
Less accumulated depreciation, depletion, amortization and
impairment................................................ 125,083 99,134
-------- --------
Property and equipment, net....................... $381,210 $241,992
======== ========
</TABLE>
F-20
<PAGE> 138
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 5 -- BUSINESS SEGMENT INFORMATION:
The following table summarizes certain financial information for each
business segment (in thousands):
<TABLE>
<CAPTION>
GATHERING,
TRANSPORTATION
AND PLATFORM OIL AND EQUITY ELIMINATIONS
SERVICES NATURAL GAS INVESTMENTS SUBTOTAL AND OTHER TOTAL
-------------- ----------- ----------- -------- ------------ --------
<S> <C> <C> <C> <C> <C> <C>
QUARTER ENDED JUNE 30,
1999:
Revenue from external
customers.......... $ 6,425 $ 8,295 $ 9,252 $ 23,972 $ -- $ 23,972
Intersegment
revenue............ 3,136 -- -- 3,136 (3,136) --
Depreciation,
depletion and
amortization....... (2,323) (4,686) -- (7,009) -- (7,009)
Operating income
(loss)............. 4,632 (1,177) 8,298 11,753 -- 11,753
Net cash flows........ 6,956 3,508 13,064 23,528 -- 23,528
Segment assets........ 310,609 77,871 222,038 610,518 15,395 625,913
QUARTER ENDED JUNE 30,
1998:
Revenue from external
customers.......... $ 4,522 $ 6,599 $ 7,252 $ 18,373 $ -- $ 18,373
Intersegment
revenue............ 2,486 -- -- 2,486 (2,486) --
Depreciation,
depletion and
amortization....... (1,903) (5,075) -- (6,978) -- (6,978)
Operating income
(loss)............. 2,700 (3,061) 6,494 6,133 -- 6,133
Net cash flows........ 4,603 2,014 6,215 12,832 -- 12,832
Segment assets........ 143,340 58,662 188,530 390,532 15,555 406,087
SIX MONTHS ENDED JUNE
30, 1999:
Revenue from external
customers.......... $ 10,798 $15,100 $ 19,953 $ 45,851 $ -- $ 45,851
Intersegment
revenue............ 6,010 -- -- 6,010 (6,010) --
Depreciation,
depletion and
amortization....... (4,243) (9,484) -- (13,727) -- (13,727)
Operating income
(loss)............. 7,642 (4,043) 17,591 21,190 -- 21,190
Net cash flows........ 11,885 5,441 21,746 39,072 -- 39,072
Segment assets........ 310,609 77,871 222,038 610,518 15,395 625,913
SIX MONTHS ENDED JUNE
30, 1998:
Revenue from external
customers.......... $ 7,782 $15,734 $ 12,571 $ 36,087 $ -- $ 36,087
Intersegment
revenue............ 5,075 -- -- 5,075 (5,075) --
Depreciation,
depletion and
amortization....... (3,519) (11,326) -- (14,845) -- (14,845)
Operating income
(loss)............. 3,129 (5,109) 10,173 8,193 -- 8,193
Net cash flows........ 6,648 6,217 10,900 23,765 -- 23,765
Segment assets........ 143,340 58,662 188,530 390,532 15,555 406,087
</TABLE>
F-21
<PAGE> 139
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 6 -- FINANCING TRANSACTIONS:
Senior Subordinated Notes
Leviathan entered into an indenture dated May 27, 1999 with Chase Bank of
Texas, National Association, pursuant to which it issued $175 million in
aggregate principal amount of Senior Subordinated Notes (along with the
indenture, the "Subordinated Notes"). Leviathan capitalized $5.2 million of debt
issue costs related to the issuance of the Subordinated Notes. Approximately
$19.9 million of the proceeds were used to consummate the Viosca Knoll
acquisition (see Note 2), $33.4 million were contributed to Viosca Knoll to
repay the remaining unpaid balance of the Viosca Knoll credit facility, and the
remaining proceeds were used to reduce the balance outstanding of and to extend
Leviathan's revolving credit facility (discussed below).
The Subordinated Notes bear interest at a rate of 10 3/8% per annum,
payable semi-annually, on June 1 and December 1, mature on June 1, 2009 and are
junior to substantially all of Leviathan's other indebtedness other than trade
payables and indebtedness that by its terms expressly states it is equal or
junior to the Subordinated Notes. Generally, Leviathan does not have the right
to prepay the Subordinated Notes prior to May 31, 2004 and thereafter, Leviathan
may prepay the Subordinated Notes at a premium of 5% of the face amount, which
premium declines ratably through maturity. Although the Subordinated Notes are
unsecured, all of Leviathan's subsidiaries have guaranteed those obligations.
The Subordinated Notes contain customary terms and conditions, including various
affirmative and negative covenants and the obligation to offer to repurchase the
notes at a premium under certain circumstances. Among other things, the terms of
the Subordinated Notes limit Leviathan's ability to make distributions to its
unitholders, redeem or otherwise reacquire any of its equity, incur additional
indebtedness, incur or permit to exist certain liens, make additional
investments, engage in transactions with affiliates, engage in certain types of
businesses and dispose of assets under certain circumstances, including if
certain financial tests are not satisfied or there is a default. In addition,
Leviathan will be obligated to offer to repurchase the Subordinated Notes if it
experiences certain types of changes of control or if it disposes of certain
assets and does not reinvest the proceeds or repay senior indebtedness. Also,
Leviathan agreed to file a registration statement for an offer to exchange the
Subordinated Notes for debt securities with identical terms and to complete the
registered exchange offer within 180 days after June 1, 1999.
Leviathan Credit Facility
Concurrent with the closing of the offering of the Subordinated Notes,
Leviathan amended and restated its $375 million credit facility (the "Leviathan
Credit Facility") to, among other things, extend its maturity from December 1999
to May 2002. Leviathan incurred approximately $3.0 million related to the
amendment and restatement of the credit facility. The Leviathan Credit Facility,
as amended, is a revolving credit facility with a syndicate of commercial banks
providing for up to $375 million of available credit, subject to customary terms
and conditions, including certain limitations on incurring additional
indebtedness (including borrowings under this facility) if certain financial
targets are not achieved and maintained. In addition, Leviathan will be required
to prepay a portion of the balance outstanding under this credit facility to the
extent such financial targets are not achieved and maintained. Funds borrowed
under the Leviathan Credit Facility are available to Leviathan for general
partnership purposes, including financing capital expenditures, working capital
requirements and, subject to certain limitations, distributions to the
unitholders. The Leviathan Credit Facility can also be utilized to issue letters
of credit as may be required from time to time; however, no letters of credit
are currently outstanding. The Leviathan Credit Facility, as amended, matures in
May 2002; is guaranteed by the General Partner and each of Leviathan's
subsidiaries; and is collateralized by (i) the management agreement between the
General Partner and a subsidiary of El Paso Energy, (ii) substantially all of
the assets of Leviathan and its subsidiaries and (iii) the General Partner's 1%
general partner interest in Leviathan and approximate 1% nonmanaging
F-22
<PAGE> 140
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
member interest in certain subsidiaries of Leviathan. The Leviathan Credit
Facility has no scheduled amortization prior to maturity. As of June 30, 1999,
Leviathan had $306.5 million outstanding under its credit facility bearing
interest at an average floating rate of 7.5% per annum.
NOTE 7 -- PARTNERS' CAPITAL INCLUDING CASH DISTRIBUTIONS:
Cash distributions
Leviathan paid cash distributions of $0.275 per Preference Unit and $0.525
per Common Unit for each of the three months ended December 31, 1998 and March
31, 1999 in February 1999 and May 1999, respectively. As a result, the General
Partner received incentive distributions of $5.6 million for the six months
ended June 30, 1999. On July 19, 1999, Leviathan declared a cash distribution of
$0.275 per Preference Unit and $0.525 per Common Unit for the three months ended
June 30, 1999 which was paid on August 13, 1999, to all holders of record of
Common Units and Preference Units as of July 30, 1999. The General Partner was
paid an incentive distribution of $3.2 million for the quarter ended June 30,
1999. At the current distribution rates, the General Partner receives
approximately 19% of total cash distributions paid by Leviathan and is thus
allocated approximately 19% of Leviathan's net income.
Conversion of Preference Units into Common Units
On May 14, 1999, Leviathan notified the holders of its 1,016,906 then
outstanding Preference Units of their opportunity to submit their Preference
Units for conversion into an equal number of Common Units during a 90-day
period. During the conversion period, 725,607 Preference Units were converted
into an equal number of Common Units. The remaining 291,299 Preference Units
will retain their distribution preferences over the Common Units; that is, no
Common Unitholder or the General Partner will receive any quarterly distribution
until each Preference Unitholder has received the minimum quarterly distribution
of $0.275 per unit plus any arrearages. Holders of the Common Units and the
General Partner are entitled to distributions in excess of $0.275 per unit.
Preference Units are not entitled to any such excess distributions.
Holders of Preference Units will have a third and final conversion
opportunity in May 2000. Thereafter, any remaining Preference Units may, in
certain circumstances, be subject to mandatory redemption at below market
trading prices. Further, following this most recent conversion opportunity
period, the Preference Units may no longer meet New York Stock Exchange minimum
listing requirements and may be delisted.
F-23
<PAGE> 141
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8 -- NET INCOME PER UNIT:
Basic and diluted net income per unit is calculated based upon the net
income of Leviathan less an allocation of net income to the General Partner
proportionate to its share of cash distributions and is presented below for the
quarters and six months ended June 30, 1999 and 1998 (in thousands).
<TABLE>
<CAPTION>
QUARTER ENDED JUNE 30,
---------------------------------------------------------
1999 1998
--------------------------- ---------------------------
LIMITED GENERAL LIMITED GENERAL
PARTNERS PARTNER TOTAL PARTNERS PARTNER TOTAL
-------- ------- ------ -------- ------- ------
<S> <C> <C> <C> <C> <C> <C>
Net income(a)............................ $4,146 $ 42 $4,188 $1,495 $ 15 $1,510
Allocation to General Partner(b)......... (753) 753 -- (277) 277 --
------ ------ ------ ------ ---- ------
Allocation of net income as adjusted for
incentive distributions................ $3,393 $ 795 $4,188 $1,218 $292 $1,510
====== ====== ====== ====== ==== ======
Weighted average number of units
outstanding(c)......................... 25,244 24,367
====== ======
Basic and diluted net income per unit.... $ 0.13 $ 0.05
====== ======
</TABLE>
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30,
---------------------------------------------------------
1999 1998
--------------------------- ---------------------------
LIMITED GENERAL LIMITED GENERAL
PARTNERS PARTNER TOTAL PARTNERS PARTNER TOTAL
-------- ------- ------ -------- ------- ------
<S> <C> <C> <C> <C> <C> <C>
Net income(a)............................ $ 7,610 $ 77 $7,687 $ 85 $ 1 $ 86
Allocation to General Partner(b)......... (1,382) 1,382 -- (16) 16 --
------- ------ ------ ------ ---- ------
Allocation of net income as adjusted for
incentive distributions................ $ 6,228 $1,459 $7,687 $ 69 $ 17 $ 86
======= ====== ====== ====== ==== ======
Weighted average number of units
outstanding(c)......................... 24,808 24,367
======= ======
Basic and diluted net income per unit.... $ 0.25 $ 0.00
======= ======
</TABLE>
- ---------------
(a) Net income is initially allocated 99% to the limited partners as holders of
the Preference and Common Units and 1% to the General Partner (see (b)).
(b) Represents allocation of net income to the General Partner proportionate to
its share of each quarter's cash distributions which included incentive
distributions (see Note 7).
(c) Diluted weighted average number of units outstanding for 1999 is less than
1,000 units higher than basic weighted average units outstanding as a
result of unit options included in the diluted weighted average.
NOTE 9 -- RELATED PARTY TRANSACTIONS:
Management fees
Leviathan's partnership agreement provides for reimbursement of expenses
incurred by the General Partner, including reimbursement of expenses incurred by
El Paso Energy in providing management services to Leviathan, its subsidiaries
and the General Partner. The General Partner charged Leviathan $2.3 million,
$2.1 million, $4.7 million and $4.6 million for the quarters and six months
ended June 30, 1999 and 1998, respectively.
F-24
<PAGE> 142
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 10 -- COMMITMENTS AND CONTINGENCIES:
Leviathan may utilize derivative financial instruments for purposes other
than trading to manage its exposure to movements in interest rates and commodity
prices. In accordance with procedures established by Leviathan's Board of
Directors, Leviathan monitors current economic conditions and evaluates its
expectations of future prices and interest rates when making decisions with
respect to risk management.
Interest Rate Risk
Leviathan utilizes both fixed and variable rate long-term debt. Leviathan
is exposed to some market risk due to the floating interest rate under its
credit facility. Under the Leviathan Credit Facility, as amended, the remaining
principal and the final interest payment are due in May 2002. As of August 9,
1999, Leviathan's credit facility had a principal balance of $300 million at an
average floating interest rate of 7.7% per annum. A 1.5% increase in interest
rates could result in a $4.5 million annual increase in interest expense on the
existing principal balance. Leviathan is exposed to similar risk under the
credit facilities and loan agreements entered into by its joint ventures.
Leviathan has determined that it is not necessary to participate in interest
rate-related derivative financial instruments because it currently does not
expect significant short-term increases in the interest rates charged under its
credit facility or the various joint venture credit facilities and loan
agreements.
Commodity Price Risk
Leviathan hedges a portion of its oil and natural gas production to reduce
its exposure to fluctuations in the market prices thereof. Leviathan uses
commodity price swap transactions whereby monthly settlements are based on
differences between the prices specified in the commodity price swap agreements
and the settlement prices of certain futures contracts quoted on the NYMEX or
certain other indices. Leviathan settles the commodity price swap transactions
by paying the negative difference or receiving the positive difference between
the applicable settlement price and the price specified in the contract. The
commodity price swap transactions Leviathan uses differ from futures contracts
in that there are no contractual obligations which require or allow for the
future delivery of the product. The credit risk from Leviathan's price swap
contracts is derived from the counterparty to the transaction, typically a major
financial institution. Leviathan does not require collateral and does not
anticipate nonperformance by this counterparty, which does not transact a
sufficient volume of transactions with Leviathan to create a significant
concentration of credit risk. Gains or losses resulting from hedging activities
and the termination of any hedging instruments are initially deferred and
included as an increase or decrease to oil and natural gas sales in the period
in which the hedged production is sold. For the quarter and six months ended
June 30, 1999 and 1998, Leviathan recorded a net gain (loss) of $(0.4) million,
$0.6 million, $(0.7) million and $1.4 million, respectively, related to hedging
activities.
As of June 30, 1999, Leviathan has open sales swap transactions for 10,000
MMbtu of natural gas per day for calendar 2000 at a fixed price to be determined
at its option equal to the February 2000 Natural Gas Futures Contract on the
NYMEX as quoted at any time during 1999 and January 2000, to and including the
last two trading days of the February 2000 contract, minus $0.5450 per MMbtu.
Additionally, Leviathan has open sales swap transactions of 10,000 MMbtu of
natural gas per day at a fixed price to be determined at its option equal to the
January 2000 Natural Gas Futures Contract on NYMEX as quoted at any time during
1999, to and including the last two trading days of the January 2000 contract,
minus $0.50 per MMbtu.
At June 30, 1999, Leviathan had open crude oil hedges on approximately 500
barrels per day for the remainder of calendar 1999 at an average price of $16.10
per barrel.
F-25
<PAGE> 143
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
If Leviathan had settled its open oil and natural gas hedging positions as
of June 30, 1999, based on the applicable settlement prices of the NYMEX futures
contracts, Leviathan would have recognized a loss of approximately $2.2 million.
Other
Leviathan is involved from time to time in various claims, actions,
lawsuits and regulatory matters that have arisen in the ordinary course of
business, including various rate cases and other proceedings before the Federal
Energy Regulatory Commission.
Leviathan and several subsidiaries of El Paso Energy have been made
defendants in actions brought by Jack Grynberg on behalf of the United States
Government under the false claims act. Generally, the complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes
of the natural gas produced from federal and Indian lands, thereby depriving the
United States Government of royalties. In April 1999, the U.S. Government filed
a notice that it does not intend to intervene in these actions. Grynberg has
petitioned the Multidistrict Litigation Panel ("MLP") for consolidation of
pre-trial matters. The MLP will not consider this matter until September 1999.
Leviathan and El Paso Energy believe the complaint is without merit, and
therefore, will not have a material adverse effect on Leviathan's consolidated
financial position, results of operations or cash flows.
Leviathan is a defendant in a lawsuit filed by Transco Gas Pipe Line
Corporation ("Transco") in the 157th Judicial District Court, Harris County,
Texas on August 30, 1996. Transco alleges that, pursuant to a platform lease
agreement entered into on June 28, 1994, Transco has the right to expand its
facilities and operations on the offshore platform by connecting additional
pipeline receiving and appurtenant facilities. Management has denied Transco's
request to expand its facilities and operations because the lease agreement does
not provide for such expansion and because Transco's activities will interfere
with the Manta Ray Offshore system and Leviathan's existing and planned
activities on the platform. Transco has requested a declaratory judgment and is
seeking damages. The case is set for trial in November 1999. It is the opinion
of management that adequate defenses exist and that the final disposition of
this suit will not have a material adverse effect on Leviathan's consolidated
financial position, results of operations or cash flows.
Leviathan is a named defendant in several lawsuits and a named party in
several governmental proceedings arising in the ordinary course of business.
While the outcome of such lawsuits or other proceedings against Leviathan cannot
be predicted with certainty, management currently does not expect these matters
to have a material adverse effect on Leviathan's consolidated financial
position, results of operations or cash flows.
NOTE 11 -- NEW ACCOUNTING PRONOUNCEMENT NOT YET ADOPTED:
In June 1998, Statement of Financial Accounting Standards ("SFAS") No. 133,
Accounting for Derivative Instruments and Hedging Activities, was issued by the
Financial Accounting Standards Board to establish accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. SFAS No. 133 requires
that entities recognize all derivative investments as either assets or
liabilities on the balance sheet and measure those instruments at fair value.
Changes in the fair value of derivatives are recorded each period in current
earnings or other comprehensive income, depending on whether a derivative is
designated as a hedge transaction. For fair-value hedge transactions in which
Leviathan is hedging changes in an asset's, liability's or firm commitment's
fair value, changes in the fair value of the derivative instrument will
generally be offset in the income statement by changes in the hedged item's fair
value. For cash-flow hedge transactions in which Leviathan is hedging the
variability of cash flows related to a variable-rate asset, liability, or a
forecasted transaction, changes in the fair value of the derivative instrument
will be
F-26
<PAGE> 144
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
reported in other comprehensive income. The gains and losses on the derivative
instrument that are reported in other comprehensive income will be reclassified
as earnings in the periods in which earnings are impacted by the variability of
the cash flows of the hedged item. The ineffective portion of all hedges will be
recognized in current-period earnings. This statement was amended by SFAS No.
137 issued in June 1999. The amendment defers the effective date of SFAS No. 133
to fiscal years beginning after June 15, 2000. Leviathan is currently evaluating
the effects of this pronouncement.
NOTE 12 -- SUBSEQUENT EVENTS:
In August 1999, Leviathan and Tejas Energy, L.L.C. ("Tejas") formed Nemo
Gathering Company, LLC ("Nemo") to build a new pipeline (the "Nemo Pipeline") to
gather natural gas from the deepwater region of the Gulf.
Nemo, owned 66.08% by Tejas and 33.92% by Leviathan, has entered into a gas
gathering agreement with Shell Deepwater Development Inc. ("Shell") and will
construct a 24-mile, 20-inch gas gathering line connecting Shell's planned
Brutus development with the existing Manta Ray Offshore Gathering System. Gas
production from the Brutus development is expected to commence in late 2001.
Tejas will operate the line once it is constructed.
Shell plans to install a tension leg platform to develop its Brutus
discovery at Green Canyon Block 158 in 2,980 feet of water. The Nemo Pipeline
will interconnect with the Manta Ray Offshore Gathering System at Leviathan's
platform located in Ship Shoal Block 332.
F-27
<PAGE> 145
REPORT OF INDEPENDENT ACCOUNTANTS
To the Unitholders of Leviathan Gas Pipeline Partners, L.P.
and the Board of Directors and Stockholder of
Leviathan Gas Pipeline Company, as General Partner
In our opinion, the accompanying consolidated balance sheet and related
consolidated statements of operations, of cash flows and of partners' capital
present fairly, in all material respects, the financial position of Leviathan
Gas Pipeline Partners, L.P. and its subsidiaries ("Leviathan") at December 31,
1998 and 1997 and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1998 in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of Leviathan's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 19, 1999
F-28
<PAGE> 146
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In thousands)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1998 1997
-------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 3,108 $ 6,430
Accounts receivable....................................... 1,482 1,953
Accounts receivable from affiliates....................... 7,106 6,608
Other current assets...................................... 247 653
-------- --------
Total current assets.............................. 11,943 15,644
-------- --------
Equity investments.......................................... 186,079 182,301
-------- --------
Property and equipment:
Pipelines................................................. 64,464 78,617
Platforms and facilities.................................. 123,912 97,509
Oil and natural gas properties, at cost, using successful
efforts method......................................... 152,750 120,296
-------- --------
341,126 296,422
Less accumulated depreciation, depletion, amortization and
impairment............................................. 99,134 95,783
-------- --------
Property and equipment, net............................ 241,992 200,639
-------- --------
Investment in Tatham Offshore, Inc. (Notes 1 and 8)......... -- 7,500
Other noncurrent assets..................................... 2,712 3,758
-------- --------
Total assets...................................... $442,726 $409,842
======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities.................. $ 10,429 $ 12,522
Accounts payable to affiliates............................ 738 1,032
Notes payable............................................. 338,000 --
-------- --------
Total current liabilities......................... 349,167 13,554
Deferred federal income taxes............................... 937 1,399
Notes payable............................................... -- 238,000
Other noncurrent liabilities................................ 10,724 13,304
-------- --------
Total liabilities................................. 360,828 266,257
-------- --------
Commitments and contingencies
Minority interest........................................... (998) (381)
-------- --------
Partners' capital:
Preference unitholders' interest.......................... 7,351 163,426
Common unitholders' interest.............................. 90,972 (15,400)
General Partner's interest................................ (15,427) (4,060)
-------- --------
82,896 143,966
-------- --------
Total liabilities and partners' capital........... $442,726 $409,842
======== ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-29
<PAGE> 147
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per Unit amounts)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
-------- -------- -------
<S> <C> <C> <C>
Revenue:
Oil and natural gas sales................................. $ 186 $ 276 $ 772
Oil and natural gas sales to affiliates................... 31,225 57,830 46,296
Gathering, transportation and platform services........... 13,924 10,029 13,974
Gathering, transportation and platform services to
affiliates............................................. 3,396 7,300 10,031
Equity in earnings........................................ 26,724 29,327 20,434
-------- -------- -------
75,455 104,762 91,507
-------- -------- -------
Costs and expenses:
Operating expenses........................................ 11,369 11,352 9,068
Depreciation, depletion and amortization.................. 29,267 46,289 31,731
Impairment, abandonment and other......................... (1,131) 21,222 --
General and administrative expenses....................... 6,416 5,869 788
Management fee and general and administrative expenses
allocated from General Partner......................... 9,773 8,792 7,752
-------- -------- -------
55,694 93,524 49,339
-------- -------- -------
Operating income............................................ 19,761 11,238 42,168
Interest income and other................................... 771 1,475 1,710
Interest and other financing costs.......................... (20,242) (14,169) (5,560)
Minority interest in (income) loss.......................... (15) 7 (427)
-------- -------- -------
Income (loss) before income taxes........................... 275 (1,449) 37,891
Income tax benefit.......................................... 471 311 801
-------- -------- -------
Net income (loss)........................................... $ 746 $ (1,138) $38,692
======== ======== =======
Weighted average number of units outstanding................ 24,367 24,367 24,367
======== ======== =======
Basic and diluted net income (loss) per unit (Note 2)....... $ 0.02(a) $ (0.06) $ 1.57
======== ======== =======
</TABLE>
- ---------------
(a) Excludes 933,000 outstanding unit options to purchase an equal number of
Common Units of Leviathan as the exercise prices of the unit options were
greater than the average market price of the Common Units (Note 7).
The accompanying notes are an integral part of this financial statement.
F-30
<PAGE> 148
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
-------- -------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)....................................... $ 746 $ (1,138) $ 38,692
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Amortization of debt issue costs.................... 2,128 960 1,351
Depreciation, depletion and amortization............ 29,267 46,289 31,731
Impairment, abandonment and other................... (1,131) 21,222 --
Minority interest in income (loss).................. 15 (7) 427
Equity in earnings.................................. (26,724) (29,327) (20,434)
Distributions from equity investments............... 31,171 27,135 36,823
Deferred income taxes and other..................... (462) (323) (936)
Other noncash items................................. (310) (1,596) (6,560)
Changes in operating working capital:
Decrease (increase) in accounts receivable........ 471 4,284 (3,442)
(Increase) decrease in accounts receivable from
affiliates..................................... (498) 7,499 (7,512)
Decrease (increase) in other current assets....... 406 206 (97)
Decrease in accounts payable and accrued
liabilities.................................... (9,108) (5,247) (23,190)
(Decrease) increase in accounts payable to
affiliates..................................... (294) (2,472) 3,326
-------- -------- ---------
Net cash provided by operating activities....... 25,677 67,485 50,179
-------- -------- ---------
Cash flows from investing activities:
Acquisition and development of oil and natural gas
properties........................................... (30,548) (11,249) (59,599)
Additions to pipelines, platforms and facilities........ (27,368) (30,708) (30,095)
Equity investments...................................... (8,195) -- (12,027)
Proceeds from sales of assets and other................. 487 188 --
-------- -------- ---------
Net cash used in investing activities........... (65,624) (41,769) (101,721)
-------- -------- ---------
Cash flows from financing activities:
Decrease in restricted cash............................. -- 716 --
Debt issue costs........................................ (928) (93) (2,843)
Proceeds from notes payable............................. 129,000 65,000 89,220
Repayments of notes payable............................. (29,000) (54,000) --
Distributions to partners............................... (62,447) (47,398) (33,852)
-------- -------- ---------
Net cash provided by (used in) financing
activities.................................... 36,625 (35,775) 52,525
-------- -------- ---------
Net (decrease) increase in cash and cash equivalents...... (3,322) (10,059) 983
Cash and cash equivalents at beginning of year............ 6,430 16,489 15,506
-------- -------- ---------
Cash and cash equivalents at end of year.................. $ 3,108 $ 6,430 $ 16,489
======== ======== =========
</TABLE>
Supplemental disclosures to the statement of cash flows -- see Note 11.
The accompanying notes are an integral part of this financial statement.
F-31
<PAGE> 149
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
<TABLE>
<CAPTION>
PREFERENCE PREFERENCE COMMON COMMON GENERAL
UNITS UNITHOLDERS UNITS UNITHOLDERS PARTNER(A) TOTAL
---------- ----------- ------ ----------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Partners' capital at December 31,
1995........................... 18,075 $ 192,225 6,292 $ (5,380) $ (4) $186,841
Net income for the year ended
December 31, 1996.............. -- 28,400 -- 9,905 387 38,692
Cash distributions............... -- (24,401) -- (8,494) (615) (33,510)
------- --------- ------ -------- -------- --------
Partners' capital at December 31,
1996........................... 18,075 196,224 6,292 (3,969) (232) 192,023
Net loss for the year ended
December 31, 1997.............. -- (1,167) -- (420) 449 (1,138)
Cash distributions............... -- (31,631) -- (11,011) (4,277) (46,919)
------- --------- ------ -------- -------- --------
Partners' capital at December 31,
1997........................... 18,075 163,426 6,292 (15,400) (4,060) 143,966
Net income for the year ended
December 31, 1998.............. -- 63 -- 541 142 746
Conversion of Preference Units
into Common Units (Note 7)..... (17,058) (127,842) 17,058 127,842 -- --
Cash distributions............... -- (28,296) -- (22,011) (11,509) (61,816)
------- --------- ------ -------- -------- --------
Partners' capital at December 31,
1998........................... 1,017 $ 7,351 23,350 $ 90,972 $(15,427)(b) $ 82,896
======= ========= ====== ======== ======== ========
</TABLE>
- ---------------
(a) Leviathan Gas Pipeline Company owns a 1% general partner interest in
Leviathan Gas Pipeline Partners, L.P.
(b) Pursuant to the terms of the Partnership Agreement, no partner shall have
any obligation to restore any negative balance in its capital account upon
liquidation of Leviathan. Therefore, any net gains from the dissolution of
Leviathan's assets would be allocated first to any then-outstanding deficit
capital account balance before any of the remaining net proceeds would be
distributed to the partners in accordance with their ownership percentages.
