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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____ to ____
Commission File No. 1-11680
==========================
LEVIATHAN GAS PIPELINE PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0396023
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
600 Travis Street
Suite 7200
Houston, Texas 77002
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (713) 224-7400
==========================
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
------------------- -----------------------------------------
Preference Units representing New York Stock Exchange
Limited Partner Interests
Securities registered pursuant to Section 12(g) of the Act: NONE.
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X}
The registrant had 18,075,000 Preference Units and 6,291,894 Common Units
outstanding as of March 16, 1998. The aggregate market value on such date of the
registrant's Preference Units held by non-affiliates was approximately $578.8
million.
Documents Incorporated by Reference: None
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LEVIATHAN GAS PIPELINE PARTNERS, L.P.
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 1997
INDEX
<TABLE>
<S> <C> <C>
PART I .............................................................................. 1
Items 1 & 2 Business and Properties ......................................... 1
Item 3 Legal Proceedings ............................................... 17
Item 4 Submission of Matters to a Vote of Security Holders ............. 17
PART II .............................................................................. 18
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters.............................................. 18
Item 6. Selected Financial Data.......................................... 18
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................ 19
Item 8. Financial Statements and Supplementary Data...................... 25
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure............................................. 25
PART III .............................................................................. 26
Item 10. Directors and Executive Officers of the Registrant .............. 26
Item 11. Executive Compensation .......................................... 29
Item 12. Security Ownership of Certain Beneficial Owners
and Management ................................................ 31
Item 13. Certain Relationships and Related Transactions .................. 32
PART IV ............................................................................... 33
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.. 33
</TABLE>
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The following text is qualified in its entirety by reference to the more
detailed information and consolidated financial statements (including the notes
thereto) appearing elsewhere in the Annual Report on Form 10-K ("Annual
Report"). Unless the context otherwise requires, references in this Annual
Report to the "Partnership" shall mean Leviathan Gas Pipeline Partners, L. P., a
publicly held Delaware limited partnership; references to "Leviathan" shall mean
Leviathan Gas Pipeline Company, a Delaware corporation and the general partner
of the Partnership (in such capacity, the "General Partner"); and references to
the Partnership with respect to the operations and ownership of the
Partnership's assets are also references to its subsidiaries and the nonmanaging
interest of Leviathan in certain of the Partnership's subsidiaries. For a
description of certain terms used in this Annual Report relating to the oil and
gas industry, see Items 1 & 2. "Business and Properties - Certain Definitions."
PART I
ITEMS 1 & 2. BUSINESS AND PROPERTIES
OVERVIEW
The Partnership is primarily engaged in the gathering, transportation and
production of natural gas and crude oil in the Gulf of Mexico (the "Gulf"). The
Partnership commenced operations in February 1993 in connection with the initial
public offering of preference units representing limited partner interests in
the Partnership ("Preference Units"). In June 1994, the Partnership completed a
second public offering of Preference Units. The Preference Units are listed on
the New York Stock Exchange ("NYSE") under the symbol "LEV." The closing price
of the Preference Units on the NYSE on March 16, 1998 was $32 1/8 per Preference
Unit. As of March 16, 1998, the Partnership had 18,075,000 Preference Units and
6,291,894 common units representing limited partner interests in the Partnership
("Common Units", and collectively with the Preference Units, the "Units")
outstanding. All of the Preference Units are owned by the public, representing a
72.7% effective limited partnership interest in the Partnership. Leviathan, an
85%-owned indirect subsidiary of DeepTech International Inc. ("DeepTech"), owns
a 27.3% effective interest in the Partnership through its ownership of all of
the Common Units, its 1% general partner interest in the Partnership and its
approximate 1% nonmanaging interest in certain of the Partnership's
subsidiaries.
On March 2, 1998, DeepTech announced that its Board of Directors and a
majority of its stockholders had approved entering into a definitive merger
agreement with El Paso Natural Gas Company ("El Paso"). As a result of this
merger and through a series of transactions, El Paso will acquire 100% of
Leviathan's general partner interest in the Partnership and an overall 27.3%
effective interest in the Partnership. Subject to customary regulatory approvals
and consummation of certain related transactions, the merger is expected to be
completed by the end of the second quarter of 1998.
In addition, the Partnership has agreed to exchange 7,500 shares of Tatham
Offshore, Inc. ("Tatham Offshore") 9% Senior Convertible Preferred Stock
currently held by the Partnership for certain Tatham Offshore facilities and
offshore oil and gas properties. Tatham Offshore is an affiliate of the
Partnership. See "- Oil and Gas Properties - General."
The Partnership's assets include interests in (i) eight natural gas
pipelines (the "Gas Pipelines"), (ii) a crude oil pipeline system ("Poseidon"
and collectively with the Gas Pipelines, the "Pipelines"), (iii) five
strategically located multi-purpose platforms, (iv) three producing oil and gas
properties and (v) a dehydration facility.
NATURAL GAS AND OIL PIPELINES
GENERAL
The Partnership conducts a significant portion of its business activities
through joint ventures (the "Equity Investees"), organized as general
partnerships or limited liability companies, with other major oil and gas
companies. The Equity Investees include Stingray Pipeline Company ("Stingray"),
High Island Offshore System ("HIOS"), U-T Offshore System ("UTOS") and Viosca
Knoll Gathering Company ("Viosca Knoll"), all of which are partnerships, and
Poseidon Oil Pipeline Company, L.L.C. ("POPCO"), Manta Ray Offshore Gathering
Company, L.L.C. ("Manta Ray Offshore"), Nautilus Pipeline Company, L.L.C.
("Nautilus") and West Cameron Dehydration Company, L.L.C. ("West Cameron Dehy"),
all of which are limited liability companies. Management decisions related to
the Equity Investees are made by management committees comprised of
representatives of each partner or member, as applicable, with authority
appointed in direct relationship to ownership interests.
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Through its 100%-owned operating subsidiaries and the Equity Investees, the
Partnership owns interests in the Gas Pipelines, which are strategically located
offshore Louisiana and eastern Texas, that gather and transport natural gas for
producers, marketers, pipelines and end-users for a fee. The Gas Pipelines
include approximately 1,167 miles of pipeline with a throughput capacity of
approximately 6.5 Bcf of gas per day. During the years ended December 31, 1997,
1996 and 1995, the Gas Pipelines transported an average of approximately 2.7
Bcf, 2.7 Bcf and 2.4 Bcf, respectively, of gas per day. Each of the 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.
None of the Gas Pipelines functions as a merchant to purchase and resell
gas, thus avoiding the commodity risk associated with the purchase and resale of
gas. Each of Nautilus, Stingray, HIOS and UTOS (together, the "Regulated
Pipelines") 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 Federal Energy Regulatory Commission ("FERC"), including regulation of
rates. None of Manta Ray Offshore, Viosca Knoll, Green Canyon Pipe Line Company,
L.L.C. ("Green Canyon"), Ewing Bank Gathering Company, L.L.C. ("Ewing Bank") or
Tarpon Transmission Company ("Tarpon") is currently considered a "natural gas
company" under the NGA. See "-Regulation."
The Poseidon pipeline is a 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. During 1997 and 1996, the Poseidon
pipeline transported an average of approximately 60,500 barrels and 30,000
barrels, respectively, of oil per day.
The following table sets forth certain information with respect to the
Pipelines. The throughput information represents the average throughput net to
the Partnership's interest.
<TABLE>
<CAPTION>
Manta
Green Ray Viosca
Canyon Tarpon Offshore(1) Knoll Stingray HIOS UTOS Nautilus(2) Poseidon
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Ownership interest ........ 100% 100% 25.67% 50% 50% 40% 33.3% 25.67% 36%
Unregulated (U)/
regulated (R)(3) ....... U U U U R R R R U
In-service date ........... 1990 1978 1987/88 1994 1975 1977 1978 1997 1996
Approximate capacity
(MMcf per day) ......... 220 80 755(4) 700(5) 1,120 1,800 1,200 600 --
Approximate capacity
(MBbl per day) ......... -- -- -- -- -- -- -- -- 400
Aggregate miles of pipeline 68 40 225(1) 125 361 203 30 101 297
Average net throughput
(MMcf/MBbl per day) for
calendar year ended:
December 31, 1997 ...... 148 50 195(6) 194 353 352 105 --(2) 22(8)
December 31, 1996 ...... 142 33 217(7) 144 373 372 103 --(2) 11(8)
December 31, 1995 ...... 71 42 226(7) 83 352 327 118 --(2) --(8)
</TABLE>
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(1) In January 1997, the Partnership contributed substantially all of the
Manta Ray Gathering System and the Louisiana Offshore Gathering System to
Manta Ray Offshore. The Partnership continues to own 100% of two offshore
platforms, 19 miles of oil pipeline and 14 miles of gas pipeline which were
formerly a part of the Manta Ray Gathering System.