The accompanying notes are an integral part of this financial statement.
F-32
<PAGE> 150
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION:
Leviathan Gas Pipeline Partners, L.P., a publicly held Delaware limited
partnership ("Leviathan"), is primarily engaged in the gathering, transportation
and production of natural gas and crude oil in the Gulf of Mexico (the "Gulf").
Through its subsidiaries and joint ventures, Leviathan owns interests in
significant assets, including (i) eight natural gas pipelines, (ii) a crude oil
pipeline system, (iii) six strategically located multi-purpose platforms, (iv) a
dehydration facility, (v) four producing oil and natural gas properties and (vi)
one undeveloped oil and natural gas property.
Leviathan Gas Pipeline Company, a Delaware corporation and the general
partner of Leviathan (the "General Partner"), performs all management and
operational functions of Leviathan and its subsidiaries. In August 1998, the
General Partner became a wholly-owned indirect subsidiary of El Paso Energy
Corporation ("El Paso") pursuant to El Paso's merger with DeepTech International
Inc. ("DeepTech"), the indirect parent of the General Partner, as discussed
below.
Merger
Effective August 14, 1998, El Paso completed the acquisition of DeepTech by
merging a wholly-owned subsidiary of El Paso with and into DeepTech (the
"Merger") pursuant to the Agreement and Plan of Merger dated as of February 27,
1998 (as amended, the "Merger Agreement"). The material terms of the Merger and
the transactions contemplated by the Merger Agreement and other agreements as
these agreements relate to Leviathan are as follows:
(a) Prior to the Merger, Leviathan Holdings Company, which owns 100% of the
General Partner, was owned 85% by DeepTech resulting in DeepTech owning
an overall 23.2% effective interest in Leviathan. El Paso acquired the
minority interests of Leviathan Holdings Company and two other
subsidiaries of DeepTech primarily held by former DeepTech management
for an aggregate of $55.0 million. As a result, El Paso owns 100% of
the General Partner's interest in Leviathan and an overall 27.3%
effective interest in Leviathan.
(b) In June 1998, Tatham Offshore, Inc. ("Tatham Offshore"), an affiliate
of Leviathan through August 14, 1998, canceled its reversionary
interests in certain oil and natural gas properties owned by Leviathan
(Note 4).
(c) On August 14, 1998, Tatham Offshore transferred its remaining assets
located in the Gulf to Leviathan in exchange for the 7,500 shares of
Series B 9% Senior Convertible Preferred Stock (the "Senior Preferred
Stock") issued by Tatham offshore (Note 8) and owned by Leviathan (the
"Redemption Agreement"). Under the terms of the Redemption Agreement,
Leviathan acquired all of Tatham Offshore's right, title and interest
in and to Viosca Knoll Blocks 817 (subject to an existing production
payment obligation), West Delta Block 35, the platform located at Ship
Shoal Block 331 and other lease blocks not material to Leviathan's
current operations. The net cash expenditure of Leviathan under the
Redemption Agreement totaled $774,000 representing (i) $2,771,000 of
abandonment costs relating to wells located at Ewing Bank Blocks 914
and 915 offset by (ii) $1,997,000 of net cash generated from the
producing properties from January 1, 1998 through August 14, 1998. In
addition, Leviathan assumed all remaining abandonment and restoration
obligations associated with the platform and leases.
NOTE 2 -- SIGNIFICANT ACCOUNTING POLICIES:
Principles of consolidation
The accompanying consolidated financial statements include the accounts of
those 50% or more owned subsidiaries controlled by Leviathan. The General
Partner's approximate 1% nonmanaging interest
F-33
<PAGE> 151
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
in certain subsidiaries of Leviathan represents the minority interest in
Leviathan's consolidated financial statements. Investments in which Leviathan
owns a 20% to 50% ownership interest are accounted for using the equity method.
All significant intercompany balances and transactions have been eliminated in
consolidation. Certain amounts from the prior year have been reclassified to
conform to the current year's presentation.
Cash and cash equivalents
All highly liquid investments with a maturity of three months or less when
purchased are considered to be cash equivalents.
Property and equipment
Gathering pipelines, platforms and related facilities are recorded at cost
and are depreciated on a straight-line basis over the estimated useful lives of
the assets which generally range from 5 to 30 years for the gathering pipelines
and from 18 to 30 years for platforms and the related facilities. Repair and
maintenance costs are expensed as incurred; additions, improvements and
replacements are capitalized.
Leviathan accounts for its oil and natural gas exploration and production
activities using the successful efforts method of accounting. Under this method,
costs of successful exploratory wells, development wells and acquisitions of
mineral leasehold interests are capitalized. Production, exploratory dry hole
and other exploration costs, including geological and geophysical costs and
delay rentals, are expensed as incurred. Unproved properties are assessed
periodically and any impairment in value is recognized currently as
depreciation, depletion and amortization expense.
Depreciation, depletion and amortization of the capitalized costs of
producing oil and natural gas properties, consisting principally of tangible and
intangible costs incurred in developing a property and costs of productive
leasehold interests, are computed on the unit-of-production method.
Unit-of-production rates are based on annual estimates of remaining proved
developed reserves or proved reserves, as appropriate, for each property. Repair
and maintenance costs are charged to expense as incurred; additions,
improvements and replacements are capitalized.
Estimated dismantlement, restoration and abandonment costs and estimated
residual salvage values are taken into account in determining depreciation
provisions for gathering pipelines, platforms, related facilities and oil and
natural gas properties. Other noncurrent liabilities at December 31, 1998 and
1997 include $10,724,000 and $9,158,0000, respectively, of accrued
dismantlement, restoration and abandonment costs.
Retirements, sales and disposals of assets are recorded by eliminating the
related costs and accumulated depreciation, depletion and amortization of the
disposed assets with any resulting gain or loss reflected in income.
Leviathan evaluates impairment of its property and equipment in accordance
with Statement of Financial Accounting Standard ("SFAS") No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," which requires recognition of impairment losses on long-lived assets
(including pipelines, proved properties, wells, equipment and related
facilities) if the carrying amount of such assets, grouped at the lowest level
for which there are identifiable cash flows that are largely independent of the
cash flows from other assets, exceeds the estimated undiscounted future cash
flows of such assets. Measurement of any impairment loss is based on the fair
value of the assets.
F-34
<PAGE> 152
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Capitalization of interest
Interest and other financing costs are capitalized in connection with
construction and drilling activities as part of the cost of the asset and
amortized over the related asset's estimated useful life.
Debt issue costs
Debt issue costs are capitalized and amortized over the life of the related
indebtedness. Any unamortized debt issue costs are expensed at the time the
related indebtedness is repaid or otherwise terminated.
Revenue recognition
Revenue from pipeline transportation of hydrocarbons is recognized upon
receipt of the hydrocarbons into the pipeline systems. Revenue from oil and
natural gas sales is recognized upon delivery in the period of production.
Revenue from platform access and processing services is recognized in the period
the services are provided.
Income taxes
Leviathan and its subsidiaries other than Tarpon Transmission Company
("Tarpon") are not taxable entities. However, the taxable income or loss
resulting from the operations of Leviathan will ultimately be included in the
federal and state income tax returns of the general and limited partners.
Individual partners will have different investment bases depending upon the
timing and price of acquisition of partnership units. Further, each partner's
tax accounting, which is partially dependent upon his/her tax position, may
differ from the accounting followed in the consolidated financial statements.
Accordingly, there could be significant differences between each individual
partner's tax basis and his/her share of the net assets reported in the
consolidated financial statements. Leviathan does not have access to information
about each individual partner's tax attributes in Leviathan, and the aggregate
tax bases cannot be readily determined. Accordingly, management does not believe
that, in Leviathan's circumstances, the aggregate difference would be meaningful
information.
Tarpon is, and Manta Ray Gathering Systems, Inc. ("Manta Ray") was, prior
to its liquidation in May 1996, a subsidiary of Leviathan subject to federal
corporate income taxation. Leviathan utilizes an asset and liability approach
for accounting for income taxes of Tarpon and Manta Ray that requires the
recognition of deferred tax assets and liabilities for the expected future tax
consequences of temporary differences between the carrying amounts and tax bases
of other assets and liabilities. Resulting tax liabilities, if any, are borne by
Leviathan.
Net income per unit
Basic earnings per share ("EPS") excludes dilution and is computed by
dividing net income (loss) attributable to the limited partners by the weighted
average number of units outstanding during the period. Dilutive EPS reflects
potential dilution and is computed by dividing net income (loss) attributable to
the limited partners by the weighted average number of units outstanding during
the period increased by the number of additional units that would have been
outstanding if the dilutive potential units had been issued.
Basic income (loss) per unit and diluted income (loss) per unit for
Leviathan are the same for the years ended December 31, 1998, 1997 and 1996 as
no dilutive potential units were outstanding during the respective periods.
Leviathan includes the outstanding Preference Units in the basic and diluted net
income (loss) per unit calculation as if the Preference Units had been converted
into Common Units.
F-35
<PAGE> 153
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Basic and diluted net income (loss) per unit is calculated based upon the
net income (loss) of Leviathan less an allocation of net income to the General
Partner proportionate to its share of cash distributions and is calculated as
follows (in thousands).
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998 YEAR ENDED DECEMBER 31, 1997
----------------------------- ----------------------------
LIMITED GENERAL LIMITED GENERAL
PARTNERS PARTNER TOTAL PARTNERS PARTNER TOTAL
--------- -------- ------ -------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Net income (loss)(a)..................... $ 738 $ 8 $746 $(1,127) $(11) $(1,138)
Allocation to General Partner(b)......... (134) 134 -- (460) 460 --
------- ---- ---- ------- ---- -------
Allocation of net income (loss) as
adjusted for Incentive Distributions... $ 604 $142 $746 $(1,587) $449 $(1,138)
======= ==== ==== ======= ==== =======
Weighted average number of units
outstanding............................ 24,367 24,367
======= =======
Basic and diluted net income (loss) per
unit................................... $ 0.02 $ (0.06)
======= =======
</TABLE>
- ---------------
(a) Net income (loss) allocated 99% to the limited partners as holders of the
Preference and Common Units and 1% to the General Partner.
(b) Represents allocation of net income to the General Partner proportionate to
its share of each quarter's cash distributions which included Incentive
Distributions (Note 7).
For the year ended December 31, 1996, basic and diluted net income per unit
was computed based upon the net income of Leviathan less an allocation of
approximately 1% of Leviathan's net income to the General Partner. During 1996,
the General Partner only received a 1% allocation of net income as Leviathan did
not pay any Incentive Distributions (Note 7) until 1997. The weighted average
number of Units outstanding for the year ended December 31, 1996 was 24,366,894
Units.
Estimates
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles and the estimation of oil and natural
gas reserves requires management to make estimates and assumptions that affect
the reported amounts of certain assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the consolidated financial
statements and the related reported amounts of revenue and expenses during the
reporting period. Such estimates and assumptions include those regarding: (i)
Federal Energy Regulatory Commission ("FERC") regulations, (ii) oil and natural
gas reserve disclosure, (iii) estimated useful lives of depreciable assets and
(iv) potential abandonment, dismantlement, restoration and environmental
liabilities. Actual results could differ from those estimates. Management
believes that its estimates are reasonable.
Unit Options
In August 1998, Leviathan adopted SFAS No. 123, "Accounting for Stock Based
Compensation." While SFAS No. 123 encourages entities to adopt the fair value
method of accounting for their stock-based compensation plans, this standard
permits and Leviathan has elected to utilize the intrinsic value method under
Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued
to Employees." Prior to August 1998, compensation expense for Leviathan's unit
appreciation rights was recorded annually based on the quoted market price of
Preference Units at the end of the period and the percentage of vesting which
had occurred. A description of Leviathan's option plans and pro forma
information regarding net income (loss) and net income (loss) per unit, as
calculated under the provisions of SFAS No. 123, are disclosed in Note 7.
F-36
<PAGE> 154
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Price Risk Management Activities
Leviathan enters into commodity price swap instruments for non-trading
purposes to manage its exposure to price fluctuations on anticipated natural gas
and crude oil sales transactions. To qualify for hedge accounting, the
transactions must reduce the risk of the underlying hedge items, be designated
as hedges at inception and result in cash flows and financial impacts which are
inversely correlated to the position being hedged. If correlation ceases to
exist, hedge accounting is terminated and mark-to-market accounting is applied.
Gains and losses resulting from hedging activities and the termination of any
hedging instruments are initially deferred and included as an increase or
decrease to oil and natural gas sales in the period in which the hedged
production is sold. See Note 10.
Recent Pronouncements
Effective January 1, 1998, Leviathan adopted SFAS No. 131, "Disclosures
About Segments of an Enterprise and Related Information." SFAS No. 131
establishes standards for the method public entities report information about
operating segments in both interim and annual financial statements issued to
unitholders and requires related disclosures about products and services,
geographic areas and major customers. See Notes 3, 4, 12 and 13.
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, "Reporting on the Costs of Start-Up
Activities." This statement defines start-up activities, requires start-up and
organization costs to be expensed as incurred and requires that any such costs
that exist on the balance sheet be expensed upon adoption of this pronouncement.
The statement is effective for fiscal years beginning after December 15, 1998.
Leviathan does not expect the implementation of this statement to have a
material effect on Leviathan's financial position or results of operations.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
requires that entities recognize all derivative instruments as either assets or
liabilities on the balance sheet and measure those instruments at fair value.
Changes in the fair value of derivatives are recorded each period in current
earnings or other comprehensive income, depending on whether a derivative is
designated as a hedge transaction. For fair-value hedge transactions in which
Leviathan is hedging changes in an asset's, liability's or firm commitment's
fair value, changes in the fair value of the derivative instrument will
generally be offset in the income statement by changes in the hedged item's fair
value. For cash-flow hedge transactions, in which Leviathan is hedging the
variability of cash flows related to a variable-rate asset, liability, or a
forecasted transaction, changes in the fair value of the derivative instrument
will be reported in other comprehensive income. The gains and losses on the
derivative instrument that are reported in other comprehensive income will be
reclassified as earnings in the periods in which earnings are impacted by the
variability of the cash flows of the hedged item. The ineffective portion of all
hedges will be recognized in current-period earnings. This statement is
effective for fiscal years beginning after June 15, 1999. Leviathan has not yet
determined the impact that the adoption of SFAS No. 133 will have on its
financial position or results of operations.
In November 1998, the Emerging Issues Task Force ("EITF") reached a
consensus on EITF 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." EITF 98-10 requires energy trading contracts to
be recorded at fair value on the balance sheet, with the changes in fair value
included in earnings and is effective for fiscal years beginning after December
15, 1998. Leviathan adopted the provisions of EITF 98-10 in January 1999 and
does not believe that the application of this pronouncement will have a material
impact on Leviathan's financial position or results of operations.
F-37
<PAGE> 155
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- EQUITY INVESTMENTS:
Leviathan owns interests of 50% in Viosca Knoll Gathering Company ("Viosca
Knoll"), 36% in Poseidon Oil Pipeline Company, L.L.C. ("POPCO"), 50% in Stingray
Pipeline Company ("Stingray"), 40% in High Island Offshore System, L.L.C.,
("HIOS"), 33 1/3% in U-T Offshore System ("UTOS"), 50% in West Cameron
Dehydration Company, L.L.C. ("West Cameron Dehy") and an effective 25.67%
interest in each of Manta Ray Offshore Gathering Company, L.L.C. ("Manta Ray
Offshore") and Nautilus Pipeline Company, L.L.C. ("Nautilus").
The excess of the carrying amount of the investments accounted for using
the equity method over the underlying equity in net assets as of December 31,
1998 is $45,023,000. The difference between the cost of the investments
accounted for on the equity method and the underlying equity in net assets is
being depreciated on a straight-line basis over the estimated lives of the
underlying net assets.
The summarized financial information for investments, which are accounted
for using the equity method, is as follows.
SUMMARIZED HISTORICAL OPERATING RESULTS
YEAR ENDED DECEMBER 31, 1998
(In thousands)
<TABLE>
<CAPTION>
WEST MANTA
VIOSCA CAMERON RAY
HIOS KNOLL STINGRAY POPCO DEHY UTOS OFFSHORE(A) NAUTILUS(A) TOTAL
-------- ------- -------- ------- ------- ------- ----------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenue........ $ 43,818 $29,334 $ 23,008 $44,522 $2,796 $ 5,174 $10,949 $ 5,403
Other income............. -- 50 670 290 11 100 488 100
Operating expenses....... (19,047) (3,031) (16,814) (4,763) (183) (2,466) (3,710) (1,979)
Depreciation............. (4,772) (3,860) (6,852) (8,846) (16) (559) (4,303) (5,845)
Interest expense......... (16) (4,267) (1,668) (8,671) -- (2) -- --
-------- ------- -------- ------- ------ ------- ------- --------
Net earnings (loss)...... 19,983 18,226 (1,656) 22,532 2,608 2,247 3,424 (2,321)
Ownership percentage..... 40% 50% 50% 36% 50% 33.3% 25.67% 25.67%
-------- ------- -------- ------- ------ ------- ------- --------
7,993 9,113 (828) 8,111 1,304 749 879 (596)
Adjustments:
Depreciation(b)........ 881 -- 749 (120) -- 33 (348) --
Contract
amortization(b)...... (105) -- (127) -- -- -- -- --
Other.................. (149) -- (49) -- -- (52) -- (714)(c)
-------- ------- -------- ------- ------ ------- ------- --------
Equity in earnings
(loss)................. $ 8,620 $ 9,113 $ (255) $7,991 $1,304 $ 730 $ 531 $ (1,310) $26,724
======== ======= ======== ======= ====== ======= ======= ======== =======
Distributions(d)......... $ 9,240 $10,350 $ 1,000 $6,732 $1,100 $ 933 $ 1,182 $ 634 $31,171
======== ======= ======== ======= ====== ======= ======= ======== =======
</TABLE>
- ---------------
(a) Leviathan owns a 25.67% interest in Neptune Pipeline Company, L.L.C.
("Neptune"). Neptune owns a 99% member interest in each of Manta Ray
Offshore, which owns a non-jurisdictional natural gas system, and Nautilus,
which owns a jurisdictional natural gas system. Leviathan believes the
disclosure of separate financial data for Manta Ray Offshore and Nautilus is
more meaningful than the consolidated results of Neptune.
(b) Adjustments result from purchase price adjustments made in accordance with
APB Opinion No. 16 "Business Combinations."
(c) Primarily relates to a revision of the allowance for funds used during
construction ("AFUDC") which represents the estimated costs, during the
construction period, of funds used for construction.
(d) Future distributions could be restricted by the terms of the equity
investees' respective credit agreements.
F-38
<PAGE> 156
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMMARIZED HISTORICAL OPERATING RESULTS
YEAR ENDED DECEMBER 31, 1997
(In thousands)
<TABLE>
<CAPTION>
WEST MANTA
VIOSCA CAMERON RAY
HIOS KNOLL STINGRAY POPCO DEHY UTOS OFFSHORE(A) NAUTILUS(A) TOTAL
-------- ------- -------- ------- ------- ------- ----------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenue.......... $ 45,917 $23,128 $ 23,630 $26,161 $2,451 $ 3,785 $ 6,263 $ 54
Other income............... -- 40 970 209 29 61 1,564 6,489(b)
Operating expenses......... (17,101) (2,115) (15,612) (5,782) (164) (2,472) (2,223) (435)
Depreciation............... (4,774) (2,474) (7,216) (6,463) (16) (566) (1,823) (233)
Interest expense........... -- (1,959) (1,384) (5,341) -- 37 (1,483) --
-------- ------- -------- ------- ------ ------- ------- ------
Net earnings............... 24,042 16,620 388 8,784 2,300 845 2,298 5,875
Ownership percentage....... 40% 50% 50% 36% 50% 33.3% 25.67% 25.67%
-------- ------- -------- ------- ------ ------- ------- ------
9,617 8,310 194 3,162 1,150 281 590 1,508
Adjustments:
Depreciation(c).......... 845 -- 959 (120) -- 35 -- --
Contract
amortization(c)........ (105) -- (350) -- -- -- -- --
Other.................... (228) -- (49) (263) -- (24) 3,082(d) 733
-------- ------- -------- ------- ------ ------- ------- ------
Equity in earnings......... $ 10,129 $ 8,310 $ 754 $2,779 $1,150 $ 292 $ 3,672 $2,241 $29,327
======== ======= ======== ======= ====== ======= ======= ====== =======
Distributions(e)........... $ 12,200 $ 9,650 $ 1,375 $ -- $1,150 $ 200 $ 2,560 $ -- $27,135
======== ======= ======== ======= ====== ======= ======= ====== =======
</TABLE>
- ---------------
(a) Leviathan owns a 25.67% interest in Neptune. Neptune owns a 99% member
interest in each of Manta Ray Offshore, which owns a non-jurisdictional
natural gas system, and Nautilus, which owns a jurisdictional natural gas
system. Leviathan believes the disclosure of separate financial data for
Manta Ray Offshore and Nautilus is more meaningful than the consolidated
results of Neptune.
(b) Includes $6,431,000 related to AFUDC. Recognition of this allowance is
appropriate because it constitutes an actual cost of construction. For
regulated activities, Nautilus is permitted to earn a return on and recover
AFUDC through its inclusion in the rate base and the provision for
depreciation. The rate employed for the equity component of AFUDC is the
equity rate of return stated in Nautilus' FERC tariff.
(c) Adjustments result from purchase price adjustments made in accordance with
APB Opinion No. 16 "Business Combinations."
(d) Represents additional net earnings specifically allocated to Leviathan
related to the assets contributed by Leviathan to the Manta Ray Offshore
joint venture. Pursuant to the terms of the joint venture agreement,
Leviathan managed the operations of the assets contributed to Manta Ray
Offshore and was permitted to retain approximately 100% of the net earnings
from such assets during the construction phase of the expansion to the Manta
Ray Offshore system (January 17, 1997 through December 31, 1997). Effective
January 1, 1998, Manta Ray Offshore began allocating all net earnings in
accordance with the ownership percentages of the joint venture.
(e) Future distributions could be restricted by the terms of the equity
investees' respective credit agreements.
F-39
<PAGE> 157
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMMARIZED HISTORICAL OPERATING RESULTS
YEAR ENDED DECEMBER 31, 1996
(In thousands)
<TABLE>
<CAPTION>
WEST
VIOSCA CAMERON
HIOS KNOLL STINGRAY POPCO DEHY UTOS TOTAL
-------- ------- -------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenue............................ $ 47,440 $13,923 $ 24,146 $7,819 $1,686 $ 3,476
Other income................................. 97 -- 1,186 339 10 48
Operating expenses........................... (15,683) (424) (14,260) (3,042) (162) (2,511)
Depreciation................................. (4,775) (2,269) (7,057) (2,176) (16) (560)
Other expenses............................... -- (90) (1,679) (269) -- --
-------- ------- -------- ------- ------ -------
Net earnings................................. 27,079 11,140 2,336 2,671 1,518 453
Ownership percentage......................... 40% 50% 50% 36% 50% 33.3%
-------- ------- -------- ------- ------ -------
10,832 5,570 1,168 962 759 151
Adjustments:
Depreciation(a)............................ 783 -- 669 -- -- 2
Contract amortization(a)................... (105) -- -- -- -- --
Rate refund reserve........................ (417) -- -- -- -- --
Other...................................... (107) -- -- 167 -- --
-------- ------- -------- ------- ------ -------
Equity in earnings........................... $ 10,986 $ 5,570 $ 1,837 $1,129 $ 759 $ 153 $20,434
======== ======= ======== ======= ====== ======= =======
Distributions................................ $ 11,400 $18,450 $ 1,923 $4,000 $ 650 $ 400 $36,823
======== ======= ======== ======= ====== ======= =======
</TABLE>
- ---------------
(a) Adjustments result from purchase price adjustments made in accordance with
APB Opinion No. 16, "Business Combinations."
SUMMARIZED HISTORICAL BALANCE SHEETS
(In thousands)
<TABLE>
<CAPTION>
HIOS VIOSCA KNOLL STINGRAY POPCO
----------------- ----------------- ------------------- -------------------
DECEMBER 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
----------------- ----------------- ------------------- -------------------
1998 1997 1998 1997 1998 1997 1998 1997
------- ------- ------- ------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Current assets..................... $ 4,662 $ 5,587 $ 5,451 $ 3,354 $ 17,892 $ 20,184 $ 43,338 $ 31,763
Noncurrent assets.................. 12,936 12,081 97,758 98,004 50,109 42,541 233,082 226,055
Current liabilities................ 2,626 3,380 1,021 11,280 18,960 21,787 40,134 35,864
Long-term debt..................... -- -- 66,700 52,200 20,583 11,600 131,000 120,500
Other noncurrent liabilities....... -- 199 340 256 12,924 5,289 -- --
</TABLE>
<TABLE>
<CAPTION>
WEST CAMERON
DEHY UTOS MANTA RAY OFFSHORE NAUTILUS
----------------- ----------------- ------------------- -------------------
DECEMBER 31, DECEMBER 31, DECEMBER 31, DECEMBER 31,
----------------- ----------------- ------------------- -------------------
1998 1997 1998 1997 1998 1997 1998 1997
------- ------- ------- ------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Current assets..................... $ 848 $ 455 $ 4,699 $ 3,955 $ 7,250 $ 31,714 $ 2,782 $ 924
Noncurrent assets.................. 647 663 2,745 2,803 135,626 127,731 113,434 120,074
Current liabilities................ 13 43 4,125 2,900 5,023 32,601 709 3,699
</TABLE>
F-40
<PAGE> 158
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- OIL AND NATURAL GAS PROPERTIES:
Capitalized Costs
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1998 1997
-------- --------
(In thousands)
<S> <C> <C>
Proved properties........................................... $ 53,313 $ 38,790
Wells, equipment and related facilities..................... 99,437 81,506
-------- --------
Total capitalized costs........................... 152,750 120,296
Accumulated depreciation, depletion and amortization........ 72,194 53,684
-------- --------
Net capitalized costs............................. $ 80,556 $ 66,612
======== ========
</TABLE>
Costs incurred in the Oil and Natural Gas Acquisitions, Exploration and
Development Activities
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1998 1997
--------- ---------
(In thousands)
<S> <C> <C>
Acquisitions of proved properties........................... $16,945 $ 1
Development................................................. 17,783 10,522
Capitalized interest........................................ 328 726
------- -------
Total costs incurred.............................. $35,056 $11,249
======= =======
</TABLE>
In October 1998, Leviathan purchased a 100% working interest in Ewing Bank
Blocks 958, 959, 1002 and 1003 from a wholly-owned indirect subsidiary of El
Paso for $12,235,000. In December 1998, Leviathan completed the drilling of a
successful delineation well on the Ewing Bank unit.
In 1995, Leviathan entered into a purchase and sale agreement (the
"Purchase and Sale Agreement") with Tatham Offshore pursuant to which Leviathan
acquired, subject to certain reversionary rights, a 75% working interest in
Viosca Knoll Block 817, a 50% working interest in Garden Banks Block 72 and a
50% working interest in Garden Banks Block 117 (the "Acquired Properties") from
Tatham Offshore for $30 million. Leviathan was entitled to retain all of the
revenue attributable to the Acquired Properties until it had received net
revenue equal to the payout amount, whereupon Tatham Offshore was entitled to
receive a reassignment of the Acquired Properties, subject to certain reductions
and conditions. In connection with the Merger, Tatham Offshore canceled its
reversionary interests in the Acquired Properties (Note 1).
NOTE 5 -- REGULATORY MATTERS:
The FERC has jurisdiction under the Natural Gas Act of 1938, as amended
(the "NGA"), and the Natural Gas Policy Act of 1978, as amended (the "NGPA"),
over Nautilus, Stingray, HIOS and UTOS (the "Regulated Pipelines") with respect
to transportation of natural gas, rates and charges, construction of new
facilities, extension or abandonment of service and facilities, accounts and
records, depreciation and amortization policies and certain other matters.
Leviathan's remaining systems (the "Unregulated Pipelines") are gathering
facilities and as such are not currently subject to rate and certificate
regulation by the FERC under the NGA and the NGPA. However, the FERC has
asserted that it has rate jurisdiction under the NGA over services performed
through gathering facilities owned by a natural gas company (as defined in the
NGA) when such services are performed "in connection with" transportation
services provided by such natural gas company. Whether, and to what extent, the
FERC will exercise any NGA rate jurisdiction it may be found to have over
gathering facilities owned either by natural gas companies or affiliates thereof
is subject to case-by-case review by the FERC. Based on current FERC
F-41
<PAGE> 159
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
policy and precedent, Leviathan does not anticipate that the FERC will assert or
exercise any NGA rate jurisdiction over the Unregulated Pipelines so long as the
services provided through such lines are not performed "in connection with"
transportation services performed through any of the Regulated Pipelines. Both
the Regulated and the Unregulated Pipelines are subject to the FERC's
administration of the "equal access" requirements of the Outer Continental Shelf
Lands Act ("OCSLA").