(2) The Nautilus system was placed in service in late December 1997.
(3) Regulated Pipelines are subject to extensive rate regulation by the FERC
under the NGA. See "- Regulation."
(4) Represents the approximate aggregate capacity of the five pipelines
comprising the Manta Ray Offshore system, including approximately 52 miles
of pipeline with a capacity of 275 MMcf of gas per day that was placed in
service in November 1997.
(5) The original maximum design capacity of the Viosca Knoll system was
400 MMcf of gas per day. In 1996, Viosca Knoll installed a 6,000 horsepower
compressor on the Partnership's Viosca Knoll 817 platform to allow the
Viosca Knoll system to effect deliveries at the operating pressures on
downstream interstate pipelines with which it is interconnected, resulting
in an increase in throughput capacity to approximately 700 MMcf of gas per
day. The additional capacity also allowed the Viosca Knoll system to
transport new gas volumes during 1997 from the Shell-operated Southeast
Tahoe and Ram-Powell fields as well as other new deepwater projects in the
area.
(6) Represents throughput specifically allocated to the Partnership by
Manta Ray Offshore during the initial year of operations.
(7) Represents 100% ownership interest during this period.
(8) The Poseidon pipeline was placed in service in three phases, in April 1996,
December 1996 and December 1997.
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Currently, the Partnership operates all of its 100% owned pipelines and the
Viosca Knoll system. The remaining joint venture pipelines are operated by
unaffiliated pipeline companies.
RECENT DEVELOPMENTS
Strategic New Pipeline Joint Ventures
Poseidon. POPCO is owned by the Partnership (36%), a subsidiary of Texaco,
Inc. ("Texaco") (36%) and a subsidiary of Marathon Oil Company ("Marathon")
(28%). As consideration for their interest in POPCO, each of the Partnership,
Texaco and Marathon contributed certain assets (including pipelines, contract
rights and cash) and made certain commitments to POPCO (including significant
dedications of oil reserves by subsidiaries of Texaco and Marathon). A
subsidiary of Texaco operates and performs the administrative functions related
to Poseidon and POPCO.
The Poseidon pipeline is comprised of 118 miles of 16" to 20" pipeline
extending in an easterly direction from the Partnership's 50%-owned platform in
Garden Banks Block 72 to a platform in Ship Shoal Block 332, 77 miles of 24"
pipeline extending in a northerly direction from the Ship Shoal Block 332
platform to Calliou Island, Louisiana and 60 miles of 16" pipeline extending
northwesterly from Ewing Bank Block 873 to the Texaco operated Eugene Island
Pipeline System at Ship Shoal Block 141. Initial deliveries into this system
occurred in April 1996. An additional 42 miles of 24" pipeline extending in a
northerly direction from Calliou Island to Houma, Louisiana was placed in
service in December 1997. Prior to this expansion, the Poseidon pipeline used
existing Texaco pipelines to move oil from Calliou Island to Houma. Texaco
Pipelines Inc. accepts oil from the Poseidon pipeline at Larose and Houma,
Louisiana and redelivers it to St. James, Louisiana, a significant market hub
for batching, processing and transportation of oil. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Liquidity and Capital Resources."
Nautilus and Manta Ray Offshore. In January 1997, the Partnership and
affiliates of Marathon and Shell Oil Company ("Shell") formed Nautilus to
construct and operate a new interstate natural gas pipeline system. In addition,
the same parties formed Manta Ray Offshore to acquire an existing gathering
system from the Partnership. The gathering system was extended and is currently
delivering gas to several downstream pipelines, including the Nautilus system.
The Nautilus and Manta Ray Offshore systems are located to serve growing
production areas in the Green Canyon area of the Gulf and are indirectly owned
50% by Shell, 24.3% by Marathon and 25.7% by the Partnership. The capital costs
associated with the construction of the Nautilus interstate pipeline system and
the expansion of the Manta Ray Offshore gathering system, including the value of
existing assets contributed by the partners, totaled approximately $250 million.
The Nautilus system consists of 101 miles of 30-inch pipeline downstream from
Ship Shoal Block 207 connecting to a gas processing plant, onshore Louisiana,
operated by Exxon Company USA ("Exxon"), plus certain facilities downstream of
the Exxon plant to effect deliveries into multiple interstate pipelines.
Upstream of the Ship Shoal Block 207 platform, the existing Manta Ray Offshore
gathering system was extended into a broader gathering system that serves shelf
and deepwater production areas around Ewing Bank Block 1008 to the east and
Green Canyon Block 65 to the west. The Manta Ray Offshore 47-mile expansion was
completed and placed in service in November 1997. The Nautilus system, including
the related onshore facilities and platform connections, was completed and
placed in service in December 1997. Affiliates of Marathon and Shell dedicated
for transportation and gathering to each of the Nautilus and Manta Ray Offshore
systems significant deepwater acreage positions in the area and provided
substantially all of the capital funding for the new construction. The
Partnership provided $11.1 million of funding in the form of a newly constructed
compressor in addition to its contribution of the Manta Ray Offshore system.
Expansion of the Viosca Knoll Gathering System
In December 1997, Viosca Knoll placed in service an expansion to the system
of approximately 25 miles of 20" pipeline. This expansion will enable Viosca
Knoll to transport additional committed gas volumes from producing areas near
the eastern end of the system.
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Construction of Multi-Purpose Platform
During 1997, the Partnership began the construction and installation of a
new multi-purpose platform that will be located in East Cameron Block 373. The
platform, which the Partnership anticipates will be placed in service during
April 1998 at an estimated cost of approximately $32 million, is a four pile
production platform with processing facilities that will be strategically
located to exploit deeper water reserves in the East Cameron and Garden Banks
area of the Gulf and will be the terminus for an extension of the Stingray
system. In 1997, the Partnership and Kerr McGee Corporation entered into
agreements pursuant to which Kerr McGee Corporation 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.
North Atlantic Pipeline Project
Tatham Offshore Canada Limited ("Tatham Offshore Canada"), a wholly-owned
subsidiary of Tatham Offshore, is the Canadian representative of North Atlantic
Pipeline Partners, L.P. ("North Atlantic"), the sponsor of a proposal to build
an approximately 2,500 kilometer pipeline from offshore Newfoundland and Nova
Scotia to the eastern seaboard of the United States. The Partnership has entered
into a letter agreement with Tatham Offshore Canada regarding participation in
the North Atlantic pipeline project. Under such agreement, Tatham Offshore
Canada is responsible for pre-development costs of up to $10 million. Such
agreement contains certain termination rights, contemplates the negotiation,
execution and delivery of definitive agreements and provides that the
Partnership would hold a pro rata partnership interest of up to 20% in North
Atlantic. The Partnership has no financial commitment to the project until and
unless an application is approved by the appropriate Canadian and United States
regulatory authorities. In the event the Partnership was to terminate its
participation in North Atlantic after the date North Atlantic receives
regulatory approval of an application but prior to the in-service date of the
first phase of the North Atlantic pipeline, the Partnership, under certain
conditions, would be obligated to pay Tatham Offshore Canada an amount equal to
150% of the Partnership's pro rata share of the "success fee" earned by Tatham
Offshore Canada related to the first phase of construction. For a period of one
year after the effective date of the DeepTech/El Paso merger, the Partnership
shall have the right to terminate this agreement without incurring the liability
for the above-mentioned "success fee". During October 1997, North Atlantic filed
applications with the FERC and its Canadian counterpart, the National Energy
Board, for approval of its proposed pipeline. Tatham Offshore Canada is seeking
additional participants on similar terms as that offered to the Partnership.
Conversion of Preference Units into Common Units
The Preference Units are currently entitled to receive from Available Cash,
as defined in the Partnership Agreement, a Minimum Quarterly Distribution for
each quarter of $0.275 per Preference Unit, plus any arrearage in the payment of
the Minimum Quarterly Distribution for prior quarters, before any distribution
of Available Cash is made to holders of Common Units for such quarter. The
Partnership has determined that the Preference Period, as defined in the
Partnership Agreement, will expire on March 31, 1998.
The Partnership intends to mail a notice to the holders of Preference Units
to the effect that, for a 90-day period commencing upon the mailing of such
notice, the holders of all Preference Units shall have the right to convert
their Preference Units into a like number of Common Units. The conversion will
become effective for those Preference Units electing to convert and the
Preference Period will expire with respect to remaining outstanding Preference
Units.