Poseidon is subject to regulation under the Hazardous Liquid Pipeline
Safety Act ("HLPSA"). Operations in offshore federal waters are regulated by the
Department of the Interior. In addition, as transporter of hydrocarbons across
the Outer Continental Shelf ("OCS"), the Poseidon system must offer "equal
access" to other potential shippers of crude. Poseidon is located in federal
waters in the Gulf, and its right-of-way was granted by the federal government.
Therefore, the FERC may assert that it has jurisdiction to compel Poseidon to
grant access under OCSLA to other shippers of crude oil upon the satisfaction of
certain conditions and to apportion the capacity of the line among owner and
non-owner shippers.
The FERC has generally disclaimed jurisdiction to set rates for oil
pipelines in the OCS under the Interstate Commerce Act. As a result, POPCO has
not filed tariffs with the FERC for the Poseidon crude oil pipeline system.
Rate Cases
Tarpon. In March 1997, the FERC issued an order declaring Tarpon's
facilities exempt from NGA regulation under the gathering exception, thereby
terminating Tarpon's status as a "natural gas company" under the NGA. Tarpon has
agreed, however, to continue service for shippers that have not executed
replacement contracts on the terms and conditions, and at the rates reflected
in, its last effective regulated tariff for two years from the date of the
order.
Other. Each of Nautilus, Stingray, HIOS, and UTOS are currently operating
under agreements with their respective customers that provide for rates that
have been approved by the FERC.
NOTE 6 -- INDEBTEDNESS:
Leviathan has a revolving credit facility, as amended and restated (the
"Leviathan Credit Facility"), with a syndicate of commercial banks to provide up
to $375 million of available credit, subject to certain incurrence limitations.
As of December 31, 1998 and 1997, Leviathan had $338 million and $238 million,
respectively, outstanding under its credit facility. At the election of
Leviathan, interest under the Leviathan Credit Facility is determined by
reference to the reserve-adjusted London interbank offer rate ("LIBOR"), the
prime rate or the 90-day average certificate of deposit. The interest rate at
December 31, 1998 and 1997 was 7.1% and 6.6% per annum, respectively. A
commitment fee is charged on the unused and available to be borrowed portion of
the credit facility. This fee varies between 0.25% and 0.375% per annum and was
0.375% per annum at December 31, 1998. The amendment to the credit facility in
January 1999 increased the commitment fee to 0.50% per annum. Amounts advanced
under the Leviathan Credit Facility were used to finance Leviathan's capital
expenditures, including construction of platforms and pipelines, investments in
equity investees and the acquisition and development of oil and natural gas
properties. Amounts remaining under the Leviathan Credit Facility are available
to Leviathan for general partnership purposes, including financing capital
expenditures, for working capital, and subject to certain limitations, for
paying distributions to unitholders. The Leviathan Credit Facility can also be
utilized to issue letters of credit as may be required from time to time;
however, no letters of credit are currently outstanding. The Leviathan Credit
Facility matures in December 1999; is guaranteed by Leviathan and each of
Leviathan's subsidiaries; and is collateralized by the management agreement with
Leviathan (Note 8), substantially all of the assets of Leviathan and the General
Partner's 1% general partner interest in Leviathan and approximate 1%
nonmanaging interest in certain subsidiaries of Leviathan. Management
F-42
<PAGE> 160
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
believes it will be able to extend or refinance this credit facility on
acceptable terms and conditions prior to its maturity.
Interest and other financing costs totaled $21,308,000, $15,890,000 and
$17,470,000 for the years ended December 31, 1998, 1997 and 1996, respectively.
During the years ended December 31, 1998, 1997 and 1996, Leviathan capitalized
$1,066,000, $1,721,000 and $11,910,000, respectively, of such interest costs in
connection with construction projects and drilling activities in progress during
such periods. At December 31, 1998 and 1997, the unamortized portion of debt
issue costs totaled $2,549,000 and $3,749,000, respectively.
NOTE 7 -- PARTNERS' CAPITAL:
General
As of December 31, 1998, Leviathan had 23,349,988 Common Units and
1,016,906 Preference Units outstanding. Preference Units and Common Units
totaling 18,075,000 are owned by the public, representing a 72.7% effective
limited partner interest in Leviathan. The General Partner, through its
ownership of a 25.3% limited partner interest in the form of 6,291,894 Common
Units, its 1% general partner interest in Leviathan and its approximate 1%
nonmanaging interest in certain subsidiaries of Leviathan, owns a 27.3%
effective interest in Leviathan. See Note 14.
Conversion of Preference Units into Common Units
On May 7, 1998, Leviathan notified the holders of its 18,075,000 then
outstanding Preference Units of their right to convert their Preference Units
into an equal number of Common Units within a 90-day period. On August 5, 1998,
the conversion period expired and holders of 17,058,094 Preference Units,
representing approximately 94% of the Preference Units then outstanding, elected
to convert to Common Units. As a result, the Preference Period, as defined in
the Amended and Restated Agreement of Limited Partnership (the "Partnership
Agreement"), ended and the Common Units (including the 6,291,894 Common Units
held by Leviathan) became the primary listed security on the New York Stock
Exchange ("NYSE") under the symbol "LEV." A total of 1,016,906 Preference Units
remain outstanding and trade as Leviathan's secondary listed security on the
NYSE under the symbol "LEV.P". Leviathan reallocated partners' capital to
reflect this conversion of Preference Units into Common Units.
The remaining Preference Units retain their distribution preferences over
the Common Units; that is, holders of such Preference Units will be paid up to
the minimum quarterly distribution of $0.275 per unit before any quarterly
distributions are made to the Common Unitholders or the General Partner.
However, holders of Preference Units will not receive any distributions in
excess of the minimum quarterly distribution of $0.275 per unit. Only holders of
Common Units and the General Partner will be eligible to receive any such excess
distributions. See "Cash Distributions" below.
In accordance with the Partnership Agreement, holders of the remaining
Preference Units will have the opportunity to convert their Preference Units
into Common Units in May 1999 and May 2000. Thereafter, any remaining Preference
Units may, under certain circumstances, be subject to redemption.
Cash Distributions
Leviathan makes quarterly distributions of 100% of its Available Cash, as
defined in the Partnership Agreement, to its unitholders and the General
Partner. Available Cash consists generally of all the cash receipts of Leviathan
plus reductions in reserves less all of its cash disbursements and net additions
to reserves. The General Partner has broad discretion to establish cash reserves
that it determines are necessary or appropriate to provide for the proper
conduct of the business of Leviathan including cash reserves for future capital
expenditures, to stabilize distributions of cash to the unitholders and the
General
F-43
<PAGE> 161
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Partner, to reduce debt or as necessary to comply with the terms of any
agreement or obligation of Leviathan. Leviathan expects to make distributions of
Available Cash within 45 days after the end of each quarter to unitholders of
record on the applicable record date, which will generally be the last business
day of the month following the close of such calendar quarter.
The distribution of Available Cash for each quarter is subject to the
preferential rights of the Preference Unitholders to receive the minimum
quarterly distribution of $0.275 per unit for such quarter, plus any arrearages
in the payment of the minimum quarterly distribution for prior quarters, if any,
before any distribution of Available Cash is made to holders of Common Units for
such quarter. The holders of Common Units are not entitled to arrearages in the
payment of the minimum quarterly distribution. See the discussion above
regarding distributions subsequent to the end of the Preference Period.
Since commencement of operations on February 19, 1993 through December 31,
1998, Leviathan has made distributions to the unitholders equal to and in excess
of the minimum quarterly distribution of $0.275 per unit. See Note 16.
Distributions by Leviathan of its Available Cash are effectively made 98%
to unitholders and 2% to the General Partner, subject to the payment of
incentive distributions to the General Partner if certain target levels of cash
distributions to unitholders are achieved ("Incentive Distributions"). As an
incentive, the general partner's interest in the portion of quarterly cash
distributions in excess of $0.325 per Unit and less than or equal to $0.375 per
Unit is increased to 15%. For quarterly cash distributions over $0.375 per Unit
but less than or equal to $0.425 per Unit, the general partner receives 25% of
such incremental amount and for all quarterly cash distributions in excess of
$0.425 per Unit, the general partner receives 50% of the incremental amount.
During the years ended December 31, 1998, 1997 and 1996, the General Partner
received Incentive Distributions totaling $11,113,000, $3,885,000 and $285,000,
respectively. In February 1999, Leviathan paid a cash distribution of $0.275 per
Preference Unit and $0.525 per Common Unit and an Incentive Distribution of
$2,835,000 to the General Partner.
Unit Rights Appreciation Plan
In 1995, Leviathan adopted the Unit Rights Appreciation Plan (the "Plan")
to provide Leviathan with the ability of making awards of unit rights to certain
officers and employees of the General Partner or its affiliates as an incentive
for these individuals to continue in the service of Leviathan or its affiliates.
Under the Plan, Leviathan granted 1,200,000 unit rights to certain officers and
employees of the General Partner or its affiliates that provided for the right
to purchase, or realize the appreciation of, a Preference Unit or a Common Unit
(a "Unit Right"), pursuant to the provisions of the Plan. The exercise prices
covered by the Unit Rights granted pursuant to the Plan ranged from $15.6875 to
$21.50, the closing prices of the Preference Units as reported on the NYSE on
the grant date of the respective Unit Rights. For the years ended December 31,
1997 and 1996, Leviathan had accrued $3,710,000 and $436,000, respectively,
related to the appreciation and vestiture of these Unit Rights through such
dates. As a result of the "change in control" occurring upon the closing of the
Merger, the Unit Rights fully vested and the holders of the Unit Rights elected
to be paid $8,591,000, the amount equal to the difference between the grant
price of the Unit Rights and the average of the high and the low sales price of
the Common Units on the date of exercise. Upon the exercise of all of the Unit
Rights outstanding, the Plan was terminated. Leviathan replaced the Plan with
the Omnibus Plan discussed below.
Option Plans
In August 1998, Leviathan adopted the 1998 Omnibus Compensation Plan (the
"Omnibus Plan") to provide the General Partner with the ability to issue unit
options to attract and retain the services of knowledgeable officers and key
management personnel. Unit options to purchase a maximum of 3,000,000 Common
Units of Leviathan may be issued pursuant to the Omnibus Plan. Unit options
granted pursuant
F-44
<PAGE> 162
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to the Omnibus Plan are not immediately exercisable. One-half of the unit
options are considered vested and exercisable one year after the date of grant
and the remaining one-half of the unit options are considered vested and
exercisable one year after the first anniversary of the date of grant. The unit
options shall expire ten years from such grant date, but shall be subject to
earlier termination under certain circumstances.
In August 1998, Leviathan adopted the 1998 Unit Option Plan for
Non-Employee Directors (the "Director Plan" and collectively with the Omnibus
Plan, the "Option Plans") to provide the General Partner with the ability to
issue unit options to attract and retain the services of knowledgeable
directors. Unit options to purchase a maximum of 100,000 Common Units of
Leviathan may be issued pursuant to the Director Plan. Each unit option granted
under the Director Plan vests immediately at the date of grant and shall expire
ten years from such date, but shall be subject to earlier termination in the
event that the director ceases to be a director of the General Partner for any
reason, in which case the unit options expire 36 months after such date except
in the case of death, in which case the unit options expire 12 months after such
date.
The following table summarizes the Option Plans as of and for the year
ended December 31, 1998. No unit options had been granted by Leviathan prior to
August 1998.
<TABLE>
<CAPTION>
NUMBER UNITS OF WEIGHTED AVERAGE
UNDERLYING OPTIONS EXERCISE PRICE
------------------ ----------------
<S> <C> <C>
Outstanding at beginning of year..................... -- $ --
Granted............................................ 933,000 27.18
Exercised.......................................... -- --
Forfeited.......................................... -- --
Canceled........................................... -- --
------- ------
Outstanding at end of year........................... 933,000(1) $27.18(3)
======= ======
Options Exercisable at end of year................... 3,000(2) $26.17
======= ======
</TABLE>
- ---------------
(1) The weighted average remaining contractual life approximates 9.8 years.
(2) The weighted average remaining contractual life approximates 9.6 years.
(3) The exercise prices for outstanding options range from $25.00 to $27.3438.
The fair value of each unit option granted is estimated on the date of
grant using the Black-Scholes option pricing model with the following weighted
average assumptions: an expected volatility of 37%, a risk-free interest rate of
4.65%, an expected dividend yield of 8% and an expected term of 8 years. The
weighted average fair value of the unit options granted during the year ended
December 31, 1998 was $4.59. All of the unit options granted during 1998 were
granted at market value on the date of grant.
Leviathan applied APB Opinion No. 25 and related interpretations in
accounting for its Option Plans, under which no compensation expense has been
recognized during 1998 as the exercise price of each grant equaled the market
price on the date of grant. Had compensation costs for the Option Plans been
determined consistent with the methodology prescribed by SFAS No. 123,
Leviathan's net income and net income per unit would have been adjusted to a net
loss of $461,000 or $0.015 per unit on a proforma basis. The effects of applying
SFAS No. 123 in this pro forma disclosure are not indicative of future amounts.
F-45
<PAGE> 163
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8 -- RELATED PARTY TRANSACTIONS:
Management Fees
Substantially all of the individuals who perform the day-to-day financial,
administrative, accounting and operational functions for Leviathan as well as
those who are responsible for the direction and control of Leviathan are
currently employed by El Paso or were employed by DeepTech. Pursuant to a
management agreement between DeepTech and the General Partner, a management fee
is charged to the General Partner which is intended to approximate the amount of
resources allocated by El Paso and/or DeepTech in providing various operational,
financial, accounting and administrative services on behalf of the General
Partner and Leviathan. The management agreement expires on June 30, 2002, and
may be terminated thereafter upon 90 days notice by either party. Pursuant to
the terms of the Partnership Agreement, the General Partner is entitled to
reimbursement of all reasonable general and administrative expenses and other
reasonable expenses incurred by the General Partner and its affiliates for or on
behalf of Leviathan including, but not limited to, amounts payable by the
General Partner to DeepTech under the management agreement.
Effective November 1, 1995, July 1, 1996 and July 1, 1997, primarily as a
result of the increased activities of Leviathan, the General Partner amended its
management agreement with DeepTech to provide for an annual management fee of
45.3%, 54% and 52%, respectively, of DeepTech's overhead. In connection with the
Merger, the General Partner amended its management agreement with DeepTech to
provide for a monthly management fee of $775,000. The General Partner charged
Leviathan $9,283,000, $8,080,000 and $6,590,000 pursuant to its management
agreement with DeepTech for the years ended December 31, 1998, 1997 and 1996,
respectively.
The General Partner is also required to reimburse DeepTech for certain tax
liabilities resulting from, among other things, additional taxable income
allocated to the General Partner due to (i) the issuance of additional
Preference Units (including the sale of the Preference Units by Leviathan
pursuant to its second public offering) and (ii) the investment of such proceeds
in additional acquisitions or construction projects. During the years ended
December 31, 1998, 1997 and 1996, the General Partner charged Leviathan
$489,000, $713,000 and $1,162,000, respectively, to compensate DeepTech for
additional taxable income allocated to the General Partner.
Platform Access and Transportation Agreements
General. In 1993, Leviathan entered into a master gas dedication
arrangement with Tatham Offshore (the "Master Dedication Agreement"). Under the
Master Dedication Agreement, Tatham Offshore dedicated all production from its
Viosca Knoll, Garden Banks, Ewing Bank and Ship Shoal leases as well as certain
adjoining areas of mutual interest to Leviathan for transportation. In exchange,
Leviathan agreed to install the pipeline facilities necessary to transport
production from the areas and certain related facilities and to provide
transportation services with respect to such production. Tatham Offshore agreed
to pay certain fees for transportation services and facilities access provided
under the Master Dedication Agreement. Pursuant to the terms of the Purchase and
Sale Agreement (Note 4) and the Redemption Agreement (Note 1), a subsidiary of
Leviathan assumed all of Tatham Offshore's obligations under the Master
Dedication Agreement and certain ancillary agreements.
Viosca Knoll. For the years ended December 31, 1998, 1997 and 1996,
Leviathan received $1,099,000, $1,973,000 and $1,896,000, respectively, from
Tatham Offshore as platform access and processing fees related to Leviathan's
platform located in Viosca Knoll Block 817.
For the years ended December 31, 1998, 1997 and 1996, Leviathan charged
Viosca Knoll $2,447,000, $2,116,000 and $249,000, respectively, for expenses and
platform access fees related to the Viosca Knoll Block 817 platform.
F-46
<PAGE> 164
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In addition, for the years ended December 31, 1998, 1997 and 1996, Viosca
Knoll reimbursed $152,000, $47,000 and $254,000, respectively, to Leviathan for
costs incurred by Leviathan in connection with the acquisition and installation
of a booster compressor on Leviathan's Viosca Knoll Block 817 platform.
During the years ended December 31, 1998, 1997 and 1996, Viosca Knoll
charged Leviathan $1,881,000, $3,921,000 and $3,229,000, respectively, for
transportation services related to transporting production from the Viosca Knoll
Block 817 lease.
Garden Banks. During the years ended December 31, 1998, 1997 and 1996,
POPCO charged Leviathan $1,445,000, $2,003,000 and $1,056,000, respectively, for
transportation services related to transporting production from the Garden Banks
Block 72 and 117 leases.
Ewing Bank. Pursuant to a gathering agreement (the "Ewing Bank Agreement")
among Tatham Offshore, DeepTech, and a subsidiary of Leviathan, Tatham Offshore
dedicated all natural gas and crude oil produced from eight of its Ewing Bank
leases for gathering and redelivery by Leviathan and was obligated to pay a
demand and a commodity rate for shipment of all oil and natural gas under this
agreement. Pursuant to the Ewing Bank Agreement, Leviathan constructed gathering
facilities connecting Tatham Offshore's Ewing Bank 914 #2 well to a third party
platform at Ewing Bank Block 826. For the years ended December 31, 1997 and
1996, Tatham Offshore paid Leviathan demand and commodity charges of $54,000 and
$349,000, respectively, under this agreement. Additionally, through May 1997,
Leviathan received revenue from the oil and natural gas production from the
Ewing Bank 914 #2 well as a result of its 7.13% overriding royalty interest in
the well. In 1995, Tatham Offshore experienced production problems with its
Ewing Bank 914 #2 well and in March 1996, as a result of the continued
production problems, Leviathan settled all remaining unpaid demand charge
obligations under the Ewing Bank Agreement in exchange for certain consideration
as discussed below.
Ship Shoal. Pursuant to the Master Dedication Agreement, Leviathan and
Tatham Offshore entered into a gathering and processing agreement (the "Ship
Shoal Agreement") pursuant to which Leviathan constructed a gathering line from
Tatham Offshore's Ship Shoal Block 331 to interconnect with a third-party
pipeline at Leviathan's platform and processing facilities located on Ship Shoal
Block 332 in exchange for the dedication of all of the production from Tatham
Offshore's Ship Shoal Block 331 and eight additional surrounding leases and
receipt of a demand charge of $113,000 per month over a five-year period ending
June 1999. During late 1994, all of Tatham Offshore's wells at Ship Shoal Block
331 experienced completion and production problems and in March 1996, as a
result of the continued production problems, Leviathan settled all remaining
unpaid demand charge obligations under this transportation agreement in exchange
for certain consideration as discussed below.
Transportation Agreements Settled. Tatham Offshore was obligated to make
demand charge payments to Leviathan pursuant to the Ewing Bank and Ship Shoal
Agreements discussed above. However, production problems at Ship Shoal Block 331
and the Ewing Bank 914 #2 well affected Tatham Offshore's ability to pay the
demand charge obligations under agreements relative to these properties. As a
result, effective February 1, 1996, Leviathan released Tatham Offshore from all
remaining demand charge payments under the Ewing Bank Agreement and the Ship
Shoal Agreement, a total of $17,800,000. In exchange, Leviathan received 7,500
shares Senior Preferred Stock valued at $7,500,000 and added an additional
$7,500,000 to the payout amount under the Purchase and Sale Agreement (Note 4),
which was recorded as a noncurrent receivable. Pursuant to the Redemption
Agreement, Leviathan exchanged the Senior Preferred Stock for Tatham Offshore's
remaining assets located in the Gulf (Note 1).
During 1997, Tatham Offshore announced its intent to reserve its remaining
costs associated with the Ewing Bank 914 #2 well and the three wellbores at Ship
Shoal Block 331 as a result of production problems. In addition, Leviathan had
determined that the designated net revenue from the Acquired
F-47
<PAGE> 165
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Properties (Note 4) was not likely to be sufficient to satisfy the payout amount
and as such, would (i) retain 100% of the net revenue from the Acquired
Properties, (ii) bear all abandonment obligations related to these properties
and (iii) not realize the $7,500,000 plus accrued interest Leviathan had
recorded as a noncurrent receivable related to the settlement of the Ewing Bank
and Ship Shoal Agreements discussed above. Accordingly, in June 1997, Leviathan
recorded as impairment, abandonment and other expense on the accompanying
consolidated statement of operations a non-recurring charge of $21,222,000 to
reserve its investment in certain gathering facilities and other assets
associated with Tatham Offshore's Ewing Bank 914 #2 well and Ship Shoal Block
331 property ($6,443,000), to fully accrue its abandonment obligations
associated with the gathering facilities serving these properties ($3,825,000),
to reserve its noncurrent receivable related to the prepayment of the demand
charge obligations under the Ewing Bank and Ship Shoal Agreements ($9,094,000)
and to accrue certain abandonment obligations associated with its Viosca Knoll
and Garden Banks properties ($1,860,000).
During 1998, Leviathan abandoned the Ewing Bank flowlines at a cost of
$2,869,000 and recorded a credit to impairment, abandonment and other of
$1,131,000, which represented the excess of the accrued costs over the actual
costs incurred associated with the abandonment of the flowlines.
Other
Leviathan has agreed to sell all of its oil and natural gas production to
Offshore Gas Marketing, Inc. ("Offshore Marketing"), an affiliate of Leviathan,
on a month to month basis. The agreement with Offshore Marketing provides
Offshore Marketing fees equal to 2% of the sales value of crude oil and
condensate and $0.015 per dekatherm of natural gas for selling Leviathan's
production. During the years ended December 31, 1998, 1997 and 1996, oil and
natural gas sales to Offshore Marketing totaled $31,225,000, $57,830,000 and
$46,296,000, respectively.
Pursuant to a management agreement between Viosca Knoll and Leviathan,
Leviathan charges Viosca Knoll a base fee of $100,000 annually in exchange for
Leviathan providing financial, accounting and administrative services on behalf
of Viosca Knoll. For each of the years ended December 31, 1998, 1997 and 1996,
Leviathan charged Viosca Knoll $100,000 in accordance with this management
agreement.
For the years ended December 31, 1998 and 1997, Leviathan charged Manta Ray
Offshore $1,274,000 and $287,000, respectively, pursuant to management and
operations agreements.
Mr. Grant E. Sims and Mr. James H. Lytal entered into employment agreements
with five year terms with El Paso pursuant to which they would continue to serve
as Chief Executive Officer and President, respectively, of the General Partner
and Leviathan. However, pursuant to the terms of their respective employment
agreements, Messrs. Sims and Lytal have the right to terminate such agreements
upon thirty days notice and El Paso has the right to terminate such agreements
under certain circumstances.
Pursuant to the former Leviathan non-employee director compensation
arrangements, Leviathan was obligated to pay each non-employee director 2 1/2%
of the general partners' Incentive Distribution as a profit participation fee.
During the years ended December 31, 1998 and 1997, Leviathan paid the three non-
employee directors of Leviathan a total of $621,000 and $313,000, respectively,
as a profit participation fee. As a result of the Merger, the three non-employee
directors resigned and the compensation arrangements were terminated.
During the years ended December 31, 1997 and 1996, Leviathan was charged
$3,351,000 and $7,223,000, respectively, by Sedco Forex Division of Schlumberger
Technology Corporation ("Sedco Forex") for contract drilling services rendered
by the semisubmersible drilling rig, the FPS Laffit Pincay, at its Garden Banks
Block 117 project. The FPS Laffit Pincay was owned by an affiliate of DeepTech
and managed by Sedco Forex during such period.
F-48
<PAGE> 166
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
POPCO, which owns the Poseidon crude oil pipeline system, entered into
certain agreements with a subsidiary of Leviathan which provided for POPCO's use
of certain pipelines and platforms owned by such subsidiary for fees which
consisted of a monthly rental fee of $100,000 per month for the period from
February 1996 to January 1997 and reimbursement of $2,000,000 of capital
expenditures incurred in readying one of the platforms for use.
In 1996, a subsidiary of Leviathan received a performance fee of $1,400,000
for managing the construction and installation of the initial 117 mile segment
of the Poseidon crude oil pipeline system.
Mr. Charles M. Darling IV, a director of the General Partner and DeepTech
through August 14, 1998, was a partner in a law firm until April 1997 that
provided legal services to Leviathan. During the years ended December 31, 1997
and 1996, Leviathan incurred $55,000 and $203,000, respectively, for these
services.
Dover Technology, Inc., which is 50% owned by DeepTech, performed certain
technical and geophysical services for Leviathan in the aggregate amount of
$240,000 for the year ended December 31, 1996.
NOTE 9 -- INCOME TAXES:
Leviathan (other than its subsidiaries, Tarpon and Manta Ray) is not
subject to federal income taxes. Therefore, no recognition has been given to
income taxes other than income taxes related to Tarpon and Manta Ray. The tax
returns of Leviathan are subject to examination; if such examinations result in
adjustments to distributive shares of taxable income or loss, the tax liability
of partners could be adjusted accordingly.
Tarpon is and Manta Ray was, prior to its liquidation in May 1996, a
subsidiary of Leviathan that files separate federal income tax returns. The
income tax benefit recorded for the years ended December 31, 1998, 1997, and
1996 equals $471,000, $311,000 and $801,000, respectively, and is entirely
related to Tarpon. The benefit equals Tarpon's book loss times the effective
statutory rate for such period as no material book/tax permanent differences
exist. Leviathan's deferred income tax liability at December 31, 1998 and 1997
of $937,000 and $1,399,000, respectively, is entirely related to the differences
in the tax and book bases of the pipeline assets of Tarpon. In May 1996, Manta
Ray was merged with and into a subsidiary of Leviathan. Manta Ray had no taxable
income for the respective periods prior to its liquidation.
NOTE 10 -- COMMITMENTS AND CONTINGENCIES:
Credit Facilities
Each of POPCO, Viosca Knoll and Stingray are parties to a credit agreement
under which it has outstanding obligations that may restrict the payment of
distributions to its owners.
POPCO has a revolving credit facility, as amended, (the "POPCO Credit
Facility") with a syndicate of commercial banks to provide up to $150 million
for the construction and expansion of Poseidon and for other working capital
needs of POPCO. POPCO's ability to borrow money under the facility is subject to
certain customary terms and conditions, including borrowing base limitations.
The POPCO Credit Facility is collateralized by a substantial portion of POPCO's
assets and matures on April 30, 2001. As of December 31, 1998 and 1997, POPCO
had $131,000,000 and $120,500,000, respectively, outstanding under its credit
facility bearing interest at an average floating rate of 6.9% and 7.2% per
annum, respectively. At December 31, 1998, POPCO had approximately $19,000,000
of additional funds available under the facility.
F-49
<PAGE> 167
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Viosca Knoll has a revolving credit facility, as amended, (the "Viosca
Knoll Credit Facility") with a syndicate of commercial banks to provide up to
$100 million for the addition of compression to and expansion of the Viosca
Knoll system and for other working capital needs of Viosca Knoll, including
funds for a one-time distribution of $25 million to its partners. In December
1996, Leviathan received a $12,500,000 distribution from Viosca Knoll as a
result of its 50% interest in Viosca Knoll. Viosca Knoll's ability to borrow
money under its credit facility is subject to certain customary terms and
conditions, including borrowing base limitations. The Viosca Knoll Credit
Facility is collateralized by all of Viosca Knoll's material contracts and
agreements, receivables and inventory and matures on December 20, 2001. If
Viosca Knoll fails to pay any principal, interest or other amounts due pursuant
to the Viosca Knoll Credit Facility, Leviathan is obligated to pay up to a
maximum of $2,500,000 in settlement of 50% of Viosca Knoll's obligations under
the Viosca Knoll Credit Facility agreement. As of December 31, 1998 and 1997,
Viosca Knoll had $66,700,000 and $52,200,000, respectively, outstanding under
the Viosca Knoll Credit Facility bearing interest at an average floating rate of
6.7% per annum. At December 31, 1998, Viosca Knoll had approximately $33,300,000
of additional funds available under the facility. See Note 14.
In March 1998, Stingray amended an existing term loan agreement (the
"Stingray Credit Agreement") to provide for additional borrowings of up to $11.1
million and to extend the maturity date of the loan from December 31, 2000 to
March 31, 2003. The Stingray Credit Agreement requires Stingray to make 18
quarterly principal payments of $1,583,333 commencing December 31, 1998. The
term loan agreement is principally collateralized by current and future natural
gas transportation contracts between Stingray and its customers. As of December
31, 1998 and 1997, Stingray had $26,917,000 and $17,400,000, respectively,
outstanding under the Stingray Credit Agreement bearing interest at an average
floating rate of 6.5% per annum. On the earlier to occur of March 31, 2003 or
the accelerated due date pursuant to the Stingray Credit Agreement, if Stingray
has not settled all amounts due under the Stingray Credit Agreement, Leviathan
is obligated to pay the lesser of (i) $8,500,000, (ii) the aggregate amount of
distributions received by Leviathan from Stingray subsequent to January 1, 1998,
or (iii) 50% of any then outstanding amounts due pursuant to the Stingray Credit
Agreement. Management cannot determine the likelihood of Leviathan's potential
obligation associated with the Stingray Credit Agreement.
Hedging Activities
Leviathan hedges a portion of its oil and natural gas production to reduce
Leviathan's exposure to fluctuations in market prices of oil and natural gas and
to meet certain requirements of the Leviathan Credit Facility. Leviathan uses
commodity price swap instruments whereby monthly settlements are based on
differences between the prices specified in the instruments and the settlement
prices of certain futures contracts quoted on the New York Mercantile Exchange
("NYMEX") or certain other indices. Leviathan settles the instruments by paying
the negative difference or receiving the positive difference between the
applicable settlement price and the price specified in the contract. The
instruments utilized by Leviathan differ from futures contracts in that there is
no contractual obligation which requires or allows for the future delivery of
the product. The credit risk from Leviathan's price swap contracts is derived
from the counter-party to the transaction, typically a major financial
institution. Management does not require collateral and does not anticipate
non-performance by this counter-party, which does not transact a sufficient
volume of transactions with Leviathan to create a significant concentration of
credit risk. Gains or losses on hedging activities are recognized as oil and gas
sales in the period in which the hedged production is sold. For the years ended
December 31, 1998, 1997 and 1996, Leviathan recorded a net (gain) loss of
($2,526,000), $6,340,000 and $2,826,000, respectively, from such activities.
As of December 31, 1998, Leviathan had open sales swap transactions for
calendar 1999 of 10,000 million British thermal units ("MMbtu") of natural gas
per day at a fixed price to be determined at Leviathan's option equal to the
February 1999 Natural Gas Futures Contract on NYMEX as quoted at any time during
1998 and January 1999, to and including the last two trading days of the
February 1999
F-50
<PAGE> 168
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
contract, minus $0.23 per MMbtu. In January 1999, Leviathan renegotiated this
contract to provide for 10,000 MMbtu of natural gas per day for calendar 2000 at
a fixed price to be determined at Leviathan's option equal to the February 2000
Natural Gas Futures Contract on NYMEX as quoted at any time during 1999 and
January 2000, to and including the last two trading days of the February 2000
contract, minus $0.5450 per MMbtu.
Additionally, Leviathan had open sales swap transactions for calendar 2000
of 10,000 MMbtu of natural gas per day at a fixed price to be determined at
Leviathan's option equal to the January 2000 Natural Gas Futures Contract on
NYMEX as quoted at any time during 1999, to and including the last two trading
days of the January 2000 contract minus, $0.50 per MMbtu.
If Leviathan had settled its open natural gas hedging positions as of
December 31, 1998 and 1997 based on the applicable settlement prices of the
NYMEX futures contracts, Leviathan would have recognized a loss (gain) of
approximately $2.6 million and ($2.2 million), respectively.
Other
Leviathan is involved from time to time in various claims, actions,
lawsuits and regulatory matters that have arisen in the ordinary course of
business, including various rate cases and other proceedings before the FERC.
Leviathan and several subsidiaries of El Paso have been made defendants in
United States ex rel Grynberg v. El Paso Natural Gas Company, et al. litigation.
Generally, the complaint in this motion alleges an industry-wide conspiracy to
underreport the heating value as well as the volumes of the natural gas produced
from federal and Indian lands, thereby depriving the United States government of
royalties. The complaint remains sealed. Leviathan and El Paso believe the
complaint is without merit and therefore will not have a material adverse effect
on the consolidated financial position, operations or cash flows of Leviathan.
Leviathan is a defendant in a lawsuit filed by Transco Gas Pipe Line
Corporation ("Transco") in the 157th Judicial District Court, Harris County,
Texas on August 30, 1996. Transco alleges that, pursuant to a platform lease
agreement entered into on June 28, 1994, Transco has the right to expand its
facilities and operations on the offshore platform by connecting additional
pipeline receiving and appurtenant facilities. Management has denied Transco's
request to expand its facilities and operations because the lease agreement does
not provide for such expansion and because Transco's activities will interfere
with the Manta Ray Offshore system and Leviathan's existing and planned
activities on the platform. Transco has requested a declaratory judgment and is
seeking damages. The case is set for trial in June 1999. It is the opinion of
management that adequate defenses exist and that the final disposition of this
suit individually, and all of Leviathan's other pending legal proceedings in the
aggregate, will not have a material adverse effect on the consolidated financial
position, operations or cash flows of Leviathan.
In the ordinary course of business, Leviathan is subject to various laws
and regulations. In the opinion of management, compliance with existing laws and
regulations will not materially affect the consolidated financial position,
operations or cash flows of Leviathan. Various legal actions which have arisen
in the ordinary course of business are pending with respect to the pipeline
interests and other assets of Leviathan. Management believes that the ultimate
disposition of these actions, either individually or in the aggregate, will not
have a material adverse effect on the consolidated financial position,
operations or cash flows of Leviathan.
F-51
<PAGE> 169
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 11 -- SUPPLEMENTAL DISCLOSURES TO THE STATEMENT OF CASH FLOWS:
Cash paid, net of amounts capitalized, during each of the periods presented
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1998 1997 1996
------- ------- ------
(In thousands)
<S> <C> <C> <C>
Interest................................................. $17,608 $12,965 $2,890
Taxes.................................................... $ -- $ 11 $ 20
</TABLE>
Supplemental disclosures of noncash investing and financing activities
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1998 1997 1996
------- ------- -------
(In thousands)
<S> <C> <C> <C>
Decrease (increase) in investment in Tatham Offshore.... $ 7,500 $ -- $(7,500)
Additions to oil and natural gas properties............. (4,683) -- --
Additions to platform and facilities.................... (7,024) -- --
Assumption of abandonment obligations................... 4,033 -- --
Increase in other noncurrent receivable................. -- -- (7,500)
Increase in deferred revenue............................ -- -- 15,000
Conveyance of assets and liabilities to POPCO........... -- -- 29,758
Conveyance of assets and liabilities to Manta Ray
Offshore and Nautilus................................. 30 72,080 --
</TABLE>
NOTE 12 -- MAJOR CUSTOMERS:
As discussed in Note 8, Leviathan sells substantially all of its oil and
natural gas production to Offshore Marketing.
The percentage of gathering, transportation and platform services revenue
from major customers was as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1998 1997 1996
----- ----- -----
(In thousands)
<S> <C> <C> <C>
Kerr-McGee Corporation...................................... 32% -- --
Texaco Gas Marketing, Inc................................... 10% 13% --
Viosca Knoll................................................ 13% -- --
Walter Oil & Gas Corporation................................ 7% 13% --
Shell Gas Trading Company................................... -- -- 17%
Tatham Offshore............................................. -- -- 30%
</TABLE>
F-52
<PAGE> 170
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 13 -- BUSINESS SEGMENT INFORMATION:
Leviathan's operations consist of three segments: (i) gathering,
transportation and platform services, (ii) oil and natural gas and (iii) equity
investments. All of Leviathan's operations are conducted in the Gulf. The
gathering, transportation and platform services segment owns interests in
natural gas systems and platforms strategically located offshore Texas,
Louisiana and Mississippi that provides services to producers, marketers, other
pipelines and end-users for a fee. Leviathan is engaged in the development and
production of hydrocarbons through its oil and natural gas segment (Note 4).
Equity investments primarily include Leviathan's nonregulated and regulated
gathering and transportation activities that are conducted through joint
ventures, organized as general partnerships or limited liability companies, with
subsidiaries of major energy companies. The operational and administrative
activities of Leviathan's equity investments are primarily conducted by the
major energy companies and management decisions related to the operations are
made by management committees comprised of representatives of each partner or
member, as applicable, with authority appointed in direct relationship to
ownership interests (Note 3). Leviathan evaluates segment performance based on
operating net cash flows. The accounting policies of the individual segments are
the same as those of Leviathan, as a whole, as described in Note 2. The
following table summarizes certain financial information for each business
segment (in thousands):
<TABLE>
<CAPTION>
GATHERING,
TRANSPORTATION
AND PLATFORM OIL AND EQUITY INTERSEGMENT
SERVICES NATURAL GAS INVESTMENTS SUBTOTAL ELIMINATIONS TOTAL
-------------- ----------- ----------- -------- ------------ --------
<S> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1998:
Revenue from external customers... $ 17,320 $ 31,411 $26,724 $ 75,455 $ -- $ 75,455
Intersegment revenue.............. 10,673 -- -- 10,673 (10,673) --
Depreciation, depletion and
amortization.................... (7,134) (22,133) -- (29,267) -- (29,267)
Impairment, abandonment and
other........................... 1,131 -- -- 1,131 -- 1,131
Operating income (loss)........... 9,128 (10,271) 20,904 19,761 -- 19,761
YEAR ENDED DECEMBER 31, 1997:
Revenue from external customers... $ 17,329 $ 58,106 $29,327 $104,762 $ -- $104,762
Intersegment revenue.............. 11,162 -- -- 11,162 (11,162) --
Depreciation, depletion and
amortization.................... (9,900) (36,389) -- (46,289) -- (46,289)
Impairment, abandonment and
other........................... (10,268) (10,954) -- (21,222) -- (21,222)
Operating income (loss)........... (1,278) (9,676) 22,192 11,238 -- 11,238
YEAR ENDED DECEMBER 31, 1996:
Revenue from external customers... $ 24,005 $ 47,068 $20,434 $ 91,507 $ -- $ 91,507
Intersegment revenue.............. 10,052 -- -- 10,052 (10,052) --
Depreciation, depletion and
amortization.................... (15,002) (16,729) -- (31,731) -- (31,731)
Operating income.................. 9,787 15,489 16,892 42,168 -- 42,168
</TABLE>
NOTE 14 -- SUBSEQUENT EVENTS:
Acquisition of Additional Interest in Viosca Knoll Gathering Company, the
Issuance of Common Units to the General Partner and the Amendment to the
Partnership Agreement
Currently, Viosca Knoll is effectively owned 50% by Leviathan and 50% by El
Paso (Note 3). In January 1999, Leviathan announced its intent to acquire all of
El Paso's interest in Viosca Knoll, other than a 1% interest in profits and
capital of Viosca Knoll, for approximately $85.26 million (subject to
adjustment), comprised of 25% cash (up to a maximum of $21.315 million) and 75%
Common Units (up
F-53
<PAGE> 171
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to a maximum of 3,205,263 Common Units), the number of which will depend on the
average closing price of Common Units during the applicable trading reference
period. At the closing, (i) El Paso will contribute to Viosca Knoll an amount of
money equal to 50% of the amount then outstanding under the Viosca Knoll Credit
Facility (currently a total of $66.7 million is outstanding), (ii) Leviathan
will deliver to El Paso the cash and Common Units discussed above and (iii) as
required by the Partnership Agreement, the General Partner will contribute
approximately $650,000 to Leviathan in order to maintain its 1% capital account
balance. Then, during the six month period commencing on the day after the first
anniversary of that closing date, Leviathan would have the option to acquire the
remaining 1% in profits and capital in Viosca Knoll for a cash payment equal to
the sum of $1.74 million plus the amount of additional distributions which would
have been paid, accrued or been in arrears had Leviathan acquired the remaining
1% of Viosca Knoll at the initial closing by issuing additional Common Units in
lieu of a cash payment of $1.74 million.
The number of units actually issued by Leviathan will vary depending on the
market price of Common Units during the applicable trading reference period.
Such number will be determined by dividing $63.945 million (subject to
adjustment) by the average closing sales price for a Common Unit on the NYSE for
the ten day trading period ending two days prior to the closing date (the
"Market Price"); provided that, for purposes of such calculation, the Market
Price will not be less than $19.95 per Common Unit or more than $24.15 per
Common Unit. Accordingly, Leviathan will neither issue less than 2,647,826 nor
more than 3,205,263 Common Units, subject to adjustments contemplated by the
definitive agreements. Based on the closing sales price of the Common Units on
March 5, 1999 of $20.875 per unit, Leviathan would issue 3,063,234 Common Units
to El Paso, which issuance would constitute approximately 10.9% of the units
(Common and Preference) outstanding immediately after such issuance and would
result in El Paso owning, indirectly through its subsidiaries, a combined 35.4%
effective interest in Leviathan, consisting of a 1% general partnership
interest, a 33.4% limited partnership interest comprised of 9,355,128 Common
Units and an approximate 1% nonmanaging interest in certain subsidiaries of
Leviathan.
Although certain federal and state securities laws would otherwise limit El
Paso's ability to dispose of any Common Units held by it, El Paso would have the
right on three occasions to require Leviathan to file a registration statement
covering such Common Units and to participate in offerings made pursuant to
certain other registration statements filed by Leviathan during a ten year
period. Such registrations would be at Leviathan's expense and, generally, would
allow El Paso to dispose of all or any of its Common Units. If the acquisition
is consummated, there can be no assurance regarding how long El Paso may hold
any of its Common Units or whether El Paso's disposition of a significant number
of Common Units in a short period of time would not depress the market price of
the Common Units.
Upon consummation of the acquisition, Leviathan would be the beneficial
owner of 99% of Viosca Knoll and have the option to acquire the remaining 1%
interest. Leviathan and El Paso entered into a Contribution Agreement dated
January 22, 1999, which is effective as of January 1, 1999. Consummation of the
acquisition is subject to the satisfaction of certain closing conditions,
including, among other things, obtaining certain third party consents. The
consent of the lenders under the Leviathan Credit Facility and the Viosca Knoll
Credit Facility must be obtained prior to consummating this transaction. There
can be no assurance that all such required consents will be obtained. Management
believes that the acquisition of the Viosca Knoll interest does not require any
federal, state or other regulatory approval.
On January 19, 1999, the Board of Directors of the General Partner
unanimously approved and ratified and recommended that the unitholders approve
and ratify the acquisition of the additional Viosca Knoll interest. Based upon,
among other things, a multi-faceted review and analysis of the acquisition, as
well as the recommendation for approval and ratification from the Special
Committee of independent directors and the fairness opinion of an independent
financial advisor, the Board of Directors of the
F-54
<PAGE> 172
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
General Partner believes that the acquisition is fair to and in the best
interests of Leviathan and its unitholders. On March 5, 1999, the unitholders of
record as of January 28, 1999, held a meeting and ratified and approved (i) the
transactions relating to Leviathan's acquisition of El Paso's interest in Viosca
Knoll and (ii) an amendment of the Partnership Agreement to decrease the vote
required for approval of certain actions, including the removal of the general
partner without cause, from 66 2/3% to 55%.
If the remaining conditions to closing are satisfied, including obtaining
certain third party consents, management believes that the closing of the
acquisition of the Viosca Knoll interest will occur during the second quarter of
1999.
Joint Venture Restructuring and New Pipeline Construction
In December 1998, the partners of High Island Offshore System, a Delaware
partnership between Leviathan (40%), subsidiaries of ANR Pipeline Company
("ANR") (40%) and a subsidiary of Natural Gas Pipeline Company ("NGPL") (20%),
restructured the joint venture arrangement by (i) creating a holding company,
Western Gulf Holdings, L.L.C. ("Western Gulf"), (ii) converting High Island
Offshore System, which owns a jurisdictional natural gas pipeline located in the
Gulf, into a limited liability company, HIOS and (iii) forming a new limited
liability company, East Breaks Gathering Company, L.L.C. ("East Breaks") to
construct and operate a non-jurisdictional natural gas pipeline system. Western
Gulf, owned 40% by Leviathan, 40% by ANR and 20% by NGPL, owns 100% of each of
HIOS and East Breaks.
In February 1999, Western Gulf entered into a $100 million revolving credit
facility (the "Western Gulf Credit Facility") with a syndicate of commercial
banks to provide funds for the construction of the East Breaks system and for
other working capital needs of Western Gulf. The ability of Western Gulf to
borrow money under its credit facility is subject to certain customary terms and
conditions, including borrowing base limitations. The credit facility is
collateralized by substantially all of the material contracts and agreements of
East Breaks and Western Gulf including Western Gulf's ownership in HIOS and East
Breaks, and matures in February 2004. As of March 10, 1999, Western Gulf had
$44.1 million outstanding under its credit facility bearing interest at an
average floating rate of 6.4% per annum and $55.9 million of additional funds
were available under the credit facility.
The East Breaks system will initially consist of 85 miles of an 18 to
20-inch pipeline and related facilities connecting the Diana/Hoover prospects
developed by Exxon Company USA ("Exxon") and BP Amoco Plc ("BP Amoco") in
Alaminos Canyon Block 25 in the Gulf, with the HIOS system. The majority of the
construction of the East Breaks system will occur in 1999 and the system is
anticipated to be in service in late 2000 at an estimated cost of approximately
$90 million. East Breaks entered into long-term agreements with Exxon and BP
Amoco involving the commitment, gathering and processing of production from the
Diana/Hoover prospects. All of the natural gas to be produced from 11 blocks in
the East Breaks and Alaminos Canyon areas will be dedicated for transportation
services on the HIOS system.
NOTE 15 -- SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED):
Oil and natural gas reserves
The following table represents Leviathan's net interest in estimated
quantities of developed and undeveloped reserves of crude oil, condensate and
natural gas and changes in such quantities at fiscal year end 1998, 1997 and
1996. Estimates of Leviathan's reserves at December 31, 1998, 1997 and 1996 have
been made by the independent engineering consulting firm, Netherland, Sewell &
Associates, Inc. Net proved reserves are the estimated quantities of crude oil
and natural gas which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are
proved reserve volumes that can
F-55
<PAGE> 173
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
be expected to be recovered through existing wells with existing equipment and
operating methods. Proved undeveloped reserves are proved reserve volumes that
are expected to be recovered from new wells on undrilled acreage or from
existing wells where a significant expenditure is required for recompletion.
Estimates of reserve quantities are based on sound geological and
engineering principles, but, by their very nature, are still estimates that are
subject to substantial upward or downward revision as additional information
regarding producing fields and technology becomes available.
<TABLE>
<CAPTION>
OIL/CONDENSATE NATURAL GAS
(BARRELS) (MCF)
-------------- -----------
(In thousands)
<S> <C> <C>
Proved reserves -- December 31, 1995....................... 4,323 61,292
Revisions of previous estimates.......................... (734) (4,823)
Extensions, discoveries and other additions.............. 294 3,832
Production............................................... (421) (15,787)
----- -------
Proved reserves -- December 31, 1996....................... 3,462 44,514
Revisions of previous estimates.......................... (542) 5,441
Production............................................... (801) (19,792)
----- -------
Proved reserves -- December 31, 1997....................... 2,119 30,163
Revisions of previous estimates.......................... (33) 1,833
Purchase of reserves in place............................ 32 8,212
Production............................................... (540) (11,324)
----- -------
Proved reserves -- December 31, 1998....................... 1,578 28,884
===== =======
Proved developed reserves -- December 31, 1996............. 3,149 44,075
===== =======
Proved developed reserves -- December 31, 1997............. 2,119 28,324
===== =======
Proved developed reserves -- December 31, 1998............. 1,578 26,432
===== =======
</TABLE>
In general, estimates of economically recoverable oil and natural gas
reserves and of the future net revenue therefrom are based upon a number of
variable factors and assumptions, such as historical production from the subject
properties, the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices, future operating costs
and future plugging and abandonment costs, all of which may vary considerably
from actual results. All such estimates are to some degree speculative, and
classifications of reserves are only attempts to define the degree of
speculation involved. For these reasons, estimates of the economically
recoverable oil and natural gas reserves attributable to any particular group of
properties, classifications of such reserves based on risk of recovery and
estimates of the future net revenue expected therefrom, prepared by different
engineers or by the same engineers at different times, may vary substantially.
The meaningfulness of such estimates is highly dependent upon the assumptions
upon which they are based.
Furthermore, Leviathan's wells have only been producing for a short period
of time and, accordingly, estimates of future production are based on this
limited history. Estimates with respect to proved undeveloped reserves that may
be developed and produced in the future are often based upon volumetric
calculations and upon analogy to similar types of reserves rather than upon
actual production history. Estimates based on these methods are generally less
reliable than those based on actual production history. Subsequent evaluation of
the same reserves based upon production history will result in variations, which
may be substantial, in the estimated reserves. A significant portion of
Leviathan's reserves is based upon volumetric calculations.
F-56
<PAGE> 174
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Future net cash flows
The standardized measure of discounted future net cash flows relating to
Leviathan's proved oil and natural gas reserves is calculated and presented in
accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing
Activities." Accordingly, future cash inflows were determined by applying
year-end oil and natural gas prices, as adjusted for hedging and other fixed
price contracts in effect, to Leviathan's estimated share of future production
from proved oil and natural gas reserves. The average prices utilized in the
calculation of the standardized measure of discounted future net cash flows at
December 31, 1998 were $9.80 per barrel of oil and $1.53 per Mcf of gas. Future
production and development costs were computed by applying year-end costs to
future years. As Leviathan is not a taxable entity, no future income taxes were
provided. A prescribed 10% discount factor was applied to the future net cash
flows.
In Leviathan's opinion, this standardized measure is not a representative
measure of fair market value, and the standardized measure presented for
Leviathan's proved oil and natural gas reserves is not representative of the
reserve value. The standardized measure is intended only to assist financial
statement users in making comparisons between companies.
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(In thousands)
<S> <C> <C> <C>
Future cash inflows.................................. $ 53,299 $104,192 $206,311
Future production costs.............................. (13,412) (15,895) (13,019)
Future development costs............................. (10,566) (10,463) (5,328)
Future income tax expenses........................... -- -- --
-------- -------- --------
Future net cash flows................................ 29,321 77,834 187,964
Annual discount at 10% rate.......................... (2,649) (10,468) (32,326)
-------- -------- --------
Standardized measure of discounted future net cash
flows.............................................. $ 26,672 $ 67,366 $155,638
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, 1998
------------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
--------- -------------- -------
(In thousands)
<S> <C> <C> <C>
Undiscounted estimated future net cash flows from
proved reserves before income taxes............... $28,457 $864 $29,321
======= ==== =======
Present value of estimated future net cash flows
from proved reserves before income taxes,
discounted at 10%................................. $26,131 $541 $26,672
======= ==== =======
</TABLE>
F-57
<PAGE> 175
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following are the principal sources of change in the standardized
measure (in thousands):
<TABLE>
<CAPTION>
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
Beginning of year.................................... $ 67,366 $155,638 $115,170
Sales and transfers of oil and natural gas
produced, net of production costs............... (22,131) (53,492) (40,420)
Net changes in prices and production costs......... (32,129) (35,645) 45,358
Extensions, discoveries and improved recovery, less
related costs................................... -- -- 17,077
Oil and natural gas development costs incurred
during the year................................. 120 11,140 57,501
Changes in estimated future development costs...... (443) (12,439) (29,421)
Revisions of previous quantity estimates........... 1,920 (3,817) (19,686)
Purchase of reserves in place...................... 7,573 -- --
Accretion of discount.............................. 6,736 15,564 11,517
Changes in production rates, timing and other...... (2,340) (9,583) (1,458)
-------- -------- --------
End of year.......................................... $ 26,672 $ 67,366 $155,638
======== ======== ========
</TABLE>
F-58
<PAGE> 176
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 16 -- SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
<TABLE>
<CAPTION>
YEAR 1998
---------------------------------------------------------
QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 YEAR
-------- ------- ------------ ----------- -------
(In thousands, except for per Unit data)
<S> <C> <C> <C> <C> <C>
Revenue.................................. $17,714 $18,373 $18,230 $21,138 $75,455
Gross profit(a).......................... $ 7,010 $ 8,687 $ 8,165 $10,957 $34,819
Net income (loss)........................ $(1,424) $ 1,510 $(1,806) $ 2,466 $ 746
Basic and diluted net income (loss) per
unit................................... $ (0.05) $ 0.05 $ (0.06) $ 0.08 $ 0.02
Weighted average number of Units
outstanding............................ 24,367 24,367 24,367 24,367 24,367
Distributions declared per Common Unit... $ 0.525 $ 0.525 $ 0.525 $ 0.525 $ 2.10
Distributions declared per Preference
Unit................................... $ 0.525 $ 0.525 $ 0.275 $ 0.275 $ 1.60
</TABLE>
<TABLE>
<CAPTION>
YEAR 1997
-----------------------------------------------------------
QUARTER ENDED
------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 YEAR
-------- -------- ------------ ----------- --------
(In thousands, except for per Unit data)
<S> <C> <C> <C> <C> <C>
Revenue.................................. $31,028 $ 28,226 $25,474 $20,034 $104,762
Gross profit(a).......................... $13,980 $ 11,289 $11,311 $10,541 $ 47,121
Net income (loss)........................ $ 8,964 $(15,855) $ 3,274 $ 2,479 $ (1,138)
Basic and diluted net income (loss) per
unit................................... $ 0.32 $ (0.58) $ 0.12 $ 0.08 $ (0.06)
Weighted average number of Units
outstanding............................ 24,367 24,367 24,367 24,367 24,367
Distributions declared per Preference and
Common Unit............................ $ 0.425 $ 0.45 $ 0.475 $ 0.50 $ 1.85
</TABLE>
<TABLE>
<CAPTION>
YEAR 1996
---------------------------------------------------------
QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 YEAR
-------- ------- ------------ ----------- -------
(In thousands, except for per Unit data)
<S> <C> <C> <C> <C> <C>
Revenue.................................. $19,637 $18,562 $24,214 $29,094 $91,507
Gross profit(a).......................... $12,437 $10,792 $13,246 $14,233 $50,708
Net income (loss)........................ $10,910 $ 9,161 $10,006 $ 8,615 $38,692
Basic and diluted net income (loss) per
unit................................... $ 0.44 $ 0.37 $ 0.41 $ 0.35 $ 1.57
Weighted average number of Units
outstanding............................ 24,367 24,367 24,367 24,367 24,367
Distributions declared per Preference and
Common Unit............................ $ 0.325 $ 0.35 $ 0.375 $ 0.40 $ 1.45
</TABLE>
- ---------------
(a) Represent revenue less operating and depreciation, depletion and
amortization expenses.
F-59
<PAGE> 177
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder of
Leviathan Finance Corporation
In our opinion, the accompanying balance sheet presents fairly, in all
material respects, the financial position of Leviathan Finance Corporation (the
"Company") at April 30, 1999 in conformity with generally accepted accounting
principles. This financial statement is the responsibility of the Company's
management; our responsibility is to express an opinion on this financial
statement based on our audit. We conducted our audit of this statement in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statement is free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statement, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Houston, Texas
May 3, 1999
F-60
<PAGE> 178
LEVIATHAN FINANCE CORPORATION
(A WHOLLY OWNED SUBSIDIARY OF LEVIATHAN GAS PIPELINE PARTNERS, L.P.)
BALANCE SHEET
APRIL 30, 1999
<TABLE>
<S> <C>
ASSETS
Subscription receivable from parent......................... $1,000
------
Total assets...................................... $1,000
======
STOCKHOLDER'S EQUITY
Common stock, $1.00 par value, 1,000 shares authorized;
1,000 issued and outstanding.............................. $1,000
------
Total stockholder's equity........................ $1,000
======
</TABLE>
The accompanying note is an integral part of this financial statement.
F-61
<PAGE> 179
LEVIATHAN FINANCE CORPORATION
(A WHOLLY OWNED SUBSIDIARY OF LEVIATHAN GAS PIPELINE PARTNERS, L.P.)