Following the end of the Preference Period, holders of Preference Units
will not be entitled to participate in any distributions of Available Cash in
excess of the Minimum Quarterly Distribution. Since the current quarterly
distributions are significantly in excess of the Minimum Quarterly Distribution,
the Partnership anticipates that substantially all of the Preference Unitholders
will elect to convert their Preference Units into Common Units.
OIL AND GAS SUPPLY
The reserves that are currently available for gathering and transportation
on the Pipelines are depleting assets and, as such, will be produced over a
finite period. Each of the Pipelines must access additional reserves to offset
the natural decline in production from existing wells connected thereto or the
loss of any such production to a competitor. Management believes that there will
be sufficient reserves available to the Gas Pipelines for transportation to
maintain throughput at or near current levels for at least the next five years.
Management believes that there should be significant increases in reserves
committed to the Poseidon pipeline over the next several years.
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POPCO commenced operations on the Poseidon pipeline in April 1996 and
placed expansion lines in service in December 1996 and December 1997. Currently,
the Poseidon pipeline is transporting an average of 80,350 barrels of oil per
day. In addition to the production commitments from Texaco and Marathon, POPCO
has been successful in obtaining long-term commitments of production from
several properties containing significant reserves. POPCO has contracted with
Phillips, Amoco Petroleum Company, Anadarko Petroleum Company, Newfield
Exploration, Mobil Oil, Amerada Hess Corporation, Oryx Crude Trading &
Transportation Limited Partnership, Sun Operating Limited Partnership, Pennzoil,
Enterprise Oil, PLC, Exxon, British Borneo, Reading and Bates (U.K.), Limited,
Occidental Petroleum Corporation and the Partnership. In addition, discussions
are currently pending with a number of other producers regarding possible
commitments of reserves to the Poseidon pipeline. The Partnership anticipates
adding more commitments as new subsalt and deepwater fields are developed in the
area which it serves, although there can be no assurance regarding if or when
any such commitment would be made or when the production from such commitment
would be made or when the production from such commitment would be initiated.
See " - Recent Developments - Strategic New Pipeline Joint Ventures - Poseidon."
The Tarpon system experienced a 52% increase in throughput for the year
ended December 31, 1997 as compared with the previous year, primarily as a
result of new producing fields attached to the system in June and July 1997. The
Viosca Knoll system experienced an increase of 34% in throughput during 1997
primarily as a result of new throughput from the Shell-operated Southeast Tahoe
and Ram-Powell fields. The Green Canyon system's throughput increased 4% for
1997 as compared with 1996. UTOS experienced a 3% increase in transportation
volume for the year ended December 31, 1997 as compared with the previous year.
The Ewing Bank system experienced an 82% decrease in throughput during 1997
as compared with 1996 due to a mechanical problem in May 1997 which shut-in
Tatham Offshore's Ewing Bank Block 914 #2 well, the only production currently
dedicated to the Ewing Bank system. No further production is expected from such
well. See the Partnership's "Notes to Consolidated Financial Statements - Note 5
- - Impairment, Abandonment and Other" located elsewhere in this Annual Report.
The Manta Ray Offshore system experienced a decline in throughput of 9% during
1997 primarily as a result of temporary platform related production problems
from two of the fields connected to the system as well as lower production from
a low margin field connected to the system. HIOS experienced a 6% decrease in
transportation volume for the year ended December 31, 1997 as compared with the
previous year. HIOS accesses the East Breaks and Garden Banks areas of the
flextrend and deepwater areas of the Gulf. Management believes that development
in these and other areas served by HIOS is likely to occur in future years,
resulting in additional throughput on HIOS, and partially offsetting the
continuing decline in reservoir deliverability from existing wells connected to
HIOS. For the year ended December 31, 1997, Stingray experienced a 5% decrease
in throughput as compared with the previous year.
OFFSHORE PLATFORMS AND OTHER FACILITIES
Offshore platforms play a key role in the development of oil and gas
reserves and, thus, in the offshore pipeline network. Platforms are used to
interconnect the offshore pipeline grid and to provide an efficient means to
perform pipeline maintenance and to operate compression facilities, separation,
processing and other facilities. In addition to numerous platforms owned by the
Equity Investees, the Partnership owns five strategically located platforms in
the Gulf.
Viosca Knoll Block 817. The Partnership constructed a multi-purpose
platform located in Viosca Knoll Block 817 (the "VK 817 Platform") in 1995. The
VK 817 Platform was used by the Partnership as a base for conducting drilling
operations for oil and 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 processing fees
for the Partnership. The Partnership also leases platform space to Viosca Knoll
for the location of compression equipment for the Viosca Knoll system.
Garden Banks Block 72. The Partnership owns a 50% interest in a
multipurpose platform located in Garden Banks Block 72 (the "GB 72 Platform").
The GB 72 Platform is located at the south end of the Stingray system and serves
as the westernmost terminus of Poseidon. The GB 72 Platform was also used as a
drilling and production platform and as the landing site for production from the
Partnership's Garden Banks Block 117 lease located in an adjacent lease block.
5
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Ship Shoal Block 332. The Partnership owns a 100% interest in a platform
located in Ship Shoal Block 332 which serves as a junction platform for gas
pipelines in Manta Ray Offshore's system as well as an eastern junction for
Poseidon.
South Timbalier Block 292. The South Timbalier Block 292 platform (the "ST
292 Platform") is a 100%-owned facility located at the easternmost terminus of
Manta Ray Offshore's system. The ST 292 Platform serves as a landing site for
gas production in the area.
East Cameron Block 373. The Partnership began construction and installation
of a new platform and processing facilities at East Cameron Block 373 in July
1997. This new platform, which the Partnership anticipates will be placed in
service during April 1998 at a projected cost of approximately $32 million, will
be strategically located to exploit reserves in the East Cameron and Garden
Banks area of the Gulf and will be the terminus for an extension of the Stingray
system. See "- Recent Developments - Construction of Multi-Purpose Platform."
Other Facilities. Through its 50% ownership interest in West Cameron
Dehy, the Partnership owns an interest in certain dehydration facilities located
at the northern terminus of the Stingray system, onshore Louisiana.
MAINTENANCE
Each of the Pipelines requires regular and thorough maintenance. The
interior of the pipelines are 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 itself at prescribed
intervals, providing exterior corrosion protection from sea water. The 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. Remote operated
vehicles or divers inspect the 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 the platforms are responsible for site maintenance, operations of the
facilities on the platform, measurement of the gas stream at the source of
production and corrosion control (pig launching and inhibitor injection).
COMPETITION
Each of the Gas Pipelines is located in or near natural gas production
areas that are served by other pipelines. As a result, each of the Partnership's
systems face competition from both regulated pipelines and gathering systems
with respect to its transportation services. Certain of these pipelines are not
subject to the same level of rate and service regulation as, and may have a
lower cost structure than, the Gas Pipelines, and other pipelines, such as
long-haul transporters, have rate design alternatives unavailable to the Gas
Pipelines. Consequently, such pipelines may be able to provide service on more
flexible terms and at rates significantly below the rates offered by the Gas
Pipelines. The Gas Pipelines' principal interstate pipeline competitors are
Shell Offshore, Inc., Texaco Natural Gas, Inc., ANR Pipeline Company, Transco
Energy Company, Trunkline Gas Co., El Paso, Texas Eastern Transmission
Corporation, Sea Robin Pipeline Company, Columbia Gas Transmission Corporation
and their affiliates. Poseidon was built as a result of the Partnership's belief
that additional sour crude oil capacity was required to transport new subsalt
and deepwater oil production to shore. The Poseidon pipeline's principal
competitors for additional crude oil production are the Texaco operated Eugene
Island Pipeline System and the Shell-operated Amberjack System. The 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.
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CUSTOMERS AND CONTRACTS
Principal Customers. See the Partnership's "Notes to Consolidated Financial
Statements - Note 14 - Major Customers" for certain information regarding the
Partnership's principal transportation customers.
The Gas Pipelines gather and transport gas under both firm and
interruptible transportation service agreements. Under firm service agreements,
a pipeline is obligated to receive and deliver up to a specified maximum
quantity of gas without interruption, except upon occurrence of a force majeure
event. Firm customers often pay a two part rate, a demand charge and a commodity
charge. The demand charge is payable monthly based on the maximum contract
quantity the pipeline is obligated to transport, without regard to the quantity
actually transported during such month. The commodity charge is payable monthly
based on the actual quantity of gas transported during such month. However, many
of the Gas Pipelines' firm customers pay only a one part rate that includes both
the demand and commodity components of the rate. Under interruptible contracts,
a pipeline is usually obligated to receive and deliver up to a specified maximum
quantity of gas, subject to availability of capacity, on a first-come,
first-served basis. Interruptible customers pay only a one-part commodity rate
that includes both the demand and commodity elements of the firm rate. The
Poseidon system receives crude oil from the leases connected to the pipeline
under long-term buy/sell agreements.