NOTE TO BALANCE SHEET
NOTE 1 -- ORGANIZATION:
Leviathan Finance Corporation (the "Company"), a Delaware corporation, was
formed on April 30, 1999 for the sole purpose of co-issuing $175,000,000
aggregate principal amount of Senior Subordinated Notes due May 2009 (the
"Notes") with Leviathan Gas Pipeline Partners, L.P. ("Leviathan"), the Company's
parent. Leviathan, a publicly held Delaware master limited partnership, is
primarily engaged in the gathering, transportation and production of natural gas
and crude oil in the Gulf of Mexico. Through its subsidiaries and joint
ventures, Leviathan owns interests in significant assets, including (i) eight
natural gas pipelines, (ii) a crude oil pipeline system, (iii) six
strategically-located multi-purpose platforms, (iv) a dehydration facility, (v)
four producing oil and natural gas properties and (vi) one undeveloped oil and
natural gas property.
The Company's subscription receivable was generated from the initial
capitalization of the Company in which the Company issued 1,000 shares of common
stock at $1.00 par value. The Company has not conducted any operations and all
activities have related to the issuance of the Notes.
F-62
<PAGE> 180
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Viosca Knoll Gathering
Company (a Delaware general partnership)
In our opinion, the accompanying balance sheet and the related statements
of operations, of cash flows and of partners' capital present fairly, in all
material respects, the financial position of Viosca Knoll Gathering Company (a
Delaware general partnership) ("Viosca Knoll") as of December 31, 1998 and 1997,
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1998 in conformity with generally accepted
accounting principles. These financial statements are the responsibility of
Viosca Knoll's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits in accordance
with generally accepted auditing standards which require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Houston, Texas
March 19, 1999
F-63
<PAGE> 181
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
BALANCE SHEET
(In thousands)
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, -------------------
1999 1998 1997
----------- -------- --------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 182 $ 155 $ 135
Accounts receivable....................................... 3,068 4,885 2,658
Accounts receivable from affiliates....................... 1,590 179 561
Other current assets...................................... 232 232 --
-------- -------- --------
Total current assets.............................. 5,072 5,451 3,354
-------- -------- --------
Property and equipment:
Pipelines.............................................. 145,652 108,121 103,121
Construction-in-progress............................... 67 -- 1,449
Other.................................................. 77 77 24
-------- -------- --------
145,796 108,198 104,594
Less: Accumulated depreciation......................... 12,811 10,662 6,886
-------- -------- --------
Property, plant and equipment, net................... 132,985 97,536 97,708
-------- -------- --------
Debt issue costs, net....................................... -- 222 296
-------- -------- --------
Total assets...................................... $138,057 $103,209 $101,358
======== ======== ========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable.......................................... $ 27 $ 414 $ 3,841
Accounts payable to affiliates............................ 155 552 851
Accrued liabilities....................................... 5,102 55 6,588
-------- -------- --------
Total current liabilities......................... 5,284 1,021 11,280
Provision for negative salvage.............................. 382 340 256
Notes payable............................................... -- 66,700 52,200
-------- -------- --------
5,666 68,061 63,736
-------- -------- --------
Commitments and contingencies (Note 5)
Partners' capital:
VK Deepwater.............................................. 131,389 17,574 18,811
EPEC Deepwater............................................ 1,002 17,574 18,811
-------- -------- --------
132,391 35,148 37,622
-------- -------- --------
Total liabilities and partners' capital........... $138,057 $103,209 $101,358
======== ======== ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-64
<PAGE> 182
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
STATEMENT OF OPERATIONS
(In thousands)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED JUNE 30, YEAR ENDED DECEMBER 31,
----------------- ---------------------------
1999 1998 1998 1997 1996
------- ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenue:
Transportation services.................... $14,743 $14,314 $28,806 $23,128 $13,923
Oil and natural gas sales.................. 49 432 528 -- --
------- ------- ------- ------- -------
14,792 14,746 29,334 23,128 13,923
------- ------- ------- ------- -------
Costs and expenses:
Operating expenses......................... 1,129 1,181 2,877 1,990 298
Depreciation............................... 2,191 1,893 3,860 2,474 2,269
General and administrative expenses........ 71 82 154 125 126
------- ------- ------- ------- -------
3,391 3,156 6,891 4,589 2,693
------- ------- ------- ------- -------
Operating income............................. 11,401 11,590 22,443 18,539 11,230
Interest income.............................. 33 23 50 40 --
Interest and other financing costs........... (1,973) (1,989) (4,267) (1,959) (90)
------- ------- ------- ------- -------
Net income................................... $ 9,461 $ 9,624 $18,226 $16,620 $11,140
======= ======= ======= ======= =======
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-65
<PAGE> 183
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
STATEMENT OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED JUNE 30, YEAR ENDED DECEMBER 31,
------------------- ------------------------------
1999 1998 1998 1997 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income............................ $ 9,461 $ 9,624 $ 18,226 $ 16,620 $ 11,140
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation....................... 2,191 1,893 3,860 2,474 2,269
Amortization of debt issue costs... 222 37 74 73 --
Changes in operating working
capital:
Decrease (increase) in accounts
receivable.................... 1,817 (496) (2,227) 340 (1,462)
(Increase) decrease in accounts
receivable from affiliates.... (1,411) 546 382 573 (1,046)
Increase in other current
assets........................ -- -- (232) -- --
(Decrease) increase in accounts
payable....................... (387) (3,572) (3,427) 1,937 1,557
(Decrease) increase in accounts
payable to affiliates......... (397) (498) (299) 513 (2,312)
Decrease (increase) in accrued
liabilities................... (53) (6,538) (6,533) 6,328 (251)
-------- -------- -------- -------- --------
Net cash provided by operating
activities.................. 11,443 996 9,824 28,858 9,895
-------- -------- -------- -------- --------
Cash flows from investing activities:
Additions to pipeline assets.......... (49) (1,179) (3,604) (27,541) (5,219)
Construction-in-progress.............. (67) -- -- (1,449) (3,410)
-------- -------- -------- -------- --------
Net cash used in investing
activities.................. (116) (1,179) (3,604) (28,990) (8,629)
-------- -------- -------- -------- --------
Cash flows from financing activities:
Proceeds from notes payable........... -- 11,800 14,500 18,900 33,300
Repayment of notes payable............ (66,700) -- -- -- --
Contributions from partners........... 68,100 -- -- 320 3,018
Distributions to partners............. (12,700) (11,600) (20,700) (19,300) (36,900)
Debt issue costs...................... -- -- -- (70) (300)
-------- -------- -------- -------- --------
Net cash (used in) provided by
financing activities........ (11,300) 200 (6,200) (150) (882)
-------- -------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents........................... 27 17 20 (282) 384
Cash and cash equivalents at beginning
of year............................... 155 135 135 417 33
-------- -------- -------- -------- --------
Cash and cash equivalents at end of
period................................ $ 182 $ 152 $ 155 $ 135 $ 417
======== ======== ======== ======== ========
Cash paid for interest, net of amounts
capitalized........................... $ 1,804 $ 1,943 $ 4,180 $ 1,878 $ --
======== ======== ======== ======== ========
Noncash investing activities:
Additions to pipeline assets offset by
additions to accrued liabilities...... $ 5,100 $ -- $ -- $ -- $ --
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-66
<PAGE> 184
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
STATEMENT OF PARTNERS' CAPITAL
(In thousands)
<TABLE>
<CAPTION>
VK EPEC
DEEPWATER DEEPWATER TOTAL
--------- --------- ---------
<S> <C> <C> <C>
Partners' capital at December 31, 1995...................... $ 31,362 $ 31,362 $ 62,724
Contributions............................................. 1,509 1,509 3,018
Distributions............................................. (18,450) (18,450) (36,900)
Net income................................................ 5,570 5,570 11,140
--------- --------- ---------
Partners' capital at December 31, 1996...................... 19,991 19,991 39,982
Contributions............................................. 160 160 320
Distributions............................................. (9,650) (9,650) (19,300)
Net income................................................ 8,310 8,310 16,620
--------- --------- ---------
Partners' capital at December 31, 1997...................... 18,811 18,811 37,622
Distributions............................................. (10,350) (10,350) (20,700)
Net income................................................ 9,113 9,113 18,226
--------- --------- ---------
Partners' capital at December 31, 1998...................... 17,574 17,574 35,148
Contributions (unaudited)................................. 34,050 34,050 68,100
Distributions (unaudited)................................. (6,350) (6,350) (12,700)
Transfer ownership interest (unaudited) (Note 9).......... 48,151 (48,151) --
Capital contribution related to acquisition of 49%
interest (unaudited) (Note 9).......................... 32,382 -- 32,382
Net income (unaudited).................................... 5,582 3,879 9,461
--------- --------- ---------
Partners' capital at June 30, 1999 (unaudited).............. $ 131,389 $ 1,002 $ 132,391
========= ========= =========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-67
<PAGE> 185
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION:
Viosca Knoll Gathering Company ("Viosca Knoll") is a Delaware general
partnership formed in May 1994 to design, construct, own and operate the Viosca
Knoll Gathering System (the "Viosca Knoll system") and any additional facilities
constructed or acquired pursuant to the Joint Venture Agreement between VK
Deepwater Gathering Company, L.L.C. ("VK Deepwater"), an approximate 99% owned
subsidiary of Leviathan Gas Pipeline Partners, L.P. ("Leviathan"), and EPEC
Deepwater Gathering Company ("EPEC Deepwater"), an indirect subsidiary of El
Paso Energy Corporation ("El Paso"). El Paso, as a result of its merger with
DeepTech International Inc. on August 14, 1998, owns an effective 27.3% interest
in Leviathan. Each of the partners has a 50% interest in Viosca Knoll. Viosca
Knoll is managed by a committee consisting of representatives from each of the
partners. Viosca Knoll has no employees. VK Deepwater is the operator of Viosca
Knoll and has contracted with an affiliate of EPEC Deepwater to maintain the
pipeline and with Leviathan to perform financial, accounting and administrative
services.
The Viosca Knoll system is a non-jurisdictional gathering system designed
to serve the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of
Mexico (the "Gulf"), southeast of New Orleans, offshore Louisiana. The Viosca
Knoll system, has a maximum design capacity of approximately 1 billion cubic
feet of natural gas per day and consists of 125 miles of predominantly 20-inch
natural gas pipelines and a large compressor. The Viosca Knoll system provides
its customers access to the facilities of a number of major interstate
pipelines, including Tennessee Gas Pipeline Company, Columbia Gulf Transmission
Company, Southern Natural Gas Company, Transcontinental Gas Pipe Line and Destin
Pipeline Company.
The base system, comprised of (i) an approximately 94 mile, 20-inch
diameter pipeline from a platform in Main Pass Block 252 owned by Shell
Offshore, Inc. ("Shell") to a pipeline owned by Tennessee Gas Pipeline Company
at South Pass Block 55 and (ii) a six mile, 16-inch diameter pipeline from an
interconnection with the 20-inch diameter pipeline at Viosca Knoll Block 817 to
a pipeline owned by Southern Natural Gas Company at Main Pass Block 289, was
constructed in 1994. A 7,000 horsepower compressor was installed in 1996 on
Leviathan's Viosca Knoll 817 platform to allow Viosca Knoll to effect deliveries
at the operating pressures on downstream interstate pipelines with which it is
interconnected. The additional capacity created by such compression allowed
Viosca Knoll to transport new natural gas volumes during 1997 from the
Shell-operated Southeast Tahoe and Ram-Powell fields as well as other new
deepwater projects in the area. In 1997, Viosca Knoll added approximately 25
miles of parallel 20-inch pipelines.
NOTE 2 -- SIGNIFICANT ACCOUNTING POLICIES:
Cash and cash equivalents
All highly liquid investments with a maturity of three months or less when
purchased are considered to be cash equivalents.
Property and equipment
Gathering pipelines and related facilities are recorded at cost and
depreciated on a straight-line basis over an estimated useful life of 30 years.
Viosca Knoll also calculates a negative salvage provision using the
straight-line method based on an estimated cost of abandoning the pipeline of
$2.5 million. Other property, plant and equipment is depreciated on a
straight-line basis over an estimated useful life of five years. Maintenance and
repair costs are expensed as incurred; additions, improvements and replacements
F-68
<PAGE> 186
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
are capitalized. Retirements, sales and disposals of assets are recorded by
eliminating the related costs and accumulated depreciation of the disposed
assets with any resulting gain or loss reflected in income.
Viosca Knoll evaluates impairment of its property and equipment in
accordance with Statement of Financial Accounting Standard ("SFAS") No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of" which requires recognition of impairment losses on long-lived
assets if the carrying amount of such assets, grouped at the lowest level for
which there are identifiable cash flows that are largely independent of the cash
flows from other assets, exceeds the estimated undiscounted future cash flows of
such assets. Measurement of any impairment loss will be based on the fair value
of the assets.
Capitalization of interest
Interest and other financing costs are capitalized in connection with
construction activities as part of the cost of the asset and amortized over the
related asset's estimated useful life.
Debt issue costs
Debt issue costs are capitalized and amortized over the life of the related
indebtedness. Any unamortized debt issue costs are expensed at the time the
related indebtedness is repaid or otherwise terminated.
Revenue recognition
Revenue from pipeline transportation of natural gas is recognized upon
receipt of the natural gas into the pipeline system. Revenue from demand charges
is recognized in the period the services are provided. Revenue from oil and
natural gas sales is recognized upon delivery in the period of production.
Income taxes
Viosca Knoll is not a taxable entity. Income taxes are the responsibility
of the partners and are not reflected in these financial statements. However,
the taxable income or loss resulting from the operations of Viosca Knoll will
ultimately be included in the federal income tax returns of the partners and may
vary substantially from income or loss reported for financial statement
purposes.
Estimates
The preparation of Viosca Knoll's financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions, including those related to potential environmental liabilities
and future regulatory status, that affect the reported amounts of assets and
liabilities, disclosures of contingent 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.
Management believes that the estimates are reasonable.
Recent Pronouncements
In April 1998, the American Institute of Certified Public Accountants
issued SOP 98-5, "Reporting on the Costs of Start-Up Activities." This statement
defines start-up activities, requires start-up and organization costs to be
expensed as incurred and requires that any such costs that exist on the balance
sheet be expensed upon adoption of this pronouncement. The statement is
effective for fiscal years beginning after December 15, 1998. Viosca Knoll
adopted the provisions of this statement on January 1, 1999 resulting in no
material impact on its financial position or results of operations.
F-69
<PAGE> 187
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities," to be effective for all fiscal years beginning after June 15, 2000.
SFAS No. 133, as amended, requires that entities recognize all derivative
instruments as either assets or liabilities on the balance sheet and measure
those instruments at fair value. The accounting for changes in the fair value of
a derivative will depend on the intended use of the derivative and the resulting
designation. Viosca Knoll is currently evaluating the impact, if any, of SFAS
No. 133, as amended.
NOTE 3 -- INDEBTEDNESS:
In December 1996, Viosca Knoll entered into a revolving credit facility
(the "Viosca Knoll Credit Facility") with a syndicate of commercial banks to
provide up to $100 million for the addition of compression and expansion to the
Viosca Knoll System and for other working capital needs of Viosca Knoll,
including providing a one time distribution not to exceed $25 million to its
partners (Note 7). Viosca Knoll's ability to borrow money under the facility is
subject to certain customary terms and conditions, including borrowing base
limitations. The Viosca Knoll Credit Facility is collateralized by all of Viosca
Knoll's material contracts and agreements, receivables and inventory and matures
on December 20, 2001. As of December 31, 1998 and 1997, Viosca Knoll had
$66,700,000 and $52,200,000, respectively, outstanding under the Viosca Knoll
Credit Facility bearing interest at an average floating rate of 6.7% per annum.
As of December 31, 1998, approximately $33,300,000 of additional funds were
available under the Viosca Knoll Credit Facility. See Note 8.
Interest and other financing costs totaled $1,973,000 (unaudited),
$4,278,000, $2,710,000 and $90,000 for the six months ended June 30, 1999 and
for the years ended December 31, 1998, 1997 and 1996, respectively. During the
six months ended June 30, 1999 and the years ended December 31, 1998 and 1997,
Viosca Knoll capitalized $0 (unaudited), $11,000 and $751,000, respectively, of
such costs in connection with construction projects in progress.
NOTE 4 -- RELATED PARTY TRANSACTIONS:
Pursuant to a management agreement dated May 24, 1994 between Viosca Knoll
and Leviathan, Leviathan charges Viosca Knoll a base fee of $100,000 annually in
exchange for Leviathan providing financial, accounting and administrative
services on behalf of Viosca Knoll. For each of the years ended December 31,
1998, 1997 and 1996, Leviathan charged Viosca Knoll $100,000 in accordance with
this management agreement.
Viosca Knoll and EPEC Gas Services Company ("EPEC Gas"), an affiliate of
EPEC Deepwater, entered into a construction and operation agreement whereby EPEC
Gas provided personnel to manage the construction and operation of the Viosca
Knoll System in exchange for a one-time management fee of $3,000,000 and
provides routine maintenance services on behalf of Viosca Knoll. For the years
ended December 31, 1998, 1997 and 1996, EPEC Gas charged Viosca Knoll $415,000,
$216,000 and $200,000, respectively, with respect to its operating and
maintenance services.
In addition, EPEC Gas and VK-Main Pass Gathering Company, L.L.C. ("VK Main
Pass"), a subsidiary of Leviathan, acquired and installed a compressor on the
Viosca Knoll 817 Platform, which is owned by Leviathan. The compressor was
placed in service in January 1997. For the years ended December 31, 1998, 1997
and 1996, Viosca Knoll reimbursed EPEC Gas $1,762,000, $1,282,000 and
$8,072,000, respectively, for construction related costs. For the years ended
December 31, 1998, 1997 and 1996, Viosca Knoll reimbursed VK Main Pass $152,000,
$47,000 and $254,000, respectively, for construction related items.
F-70
<PAGE> 188
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Included in transportation services revenue during the years ended December
31, 1998, 1997 and 1996 is $1,881,000, $3,921,000 and $3,229,000, respectively,
of revenue earned from transportation services provided to Flextrend Development
Company, L.L.C., a subsidiary of Leviathan. Included in operating expenses for
the years ended December 31, 1998, 1997 and 1996 is $2,447,000, $2,116,000 and
$249,000, respectively, of platform access fees and related expenses charged to
Viosca Knoll by VK Main Pass.
NOTE 5 -- COMMITMENTS AND CONTINGENCIES:
In the ordinary course of business, Viosca Knoll is subject to various laws
and regulations. In the opinion of management, compliance with existing laws and
regulations will not materially affect the financial position or operations of
Viosca Knoll.
The Viosca Knoll system is a gathering facility and as such is not
currently subject to rate and certificate regulation by the Federal Energy
Regulatory Commission (the "FERC"). However, the FERC has asserted that it has
rate jurisdiction under the Natural Gas Act of 1938, as amended (the "NGA"),
over gathering services performed through gathering facilities owned by a
natural gas company (as defined in the NGA) when such services were performed
"in connection with" transportation services provided by such natural gas
company. Whether, and to what extent, the FERC should exercise any NGA rate
jurisdiction it may be found to have over gathering facilities owned either by
natural gas companies or affiliates thereof is subject to case-by-case review by
the FERC. Based on current FERC policy and precedent, Viosca Knoll does not
anticipate that the FERC will assert or exercise any NGA rate jurisdiction over
the Viosca Knoll system so long as the services provided through such system are
not performed "in connection with" transportation services performed through any
of the regulated pipelines of either of the partners.
NOTE 6 -- MAJOR CUSTOMERS:
Transportation revenue from major customers was as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
------------- ------------- -------------
AMOUNT % AMOUNT % AMOUNT %
------- --- ------- --- ------- ---
<S> <C> <C> <C> <C> <C> <C>
Shell Offshore, Inc........................ $10,836 38 $11,198 48 $ 5,141 37
Snyder Oil Corporation..................... 4,801 17 3,653 16 3,275 24
Exxon Corporation.......................... 3,354 12 498 2 -- --
Amoco Production Company................... 3,292 11 475 2 -- --
Flextrend Development Company, L.L.C. ..... 1,881 7 3,921 17 3,229 23
Other...................................... 4,642 15 3,383 15 2,278 16
------- --- ------- --- ------- ---
$28,806 100 $23,128 100 $13,923 100
======= === ======= === ======= ===
</TABLE>
NOTE 7 -- CASH DISTRIBUTIONS:
In March 1995, Viosca Knoll began making monthly distributions of 100% of
its Available Cash, as defined in the Joint Venture Agreement, to the partners.
Available Cash consists generally of all the cash receipts of Viosca Knoll less
all of its cash disbursements less reasonable reserves, including, without
limitation, those necessary for working capital and near-term commitments and
obligations or other contingencies of Viosca Knoll. Viosca Knoll expects to make
distributions of Available Cash within 15 days after the end of each month to
its partners. During the six months ended June 30, 1999 and the years ended
December 31, 1998, 1997 and 1996, Viosca Knoll paid distributions of $12,700,000
(unaudited), $20,700,000, $19,300,000 and $36,900,000, respectively, to its
partners. The distributions paid
F-71
<PAGE> 189
VIOSCA KNOLL GATHERING COMPANY
(A DELAWARE GENERAL PARTNERSHIP)
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
during 1996 include $25 million of funds provided from borrowings under the
Viosca Knoll Credit Facility. The Viosca Knoll Credit Facility Agreement
includes a covenant by which distributions are limited to the greater of net
income or 90% of earnings before interest and depreciation as defined in the
agreement. See Note 8.
NOTE 8 -- RECENT EVENTS:
In January 1999, EPEC Deepwater announced the sale of (a) all of its
interest in Viosca Knoll, other than a 1% interest in profits and capital in
Viosca Knoll, to VK Deepwater for approximately $85.26 million (subject to
adjustment), comprised of 25% cash (up to a maximum of $21.315 million) and 75%
common units of Leviathan (up to a maximum of 3,205,263 common units), the
actual number of which will depend on the average closing price of the common
units during the applicable trading reference period, and (b) an option to
acquire the remaining 1% interest in the profits and capital in Viosca Knoll.
Prior to closing, Viosca Knoll must obtain consent from its lenders under
the Viosca Knoll Credit Facility and Leviathan must obtain consent from its
lenders as well. At such time, either or both of such credit facilities may be
restructured.
At the closing, which is anticipated to be during the second quarter of
1999, (i) EPEC Deepwater will contribute to Viosca Knoll an amount of money
equal to 50% of the amount then outstanding under the Viosca Knoll Credit
Facility (currently a total of $66.7 million is outstanding) and (ii) VK
Deepwater, through Leviathan, will pay El Paso and EPEC Deepwater the cash and
common units discussed above. Then, during the six month period commencing on
the day after the first anniversary of that closing date, VK Deepwater would
have the option to acquire the remaining 1% in profits and capital in Viosca
Knoll for a cash payment equal to the sum of $1.74 million plus the amount of
additional distributions which would have been paid, accrued or been in arrears
had VK Deepwater acquired the remaining 1% of Viosca Knoll at the initial
closing by issuing additional common units of Leviathan in lieu of a cash
payment of $1.74 million.
NOTE 9 -- CONSUMMATION OF VIOSCA KNOLL TRANSACTIONS (UNAUDITED)
On June 1, 1999, VK Deepwater and EPEC Deepwater consummated the Viosca
Knoll transactions (See Note 8). In connection therewith, (i) EPEC Deepwater
contributed to Viosca Knoll $33.4 million, and (ii) EPEC Deepwater transferred a
49% interest in Viosca Knoll to VK Deepwater in exchange for a cash payment of
approximately $19.9 million and the issuance of 2,661,870 common units of
Leviathan valued at $59.8 million. The excess of VK Deepwater's cost over the
underlying book value of Viosca Knoll's net assets at June 1, 1999
(approximately $32.3 million) has been pushed down to the financial statements
of Viosca Knoll as an adjustment to property and equipment and partners'
capital. Accordingly, the financial statements as of and for the six months
ended June 30, 1999 are not comparable with prior periods.
F-72
<PAGE> 190
INDEPENDENT AUDITORS' REPORT
To the Management Committee
High Island Offshore System, L.L.C.
Detroit, Michigan
We have audited the accompanying statements of financial position of High
Island Offshore System, L.L.C. as of December 31, 1998 and 1997, and the related
statements of income, members' equity, and cash flows for each of the three
years in the period ended December 31, 1998. These financial statements are the
responsibility of the High Island Offshore System, L.L.C.'s management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of High Island Offshore System, L.L.C. as of
December 31, 1998 and 1997, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1998 in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Detroit, Michigan
February 19, 1999
F-73
<PAGE> 191
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
STATEMENTS OF FINANCIAL POSITION
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
AS OF ---------------------------
JUNE 30, 1999 1998 1997
------------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents........................ $ 1,272,342 $ 868,312 $ 876,845
Accounts receivable.............................. 5,872,504 3,777,590 4,709,918
Prepayments...................................... 234,151 15,948 --
------------ ------------ ------------
Total current assets..................... 7,378,997 4,661,850 5,586,763
------------ ------------ ------------
Gas transmission plant............................. 373,121,843 372,370,180 371,321,033
Less -- accumulated depreciation................. 366,923,035 364,601,970 359,830,332
------------ ------------ ------------
Net gas transmission plant............... 6,198,808 7,768,210 11,490,701
------------ ------------ ------------
Deferred charges................................... 4,205,497 5,168,277 590,189
------------ ------------ ------------
Total assets............................. $ 17,783,302 $ 17,598,337 $ 17,667,653
============ ============ ============
LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
Accounts payable................................. $ 4,763,200 $ 2,424,849 $ 3,077,779
Unamortized rate reductions for excess deferred
federal income taxes.......................... 50,337 201,347 302,021
------------ ------------ ------------
Total current liabilities................ 4,813,537 2,626,196 3,379,800
------------ ------------ ------------
Noncurrent liabilities
Unamortized rate reductions for excess deferred
federal income taxes.......................... -- -- 198,510
------------ ------------ ------------
Commitments and contingencies (Note 6)............. -- -- --
------------ ------------ ------------
Members' equity.................................... 12,969,765 14,972,141 14,089,343
------------ ------------ ------------
Total liabilities and members' equity.... $ 17,783,302 $ 17,598,337 $ 17,667,653
============ ============ ============
</TABLE>
See notes to the financial statements.
F-74
<PAGE> 192
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
STATEMENTS OF INCOME AND STATEMENTS OF MEMBERS' EQUITY
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31,
--------------------------- ------------------------------------------
1999 1998 1998 1997 1996
------------ ------------ ------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENTS OF INCOME
Operating revenues:
Transportation
services.............. $ 19,279,440 $ 21,667,940 $ 43,477,250 $ 45,414,839 $ 47,052,978
Other.................... 188,209 196,280 340,323 502,111 387,764
------------ ------------ ------------ ------------ ------------
Total operating
revenues....... 19,467,649 21,864,220 43,817,573 45,916,950 47,440,742
------------ ------------ ------------ ------------ ------------
Operating expenses:
Operation and
maintenance........... 8,540,105 8,521,170 18,935,495 16,975,738 15,548,824
Depreciation............. 2,321,066 2,384,078 4,771,638 4,773,588 4,775,405
Property taxes........... 108,854 111,105 111,105 125,368 133,662
------------ ------------ ------------ ------------ ------------
Total operating
expenses....... 10,970,025 11,016,353 23,818,238 21,874,694 20,457,891
------------ ------------ ------------ ------------ ------------
Net operating
income......... 8,497,624 10,847,867 19,999,335 24,042,256 26,982,851
------------ ------------ ------------ ------------ ------------
Other income and
deductions............... -- -- (16,537) -- 96,624
------------ ------------ ------------ ------------ ------------
Total other
income and
deductions..... -- -- (16,537) -- 96,624
------------ ------------ ------------ ------------ ------------
Net income................. $ 8,497,624 $ 10,847,867 $ 19,982,798 $ 24,042,256 $ 27,079,475
============ ============ ============ ============ ============
STATEMENTS OF MEMBERS'
EQUITY
Balance at beginning of
period................... $ 14,972,141 $ 14,089,343 $ 14,089,343 $ 20,547,087 $ 21,967,612
Net income............... 8,497,624 10,847,867 19,982,798 24,042,256 27,079,475
Capital contributions.... -- -- 4,000,000 -- --
Distributions to
members............... (10,500,000) (13,100,000) (23,100,000) (30,500,000) (28,500,000)
------------ ------------ ------------ ------------ ------------
Balance at end of period... $ 12,969,765 $ 11,837,210 $ 14,972,141 $ 14,089,343 $ 20,547,087
============ ============ ============ ============ ============
</TABLE>
See notes to the financial statements.
F-75
<PAGE> 193
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31,
--------------------------- ------------------------------------------
1999 1998 1998 1997 1996
------------ ------------ ------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating
activities:
Net income.............. $ 8,497,624 $ 10,847,867 $ 19,982,798 $ 24,042,256 $ 27,079,475
Adjustments to reconcile
net income to cash
provided by operating
activities
Depreciation....... 2,321,066 2,384,078 4,771,638 4,773,588 4,775,405
Accounts
receivable...... (2,094,914) 948,775 932,328 7,260 (353,633)
Prepayments........ (218,203) -- (15,948) 211,842 91,444
Deferred charges
and other....... 811,770 242,547 (4,877,271) (145,294) 67,173
Provision for
regulatory
matters......... -- -- -- -- (1,050,623)
Accounts payable... 2,753,441 (643,394) (335,434) 23,821 (1,515,481)
------------ ------------ ------------ ------------ ------------
Cash provided by
operating
activities.... 12,070,784 13,779,873 20,458,111 28,913,473 29,093,760
------------ ------------ ------------ ------------ ------------
Cash flows from investing
activities:
Capital expenditures.... (1,166,754) (20,478) (1,366,644) (822,554) (209,863)
------------ ------------ ------------ ------------ ------------
Cash used in
investing
activities.... (1,166,754) (20,478) (1,366,644) (822,554) (209,863)
------------ ------------ ------------ ------------ ------------
Cash flows from financing
activities:
Capital contributions... -- -- 4,000,000 -- --
Distributions to
members.............. (10,500,000) (13,100,000) (23,100,000) (30,500,000) (28,500,000)
------------ ------------ ------------ ------------ ------------
Cash used in
financing
activities.... (10,500,000) (13,100,000) (19,100,000) (30,500,000) (28,500,000)
------------ ------------ ------------ ------------ ------------
Increase (decrease) in
cash and cash
equivalents............. 404,030 659,395 (8,533) (2,409,081) 383,897
Cash and cash equivalents
at beginning of
period.................. 868,312 876,845 876,845 3,285,926 2,902,029
------------ ------------ ------------ ------------ ------------
Cash and cash equivalents
at end of period........ $ 1,272,342 $ 1,536,240 $ 868,312 $ 876,845 $ 3,285,926
============ ============ ============ ============ ============
</TABLE>
See notes to the financial statements.
F-76
<PAGE> 194
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
NOTES TO THE FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
NOTE 1 -- FORMATION AND OWNERSHIP STRUCTURE
Description and Business Purpose
Effective December 10, 1998, High Island Offshore System, ("HIOS" or the
"Company"), a Delaware partnership, was converted to a Delaware Limited
Liability Corporation ("L.L.C."). In January 1999, the members of HIOS, each of
which owned a 20% interest, contributed their capital accounts to Western Gulf
Holdings, L.L.C. ("Western Gulf") in exchange for an equivalent ownership
interest in Western Gulf. As a result, Western Gulf now owns a 100% interest in
the Company. Western Gulf was formed to invest in the development of a 85 mile
pipeline which will connect to HIOS and extend to the deep water "Diana"
prospect containing an estimated 1 trillion cubic feet of reserves. The new line
is scheduled to begin transporting gas in late 2000 and is projected to cost $90
million. The line will be owned by East Breaks Gathering Company, L.L.C., which
is also owned by Western Gulf.
HIOS owns a 203.4 mile undersea gas transmission system in the Gulf of
Mexico which provides transportation services as authorized by the Federal
Energy Regulatory Commission ("FERC"). HIOS' major transportation customers
include natural gas marketers and producers, and interstate natural gas pipeline
companies. The Company extends credit for transportation services provided to
these customers. The concentrations of customers, described above, may affect
the Company's overall credit risk in that the customers may be similarly
affected by changes in economic, regulatory and other factors.
HIOS is managed by a committee consisting of representatives from each of
the member companies. HIOS has no employees. ANR Pipeline Company ("ANR")
operates the system on behalf of HIOS under an agreement which provides that
services rendered to HIOS will be reimbursed at cost ($12.4 million for 1998,
$11.4 million for 1997, and $9.6 million for 1996).
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The Company is regulated by the FERC. In addition, the Company meets the
criteria and, accordingly, follows the accounting and reporting requirements of
Statement of Financial Accounting Standards No. 71 for regulated enterprises.
Use of Estimates
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 and the
reported amounts of revenues and expenses. Actual results could differ from
those estimates. Management believes that its estimates are reasonable.
Depreciation
Annual depreciation and negative salvage provisions are computed on a
straight-line basis using rates of depreciation which vary by type of property.
The annual composite depreciation rates were approximately 1.29% for 1998, 1997,
and 1996 which include a provision for negative salvage of .2% for offshore
facilities.
Income Taxes
For tax filing purposes, the Company has elected partnership status, and
therefore, income taxes are the responsibility of the Members and are not
reflected in the financial statements of the Company.
F-77
<PAGE> 195
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
Statement of Cash Flows
For purposes of these financial statements, the Company considers
short-term investments purchased with an original maturity of three months or
less to be cash equivalents. The Company had short-term investments in the
amount of $.9 million at December 31, 1998 and 1997. The Company made no cash
payments for interest in 1998, 1997, or 1996.
Accounting Pronouncements
The Financial Accounting Standards Board has issued FAS 133, as amended by
FAS 137, "Accounting for Derivative Instruments and Hedging Activities," to be
effective for all fiscal years beginning after June 15, 2000. FAS 133, as
amended, requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. The accounting for changes in the fair value of a derivative will
depend on the intended use of the derivative and the resulting designation. The
Company is currently evaluating the impact, if any, of FAS 133, as amended.
NOTE 3 -- REGULATORY MATTERS
By letter order issued September 18, 1995, the FERC approved the settlement
of the Company's rate filing at Docket No. RP94-162, which required that the
Company file a new rate case within three years. On October 8, 1998, the FERC
granted a request filed by the Company for an extension of time for the filing
of its next general rate case until January 1, 2003. Costs incurred in
connection with the extension of the rate case settlement have been deferred and
are being amortized on a straight-line basis through the period ending December
31, 2002.
NOTE 4 -- FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of cash invested on a temporary basis at short-term
market rates of interest approximates the fair market value of the investments.
NOTE 5 -- RELATED PARTY TRANSACTIONS
Transportation revenues derived from affiliated pipeline companies were $.8
million for 1998, $6.2 million for 1997, and $16.7 million for 1996. The Company
had no accounts receivable balances due from these affiliates for transportation
services at December 31, 1998 and 1997.
Both ANR and U-T Offshore System ("UTOS") provide separation, dehydration
and measurement services to HIOS. UTOS is equally owned by affiliates of ANR,
Natural Gas Pipeline Company of America, and Leviathan Gas Pipeline Partners,
L.P. HIOS incurred charges for these services of $2.5 million in 1998, $2.5
million in 1997, and $2.8 million in 1996 from ANR and $2.0 million in 1998,
$1.7 million in 1997, and $1.4 million in 1996 from UTOS.
In February 1996, the Company reached an agreement with ANR, which was
approved by the FERC, which provides that rates charged by ANR would be $2.8
million for calendar year 1996, $2.5 million per year for calendar years 1997,
1998 and 1999 and $2.2 million for calendar year 2000. The rate would be
negotiated for calendar year 2001 and thereafter.
Amounts due to ANR were $1.9 million and $1.8 million at December 31, 1998
and 1997, respectively, and amounts due to UTOS were $.2 million and $.1 million
at December 31, 1998 and 1997, respectively.
F-78
<PAGE> 196
HIGH ISLAND OFFSHORE SYSTEM, L.L.C.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 6 -- COMMITMENTS AND CONTINGENCIES
In the ordinary course of business, the Company is subject to various laws
and regulations. In the opinion of management, compliance with existing laws and
regulations will not materially affect the financial position or the results of
operations of the Company.
NOTE 7 -- LEGAL PROCEEDINGS
In 1996, Jack Grynberg filed a claim under the False Claims Act on behalf
of the U.S. government in the U.S. District Court, District of Columbia, against
70 defendants, including the Company. The suit sought damages for the alleged
underpayment of royalties due to the purported improper measurement of gas. The
1996 suit was dismissed without prejudice in March 1997 and the dismissal was
affirmed by the D.C. Court of Appeals in October 1998. In September 1997, Mr.
Grynberg filed 77 separate, similar False Claims Act suits against natural gas
transmission companies and producers, gatherers, and processors of natural gas,
seeking unspecified damages. The Company has been included in two of the
September 1997 suits. The suits were filed in the U.S. District Court, District
of Colorado and the U.S. District Court, Eastern District of Michigan. In April
1999, the United States Department of Justice notified the Company that the
United States will not intervene in these cases (unaudited).
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all such claims and
that any liability which may be finally determined should not have a material
adverse effect on the Company's financial position or results of operations.
F-79
<PAGE> 197
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Members of
Poseidon Oil Pipeline Company, L.L.C.:
We have audited the accompanying balance sheets of Poseidon Oil Pipeline
Company, L.L.C. (a Delaware limited liability company), as of December 31, 1998
and 1997, and the related statements of income, members' equity and cash flows
for the years ended December 31, 1998 and 1997, and for the period from
inception (February 14, 1996) through December 31, 1996. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Poseidon Oil Pipeline
Company, L.L.C., as of December 31, 1998 and 1997, and the results of its
operations and its cash flows for the years ended December 31, 1998 and 1997,
and for the period from inception (February 14, 1996) through December 31, 1996,
in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
March 18, 1999
F-80
<PAGE> 198
POSEIDON OIL PIPELINE COMPANY, L.L.C.
BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 685,540 $ 1,671,451
Crude oil receivables --
Related parties........................................ 28,216,308 21,729,130
Other.................................................. 12,179,468 7,316,566
Construction advances to operator (Note 6)................ 1,234,467 --
Materials, supplies and other............................. 1,022,450 1,045,937
------------ ------------
Total current assets.............................. 43,338,233 31,763,084
Debt reserve fund (Notes 2 and 4)........................... 4,329,254 3,717,627
Property, plant and equipment, net of accumulated
depreciation
(Note 3).................................................. 228,752,910 222,337,758
------------ ------------
Total assets...................................... $276,420,397 $257,818,469
============ ============
LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
Accounts payable --
Related parties........................................ $ 4,945,839 $ 2,602,133
Other.................................................. 2,165,159 5,516,554
Crude oil payables --
Related parties........................................ 28,646,791 22,534,661
Other.................................................. 3,778,243 5,139,391
Other..................................................... 597,590 70,922
------------ ------------
Total current liabilities......................... 40,133,622 35,863,661
------------ ------------
Long-term debt (Note 4)..................................... 131,000,000 120,500,000
------------ ------------
Members' equity (Note 1):
Capital contributions..................................... 107,999,320 107,999,320
Capital distributions..................................... (36,699,320) (17,999,320)
Retained earnings......................................... 33,986,775 11,454,808
------------ ------------
Total members' equity............................. 105,286,775 101,454,808
------------ ------------
Total liabilities and members' equity............. $276,420,397 $257,818,469
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-81
<PAGE> 199
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
AND FOR THE PERIOD FROM INCEPTION (FEBRUARY 14, 1996)
THROUGH DECEMBER 31, 1996
<TABLE>
<CAPTION>
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Crude oil sales................................. $ 370,431,640 $ 310,828,794 $ 176,849,075
Crude oil purchases............................. (325,909,477) (284,667,502) (169,030,526)
------------- ------------- -------------
Net sales revenue..................... 44,522,163 26,161,292 7,818,549
------------- ------------- -------------
Operating costs:
Transportation costs.......................... 1,636,162 3,146,736 858,229
Operating expenses............................ 3,127,134 2,635,717 2,183,375
Depreciation.................................. 8,846,395 6,463,327 2,176,157
------------- ------------- -------------
Total operating costs................. 13,609,691 12,245,780 5,217,761
------------- ------------- -------------
Operating income................................ 30,912,472 13,915,512 2,600,788
Other income (expense):
Interest income............................... 290,745 208,961 339,452
Interest expense.............................. (8,671,250) (5,340,742) (269,163)
------------- ------------- -------------
Net income...................................... $ 22,531,967 $ 8,783,731 $ 2,671,077
============= ============= =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-82
<PAGE> 200
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF MEMBERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
AND FOR THE PERIOD FROM INCEPTION (FEBRUARY 14, 1996)
THROUGH DECEMBER 31, 1996
<TABLE>
<CAPTION>
POSEIDON
MARATHON PIPELINE TEXACO
OIL COMPANY, TRADING AND
COMPANY L.L.C. TRANSPORTATION, INC.
(28%) (36%) (36%) TOTAL
----------- ----------- -------------------- ------------
<S> <C> <C> <C> <C>
Balance, February 14, 1996.......... $ -- $ -- $ -- $ --
Cash contributions................ 5,200,000 -- 36,399,660 41,599,660
Property contributions............ 20,000,000 36,399,660 10,000,000 66,399,660
Cash distributions................ -- (3,999,660) (13,999,660) (17,999,320)
Net income........................ 747,901 961,588 961,588 2,671,077
----------- ----------- ------------ ------------
Balance, December 31, 1996.......... 25,947,901 33,361,588 33,361,588 92,671,077
Net income........................ 2,459,445 3,162,143 3,162,143 8,783,731
----------- ----------- ------------ ------------
Balance, December 31, 1997.......... 28,407,346 36,523,731 36,523,731 101,454,808
Net income........................ 6,308,951 8,111,508 8,111,508 22,531,967
Cash distributions................ (5,236,000) (6,732,000) (6,732,000) (18,700,000)
----------- ----------- ------------ ------------
Balance, December 31, 1998.......... $29,480,297 $37,903,239 $ 37,903,239 $105,286,775
=========== =========== ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-83
<PAGE> 201
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
AND FOR THE PERIOD FROM INCEPTION (FEBRUARY 14, 1996)
THROUGH DECEMBER 31, 1996
<TABLE>
<CAPTION>
1998 1997 1996
----------- ------------ -------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income....................................... $22,531,967 $ 8,783,731 $ 2,671,077
Adjustments to reconcile net income to net cash
provided by operating activities --
Depreciation.................................. 8,846,395 6,463,327 2,176,157
Changes in operating assets and liabilities --
Crude oil receivables....................... (11,350,080) 2,509,382 (31,555,078)
Materials, supplies and other............... 23,487 (952,294) (93,643)
Accounts payable............................ (1,007,689) 5,939,637 2,179,050
Crude oil payables.......................... 4,750,982 (8,098,087) 35,772,139
Other current liabilities................... 526,668 (16,110) 87,032
----------- ------------ -------------
Net cash provided by operating
activities............................. 24,321,730 14,629,586 11,236,734
----------- ------------ -------------
Cash flows from investing activities:
Capital expenditures............................. (15,261,547) (54,024,948) (110,698,884)
Construction advances to operator, net........... (1,234,467) 7,407,710 (7,407,710)
Proceeds from the sale of property, plant and
equipment..................................... -- 146,250 --
----------- ------------ -------------
Net cash used in investing activities.... (16,496,014) (46,470,988) (118,106,594)
----------- ------------ -------------
Cash flows from financing activities:
Proceeds from issuance of debt................... 32,000,000 38,000,000 107,000,000
Cash contributions............................... -- -- 41,599,660
Repayments of long-term debt..................... (21,500,000) (1,500,000) (23,000,000)
Cash distributions............................... (18,700,000) -- (17,999,320)
Increase in debt reserve fund.................... (611,627) (3,717,627) --
----------- ------------ -------------
Net cash provided by financing
activities............................. (8,811,627) 32,782,373 107,600,340
----------- ------------ -------------
Increase in cash and cash equivalents.............. (985,911) 940,971 730,480
Cash and cash equivalents, beginning of year....... 1,671,451 730,480 --
----------- ------------ -------------
Cash and cash equivalents, end of year............. $ 685,540 $ 1,671,451 $ 730,480
=========== ============ =============
Supplemental disclosure of cash flow information:
Cash paid for interest, net of amounts
capitalized................................... $ 8,596,583 $ 5,342,217 $ 205,713
=========== ============ =============
Supplemental disclosure of noncash financing
activities:
Initial Poseidon property contribution........... $ -- $ -- $ 36,399,660
=========== ============ =============
Block 873 Pipeline property contribution......... $ -- $ -- $ 30,000,000
=========== ============ =============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-84
<PAGE> 202
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1998 AND 1997
NOTE 1 -- ORGANIZATION AND NATURE OF BUSINESS
Poseidon Oil Pipeline Company, L.L.C. (the Company), is a Delaware limited
liability company formed on February 14, 1996, to design, construct, own and
operate the unregulated Poseidon Pipeline extending from the Gulf of Mexico to
onshore Louisiana. The original members of the Company were Texaco Trading and
Transportation, Inc. (TTTI), and Poseidon Pipeline Company, L.L.C. (Poseidon), a
subsidiary of Leviathan Gas Pipeline Partners, L.P. TTTI contributed $36,399,660
in cash, and Poseidon contributed property, plant and equipment, valued by the
two parties (TTTI and Poseidon) at $36,399,660, at the formation of the Company.
Each member received a 50 percent ownership interest in the Company.
Subsequently, $2,799,320 in cash was equally distributed to TTTI and Poseidon,
leaving $70 million of equity in the Company as of April 23, 1996.
On July 1, 1996, Marathon Pipeline Company (MPLC) and Texaco Pipeline, Inc.
(TPLI), through their 66 2/3 percent and 33 1/3 percent respectively owned
venture, Block 873 Pipeline Company (Block 873), contributed property, plant and
equipment valued by the parties (Block 873, TTTI and Poseidon) at $30,000,000.
In return, they received a 33 1/3 percent interest in the Company. Immediately
after the contribution, MPLC and TPLI transferred their pro rata ownership
interests in the Company to Marathon Oil Company (Marathon) and TTTI,
respectively. Marathon then contributed an additional $5.2 million in cash, and
distributions of $12.6 million and $2.6 million in cash were made to TTTI and
Poseidon, respectively. Upon completion of this transaction, TTTI, Poseidon and
Marathon owned 36 percent, 36 percent and 28 percent of the Company,
respectively, and total equity was $90,000,000.
The Company purchased crude oil line-fill and began operating Phase I of
the pipeline in April 1996. Phase I consists of 16-inch and 20-inch sections of
pipe extending from the Garden Banks Block 72 to Ship Shoal Block 332. Phase II
of the pipeline is a 24-inch section of pipe from Ship Shoal Block 332 to
Caillou Island. Line-fill was purchased for Phase II in late December 1996 and
operations began in January 1997. Construction of Phase III of the pipeline
consisting of a section of 24-inch line extending from Caillou Island to the
Houma, Louisiana, area was completed during 1997, and operations began in
December 1997.
The Company is in the business of transporting crude oil in the Gulf of
Mexico in accordance with various purchase and sale contracts with producers
served by the pipeline. The Company buys crude oil at various points along the
pipeline and resells the crude oil at a destination point in accordance with
each individual contract. Net sales revenue is earned based upon the
differential between the sale price and purchase price. Differences between
purchased and sold volumes in any period are recorded as changes in line-fill.
Effective January 1, 1998, Shell Oil Company and Texaco Inc. (Texaco)
formed Equilon Enterprises LLC (Equilon). Equilon is a joint venture which
combines both companies' western and midwestern U.S. refining and marketing
businesses and both companies' nationwide trading, transportation and lubricants
businesses. Under the formation agreement, Shell Oil Company and Texaco
assigned, or caused to be assigned, the economic benefits and detriments of
certain regulated and unregulated pipeline assets, including TTTI's beneficial
interest in the Company. As a result of the joint venture, Equilon became
operator of the Company on January 1, 1998.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Accounting
The accompanying financial statements have been prepared on the accrual
basis of accounting in accordance with generally accepted accounting principles.
F-85
<PAGE> 203
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Use of Estimates
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 and
disclosure of contingent 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.
Property, Plant and Equipment
Contributed property, plant and equipment is recorded at fair value as
agreed to by the members at the date of contribution. Acquired property, plant
and equipment is recorded at cost. Pipeline equipment is depreciated using a
composite, straight-line method over estimated useful lives of three to 30
years. Line-fill is not depreciated as management of the Company believes the
cost of all barrels is fully recoverable. Major renewals and betterments are
capitalized in the property accounts while maintenance and repairs are expensed
as incurred. No gain or loss is recognized on normal asset retirements under the
composite method.
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an
original maturity of three months or less to be cash equivalents.
Debt Reserve Fund
In connection with the Company's revolving credit facility (see Note 4),
the Company is required to maintain a debt reserve account as security on the
outstanding balance. At December 31, 1998, the balance in the account totaled
$4,329,254 and was comprised of funds earning interest at a money market rate.
Fair Value of Financial Instruments
The Company's financial instruments consist of cash and cash equivalents,
short-term receivables, payables and long-term debt. The carrying values of cash
and cash equivalents, short-term receivables and payables approximate fair
value. The fair value for long-term debt is estimated based on current rates
available for similar debt with similar maturities and securities and, at
December 31, 1998, approximates the carrying value.
F-86
<PAGE> 204
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following at December 31,
1998 and 1997:
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Rights-of-way............................................ $ 3,218,788 $ 3,218,788
Line-fill................................................ 11,350,466 11,160,410
Line pipe, line pipe fittings and pipeline
construction........................................... 223,076,191 206,041,256
Pumping and station equipment............................ 4,613,516 4,584,563
Office furniture, vehicles and other equipment........... 83,812 67,609
Construction work in progress............................ 3,896,016 5,904,616
------------ ------------
246,238,789 230,977,242
Less -- Accumulated depreciation......................... (17,485,879) (8,639,484)
------------ ------------
$228,752,910 $222,337,758
============ ============
</TABLE>
Management evaluates the carrying value of the pipeline in accordance with
the guidelines presented under Statement of Financial Accounting Standards
(SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of." SFAS No. 121 establishes standards for
measuring the impairment of long-lived assets to be held and used and of those
to be disposed. Management believes no impairment of assets exists as of
December 31, 1998.
During 1998 and 1997, the Company capitalized approximately $-- and
$2,151,000, respectively, of interest cost into property, plant and equipment.
NOTE 4 -- DEBT
The Company maintains a $150,000,000 revolving credit facility with a group
of banks. The outstanding balance at December 31, 1998, is $131,000,000. Under
the terms of the related credit agreement, the Company has the option to either
draw or renew amounts at various maturities ranging from one to 12 months if a
Eurodollar interest rate arrangement is selected (6.875 percent to 6.9375
percent at December 31, 1998). These borrowings can then be renewed assuming no
event of default exists. Alternatively, the Company may select to borrow under a
base interest rate arrangement, calculated in accordance with the credit
agreement. The revolving credit facility matures on April 30, 2001.
At December 31, 1998, the entire outstanding balance had been borrowed
under the Eurodollar alternative, and it is the Company's intent to extend
repayment beyond one year, thus the entire balance has been classified as
long-term.
The debt is secured by various assets of the Company including accounts
receivable, inventory, pipeline equipment and investments. The Company has used
the funds drawn on the revolver primarily for construction costs associated with
Phases II and III of the pipeline.
The revolving credit agreement requires the Company to meet certain
financial and nonfinancial covenants. The Company must maintain a tangible net
worth, calculated in accordance with the credit agreement, of not less than
$80,000,000. Beginning April 1, 1997, the Company is required to maintain a
ratio of earnings before interest, taxes, depreciation and amortization to
interest paid or accrued, as calculated in accordance with the credit agreement,
of 2.50 to 1.00. In addition, the Company is required to maintain a debt reserve
fund (see Note 2) with a balance equal to two times the interest payments made
in the previous quarter under the credit facility.
F-87
<PAGE> 205
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 5 -- INCOME TAXES
A provision for income taxes has not been recorded in the accompanying
financial statements because such taxes accrue directly to the members. The
federal and state income tax returns of the Company are prepared and filed by
the operator.
NOTE 6 -- TRANSACTIONS WITH RELATED PARTIES
The Company derives a significant portion of its gross sales and gross
purchases from its members and other related parties. The Company generated
approximately $263,872,000 in gross affiliated sales and approximately
$226,184,000 in gross affiliated purchases for 1998. During 1997 and 1996, the
Company generated approximately $19,790,000 and $4,086,000 of net sales revenue
from related parties.
The Company paid approximately $558,000 to Equilon in 1998 and $454,000 and
$401,000 to TTTI in 1997 and 1996, respectively, for management, administrative
and general overhead. In 1998, 1997 and 1996, the Company paid construction
management fees of $2,133,507, $1,091,000 and $2,364,000, respectively, to
Equilon in connection with the completion of Phase II and Phase III. As of
December 31, 1998 and 1997, the Company had outstanding advances to Equilon of
approximately $1,234,000 and $--, respectively, in connection with construction
work in progress.
NOTE 7 -- CONTINGENCIES
In the normal course of business, the Company is involved in various legal
actions arising from its operations. In the opinion of management, the outcome
of these legal actions will not significantly affect the financial position or
results of operations of the Company.
F-88
<PAGE> 206
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Members
of Neptune Pipeline Company, L.L.C.
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, of members' capital and of cash flows present
fairly, in all material respects, the financial position of Neptune Pipeline
Company, L.L.C. at December 31, 1998 and 1997, and the result of its operations
and its cash flows for the years then ended, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 11, 1999
F-89
<PAGE> 207
NEPTUNE PIPELINE COMPANY, L.L.C.
CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 6,016,841 $ 18,531,456
Transportation receivable................................. 1,279,405 764,008
Owing from related parties................................ 2,880,664 11,974,091
Other receivable.......................................... 104,756 89,821
------------ ------------
Total current assets.............................. 10,281,666 31,359,376
Pipelines and equipment..................................... 261,104,113 249,861,312
Less: accumulated depreciation............................ 12,204,577 2,056,246
------------ ------------
248,899,536 247,805,066
Long-term receivable........................................ 160,000 --
------------ ------------
Total assets...................................... $259,341,202 $279,164,442
============ ============
LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 964,761 $ 2,001,863
Owing to related parties.................................. 4,784,102 32,779,237
Deferred income........................................... -- 20,478
------------ ------------
Total current liabilities......................... 5,748,863 34,801,578
Minority interest........................................... 1,872,959 1,778,740
Members' equity............................................. 251,719,380 242,584,124
------------ ------------
Total liabilities and members' equity............. $259,341,202 $279,164,442
============ ============
</TABLE>
The accompanying notes are an integral part of these statements.
F-90
<PAGE> 208
NEPTUNE PIPELINE COMPANY, L.L.C.
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
1998 1997
----------- ----------
<S> <C> <C>
Operating income:
Transportation revenue.................................... $16,172,659 $6,317,728
Other gas revenue......................................... 180,236 --
----------- ----------
Total revenues.................................... 16,352,895 6,317,728
Operating expenses:
Operating & maintenance................................... 3,575,712 1,693,978
Administrative & general.................................. 1,455,240 992,520
Depreciation.............................................. 10,148,332 2,056,246
Property taxes............................................ 326,332 --
----------- ----------
Total operating expenses.......................... 15,505,616 4,742,744
Net operating income........................................ 847,279 1,574,984
Other income (expense)
Other expense.......................................... (150,100) --
Interest income........................................ 385,123 362,142
Allowance for funds used during construction........... -- 6,430,641
----------- ----------
Total other income, net........................... 235,023 6,792,783
Net income before minority interest......................... 1,082,302 8,367,767
Minority interest in income of subsidiaries............... 11,026 81,736
----------- ----------
Net income.................................................. $ 1,071,276 $8,286,031
=========== ==========
</TABLE>
The accompanying notes are an integral part of these statements.
F-91
<PAGE> 209
NEPTUNE PIPELINE COMPANY, L.L.C.
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
1998 1997
------------ -------------
<S> <C> <C>
Cash flows from operating activities:
Net income................................................ $ 1,071,276 $ 8,286,031
Adjustments to reconcile net income to net cash provided
by (used for) operating activities:
Depreciation........................................... 10,148,332 2,056,246
Allowance for funds used during construction........... -- (6,430,641)
Minority interest in income of subsidiaries............ 11,026 81,736
(Increases) decreases in working capital:
Transportation receivables............................. (515,397) (764,008)
Owing from related parties............................. 9,093,427 (11,974,091)
Other receivable....................................... 25,065 (89,503)
Accounts payable....................................... (1,037,102) 2,001,863
Owing to related parties............................... (30,791,136) 32,779,237
Deferred income........................................ (20,478) (54,522)
------------ -------------
Net cash provided by (used for) operating
activities...................................... (12,014,987) 25,892,348
------------ -------------
Cash flows used for investing activities:
Capital expenditures...................................... (9,252,950) (179,087,955)
Proceeds from property sales and salvage.................. 187,149 --
Contributions in aid of construction...................... 419,000 --
------------ -------------
Net cash used for investing activities............ (8,646,801) (179,087,955)
------------ -------------
Cash flows provided by financing activities:
Members' contributed capital.............................. 13,985,491 172,512,990
Minority interest contributed capital..................... 83,193 1,696,980
Distributions............................................. (5,921,511) (2,560,000)
------------ -------------
Net cash provided by financing activities......... 8,147,173 171,649,970
------------ -------------
Increase (decrease) in cash and cash equivalents............ $(12,514,615) $ 18,454,363
============ =============
Reconciliation of beginning and ending balances
Cash and cash equivalents -- beginning of year............ $ 18,531,456 $ 77,093
Increase (decrease) in cash and cash equivalents.......... (12,514,615) 18,454,363
------------ -------------
Cash and cash equivalents -- end of year.................... $ 6,016,841 $ 18,531,456
============ =============
</TABLE>
The accompanying notes are an integral part of these statements.