OIL AND GAS PROPERTIES
GENERAL
The Partnership conducts exploration and production activities through a
subsidiary that is an independent energy company engaged in the development and
production of reserves located offshore the United States in the Gulf, focusing
principally on the flextrend and deepwater areas. As of December 31, 1997, the
Partnership owned interests in three lease blocks in the Gulf comprising 17,280
gross (10,080 net) acres. See "- Oil and Gas Reserves" for a discussion of the
assumptions used in, and inherent difficulties relating to, estimating reserves.
The Partnership sells all of its oil and gas production to Offshore Gas
Marketing, Inc., an affiliate of the Partnership.
In 1995, the Partnership acquired from Tatham Offshore 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") subject to certain reversionary rights.
In connection with the merger of DeepTech and El Paso, Tatham Offshore
has agreed to relinquish its reversionary rights relating to the Acquired
Properties and the Partnership has agreed to exchange 7,500 shares of Tatham
Offshore 9% Senior Convertible Preferred Stock currently held by the Partnership
for 100% of Tatham Offshore's right, title and interest in and to Viosca Knoll
Blocks 772, 773, 774, 817, 818 and 861, West Delta Block 35, Ewing Bank Blocks
871, 914, 915 and 916 and the platform located on Ship Shoal Block 331. At the
closing, the Partnership will receive from/pay to Tatham Offshore an amount
equal to the net cash generated from/required by such properties from January 1,
1998 through the closing date. In addition, the Partnership has agreed to assume
all abandonment and restoration obligations associated with the platform and
leases. This transaction has been approved by the Board of Directors of each of
Tatham Offshore and Leviathan and is expected to close in July 1998.
DESCRIPTION OF OIL AND GAS PROPERTIES
Viosca Knoll Block 817. Viosca Knoll Block 817 is a producing property that
is comprised of 5,760 gross (4,320 net) acres located 40 miles off the coast of
Louisiana in approximately 650 feet of water. The Partnership acquired from
Tatham Offshore a 75% working interest in Viosca Knoll Block 817 from the
sea-floor through the stratigraphic equivalent of the base of the Tex X-6 Sand.
Tatham Offshore owns the remaining 25% working interest in this property.
The Partnership, as operator, concluded a drilling program and placed eight
wells on production on Viosca Knoll Block 817. The Partnership does 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, 1997, the Viosca Knoll project has produced 32,937 MMcf of gas and 64,770
barrels of oil, net to the Partnership's interest. The Viosca Knoll Block 817 is
currently producing an aggregate of approximately 56 MMcf of gas and 865 barrels
of water per day. Gas production from Viosca Knoll Block 817 is
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<PAGE> 10
dedicated to the Partnership for gathering through the Viosca Knoll system and
oil production is being transported through a Shell-operated system.
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. Tatham Offshore and Midcon Exploration Company ("MidCon
Exploration") jointly bought the Garden Banks Block 72 lease in 1991. In June
1995, the Partnership acquired from Tatham Offshore its 50% working interest
(approximately 40.2% net revenue interest) in Garden Banks Block 72. MidCon
Exploration owns the remaining 50% working interest in Garden Banks Block 72.
Since May 1996, the Partnership has placed five wells on production at
Garden Banks Block 72. The Partnership does 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 2,081 MMcf of gas and 629,280 barrels of oil, net
to the Partnership's interest, from the inception of production in May 1996
through December 31, 1997. The five wells are currently producing a total of
approximately 2,100 barrels of oil, 8 MMcf of gas and 975 barrels of water per
day. Gas production from Garden Banks Block 72 is being transported through the
Stingray system and the oil production is delivered to the Poseidon pipeline.
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. Tatham Offshore and MidCon Exploration jointly acquired the
Garden Banks Block 117 lease from Shell Offshore, Inc. under a farm-in
arrangement which provides that Shell Offshore, Inc. retains a 1/12 overriding
royalty interest in Garden Banks Block 117 with an option to convert the
overriding royalty interest into a 30% working interest after the property has
produced 25 million net equivalent barrels of oil. In November 1994, Tatham
Offshore completed the drilling of its Garden Banks 117 #1 well. In June 1995,
the Partnership acquired from Tatham Offshore its 50% working interest
(approximately 37.5% net revenue interest) in Garden Banks Block 117. MidCon
Exploration owns the remaining 50% working interest in Garden Banks Block 117.
In July 1996 and May 1997, the Partnership completed and initiated
production from the Garden Banks Block 117 #1 and #2 wells, respectively, which
are currently producing a total of approximately 2,300 barrels of oil, 5 MMcf of
gas and 4,290 barrels of water per day. Since inception of production through
December 31, 1997, Garden Banks Block 117 produced 896 MMcf of gas and 499,925
barrels of oil, net to the Partnership's interest. The Partnership does not
anticipate drilling any more wells on this property except for a possible
recompletion of the Garden Banks 117 #2 well. Gas production from Garden Banks
Block 117 is transported on the Stingray system and oil production is delivered
to the Poseidon pipeline.
COMPETITION
The exploration and production of oil and gas is highly competitive and
cyclical. Competition in the industry has increased significantly during the
last several years due to an increase in worldwide demand for oil and gas, which
has stabilized and periodically increased the prices of those commodities.
However, from the mid 1980's through the early 1990's, increases in worldwide
energy production capability, decreases in energy consumption as a result of
conservation efforts, and the continued development of alternate energy sources
have brought about substantial surpluses in oil and gas supplies, resulting in
substantial competition for the marketing of oil and gas. As a result, there
were precipitous declines in oil and gas prices and delays in producing and
marketing natural gas after it is discovered. Changes in government regulations
relating to the production, transportation and marketing of gas have also
resulted in the abandonment by many pipelines of long-term contracts for the
purchase of gas, the development by gas producers and other entities of their
own marketing programs to take advantage of new regulations requiring pipelines
to transport natural gas for regulated fees and an increasing tendency to rely
on short-term sales contracts priced at spot market prices. See "- Regulation."
Many of the Partnership's competitors have financial and other resources
substantially in excess of those available to the Partnership and may,
accordingly, be better positioned to acquire and exploit prospects, hire
personnel and market production. In addition, many of the Partnership's larger
competitors may be better able to withstand the effect of changes in factors
such as worldwide oil and natural gas prices and levels of production, the cost
and availability of alternative fuels and the application of government
regulations, which affect demand for oil and natural gas production and are
beyond the control of the Partnership.
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<PAGE> 11
OIL AND GAS RESERVES
The following estimates of the Partnership's total proved developed and
proved undeveloped reserves of oil and gas as of December 31, 1997 have been
made by Netherland, Sewell & Associates, Inc. ("Netherland, Sewell), an
independent petroleum engineering consulting firm.
<TABLE>
<CAPTION>
Gas (MMcf)
Oil (barrels) ------------------------------
Proved Proved Proved
Developed Developed Undeveloped
----------- --------- -----------
<S> <C> <C> <C>
Viosca Knoll Block 817 132,663 22,937 1,839
Garden Banks Block 72 716,141 3,266 --
Garden Banks Block 117 1,270,151 2,121 --
--------- ------ -----
Total 2,118,955 28,324 1,839
========= ====== =====
</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 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 the
Partnership's reserves is based upon volumetric calculations.
The following table sets forth, as of December 31, 1997, the estimated
future net cash flows and the present value of estimated future net cash flows,
discounted at 10% per annum, from the production and sale of the proved
developed and undeveloped reserves attributable to the Partnership's interest in
oil and 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, 1997
------------------------------------------
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) $75,635 $2,199 $77,834
Present value of estimated future net cash flows
from proved reserves before
income taxes, discounted at 10% $65,688 $1,678 $67,366
</TABLE>
- ---------------------
(1) The average oil and gas prices, as adjusted by lease for gravity and Btu
content, regional posted price differences and oil and 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, 1997
are $17.54 per barrel of oil and $2.49 per Mcf of gas.
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<PAGE> 12
In accordance with applicable requirements of the Securities and Exchange
Commission (the "Commission"), 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 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 methodology approved by the Commission, 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 the Partnership for oil and 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 on certain of the Partnership's properties.
Future net cash flows were discounted at 10% per annum to arrive at
discounted future net cash flows. The 10% discount factor used to calculate
present value is required by the Commission, 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 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 Partnership
distributions. The present value of future net cash flows shown above should not
be construed as the current market value as of December 31, 1997, or any prior
date, of the estimated oil and gas reserves attributable to the Partnership's
properties.