F-92
<PAGE> 210
NEPTUNE PIPELINE COMPANY, L.L.C.
STATEMENT OF MEMBERS' CAPITAL
AS OF DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
TEJAS OFFSHORE
PIPELINE LLC/ MARATHON GAS SAILFISH
SHELL SEAHORSE TRANSMISSION PIPELINE
COMPANY INC. COMPANY LLC TOTAL
-------------- ------------ ----------- ------------
<S> <C> <C> <C> <C>
Capital account balances at December
31, 1996............................ $ 1,194 $ 581 $ 612 $ 2,387
Members' contributions................ 115,473,693 56,659,297 380,000 172,512,990
Contributed assets.................... 4,100,000 -- 60,242,716 64,342,716
Net income............................ 3,433,401 1,328,264 3,524,366 8,286,031
Distributions......................... -- -- (2,560,000) (2,560,000)
------------ ----------- ----------- ------------
Capital account balances at December
31, 1997............................ 123,008,288 57,988,142 61,587,694 242,584,124
Members' contributions................ 5,369,182 3,524,321 5,091,988 13,985,491
Net income............................ 585,317 236,169 249,790 1,071,276
Distributions......................... (3,358,512) (1,246,864) (1,316,135) (5,921,511)
------------ ----------- ----------- ------------
Capital account balances at December
31, 1998............................ $125,604,275 $60,501,768 $65,613,337 $251,719,380
============ =========== =========== ============
</TABLE>
The accompanying notes are an integral part of these statements.
F-93
<PAGE> 211
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998
NOTE 1 -- ORGANIZATION AND CONTROL
Neptune Pipeline Company, L.L.C. (Neptune) owns a 99% member interest in
Manta Ray Offshore Gathering Company, L.L.C. (Manta Ray) and Nautilus Pipeline
Company, L.L.C. (Nautilus). Neptune is owned as follows: Tejas Offshore
Pipeline, LLC (Tejas), an affiliate of Shell Oil Company owns a 49.9% member
interest; Shell Seahorse Company (Shell Seahorse), an affiliate of Shell Oil
Company owns a 0.1% member interest; Marathon Gas Transmission Inc. (Marathon)
owns a 24.33% member interest; Sailfish Pipeline Company, L.L.C. (Sailfish) owns
a 25.67% member interest.
Tejas acquired its 49.9% interest from Shell Seahorse on February 2, 1998.
Agreements between the member companies address the allocation of income
and capital contributions and distributions amongst the respective members'
capital accounts. As a result of these agreements, the ratio of members' equity
accounts per the Statement of Members' Capital differs from the members'
ownership interests in Neptune.
Neptune was formed to acquire, construct, own and operate through Manta Ray
and Nautilus, the Manta Ray System and the Nautilus System and any other natural
gas pipeline systems approved by the members. As of December 31, 1998 the Manta
Ray System and the Nautilus System are the only pipelines owned by Manta Ray and
Nautilus, respectively.
The formation of Manta Ray was accomplished through cash and fixed asset
contributions from the member companies. Fixed asset contributions, which
accounted for approximately 50% of all contributions, consisted of the Manta Ray
System and various compressor equipment (contributed by Sailfish) and the
Boxer-Bullwinkle System (contributed by Shell Seahorse). Because both cash and
fixed assets were contributed, the Manta Ray System and related compressor
equipment and the Boxer-Bullwinkle System were recorded at $64,342,716, which
represented their fair value on the date of contribution.
The Manta Ray System consists of a 169 mile gathering system located in the
South Timbalier and Ship Shoal areas of the Gulf of Mexico. An additional
segment, 47 miles of 24 inch pipeline and associated facilities, extending from
Green Canyon Block 65, offshore Louisiana, to Ship Shoal Block 207, offshore
Louisiana, was constructed during 1997 and first provided natural gas
transportation service on December 15, 1997. This newly constructed pipeline is
referred to as Phase II Facilities elsewhere in these notes.
The Nautilus System consists of a 30-inch natural gas pipeline and
appurtenant facilities extending approximately 101 miles from Ship Shoal Block
207, offshore Louisiana, to six delivery point interconnects near the outlet of
Exxon Company, U.S.A.'s Garden City Gas Processing Plant in St. Mary Parish,
Louisiana. The Nautilus System was constructed during 1997 and first provided
natural gas transportation service on December 15, 1997.
Neptune, Manta Ray and Nautilus (collectively referred to as the Companies)
have no employees and receive all administrative and operating support through
contractual arrangements with affiliated companies. These services and
agreements are outlined in Note 3, Related Party Transactions.
NOTE 2 -- SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Neptune and
its subsidiaries. All intercompany transactions and balances have been
eliminated in consolidation.
F-94
<PAGE> 212
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Regulation
Nautilus, as an interstate pipeline, is subject to regulation by the
Federal Energy Regulatory Commission (FERC). Nautilus has accounting policies
that conform to generally accepted accounting principles, as applied to
regulated enterprises and are in accordance with the accounting requirements and
ratemaking practices of the FERC.
Cash and Cash Equivalents
All highly liquid investments with a maturity of three months or less when
purchased are considered to be cash equivalents.
Pipelines and Equipment
Newly constructed pipelines are recorded at historical cost. Regulated
pipelines and equipment includes an Allowance for Funds Used During Construction
(AFUDC). The rates used in the calculation of AFUDC are determined in accordance
with guidelines established by FERC. The Manta Ray pipeline and related
facilities are depreciated on a straight-line basis over their estimated useful
life of 30 years, while the Nautilus pipeline and related facilities are
depreciated on a straight line basis over their estimated useful life of 20
years. Maintenance and repair costs are expensed as incurred while additions,
improvements and replacements are capitalized.
Income Taxes
Neptune is treated as a tax partnership under the provisions of the
Internal Revenue Code. Accordingly, the accompanying financial statements do not
reflect a provision for income taxes since Neptune's results of operations and
related credits and deductions will be passed through to and taken into account
by its partners in computing their respective tax liabilities.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standard (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
requires recognition of impairment losses on long-lived assets if the carrying
amount of such assets, grouped at the lowest level for which there are
identifiable cash flows that are largely independent of the cash flows from
other assets, exceeds the estimated undiscounted future cash flows of such
assets. Measurement of any impairment loss is based on the fair value of the
asset. At December 31, 1998 and 1997, there were no impairments.
Revenue Recognition
Revenue from Manta Ray's and Nautilus' transportation of natural gas is
recognized upon receipt of natural gas into the pipeline systems.
In the course of providing transportation services to customers, Nautilus
and Manta Ray may receive different quantities of gas from shippers than the
quantities delivered on behalf of those shippers. These transactions result in
imbalances which are settled in cash on a monthly basis. In addition, certain
imbalances may occur with interconnecting facilities when the Companies deliver
more or less than what is nominated (scheduled). The settlement of these
imbalances is governed by Operational Balancing Agreements (OBA). Certain OBAs
stipulate that settlement will occur through delivery of physical quantities in
subsequent months. The Companies record the net of all imbalances as
Transportation Revenue or Other Revenue and carry the net position as a payable
or a receivable, as appropriate.
F-95
<PAGE> 213
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Fair Value of Financial Instruments
The reported amounts of financial instruments such as cash and cash
equivalents, receivables, and current liabilities approximate fair value because
of their maturities.
Use of Estimates and Significant Risks
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 certain assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the financial
statements and the related reported amounts of revenue and expenses during the
reporting period. Such estimates and assumptions include those made in areas of
FERC regulations, fair value of financial instruments, future cash flows
associated with assets, useful lives for depreciation and potential
environmental liabilities. Actual results could differ from those estimates.
Management believes that the estimates are reasonable.
Development and production of natural gas in the service area of the
pipelines are subject to, among other factors, prices for natural gas and
federal and state energy policy, none of which are within the Companies'
control.
Reclassification
Certain prior period amounts in the financial statements and notes thereto
have been reclassified to conform with the current year presentation.
NOTE 3 -- RELATED PARTY TRANSACTIONS
Construction Management Agreements
On January 17, 1997, Nautilus entered into a Construction Management
Agreement (the Agreement) with Marathon under which Marathon agreed to construct
the Nautilus System. As of December 31, 1998 and 1997 respectively, Nautilus had
incurred $113,127,385, and $113,041,314 of costs under the Agreement. Of these
amounts, $309,238 and $2,665,922 were recorded as liabilities to affiliates at
December 31, 1998 and 1997, respectively.
On January 17, 1997, Manta Ray entered into a Construction Management
Agreement with Shell Seahorse under which Shell Seahorse agreed to construct the
Phase II Facilities. Also on January 17, 1997, Manta Ray entered into a
Construction Management Agreement with Marathon under which Marathon agreed to
construct a slug catcher. On August 1, 1998, Manta Ray entered into a
Construction Management Agreement with Marathon under which Marathon agreed to
construct condensate stabilization facilities. As of December 31, 1998 and 1997,
Manta Ray had incurred $83,388,913 and $64,016,789, respectively, under these
agreements. Of these amounts, $4,236,507 and $7,875,533 were recorded as
liabilities to affiliates at December 31, 1998 and 1997, respectively.
Transportation Services
During 1998, $3,881,667 of transportation revenues for Nautilus were
derived from related parties. During 1997, Nautilus derived substantially all of
its transportation revenue from transportation services provided under
agreements with Shell Offshore Incorporated (SOI) and Marathon Oil Company, both
of which are affiliates of Nautilus. All transactions were at rates pursuant to
the existing tariff. At December 31, 1998 and 1997 respectively, Nautilus had
affiliate receivables of $596,090 and $0 relating to transportation and gas
imbalances. At December 31, 1998 and 1997, respectively, Nautilus had affiliate
payables of $230,730 and $0 relating to transportation and gas imbalances.
F-96
<PAGE> 214
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In 1998, $4,902,613 of transportation revenues on Manta Ray were derived
from related parties. During 1997, Manta Ray derived substantially all of its
transportation revenue from transportation services provided under agreements
with third parties. All transactions were at negotiated rates. At December 31,
1998 and 1997 respectively, Manta Ray had receivables of $1,857,320 and $639,208
relating to transportation and gas imbalances.
At December 31, 1998, Manta Ray also had a receivable from Sailfish of
$297,348 relating to accumulated transportation and gas balancing activity
associated with the assets contributed by Sailfish.
Leases
Effective December 1, 1997, Manta Ray, as lessor, and Nautilus, as lessee,
entered into a lease agreement for usage of offshore platform space located at
Ship Shoal Block 207. The term of the lease is for the life of the platform,
subject to certain early termination conditions, and requires minimum lease
payments of $225,000 per year adjusted annually for inflation. The associated
lease revenue and expense have been eliminated in consolidation.
Operating and Administrative Expense
Since the Companies have no employees, operating, maintenance and general
and administrative services are provided to the Companies under service
agreements with Manta Ray Gathering Company, L.L.C., Marathon, and Shell
Seahorse, all of which are affiliates of the Companies. Substantially all
operating and administrative expenses were incurred through services provided
under these agreements.
Other Affiliate Transactions
During 1997, Manta Ray and Nautilus had various transactions relating to
construction with member companies or affiliates which resulted in affiliate
receivables of $11,337,218 and affiliate payables of $22,237,782.
Also included in Owing from Related Parties at December 31, 1998 is a
receivable from an affiliate for $129,698 relating to the sale of land during
the fourth quarter of 1998 by Nautilus. No gain or loss was recognized on the
sale.
NOTE 4 -- PIPELINES AND EQUIPMENT
Pipelines and equipment at December 31, 1998 and 1997 is comprised of the
following (in thousands):
<TABLE>
<CAPTION>
1998 1997
-------- --------
<S> <C> <C>
Pipelines and equipment..................................... $244,835 $242,194
Land........................................................ 1,107 1,237
AFUDC....................................................... 6,430 6,430
Construction in progress.................................... 8,732 --
-------- --------
Subtotal.......................................... 261,104 249,861
Accumulated depreciation.................................... 12,204 2,056
-------- --------
Total............................................. $248,900 $247,805
======== ========
</TABLE>
At December 31, 1997, included in pipelines and equipment is an accrued
estimate of costs incurred to date of $3,022,000. Actual costs incurred during
1998 relating to this accrual totaled $1,855,000. Pipelines and Equipment and
Owing to Related Parties have been adjusted in 1998.
F-97
<PAGE> 215
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During 1998, Nautilus entered into interconnection agreements with certain
other parties in which Nautilus agreed to construct interconnection facilities
whereby the parties agreed to contribute $619,000 as partial reimbursement for
construction costs. Nautilus was reimbursed $419,000 during 1998 and the
remaining balance will be paid monthly based on throughput. The receivable
balance at December 31, 1998 was $200,000, the current portion of which is
$40,000.
NOTE 5 -- REGULATORY MATTERS
The FERC has jurisdiction over the Nautilus System with respect to
transportation of gas, rates and charges, construction of new facilities,
extension or abandonment of service facilities, accounts and records,
depreciation and amortization policies and certain other matters.
NOTE 6 -- COMMITMENTS AND CONTINGENCIES
In the ordinary course of business, the Companies are subject to various
laws and regulations. In the opinion of management, compliance with existing
laws and regulations will not materially affect the financial position, the
results of operations or cash flows of the Companies.
Various legal actions, which have arisen in the ordinary course of
business, are pending with respect to the assets of the Companies. Management
believes that the ultimate disposition of these actions, either individually or
in aggregate, will not have a material adverse effect on the financial position,
the results of operations or the cash flows of the Companies.
Pursuant to the terms of a construction agreement entered into in 1995,
Manta Ray agreed to pay liquidated damages to various parties if Manta Ray did
not complete an interconnect by May 31, 1998 between the Manta Ray System and
the system operated by Trunkline Gas Pipeline Company. Under the provision,
Manta Ray incurred $150,000 in 1998, which is recorded in Other Expense. Manta
Ray will be obligated to pay an additional $100,000 if the interconnect is not
completed by May 31, 1999 and $50,000 if the interconnect is not completed by
May 31, 2000.
F-98
<PAGE> 216
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholder of
Leviathan Gas Pipeline Company
In our opinion, the accompanying balance sheet presents fairly, in all
material respects, the financial position of Leviathan Gas Pipeline Company at
December 31, 1998 in conformity with generally accepted accounting principles.
This financial statement is the responsibility of the Company's management; our
responsibility is to express an opinion on this financial statement based on our
audit. We conducted our audit of this statement in accordance with generally
accepted auditing standards, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statement is free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statement, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
June 2, 1999
F-99
<PAGE> 217
LEVIATHAN GAS PIPELINE COMPANY
(AN INDIRECT SUBSIDIARY OF EL PASO ENERGY CORPORATION)
BALANCE SHEET
DECEMBER 31, 1998
(In thousands, except share data)
<TABLE>
<S> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 6,409
Accounts receivable from the Partnership (Note 5)......... 406
Other..................................................... 22
-------
Total current assets.............................. 6,837
Equity investment......................................... 18,362
-------
Total assets...................................... $25,199
=======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Payable to parent......................................... $ 652
Intercompany taxes payable (Note 4)....................... 693
-------
Total current liabilities......................... 1,345
Deferred tax liability (Note 4)............................. 23,154
-------
Total liabilities................................. 24,499
-------
Commitments and contingencies
Stockholder's equity:
Common stock, $0.10 par value, 1,000 shares authorized,
issued and outstanding................................. 1
Additional paid-in capital................................ 100
Accumulated earnings...................................... 599
-------
700
-------
Total liabilities and stockholder's equity........ $25,199
=======
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-100
<PAGE> 218
LEVIATHAN GAS PIPELINE COMPANY
(AN INDIRECT SUBSIDIARY OF EL PASO ENERGY CORPORATION)
NOTES TO BALANCE SHEET
NOTE 1 -- ORGANIZATION:
Leviathan Gas Pipeline Company ("Leviathan"), a Delaware corporation and
indirect wholly-owned subsidiary of El Paso Energy Corporation ("El Paso
Energy"), was formed in 1989 to purchase, operate and expand offshore natural
gas pipeline systems. El Paso Energy is a diversified energy holding company,
engaged, through it subsidiaries, in the interstate and intrastate
transportation, gathering and processing of natural gas; the marketing of
natural gas, power and other energy-related commodities; power generation; and
the development and operation of energy infrastructure facilities worldwide.
In 1993, Leviathan contributed substantially all of its natural gas
pipeline operations, certain other assets and liabilities and related
acquisition debt to Leviathan Gas Pipeline Partners, L.P. and its subsidiaries
(collectively referred to as the "Partnership"), a publicly held Delaware master
limited partnership, in exchange for an effective 35.8% interest in the
Partnership. Leviathan's effective ownership interest in the Partnership was
reduced to 27.3% as a result of an additional public offering by the Partnership
in June 1994. The Partnership is primarily engaged in the gathering,
transportation and production of oil and natural gas in the Gulf of Mexico and
through its subsidiaries and joint ventures, owns interests in significant
assets, including (i) eight existing natural gas pipelines, (ii) a crude oil
pipeline system, (iii) six strategically-located multi-purpose platforms, (iv)
production handling and dehydration facilities, (v) four producing oil and
natural gas properties and (vi) a non-producing oil and natural gas property.
Leviathan, as general partner, performs all management and operating functions
of the Partnership. In August 1998, El Paso Energy paid approximately $422
million to acquire its interest in Leviathan through a merger with DeepTech
International Inc. ("DeepTech"), Leviathan's parent.
At December 31, 1998, Preference Units and Common Units totaling 18,075,000
were owned by the public, representing a 72.7% effective limited partner
interest in the Partnership. Leviathan, through its ownership of a 25.3% limited
partner interest in the form of 6,291,894 Common Units, its 1% general partner
interest in the Partnership and its approximate 1% nonmanaging interest in
certain subsidiaries of the Partnership, owned a 27.3% effective interest in the
Partnership as of December 31, 1998.
NOTE 2 -- SIGNIFICANT ACCOUNTING POLICIES:
Income taxes
Income taxes are based on income reported for tax return purposes along
with a provision for deferred income taxes. Deferred income taxes are provided
to reflect the tax consequences in future years of differences between the
financial statement and tax bases of assets and liabilities at each year-end.
Tax credits are accounted for under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
Deferred tax assets are reduced by a valuation allowance when, based upon
management's estimates, it is more likely than not that a portion of the
deferred tax assets will not be realized in the future period. The estimates
utilized in the recognition of deferred tax assets are subject to revision in
future periods based on new facts or circumstances.
After August 14, 1998, as a result of El Paso Energy's acquisition of
DeepTech, Leviathan's results are included in the consolidated federal income
tax return of El Paso Energy. On behalf of itself and all members filing in its
consolidated federal income tax return, including Leviathan, El Paso Energy
adopted a tax sharing policy (the "Policy") which provides, among other things,
that (i) each company in a taxable income position will be currently charged
with an amount equivalent to its federal income tax computed on a separate
return basis and (ii) each company in a tax loss position will be reimbursed
currently to the extent its deductions, including general business credits, were
utilized in the consolidated tax return. Under the Policy, El Paso Energy will
pay all federal income taxes directly to the IRS and will bill or refund, as
applicable, its subsidiaries for their applicable portion of such income tax
payments.
F-101
<PAGE> 219
LEVIATHAN GAS PIPELINE COMPANY
(AN INDIRECT SUBSIDIARY OF EL PASO ENERGY CORPORATION)
NOTES TO BALANCE SHEET -- (CONTINUED)
Estimates
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 certain assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the financial
statements and the related reported amounts of revenue and expenses during the
reporting period. Actual results could differ from those estimates. Management
believes that the estimates used are reasonable.
Recent Pronouncements
Effective July 1, 1998, Leviathan adopted Statement of Financial Accounting
Standard ("SFAS") No. 129, "Disclosure of Information About Capital Structure"
which establishes standards for disclosing information about an entity's capital
structure previously not required by nonpublic entities. The adoption of this
pronouncement did not have a material impact on Leviathan's financial position
or results of operations.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities". SFAS No. 133
requires that entities recognize all derivative investments as either assets or
liabilities on the balance sheet and measure those instruments at fair value.
Changes in the fair value of derivatives are recorded each period in current
earnings or other comprehensive income, depending on whether a derivative is
designated as part of a hedge transaction. For fair-value hedge transactions in
which Leviathan is hedging changes in an asset's, liability's or firm
commitment's fair value, changes in the fair value of the derivative instrument
will generally be offset in the income statement by changes in the hedged item's
fair value. For cash-flow hedge transactions, in which Leviathan is hedging the
variability of cash flows related to a variable-rate asset, liability, or a
forecasted transaction, changes in the fair value of the derivative instrument
will be reported in other comprehensive income. The gains and losses on the
derivative instrument that are reported in other comprehensive income will be
reclassified as earnings in the periods in which earnings are impacted by the
variability of the cash flows of the hedged item. The ineffective portion of all
hedges will be recognized in current-period earnings. This statement was amended
to be effective for fiscal years beginning after June 15, 2000. Leviathan has
not yet determined the impact that the adoption of SFAS No. 133 will have on its
financial position or results of operations.
NOTE 3 -- EQUITY INVESTMENT:
Leviathan uses the equity method to account for its investment in the
Partnership. Additional income is allocated by the Partnership to Leviathan as a
result of the Partnership achieving certain target levels of cash distributions
to its unitholders. See discussion of incentive distributions below. The
summarized financial information for Leviathan's investment in the Partnership
is as follows:
LEVIATHAN GAS PIPELINE PARTNERS, L.P.
SUMMARIZED BALANCE SHEET
DECEMBER 31, 1998
(IN THOUSANDS)
<TABLE>
<S> <C>
Current assets.............................................. $ 11,943
Noncurrent assets........................................... 430,783
Current liabilities......................................... 11,167
Notes payable............................................... 338,000
Other noncurrent liabilities................................ 10,724
</TABLE>
F-102
<PAGE> 220
LEVIATHAN GAS PIPELINE COMPANY
(AN INDIRECT SUBSIDIARY OF EL PASO ENERGY CORPORATION)
NOTES TO BALANCE SHEET -- (CONTINUED)
The Partnership distributes 100% of available cash, as defined in the
Partnership Agreement, on a quarterly basis to the unitholders of the
Partnership and to Leviathan, as general partner. During the Preference Period
(as defined in the Partnership Agreement), these distributions were effectively
made 98% to unitholders and 2% to Leviathan, subject to the payment of incentive
distributions to Leviathan if certain target levels of cash distributions to
unitholders are achieved. As an incentive, the general partner's interest in the
portion of quarterly cash distributions in excess of $0.325 per unit and less
than or equal to $0.375 per unit is increased to 15%. For quarterly cash
distributions over $0.375 per unit but less than or equal to $0.425 per unit,
the general partner receives 25% of such incremental amount and for all
quarterly cash distributions in excess of $0.425 per unit, the general partner
receives 50% of the incremental amount.
NOTE 4 -- INCOME TAXES:
After August 14, 1998, Leviathan is included in the consolidated federal
income tax return filed by El Paso Energy. The Policy provides for the manner of
determining payments with respect to federal income tax liabilities (Note 2).
Deferred federal income taxes are primarily attributable to the differences
in depreciation rates and in the timing of recognizing income from the
Partnership for financial and tax reporting purposes.
Leviathan's deferred income tax liabilities (assets) at December 31, 1998
consisted of the following (in thousands):
<TABLE>
<S> <C>
Deferred tax liabilities:
Investment in the Partnership............................. $23,141
Other..................................................... 13
-------
Total deferred tax liability...................... 23,154
-------
Deferred tax assets:
Net operating loss ("NOL") carryforwards.................. (153)
Alternative minimum tax ("AMT") credit carryforward....... (1,719)
Valuation allowance....................................... 1,872
-------
Total deferred tax assets......................... --
-------
Net deferred tax liability.................................. $23,154
=======
</TABLE>
As of December 31, 1998, approximately $1,719,000 of AMT credit
carryforwards, which have no expiration date, were available to offset future
regular tax liabilities. Additionally, as of December 31, 1998, approximately
$438,000 of NOL carryforwards, which expire in 2017, were available to offset
future tax liabilities.
Leviathan has recorded a valuation allowance (i) to reflect the estimated
amount of deferred tax assets that may not be realized due to the expiration of
NOL carryforwards and (ii) to reflect the uncertainty that the AMT credit
carryforwards will be utilized. Leviathan's NOL and AMT credit carryforwards are
subject to separate return limitation year restrictions.
Current amounts due to El Paso Energy for the intercompany charge for
federal income taxes totaled $693,000 as of December 31, 1998.
NOTE 5 -- RELATED PARTY TRANSACTIONS:
Leviathan, as general partner of the Partnership, is entitled to
reimbursement of all reasonable expenses incurred by it or its affiliates for or
on behalf of the Partnership including amounts payable by
F-103
<PAGE> 221
LEVIATHAN GAS PIPELINE COMPANY
(AN INDIRECT SUBSIDIARY OF EL PASO ENERGY CORPORATION)
NOTES TO BALANCE SHEET -- (CONTINUED)
Leviathan to El Paso Energy under a management agreement whereby El Paso Energy
provides operational, financial, accounting and administrative services to
Leviathan. The management agreement is intended to reimburse El Paso Energy for
the estimated costs of its services provided to Leviathan and the Partnership.
In addition, the management agreement also requires a payment by Leviathan
to compensate El Paso Energy for certain tax liabilities resulting from, among
other things, additional taxable income allocated to Leviathan due to (i) the
issuance of additional Preference Units (including the sale of the Preference
Units by the Partnership pursuant to the public offering of additional
Preference Units) and (ii) the investment of such proceeds in additional
acquisitions or construction projects. The management agreement expires on June
30, 2002, and may thereafter be terminated on 90 days' notice by either party.
NOTE 6 -- COMMITMENTS AND CONTINGENCIES:
In the ordinary course of business, Leviathan is subject to various laws
and regulations. In the opinion of management, compliance with existing laws and
regulations will not materially effect the financial position of Leviathan.
Various legal actions which have arisen in the ordinary course of business are
pending with respect to the assets of Leviathan. Management believes that the
ultimate disposition of these actions, either individually or in the aggregate,
will not have a material adverse effect on Leviathan's financial position.
F-104
<PAGE> 222
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
4,000,000 COMMON UNITS
LEVIATHAN GAS PIPELINE
PARTNERS, L.P.
REPRESENTING LIMITED PARTNER INTERESTS
------------
PROSPECTUS
, 1999
------------
SALOMON SMITH BARNEY
GOLDMAN, SACHS & CO.
PAINEWEBBER INCORPORATED
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
FIRST UNION CAPITAL MARKETS CORP.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 223
PART II.
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The following sets forth the estimated expenses and costs expected to be
incurred in connection with the issuance and distribution of the securities
registered hereby. All of such costs will be borne by the Partnership.
<TABLE>
<S> <C>
Securities and Exchange Commission registration fee......... $
Printing.................................................... **
Legal fees and expenses..................................... **
Accounting fees and expenses................................ **
Miscellaneous............................................... **
--------
Total $ **
========
</TABLE>
** To be filed by amendment.
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS
The section of the Prospectus entitled "Certain Other Partnership Agreement
Provisions -- Indemnification" is incorporated herein by reference. Reference is
made to Section 8 of the Underwriting Agreement filed as Exhibit 1.1 to the
Registration Statement. Subject to any terms, conditions or restrictions set
forth in the Partnership Agreement, Section 17-108 of the Delaware Revised
Uniform Limited Partnership Act empowers a Delaware limited partnership to
indemnify and hold harmless any partner or other person from and against all
claims and demands whatsoever.