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
the Partnership's sale of oil and gas for the periods indicated:
<TABLE>
<CAPTION>
Oil (barrels) Natural Gas (MMcf)
Year Ended December 31, Year Ended December 31,
----------------------- -----------------------
1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ---
<S> <C> <C> <C> <C> <C> <C>
Net production (1) 801,000 393,000 -- 19,792 15,730 392
Average sales price (1) $20.61 $21.76 $-- $ 2.08 $ 2.37 $ 2.35
Average production costs (2) $ 1.98 $ 1.59 $-- $ 0.33 $ 0.27 $ 0.44
</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 results of
operations expected by the Partnership.
ACREAGE
The following table sets forth the Partnership's developed and
undeveloped oil and gas acreage as of December 31, 1997. 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 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 a working interest is owned directly by the Partnership. The number of
net acres is the Partnership's fractional ownership of working interests in the
gross acres.
Gross Net
------ ------
Developed acreage 4,072 2,654
Undeveloped acreage 13,208 7,426
------ ------
Total acreage 17,280 10,080
====== ======
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<PAGE> 13
OIL AND GAS DRILLING ACTIVITY
The following table sets forth the gross and net number of productive, dry
and total exploratory wells and development wells that the Partnership has
drilled in each of the respective years:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------
1997 1996 1995
---------------- ---------------- --------------
Gross Net Gross Net Gross Net
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY
Productive ................ -- -- 1.00 0.50 -- --
Dry ....................... -- -- -- -- -- --
----- ----- ----- ----- ----- -----
Total ............. -- -- 1.00 0.50 -- --
===== ===== ===== ===== ===== =====
DEVELOPMENT
Productive ................ -- -- 12.00 7.75 1.00 0.75
Dry ....................... -- -- 3.00 1.75 -- --
----- ----- ----- ----- ----- -----
Total ............. -- -- 15.00 9.50 1.00 0.75
===== ===== ===== ===== ===== =====
</TABLE>
As of December 31, 1997 and March 16, 1998, the Partnership owned 15 gross
(9.5 net) producing wells.
MAJOR ENCUMBRANCES
All of the operating assets in which the Partnership owns an interest are
owned by subsidiaries or Equity Investees of the Partnership. Substantially all
of the assets of the Partnership (primarily its interest in its subsidiaries)
and its subsidiaries are pledged as collateral to secure obligations under the
Partnership Credit Facility, as hereinafter defined. In addition, certain of the
Equity Investees currently have, and others are expected to have, credit
facilities pursuant to which substantially all of such Equity Investees' assets
are or would be pledged. See Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital
Resources".
REGULATION
The oil and gas industry is extensively regulated by federal and state
authorities in the United States. Numerous departments and agencies, both
federal and state, have issued rules and regulations binding on the oil and gas
industry and its individual members, some of which carry substantial penalties
for the failure to comply. Legislation affecting the oil and gas industry is
under constant review and statutes are constantly being adopted, expanded or
amended. The regulatory burden on the oil and gas industry increases its cost of
doing business.
General. The design, construction, operation and maintenance of the Gas
Pipelines of certain of their gas transmission facilities are subject to
regulation by the Department of 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 the Pipelines is located in federal waters in the Gulf, 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.
The Poseidon system 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, 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, 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 the Regulated Pipelines (Nautilus, Stingray, HIOS and UTOS)
is classified as a "natural gas company" by the NGA. Consequently, the FERC has
jurisdiction over the Regulated Pipelines with respect to transportation of gas,
rates and charges, construction of new facilities, extension or abandonment of
service and
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<PAGE> 14
facilities, accounts and records, depreciation and amortization policies and
certain other matters. In addition, the Regulated Pipelines hold certificates of
public convenience and necessity issued by the FERC covering 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 (i) recover
operating expenses, (ii) recover the pipeline's undepreciated investment in
property, plant and equipment ("rate base") and (iii) receive an overall allowed
rate of return on the pipeline's rate base. The Partnership believes 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 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 and that will remain in effect until at least the fourth
quarter of 1998. Stingray, HIOS and UTOS have each agreed to file new rate cases
in the fourth quarter of 1998.
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 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, the Partnership does not anticipate that the FERC will assert or
exercise any NGA rate jurisdiction over the Green Canyon, Ewing Bank, Manta Ray
Offshore or Viosca Knoll 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. However, in the event the merger between
DeepTech and El Paso is consummated, the FERC may have the opportunity to
consider whether such event constitutes a change affecting the jurisdictional
status of Viosca Knoll.
The FERC has generally disclaimed jurisdiction to set rates for oil
pipelines in the OCS under the Interstate Commerce Act. As a result, Poseidon
has not filed tariffs with the FERC.
Production and Development. The production and development operations of
the Partnership 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. The Partnership's 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 gas properties.
The Partnership presently has interests in or rights to offshore leases
located in federal waters. Federal leases are administered by the Minerals
Management Service of the U.S. Department of the Interior ("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.
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<PAGE> 15
OPERATIONAL HAZARDS AND INSURANCE
A pipeline may experience damage as a result of an accident or other
natural disaster. In addition, the Partnership's 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, the Partnership maintains insurance of various
types that it considers to be adequate to cover its operations. The Insurance
Package covers all of the Partnership's assets in amounts considered reasonable,
other than for the Partnership's 50% interest in the assets of Stingray, for
which insurance is carried at the Stingray partnership level. The Insurance
Package is subject to deductibles that the Partnership considers reasonable and
not excessive. The Partnership's 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, the Partnership's insurance policies do not provide coverage for
losses or liabilities relating to pollution, except for sudden and accidental
occurrences. The Partnership does, however, have a Certificate of Financial
Responsibility of $150 million. See "- Environmental - Water."
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 the Partnership's operations and financial
condition. The Partnership believes that it is adequately insured for public
liability and property damage to others with respect to its operations. However,
no assurance can be given that the Partnership will be able to maintain adequate
insurance in the future at rates it considers reasonable.
ENVIRONMENTAL
General. The Partnership's 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 the Partnership's knowledge, its 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 the
Partnership or the Pipelines. In addition, some risk of environmental costs and
liabilities is inherent in the Partnership's operations and products as it is
with other companies engaged in similar or related businesses, and there can be
no assurance that material costs and liabilities, including substantial fines
and criminal sanctions for violation of environmental laws and regulations, will
not be incurred by the Partnership. Furthermore, the Partnership will likely be
required to increase its 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
the Pipelines. The Hazardous Materials Transportation Act, 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 Pipelines' operations may generate or transport both
hazardous and nonhazardous solid wastes that are subject to the requirements of
the federal Resource Conservation and Recovery Act, as amended, 42 U.S.C.
Section 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 the Partnership.
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<PAGE> 16
Hazardous Substances. The Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), 42 U.S.C. Section 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 Environmental Protection Agency
(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, the Partnership may nonetheless generate or transport "hazardous
substances" within the meaning of CERCLA, or comparable state statutes, in the
course of its ordinary operations. Thus, the Partnership 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. The Partnership's operations may be subject to the Clean Air Act
("CAA"), 42 U.S.C. Section 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. The Partnership 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, the Partnership
does not believe its operations will be materially adversely affected by any
such requirements.
Water. The Federal Water Pollution Control Act ("FWPCA") and Clean Water
Act, 33 U.S.C. Section 1311 et. seq., impose strict controls against the
unauthorized discharge of produced waters and other oil and 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"), 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 $150 million. 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 or its
derivatives into state waters. Further, the Coastal Zone Management Act
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") 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, may 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 the Partnership's 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 may impose similar requirements.
Communication of Hazards. The Occupational Safety and Health Act, as
amended, 29 U.S.C. Section 651 et. seq., the Emergency Planning and Community
Right-to-Know Act, as amended, 42 U.S.C. Section 11001 et. seq., and comparable
state statutes require the Partnership 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.
14
<PAGE> 17
EMPLOYEES
Leviathan and the Partnership depend primarily upon the employees of and
management services provided by DeepTech under a management agreement (the
"Management Agreement"). The Partnership reimburses Leviathan, as General
Partner, for all reasonable general and administrative expenses and other
reasonable expenses, incurred by Leviathan and its affiliates for or on behalf
of the Partnership including, but not limited to, amounts payable by Leviathan
to DeepTech under the Management Agreement. A subsidiary of the Partnership has
11 full time employees, based in Houma, Louisiana, to perform operational
functions for its gas pipeline and platform operations.
Because DeepTech has historically provided management services for
Leviathan and the Partnership, upon completion of the merger between DeepTech
and El Paso, Leviathan and the Partnership will hire a management team comprised
of the DeepTech employees that were primarily responsible for the operation of
the Partnership, including the current Chief Executive Officer and the President
of Leviathan. See Part III - Item 10. "Directors and Executive Officers of the
Registrant."