Section 145(a) of the General Corporation Law of the State of Delaware (the
"DGCL") provides that a Delaware corporation may indemnify any person who was or
is a party or is threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal, administrative or
investigative (other than an action by or in the right of the corporation) by
reason of the fact that he is or was a director, officer, employee or agent of
the corporation or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation, partnership, joint
venture, trust or other enterprise, against expenses, judgments, fines and
amounts paid in settlement actually and reasonably incurred by him in connection
with such action, suit or proceeding if he acted in good faith and in a manner
he reasonably believed to be in or not opposed to the best interests of the
corporation, and, with respect to any criminal action or proceeding, had no
cause to believe his conduct was unlawful.
Section 145(b) of the DGCL provides that a Delaware corporation may
indemnify any person who was or is a party or is threatened to be made a party
to any threatened, pending or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the fact that such
person acted in any of the capacities set forth above, against expenses actually
and reasonably incurred by him in connection with the defense or settlement of
such action or suit if he acted under similar standards, except that no
indemnification may be made in respect of any claim, issue or matter as to which
such person shall have been adjudged to be liable to the corporation unless and
only to the extent that the court in which such action or suit was brought shall
determine that despite the adjudication of liability, such person is fairly and
reasonably entitled to be indemnified for such expenses which the court shall
deem proper.
Section 145 of the DGCL further provides that to the extent a director or
officer of a corporation has been successful in the defense of any action, suit
or proceeding referred to in subsections (a) and (b) or in the defense of any
claim, issue, or matter therein, he shall be indemnified against any expenses
actually and reasonably incurred by him in connection therewith; that
indemnification provided for by Section 145 shall not be deemed exclusive of any
other rights to which the indemnified party may be entitled; and that
II-1
<PAGE> 224
the corporation may purchase and maintain insurance on behalf of a director,
officer, employee or agent of the corporation against any liability asserted
against him or incurred by him in any such capacity or arising out of his status
as such whether or not the corporation would have the power to indemnify him
against such liabilities under Section 145.
Section 102(b)(7) of the DGCL provides that a corporation in its original
certificate of incorporation or an amendment thereto validly approved by
stockholders may eliminate or limit personal liability of members of its board
of directors or governing body for breach of a director's fiduciary duty.
However, no such provision may eliminate or limit the liability of a director
for breaching his duty of loyalty, failing to act on good faith, engaging in
intentional misconduct or knowingly violating a law, paying a dividend or
approving a stock repurchase which was illegal or obtaining an improper personal
benefit. A provision of this type has no effect on the availability of equitable
remedies, such as injunction or rescission, for breach of fiduciary duty.
The Certificate of Incorporation of the general partner contains a
provision which limits the liability of the directors of the general partner to
the general partner or its stockholder (in their capacity as directors but not
in their capacity as officers) to the fullest extent permitted by the DGCL. In
addition, the Amended and Restated Bylaws of the general partner (as amended and
restated, the "Bylaws"), in substance, require the general partner to indemnify
each person who is or was a director, officer, employee or agent of the general
partner to the full extent permitted by the laws of the State of Delaware in the
event such person is involved in legal proceedings by reason of the fact that he
is or was a director, officer, employee or agent of the general partner, or is
or was serving at the general partner's request as a director, officer, employee
or agent of the general partner and its subsidiaries, another corporation,
partnership or other enterprise. The general partner is also required to advance
to such persons payments incurred in defending a proceeding to which
indemnification might apply, provided the recipient provides an undertaking
agreeing to repay all such advanced amounts if it is ultimately determined that
he is not entitled to be indemnified. In addition, the Bylaws specifically
provide that the indemnification rights granted thereunder are non-exclusive.
The general partner has entered into indemnification agreements with
certain of its current and past directors providing for indemnification to the
full extent permitted by the laws of the State of Delaware. These agreements
provide for specific procedures to assure the directors' rights to
indemnification, including procedures for directors to submit claims, for
determination of directors' entitlement to indemnification (including the
allocation of the burden of proof and selection of a reviewing party) and for
enforcement of directors' indemnification rights.
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers or persons controlling Leviathan or the
general partner pursuant to the foregoing, Leviathan and the general partner
have been informed that in the opinion of the SEC such indemnification is
against public policy as expressed in the Securities Act and is therefore
unenforceable.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES
During the past three years, we have issued and sold the unregistered
securities described below.
1. On June 1, 1999, we issued 2,661,870 common units, valued at $59.8
million or $22.46 per unit, to EPEC Deepwater Gathering Company in exchange for
a 49% partnership interest in Viosca Knoll Gathering Company, as such
transaction is more particularly described in this registration statement. We
issued these securities in an exempt transaction in reliance on Section 4(2) of
the Securities Act of 1933.
2. On May 27, 1999, we issued senior subordinated notes, guaranteed by our
subsidiaries, to Donaldson, Lufkin & Jenrette Securities Corporation and Chase
Securities Inc. for $175.0 million in cash. We issued these securities in an
exempt transaction in reliance on Section 4(2) of the Securities Act of 1933.
II-2
<PAGE> 225
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following is a list of exhibits filed as part of this Registration
Statement. Where so indicated by footnote, exhibits which were previously filed
are incorporated by reference.
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<C> <S>
1.1** Underwriting Agreement dated , 1999 among
Leviathan Gas Pipeline Partners, L.P., Salomon Smith Barney
Inc., Goldman, Sachs & Co., PaineWebber Incorporated, Dain
Rauscher Wessels, a division of Dain Rauscher Incorporated,
and First Union Capital Markets Corp.
3.1 Certificate of Limited Partnership of Leviathan (filed as
Exhibit 3.1 to Leviathan's Registration Statement on Form
S-1, File No. 33-55642).
3.2 Amended and Restated Agreement of Limited Partnership of
Leviathan (filed as Exhibit 10.41 to Amendment No. 1 to
DeepTech's Registration Statement on Form S-1, File No.
33-73538).
3.3 Amendment Number 1 to the Amended and Restated Agreement of
Limited Partnership of Leviathan (filed as Exhibit 10.1 to
Leviathan's Current Report on Form 8-K dated December 31,
1996, File No. 1-11680).
3.4 Amendment Number 2 to the Amended and Restated Agreement of
Limited Partnership of Leviathan (filed as Exhibit 3.4 to
Leviathan's Registration Statement on Form S-4, File No.
333-81143).
3.5 Certificate of Incorporation of Leviathan Finance
Corporation (filed as Exhibit 3.5 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
3.6 Bylaws of Leviathan Finance Corporation (filed as Exhibit
3.6 to Leviathan's Registration Statement on Form S-4, File
No. 333-81143).
4.1 Indenture dated as of May 27, 1999 among Leviathan Gas
Pipeline Partners, L.P., Leviathan Finance Corporation, the
Subsidiary Guarantors and Chase Bank of Texas, as Trustee
(filed as Exhibit 4.1 to Leviathan's Registration Statement
on Form S-4, File No. 333-81143).
4.2 First Supplemental Indenture dated as of June 30, 1999
(filed as Exhibit 4.2 to Leviathan's Registration Statement
on Form S-4, File No. 333-81143).
4.3 Second Supplemental Indenture dated as of July 27, 1999
(filed as Exhibit 4.3 to Leviathan's Registration Statement
on Form S-4, File No. 333-81143).
4.4 Form of Certificate of 10 3/8% Series A Senior Subordinated
Note due 2009 (included in Exhibit 4.1 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
4.5 Form of Certificate of 10 3/8% Series B Senior Subordinated
Note due 2009 (included in Exhibit 4.1 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
4.6 Form of Guarantee Notation of securities issued pursuant to
the Indenture (included in Exhibit 4.1 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
4.7 A/B Exchange Registration Rights Agreement dated as of May
27, 1999 among Leviathan Gas Pipeline Partners, L.P.,
Leviathan Finance Corporation, the Subsidiary Guarantors,
Donaldson, Lufkin & Jenrette Securities Corporation, and
Chase Securities Inc. (filed as Exhibit 4.7 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143)
5.1** Opinion of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
</TABLE>
II-3
<PAGE> 226
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<C> <S>
10.1 First Amended and Restated Management Agreement, dated June
27, 1994 and effective as of July 1, 1992, between DeepTech
International Inc. ("DeepTech") and the General Partner
(filed as Exhibit 10.1 to DeepTech's Annual Report on Form
10-K for 1994, File No. 0-23934).
10.2 First Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.76 to DeepTech's Registration Statement on Form
S-1, File No. 33-88688).
10.3 Second Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.18 to Leviathan's Annual Report on Form 10-K for
the fiscal year ended December 31, 1995, File No. 1-11680).
10.4 Third Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.4 to Leviathan's Registration Statement on Form
S-4, File No. 333-81143).
10.5 Fourth Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.1 to Leviathan's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 1997, File No.
1-11680).
10.6 Fifth Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.1 to Leviathan's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 1997, File No.
1-11680).
10.7 Sixth Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.2 to Leviathan's Annual Report on Form 10-K for
the fiscal year ended December 31, 1998, File No. 1-11680).
10.8 Redemption Agreement dated February 27, 1998 between Tatham
Offshore, Inc. and Flextrend Development Company, L.L.C., a
subsidiary of Leviathan (filed as Exhibit 10.1 to
Leviathan's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1998, File No. 1-11680).
10.9 Contribution Agreement between Leviathan and El Paso Field
Services Company (filed as Exhibit C to Leviathan's Schedule
14A (Rule 14A-101) Proxy Statement effective February 9,
1998).
10.10 Leviathan 1998 Unit Option Plan for Non-Employee Directors
Effective as of August 14, 1998 (filed as Exhibit 10.2 to
Leviathan's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1998, File No. 1-11680).
10.11 Leviathan Unit Rights Appreciation Plan (filed as Exhibit
10.25 to Leviathan's Annual Report on Form 10-K for the
fiscal year ended December 31, 1996, File No. 1-11680).
10.12 Leviathan 1998 Omnibus Compensation Plan, Amended and
Restated, Effective as of January 1, 1999 (filed as Exhibit
10.9 to Leviathan's Annual Report on Form 10-K for the
fiscal year ended December 31, 1998, File No. 1-11680).
10.13 Purchase and Sale Agreement between Natural Gas Pipeline
Company of America as Seller and Leviathan as Buyer dated as
of June 30, 1999 (filed as Exhibit 10.1 to Leviathan's
Current Report on Form 8-K dated July 15, 1999, File No.
1-11680).
10.14 Third Amended and Restated Credit Agreement dated as of
March 23, 1995, as amended and restated through May 27, 1999
among Leviathan, Leviathan Finance Corporation, The Chase
Manhattan Bank, as administrative agent, Credit Lyonnais, as
syndication agent, BankBoston, N.A., as documentation agent,
and the banks and other financial institutions from time to
time parties thereto (filed as Exhibit 10.14 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
</TABLE>
II-4
<PAGE> 227
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<C> <S>
12.1* Statement Regarding Computation of Ratios.
21.1* List of Subsidiaries of Leviathan Gas Pipeline Partners,
L.P.
23.1* Consent of PricewaterhouseCoopers LLP.
23.2* Consent of Deloitte & Touche LLP.
23.3* Consent of Arthur Andersen LLP.
23.4* Consent of Netherland, Sewell & Associates, Inc.
23.5** Consent of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
(included in Exhibit 5.1 hereto).
24.1* Power of Attorney (included on the signature pages of this
Registration Statement on Form S-3).
</TABLE>
- ---------------
* Filed as an exhibit to this Registration Statement
** To be filed by amendment to this Registration Statement
ITEM 17. UNDERTAKINGS
(b) The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
(h) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
Leviathan and the general partner pursuant to the foregoing provisions, or
otherwise, Leviathan has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as expressed
in the Act and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by Leviathan of
expenses incurred or paid by a director, officer or controlling person of
Leviathan in the successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in connection with the
securities being registered, Leviathan will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a court
of appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the final
adjudication of such issue.
(i) Leviathan hereby undertakes that:
(1) for purposes of determining any liability under the Act, the
information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A and contained in a form
of prospectus filed by Leviathan pursuant to Rule 424(b)(1) or (4) or
497(h) under the Act shall be deemed to be part of this registration
statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Act, each
post-effective amendment that contains a form of prospectus shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof.
II-5
<PAGE> 228
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Houston,
State of Texas, on August 26, 1999.
LEVIATHAN GAS PIPELINE PARTNERS, L.P.
By: Leviathan Gas Pipeline Company,
its general partner
By: /s/ GRANT E. SIMS
----------------------------------
Name: Grant E. Sims
Title: Chief Executive Officer
---------------------
<PAGE> 229
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS, that the persons whose signatures
appear below, constitute and appoint H. Brent Austin and Britton White, Jr., and
each of them as their true and lawful attorneys-in-fact and agents, with full
power of substitution and resubstitution, for them and in their names, places
and steads, in any and all capacities, to sign the Registration Statement to be
filed in connection with the public offering of limited partnership interest of
Leviathan Gas Pipeline Partners, L.P. and any and all amendments (including
post-effective amendments) to the Registration Statement, and any subsequent
registration statement filed pursuant to Rule 462(b) under the Securities Act of
1933, as amended, and to file the same, with all exhibits thereto, and the other
documents in connection therewith, with the Securities and Exchange Commission,
granting unto said attorneys-in-fact and agents, and each of them, full power
and authority to do and perform each and every act and thing requisite and
necessary to be done in connection therewith, as fully to all intents and
purposes as they might or could do in person, hereby ratifying and confirming
all that said attorneys-in-fact and agents, or any of them, or their or his or
her substitute or substitutes, may lawfully do or cause to be done by virtue
hereof.
---------------------
Pursuant to the requirements of the Securities Act of 1933, as amended,
this Registration Statement has been signed below by the following persons in
the capacities and on the dates indicated below:
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ WILLIAM A. WISE Chairman of the Board and August 26, 1999
- ----------------------------------------------------- Director
William A. Wise
/s/ GRANT E. SIMS Chief Executive Officer and August 26, 1999
- ----------------------------------------------------- Director
Grant E. Sims
/s/ KEITH B. FORMAN Chief Financial Officer and August 26, 1999
- ----------------------------------------------------- Vice President
Keith B. Forman
/s/ JAMES H. LYTAL President and Director August 26, 1999
- -----------------------------------------------------
James H. Lytal
/s/ D. MARK LELAND Vice President and Controller August 26, 1999
- ----------------------------------------------------- (Chief Accounting Officer)
D. Mark Leland
/s/ H. BRENT AUSTIN Executive Vice President and August 26, 1999
- ----------------------------------------------------- Director
H. Brent Austin
/s/ ROBERT G. PHILLIPS Executive Vice President and August 26, 1999
- ----------------------------------------------------- Director
Robert G. Phillips
/s/ MICHAEL B. BRACY Director August 26, 1999
- -----------------------------------------------------
Michael B. Bracy
/s/ H. DOUGLAS CHURCH Director August 26, 1999
- -----------------------------------------------------
H. Douglas Church
/s/ MALCOLM WALLOP Director August 26, 1999
- -----------------------------------------------------
Malcolm Wallop
</TABLE>
<PAGE> 230
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<C> <S>
1.1** Underwriting Agreement dated , 1999 among
Leviathan Gas Pipeline Partners, L.P., Salomon Smith Barney
Inc., Goldman, Sachs & Co., PaineWebber Incorporated, Dain
Rauscher Wessels, a division of Dain Rauscher Incorporated,
and First Union Capital Markets Corp.
3.1 Certificate of Limited Partnership of Leviathan (filed as
Exhibit 3.1 to Leviathan's Registration Statement on Form
S-1, File No. 33-55642).
3.2 Amended and Restated Agreement of Limited Partnership of
Leviathan (filed as Exhibit 10.41 to Amendment No. 1 to
DeepTech's Registration Statement on Form S-1, File No.
33-73538).
3.3 Amendment Number 1 to the Amended and Restated Agreement of
Limited Partnership of Leviathan (filed as Exhibit 10.1 to
Leviathan's Current Report on Form 8-K dated December 31,
1996, File No. 1-11680).
3.4 Amendment Number 2 to the Amended and Restated Agreement of
Limited Partnership of Leviathan (filed as Exhibit 3.4 to
Leviathan's Registration Statement on Form S-4, File No.
333-81143).
3.5 Certificate of Incorporation of Leviathan Finance
Corporation (filed as Exhibit 3.5 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
3.6 Bylaws of Leviathan Finance Corporation (filed as Exhibit
3.6 to Leviathan's Registration Statement on Form S-4, File
No. 333-81143).
4.1 Indenture dated as of May 27, 1999 among Leviathan Gas
Pipeline Partners, L.P., Leviathan Finance Corporation, the
Subsidiary Guarantors and Chase Bank of Texas, as Trustee
(filed as Exhibit 4.1 to Leviathan's Registration Statement
on Form S-4, File No. 333-81143).
4.2 First Supplemental Indenture dated as of June 30, 1999
(filed as Exhibit 4.2 to Leviathan's Registration Statement
on Form S-4, File No. 333-81143).
4.3 Second Supplemental Indenture dated as of July 27, 1999
(filed as Exhibit 4.3 to Leviathan's Registration Statement
on Form S-4, File No. 333-81143).
4.4 Form of Certificate of 10 3/8% Series A Senior Subordinated
Note due 2009 (included in Exhibit 4.1 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
4.5 Form of Certificate of 10 3/8% Series B Senior Subordinated
Note due 2009 (included in Exhibit 4.1 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
4.6 Form of Guarantee Notation of securities issued pursuant to
the Indenture (included in Exhibit 4.1 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
4.7 A/B Exchange Registration Rights Agreement dated as of May
27, 1999 among Leviathan Gas Pipeline Partners, L.P.,
Leviathan Finance Corporation, the Subsidiary Guarantors,
Donaldson, Lufkin & Jenrette Securities Corporation, and
Chase Securities Inc. (filed as Exhibit 4.7 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143)
5.1** Opinion of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
10.1 First Amended and Restated Management Agreement, dated June
27, 1994 and effective as of July 1, 1992, between DeepTech
International Inc. ("DeepTech") and the General Partner
(filed as Exhibit 10.1 to DeepTech's Annual Report on Form
10-K for 1994, File No. 0-23934).
</TABLE>
<PAGE> 231
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<C> <S>
10.2 First Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.76 to DeepTech's Registration Statement on Form
S-1, File No. 33-88688).
10.3 Second Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.18 to Leviathan's Annual Report on Form 10-K for
the fiscal year ended December 31, 1995, File No. 1-11680).
10.4 Third Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.4 to Leviathan's Registration Statement on Form
S-4, File No. 333-81143).
10.5 Fourth Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.1 to Leviathan's Quarterly Report on Form 10-Q
for the quarterly period ended June 30, 1997, File No.
1-11680).
10.6 Fifth Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.1 to Leviathan's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 1997, File No.
1-11680).
10.7 Sixth Amendment to First Amended and Restated Management
Agreement between DeepTech and the General Partner (filed as
Exhibit 10.2 to Leviathan's Annual Report on Form 10-K for
the fiscal year ended December 31, 1998, File No. 1-11680).
10.8 Redemption Agreement dated February 27, 1998 between Tatham
Offshore, Inc. and Flextrend Development Company, L.L.C., a
subsidiary of Leviathan (filed as Exhibit 10.1 to
Leviathan's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1998, File No. 1-11680).
10.9 Contribution Agreement between Leviathan and El Paso Field
Services Company (filed as Exhibit C to Leviathan's Schedule
14A (Rule 14A-101) Proxy Statement effective February 9,
1998).
10.10 Leviathan 1998 Unit Option Plan for Non-Employee Directors
Effective as of August 14, 1998 (filed as Exhibit 10.2 to
Leviathan's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1998, File No. 1-11680).
10.11 Leviathan Unit Rights Appreciation Plan (filed as Exhibit
10.25 to Leviathan's Annual Report on Form 10-K for the
fiscal year ended December 31, 1996, File No. 1-11680).
10.12 Leviathan 1998 Omnibus Compensation Plan, Amended and
Restated, Effective as of January 1, 1999 (filed as Exhibit
10.9 to Leviathan's Annual Report on Form 10-K for the
fiscal year ended December 31, 1998, File No. 1-11680).
10.13 Purchase and Sale Agreement between Natural Gas Pipeline
Company of America as Seller and Leviathan as Buyer dated as
of June 30, 1999 (filed as Exhibit 10.1 to Leviathan's
Current Report on Form 8-K dated July 15, 1999, File No.
1-11680).
10.14 Third Amended and Restated Credit Agreement dated as of
March 23, 1995, as amended and restated through May 27, 1999
among Leviathan, Leviathan Finance Corporation, The Chase
Manhattan Bank, as administrative agent, Credit Lyonnais, as
syndication agent, BankBoston, N.A., as documentation agent,
and the banks and other financial institutions from time to
time parties thereto (filed as Exhibit 10.14 to Leviathan's
Registration Statement on Form S-4, File No. 333-81143).
12.1* Statement Regarding Computation of Ratios.
21.1* List of Subsidiaries of Leviathan Gas Pipeline Partners,
L.P.
</TABLE>
<PAGE> 232
<TABLE>
<CAPTION>
Exhibit No. Description
----------- -----------
<C> <S>
23.1* Consent of PricewaterhouseCoopers LLP.
23.2* Consent of Deloitte & Touche LLP.
23.3* Consent of Arthur Andersen LLP.
23.4* Consent of Netherland, Sewell & Associates, Inc.
23.5** Consent of Akin, Gump, Strauss, Hauer & Feld, L.L.P.
(included in Exhibit 5.1 hereto).
24.1* Power of Attorney (included on the signature pages of this
Registration Statement on Form S-3).
</TABLE>
- ---------------
* Filed as an exhibit to this Registration Statement
** To be filed by amendment to this Registration Statement
<PAGE> 1
EXHIBIT 12.1
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------------------------------ -----------------
1994 1995 1996 1997 1998 1998 1999
------- ------- ------- ------- ------- ------ -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Earnings:
Income (loss) from continuing
operations before minority
interests and income taxes.... $22,148 $23,593 $38,318 $(1,456) $ 290 $ (79) $ 7,590
Interest and other financing
costs......................... 912 833 5,560 14,169 20,242 8,429 13,868
Interest component of rentals... -- -- -- -- -- -- --
Preferred stock dividend
requirements of majority-owned
subsidiary.................... -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------ -------
Total earnings available
for fixed charges...... $23,060 $24,426 $43,878 $12,713 $20,532 $8,350 $21,458
======= ======= ======= ======= ======= ====== =======
Fixed charges:
Interest and other financing
costs......................... $ 912 $ 6,102 $17,470 $15,890 $21,308 $8,954 $14,623
Interest component of rentals... -- -- -- -- -- -- --
Preferred stock dividend
requirements of majority-owned
subsidiary.................... -- -- -- -- -- -- --
------- ------- ------- ------- ------- ------ -------
Total fixed charges...... $ 912 $ 6,102 $17,470 $15,890 $21,308 $8,954 $14,623
======= ======= ======= ======= ======= ====== =======
Ratio of Earnings to Fixed
Charges......................... 25.3 4.0 2.5 0.8(a) 1.0(b) 0.9(c) 1.5
======= ======= ======= ======= ======= ====== =======
</TABLE>
- ------------------------------------
(a) As a result of the loss incurred, Leviathan Gas Pipeline Partners, L.P. and
its subsidiaries ("Leviathan") were unable to fully cover the indicated
fixed charges by $3.2 million due to a non-recurring asset impairment of
$21.2 million recorded in June 1997. If the impairment had not occurred,
the ratio of earnings to fixed charges would have equaled 2.1x.
(b) Leviathan was unable to cover the indicated fixed charges by $776,000 due
primarily to non-recurring expenses of $3.7 million recorded in August 1998
as a result of El Paso Energy Corporation's acquisition of Leviathan's
general partner. If the non-recurring expenses had not been incurred, the
ratio of earnings to fixed charges would have equaled 1.1x.
(c) As a result of the loss incurred, Leviathan was unable to fully cover the
indicated fixed charges by $2.0 million. During the period, Leviathan (1)
realized substantially low oil prices, (2) produced less production at
Viosca Knoll Block 817 due to the lack of acceptable markets downstream of
the Viosca Knoll system and (3) experienced non-recurring start-up costs
from two joint venture projects which began operations during the fourth
quarter of 1997. These operational events, which have been alleviated,
contributed to Leviathan's deficiency in covering its fixed charges.
For the purposes of calculating these ratios: (i) "fixed charges"
represents interest costs (whether expensed or capitalized), amortization of
debt issue costs, the estimated portion of rental expenses representing the
interest factor and preferred stock dividend requirements of majority-owned
subsidiaries; and (ii) "earnings" represent the aggregate of income from
continuing operations before minority interests and income taxes, interest
expense, amortization of debt issue costs, the portion of rental expense
representing the interest factor and the actual amount of any preferred stock
dividend requirements of majority-owned subsidiaries.
<PAGE> 1
EXHIBIT 21.1
SUBSIDIARIES OF LEVIATHAN GAS PIPELINE PARTNERS, L.P.
<TABLE>
<CAPTION>
JURISDICTION OF
NAME OF SUBSIDIARY ORGANIZATION
- ------------------ ---------------
<S> <C>
Leviathan Finance Corporation............................... Delaware
Delos Offshore Company, L.L.C............................... Delaware
Ewing Bank Gathering Company, L.L.C......................... Delaware
Flextrend Development Company, L.L.C........................ Delaware
Green Canyon Pipe Line Company, L.L.C....................... Delaware
Leviathan Finance Corporation............................... Delaware
Leviathan Oil Transport Systems, L.L.C...................... Delaware
Leviathan Operating Company, L.L.C.......................... Delaware
Manta Ray Gathering Company, L.L.C.......................... Delaware
Moray Pipeline Company, L.L.C............................... Delaware
Natoco, L.L.C............................................... Delaware
Poseidon Pipeline Company, L.L.C............................ Delaware
Sailfish Pipeline Company, L.L.C............................ Delaware
Stingray Holding, L.L.C..................................... Delaware
Transco Hydrocarbons Company, L.L.C......................... Delaware
Texam Offshore Gas Transmission, L.L.C...................... Delaware
Transco Offshore Pipeline Company, L.L.C.................... Delaware
Tarpon Transmission Company................................. Texas
UTOS Holding, L.L.C......................................... Delaware
Viosca Knoll Gathering Company.............................. Delaware
VK-Main Pass Gathering Company, L.L.C....................... Delaware
VK Deepwater Gathering Company, L.L.C....................... Delaware
</TABLE>
2
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the use in this Registration Statement on Form S-1 of
Leviathan Gas Pipeline Partners, L.P. of (i) our reports dated March 19, 1999
relating to the consolidated financial statements of Leviathan Gas Pipeline
Partners, L.P. and subsidiaries and the financial statements of Viosca Knoll
Gathering Company, (ii) our report dated March 11, 1999 relating to the
consolidated financial statements of Neptune Pipeline Company, L.L.C., (iii) our
report dated May 3, 1999 relating to the balance sheet of Leviathan Finance
Corporation and (iv) our report dated June 2, 1999 relating to the balance sheet
of Leviathan Gas Pipeline Company each of which appears in such Registration
Statement. We also consent to the reference to us under the heading "Experts" in
such Registration Statement.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
August 26, 1999
<PAGE> 1
EXHIBIT 23.2
INDEPENDENT AUDITORS' CONSENT
We consent to the use in this Registration Statement of Leviathan Gas
Pipeline Partners, L.P. on Form S-1 of our report dated February 19, 1999,
appearing in this Registration Statement, relating to the statements of
financial position of High Island Offshore System, L.L.C. as of December 31,
1998 and 1997 and the related statements of income, members' equity, and cash
flows for each of the three years in the period ended December 31, 1998.
We also consent to the reference to us under the heading "Experts" in such
Registration Statement.
/s/ DELOITTE & TOUCHE LLP
Detroit, Michigan
August 26, 1999
<PAGE> 1
EXHIBIT 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use of our
report dated March 18, 1999 relating to the financial statements of Poseidon Oil
Pipeline Company, L.L.C., as of December 31, 1998 and 1997 and for the years
ended December 31, 1998 and 1997 and the period from inception (February 14,
1996) through December 31, 1996, included in this Registration Statement on Form
S-1 of Leviathan Gas Pipeline Partners, L.P., and to all references to our Firm
in this Registration Statement.
/s/ ARTHUR ANDERSEN LLP
Houston, Texas
August 26, 1999
<PAGE> 1
EXHIBIT 23.4
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the use in this Registration Statement on Form S-1 of
Leviathan Gas Pipeline Partners, L.P. of our reserve report as of December 31,
1998, and all references to our firm appearing in this Registration Statement of
Leviathan Gas Pipeline Partners, L.P. for the fiscal year ended December 31,
1998. We also consent to the reference to us under the heading of "Experts" in
such Registration Statement.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ FREDERIC D. SEWELL
-------------------------------------
Frederic D. Sewell
President
Dallas, Texas
August 26, 1999