UNCERTAINTY OF FORWARD LOOKING STATEMENTS AND INFORMATION
This Annual Report contains certain forward looking statements and
information that are based on management's beliefs as well as assumptions made
by and information currently available to management. Such statements are
typically punctuated by words or phrases such as "anticipate," "estimate,"
"project," "should," "may," "management believes," and words or phrases of
similar import. Although management believes that such statements and
expressions are reasonable and made in good faith, it can give no assurance that
such expectations will prove to have been correct. Such statements are subject
to certain risks, uncertainties and assumptions. Should one or more of these
risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual results may vary materially from those anticipated, estimated
or projected. Among the key factors that may have a direct bearing on the
Partnership's results of operations and financial condition are: (i) competitive
practices in the industry in which the Partnership competes, (ii) the impact of
current and future laws and government regulations affecting the industry in
general and the Partnership's operations in particular, (iii) environmental
liabilities to which the Partnership may become subject in the future that are
not covered by an indemnity or insurance, (iv) the throughput levels achieved by
the Pipelines and any future pipelines in which the Partnership owns an
interest, (v) the ability to access additional reserves to offset the natural
decline in production from existing wells connected to the Pipelines, (vi)
changes in gathering, transportation, processing, handling and other rates due
to changes in government regulation and/or competitive factors, (vii) the impact
of oil and natural gas price fluctuations, (viii) the production rates and
reserve estimates associated with the Partnership's producing oil and gas
properties, (ix) significant changes from expectations of capital expenditures
and operating expenses and unanticipated project delays and (x) the ability of
the Equity Investees to make distributions to the Partnership. The Partnership
disclaims any obligation to update any forward-looking statements to reflect
events or circumstances after the date hereof.
CERTAIN DEFINITIONS
The following are abbreviations and words commonly used in the oil and gas
industry and in this Annual Report.
"Bcf" means billion cubic feet (or thousand MMcf).
"Btu" means British thermal unit, a unit of heat measure with one btu being
the amount of heat needed to raise the temperature of one pound of water one
degree Fahrenheit.
"development well" means a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.
"gathering system" means a pipeline system connecting a number of wells,
batteries or platforms to an interconnection with an interstate pipeline.
"gross" oil and natural gas wells or "gross" acres are the total number of
wells or acres, respectively, in which the Partnership has an interest, without
regard to the size of that interest.
15
<PAGE> 18
"MBbl" means thousand barrels, a barrel is a standard measure of volume for
oil, condensate and natural gas liquids which equals 42 U.S. gallons.
"Mcf" means thousand cubic feet, a standard measure of volume for gas.
"MMcf" means million cubic feet.
"net" oil and natural gas wells or "net" acres or "net" production or
reserves are the total gross number of wells, acres, production or reserves,
respectively, in which the Partnership has an interest multiplied times the
Partnership's working interest in such wells, acres, production or reserves.
"OCS" means Outer Continental Shelf; an area offshore the United States
over which the federal government has jurisdiction, which extends from the end
of state territorial waters (three to twelve nautical miles offshore, depending
on the state) to 200 nautical miles from shore. The term OCS as used herein
includes not only those areas on the Shelf itself but those areas in the
flextrend and the deepwater, to a limit of 200 nautical miles, as well.
"recompletion" means the completion of an existing well for production from
a formation that exists behind the casing of the well.
"royalty" means an interest in an oil and gas lease that gives the owner of
the interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually carved from the leasehold interest
pursuant to an assignment to a third party reserved by an owner of the leasehold
in connection with a transfer of the leasehold to a subsequent owner.
"working interest" means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. The share of production to which a working interest
owner is entitled will always be smaller than the share of costs that the
working interest owner is required to bear, with the balance of the production
accruing to the owners of royalties. For example, the owner of a 100% working
interest in a lease burdened only by a landowner's royalty of 12.5% would be
required to pay 100% of the costs of a well but would be entitled to retain
87.5% of the production.
In this Annual Report, natural gas volumes are stated at the legal pressure
base of the state or area in which the reserves are located and at 60 degrees
Fahrenheit.
16
<PAGE> 19
ITEM 3. LEGAL PROCEEDINGS
The Partnership 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.
See Items 1& 2. "Business and Properties - Regulation."
In particular, the Partnership is a defendant in a lawsuit filed by
Transcontinental 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 the
Partnership's existing and planned activities on the platform. Transco has
requested a declaratory judgment and is seeking damages. It is the opinion of
management that adequate defenses exist and that the final disposition of this
suit individually, and all of the Partnership's other pending legal proceedings
in the aggregate, will not have a material adverse effect on the Partnership.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders of the
Partnership during the three months ended December 31, 1997.
17
<PAGE> 20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Preference Units are listed on the NYSE, which is the principal trading
market for such securities, under the symbol "LEV." As of March 16, 1998, there
were approximately 665 holders of record of the Preference Units. The following
table sets forth the high and low sales prices for the Preference Units as
reported on the NYSE and the cash distributions declared per Unit for the
periods indicated.
<TABLE>
<CAPTION>
Preference Unit
Price Range
--------------- Distributions
High Low Declared per Unit
---- --- -----------------
<S> <C> <C> <C>
1996
First Quarter $ 16.19 $ 13.75 $ 0.325
Second Quarter 18.00 15.69 0.350
Third Quarter 21.19 18.00 0.375
Fourth Quarter 22.81 20.75 0.400
1997
First Quarter $ 24.25 $ 19.00 $ 0.425
Second Quarter 26.375 20.375 0.450
Third Quarter 28.75 23.25 0.475
Fourth Quarter 33.125 28.00 0.500
</TABLE>
ITEM 6. SELECTED FINANCIAL DATA
The following table presents (i) selected consolidated financial data of
the Partnership for the years ended December 31, 1997, 1996, 1995 and 1994, for
the period from commencement of operations on February 19, 1993 to December 31,
1993, and as of each of the periods then ended and (ii) selected consolidated
financial data of Leviathan for the period from July 1, 1992 through February
18, 1993. The selected financial data of the Partnership at December 31, 1997
and 1996 and for the years ended December 31, 1997, 1996 and 1995 has been
derived from the consolidated financial statements of the Partnership included
elsewhere in this Annual Report. The selected financial data of the Partnership
for the year ended December 31, 1994, for the period from commencement of
operations on February 19, 1993 through December 31, 1993 and at December 31,
1995, 1994 and 1993 has been derived from the historical consolidated financial
statements of the Partnership. The selected consolidated financial data of
Leviathan for the period from July 1, 1992 through February 18, 1993 has been
derived from the historical consolidated financial statements of Leviathan.
18
<PAGE> 21
<TABLE>
<CAPTION>
The Partnership Leviathan
---------------------------------------------------------------- -----------
Period from
February 19, 1993
(Commencement of Period from
Operations) July 1, 1992
Year Ended December 31, through through
---------------------------------------------- December 31, February 18,
1997 1996 1995 1994 1993 1993
---- ---- ---- ---- ----------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Statement of Operations:
Oil and gas sales........................... $58,106 $47,068 $ 1,858 $ 796 $ 551 $ 103
Gathering, transportation
and platform services.................... 17,329 24,005 20,547 18,554 14,588 7,227
Equity in earnings.......................... 29,327 20,434 19,588 14,786 9,351 7,326
------- ------- ------- ------- ------- -------
Total revenue...................... 104,762 91,507 41,993 34,136 24,490 14,656
------- ------- ------- ------- ------- -------
Operating expenses.......................... 11,352 9,068 4,092 1,876 1,534 664
Depreciation, depletion and amortization.... 46,289 31,731 8,290 5,085 2,679 1,003
Impairment, abandonment and other........... 21,222 -- -- -- -- --
General and administrative expenses......... 5,869 788 1,273 2,269 1,216 1,405
Management fee and general and
administrative expenses allocated
from general partner/parent.............. 8,792 7,752 5,796 3,139 1,728 1,272
------- ------- ------- ------- ------- -------
Total operating costs.............. 93,524 49,339 19,451 12,369 7,157 4,344
------- ------- ------- ------- ------- -------
Operating income............................ 11,238 42,168 22,542 21,767 17,333 10,312
Interest income and other................... 1,475 1,710 1,884 1,293 187 351
Interest and other financing costs.......... (14,169) (5,560) (833) (912) (426) (8,064)
Minority interest in income................. 7 (427) (251) (216) (171) --
------- ------- ------- ------- ------- -------
(Loss) income before income taxes........... (1,449) 37,891 23,342 21,932 16,923 2,599
Income tax (benefit) expense................ (311) (801) (603) (136) 93 817
------- ------- ------- ------- ------- -------
Net (loss) income.................. $(1,138) $38,692 $23,945 $22,068 $16,830 $ 1,782
======= ======= ======= ======= ======= =======
Basic and diluted (loss) income per Unit.... $ (0.06) $ 1.57 $ 0.97 $ 1.02 $ 0.91 $ --
======= ======= ======= ======= ======= =======
Distributions per Unit...................... $ 1.75 $ 1.35 $ 1.20 $ 1.20 $ 0.70 $ --
======= ======= ======= ======= ======= =======
Balance Sheet Data:
Property, plant and equipment, net.......... $200,639 $286,555 $285,275 $126,802 $63,313 (a)
Equity investments.......................... 182,301 107,838 82,441 80,560 50,747 (a)
Total assets................................ 409,842 453,526 398,696 231,043 124,980 (a)
Long-term debt.............................. 238,000 227,000 135,780 8,000 8,000 (a)
Partners' capital:
Preference unitholders................... 163,426 196,224 192,225 196,340 115,061 (a)
Common unitholder........................ (15,400) (3,969) (5,380) (3,960) (3,024) (a)
General partner.......................... (4,060) (232) (4) 51 117 (a)
Total partners' capital............ 143,966 192,023 186,841 192,431 112,154 (a)
</TABLE>
- -----------------------------------------
(a) Balance sheet data as of February 18, 1993 related to Leviathan has been
omitted as the information is not required.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the
Partnership's consolidated financial statements and the notes thereto located
elsewhere in this Annual Report and the information set forth under the heading
"Selected Financial Data" and is intended to assist in the understanding of the
Partnership's financial position and results of operations for each of the years
ended December 31, 1997, 1996 and 1995.
19
<PAGE> 22
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1997 COMPARED WITH YEAR ENDED DECEMBER 31, 1996
Oil and 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 the
Partnership's oil and gas properties as a result of initiating production from
Viosca Knoll Block 817 in December 1995, Garden Banks Block 72 in May 1996 and
Garden Banks Block 117 in July 1996. During the year ended December 31, 1997,
the Partnership produced and sold 19,792 MMcf of gas and 801,000 barrels of oil
at average prices of $2.08 per Mcf and $20.61 per barrel, respectively. During
1996, the Partnership produced and sold 15,730 MMcf of gas and 393,000 barrels
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 (i) $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 (ii) $3.0 million related to
lower throughput on the Ewing Bank system offset by increases of (i) $1.8
million in platform services from the Partnership's Viosca Knoll Block 817
platform as a result of additional oil and gas volumes processed on the platform
and (ii) $2.1 million from the Tarpon and Green Canyon systems primarily related
to (x) the deregulation of the Tarpon system allowing the Partnership 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. Gathering volumes from the Tarpon system increased approximately 52%
during the year ended December 31, 1997 as compared with the year ended December
31, 1996 as a result of new producing fields attached to the system in June and
July 1997. Gathering volumes for the Green Canyon system increased 4% for the
year ended December 31, 1997 as compared with the year ended December 31, 1996
due to increased production from the Texaco-operated field located in Green
Canyon Block 6. Gathering volumes from the Manta Ray system, prior to its
contribution to Manta Ray Offshore, declined 34% as compared with 1996 as a
result of temporary platform related production problems from two of the fields
connected to the Manta Ray system. Gathering volumes from the Ewing Bank system
declined 82% during the year ended December 31, 1997 as compared with the same
period in 1996 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 the Equity Investees 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 (i) $2.9
million from Viosca Knoll and UTOS as a result of increased throughput, (ii)
$1.6 million from POPCO, which placed Poseidon in service in three-phases, April
1996, December 1996 and December 1997, (iii) $0.4 million from West Cameron
Dehy, (iv) $3.7 million from Manta Ray Offshore related to the Manta Ray assets
contributed by the Partnership and (v) $2.2 million from Nautilus, primarily as
a result of Nautilus recognizing as other income an allowance for funds used
during construction offset by (vi) a $1.9 million decrease in Stingray and HIOS
as a result of increased maintenance costs during 1997. Total gas throughput
volumes for the Equity Investees increased approximately 9% 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
an Equity Investee, as discussed above. Oil volumes from Poseidon totaled 19.0
million barrels for the year ended December 31, 1997 as compared with 7.5
million barrels 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 operated by the Partnership and the operation by
the Partnership of one additional oil and 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 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 and July 1996, respectively, offset by a
decrease of $5.1 million in depreciation on pipelines, platforms and facilities.
20
<PAGE> 23
Impairment, abandonment and other totaled $21.2 million for the year ended
December 31, 1997 and consisted of a non-recurring charge to reserve the
Partnership's 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 the Partnership's abandonment obligations associated
with the gathering facilities serving these properties, to reserve the
Partnership's 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 gas properties. See "Notes to Consolidated Financial Statements - Note 5
- - Impairment, Abandonment and Other" located elsewhere in this Annual Report.
General and administrative expenses, including the management fee allocated
from Leviathan, 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 POPCO as a result of the Partnership's
management of the initial construction of Poseidon. Excluding this one-time
reimbursement by POPCO, 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 (i) a $1.5 million increase in management fees
allocated by Leviathan to the Partnership as a result of increased operational
activities, (ii) a $3.6 million increase in direct general and administrative
expenses of the Partnership primarily related to the appreciation and vesting of
unit appreciation rights granted to certain officers and employees in 1995, 1996
and 1997 and (iii) a $0.4 million decrease in the reimbursement to DeepTech for
certain tax liabilities pursuant to the management agreement with Leviathan. See
"Notes to Consolidated Financial Statements - Note 8 - Partners' Capital" and "
- - Note 10 - Related Party Transactions - Management Fees" located elsewhere in
this Annual Report.
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, net of 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, the Partnership 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.
Net loss for the year ended December 31, 1997 totaled $1.1 million as
compared with net income of $38.7 million for the year ended December 31, 1996
as a result of the items discussed above.
YEAR ENDED DECEMBER 31, 1996 COMPARED WITH YEAR ENDED DECEMBER 31, 1995
Oil and gas sales totaled $47.1 million for the year ended December 31,
1996 as compared with $1.9 million for the year ended December 31, 1995. The
increase of $45.2 million is attributable to the initiation of production from
the Partnership's Viosca Knoll Block 817 in December 1995, Garden Banks Block 72
in May 1996 and Garden Banks Block 117 in July 1996. During the year ended
December 31, 1996, the Partnership produced and sold 15,730 MMcf of gas and
393,000 barrels of oil at average prices of $2.37 per Mcf and $21.76 per barrel,
respectively. During 1995, the Partnership produced and sold 392 MMcf of gas at
an average price of $2.35 per Mcf.
Revenue from gathering, transportation and platform services totaled $24.0
million for the year ended December 31, 1996 as compared with $20.5 million for
the year ended December 31, 1995. The increase of $3.5 million includes
increases of $3.0 million in platform services from the Partnership's Viosca
Knoll Block 817 platform, which was placed in service during the third quarter
of 1995 and $2.6 million related to the Green Canyon system attributable to the
connection of a new gas field located in Green Canyon Block 136 to the system
offset by a decrease of $2.1 million attributable to lower throughput on the
Ewing Bank and Tarpon systems due to normal production declines from the wells
attached to such systems. Volumes for the gathering systems increased 15.4% from
the year ended December 31, 1995 to the year ended December 31, 1996. This
increase is primarily a result of increased throughput on the Green Canyon
system as a result of the addition of Green Canyon Block 136 partially offset by
lower production from the producing fields attached to the Ewing Bank, Tarpon
and Manta Ray Offshore systems.
Revenue from the Equity Investees totaled $20.4 million for the year ended
December 31, 1996 as compared with $19.6 million for the year ended December 31,
1995. The increase of $0.8 million primarily reflects increases of (i) $3.4
million from Viosca Knoll as a result of increased throughput on the system,
(ii) $1.1 million from POPCO, which placed Poseidon in service in April 1996 and
December 1996, and (iii) $0.7 million from West Cameron Dehy, which
21
<PAGE> 24
was placed in service in November 1995, offset by a decrease of $4.4 million
related primarily to Stingray, HIOS and UTOS. Total gas throughput volumes for
the Equity Investees increased approximately 15.6% from the year ended December
31, 1995 to the year ended December 31, 1996 primarily as a result of increased
throughput on the Viosca Knoll, HIOS and Stingray systems. Oil volumes from
Poseidon totaled 7.5 million barrels for the period from inception of operations
in April 1996 through December 31, 1996.
Operating expenses for the year ended December 31, 1996 totaled $9.1
million as compared with $4.1 million for the year ended December 31, 1995. The
increase of $5.0 million is primarily attributable to the operation by the
Partnership of 12 additional oil and gas wells during the year ended December
31, 1996 as compared with the same period in 1995.
Depreciation, depletion and amortization totaled $31.7 million for the year
ended December 31, 1996 as compared with $8.3 million for the year ended
December 31, 1995. The increase of $23.4 million results primarily from
depreciation and depletion on the oil and gas wells and facilities located on
Viosca Knoll Block 817, Garden Banks Block 72 and Garden Banks Block 117,
depreciation on additional platforms and facilities constructed by the
Partnership and accelerated depreciation on the Ewing Bank flow lines.
General and administrative expenses, including the management fee allocated
from Leviathan, totaled $8.5 million for the year ended December 31, 1996 as
compared with $7.1 million for the year ended December 31, 1995. The increase of
$1.4 million primarily reflects (i) a $1.2 million reimbursement to DeepTech for
certain tax liabilities incurred by DeepTech as a result of the Partnership's
public offering of an additional Preference Units in June 1994, (ii) a $0.8
million increase in management fees allocated by Leviathan to the Partnership as
a result of increased operational activities and (iii) a $0.8 million increase
in other general and administrative expenses of the Partnership, also as a
result of increased Partnership activities, offset by a $1.4 million
reimbursement from POPCO as a result of the Partnership's management of the
initial construction of Poseidon. See "Notes to Consolidated Financial
Statements - Note 10 - Related Party Transactions - Management Fees" and "- Note
10 - Related Party Transactions - Other" located elsewhere in this Annual
Report.
During the year ended December 31, 1995, the Partnership recognized a $1.2
million gain on sale of certain oil and gas mineral leaseholds.
Interest income and other totaled $1.7 million for the year ended December
31, 1996 as compared with $0.6 million for the year ended December 31, 1995. The
increase in interest income is primarily due to accrued interest of $1.1 million
related to the $7.5 million that was added to a payout amount in connection with
restructuring the demand charges payable to the Partnership from Tatham
Offshore. See "Notes to Consolidated Financial Statements - Note 5 Impairment,
Abandonment and Other" located elsewhere in this Annual Report.
Interest and other financing costs, net of capitalized interest, for the
year ended December 31, 1996 totaled $5.6 million as compared with $0.8 million
for the year ended December 31, 1995. Interest and fees associated with the
Partnership's credit facilities of $11.9 million and $5.3 million were
capitalized in connection with construction projects and drilling activities in
progress during the years ended December 31, 1996 and 1995, respectively.
Net income for the year ended December 31, 1996 totaled $38.7 million as
compared with $23.9 million for the year ended December 31, 1995 as a result of
the items discussed above.
LIQUIDITY AND CAPITAL RESOURCES
Sources of Cash. The Partnership intends to satisfy its capital
requirements and other working capital needs primarily from cash on hand, cash
from operations and borrowings under the Partnership Credit Facility (discussed
below). Net cash provided by operating activities for the year ended December
31, 1997 totaled $67.5 million. At December 31, 1997, the Partnership had cash
and cash equivalents of $6.4 million.
Cash from operations is derived from (i) payments for gathering gas through
the Partnership's 100% owned pipelines, (ii) platform access and processing
fees, (iii) cash distributions from Equity Investees and (iv) the sale of oil
and gas attributable to the Partnership's interest in its producing properties.
Oil and gas properties are depleting assets and will produce reduced volumes of
oil and gas in the future unless additional wells are drilled or recompletions
of existing wells are successful. See Items 1 & 2. "Business and Properties -
Oil and Gas Properties - Description of Oil and Gas Properties" for current
production rates from these properties.
22
<PAGE> 25
The Partnership's cash flows from operations will be affected by the
ability of each Equity Investee to make distributions. Distributions from such
entities are also subject to the discretion of their respective management
committees. Further, each of Stingray, POPCO and Viosca Knoll is party to a
credit agreement under which it has outstanding obligations that may restrict
the payments of distributions to its owners. Distributions to the Partnership
from Equity Investees during the year ended December 31, 1997 totaled $27.1
million.
The Partnership Credit Facility is a revolving credit facility providing
for up to $300 million of available credit subject to customary terms and
conditions, including certain debt incurrence limitations. Proceeds from the
Partnership Credit Facility are available to the Partnership for general
partnership purposes, including financing of capital expenditures, for working
capital, and subject to certain limitations, for paying distributions to the
Unitholders. The Partnership 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 Partnership Credit Facility matures in
December 1999; is guaranteed by Leviathan and each of the Partnership's
subsidiaries; and is secured by the Management Agreement, substantially all of
the assets of the Partnership and Leviathan's 1% general partner interest in the
Partnership and approximate 1% interest in certain subsidiaries of the
Partnership. As of December 31, 1997, the Partnership had $238.0 million
outstanding under its credit facility bearing interest at an average floating
rate of 6.61% per annum. Currently, approximately $38.0 million of additional
funds are available under the Partnership Credit Facility.
In December 1995, Stingray amended an existing term loan agreement to
provide for aggregate outstanding borrowings of up to $29.0 million in principal
amount. The agreement requires the payment of principal by Stingray of $1.45
million per quarter. The term loan agreement is principally secured by current
and future gas transportation contracts between Stingray and its customers and
matures on December 31, 2000. As of December 31, 1997, Stingray had $17.4
million outstanding under its term loan agreement bearing interest at an average
floating rate of 6.5% per annum.
In April 1996, POPCO entered into a revolving credit facility (the "POPCO
Credit Facility") with a group 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 secured by a substantial portion of POPCO's assets
and matures on April 30, 2001. As of December 31, 1997, POPCO had $120.5 million
outstanding under its credit facility bearing interest at an average floating
rate of 7.2% per annum. Currently, approximately $25.0 million of additional
funds are available under the POPCO Credit Facility.
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 to 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. 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 secured by a substantial portion of Viosca Knoll's assets and
matures on December 20, 2001. As of December 31, 1997, Viosca Knoll had $52.2
million outstanding under its credit facility bearing interest at an average
floating rate of 6.7% per annum. Currently, approximately $18.7 million of
additional funds are available under the Viosca Knoll Credit Facility.
Uses of Cash. The Partnership's capital requirements consist primarily of
(i) quarterly distributions to holders of Preference Units and Common Units and
to Leviathan as general partner, including incentive distributions, as
applicable, (ii) expenditures for the maintenance of its pipelines and related
infrastructure and the acquisition and construction of additional pipelines and
related facilities for the gathering, transportation and processing of oil and
gas in the Gulf, (iii) expenditures related to its producing oil and gas
properties, (iv) management fees and other operating expenses, (v) contributions
to Equity Investees as required to fund capital expenditures for new facilities
and (vi) debt service on its outstanding indebtedness.
For every full quarter since its inception, the Partnership has declared
and subsequently paid a cash distribution to holders of Preference Units and
Common Units an amount equal to or exceeding the Minimum Quarterly Distribution
(as described in the Partnership Agreement) per Unit per quarter. See Item 5.
"Market for Registrant's Common Stock and Related Stockholder Matters". At the
current distribution rate of $0.50 per Unit, the quarterly Partnership
distributions total $14.8 million in respect of the Preference Units, Common
Units and general partner interest ($59.2 million on an annual basis, including
$23.0 million to Leviathan). The Partnership believes that it will be able to
continue to pay at least the current quarterly distribution of $0.50 per
Preference and Common Unit for the foreseeable future.
23
<PAGE> 26
Distributions by the Partnership of its Available Cash are effectively made
98% to Unitholders and 2% to Leviathan, as General Partner, subject to the
payment of incentive distributions to Leviathan 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. For
the year ended December 31, 1997, the Partnership paid Leviathan Incentive
Distributions totaling $3.9 million and paid Leviathan an Incentive Distribution
of $2.4 million in February 1998.
In January 1997, the Partnership and affiliates of Marathon and Shell
formed Nautilus to construct and operate a new interstate natural gas pipeline
system. In addition, the same parties formed Manta Ray Offshore to acquire an
existing gathering system from the Partnership. The gathering system was
extended and is currently delivering gas to several downstream pipelines,
including the Nautilus system. The Nautilus and Manta Ray Offshore systems are
located to serve growing production areas in the Green Canyon area of the Gulf
and are indirectly owned 50% by Shell, 24.3% by Marathon and 25.7% by the
Partnership. The capital costs associated with the construction of the Nautilus
interstate pipeline system and the expansion of the Manta Ray Offshore gathering
system, including the value of the existing assets contributed by the partners,
totaled approximately $250 million. The Nautilus system consists of 101 miles of
30-inch pipeline downstream from Ship Shoal Block 207 connecting to a gas
processing plant, onshore Louisiana, operated by Exxon, plus certain facilities
downstream of the Exxon plant to effect deliveries into multiple interstate
pipelines. Upstream of the Ship Shoal Block 207 platform, the existing Manta Ray
Offshore gathering system was extended into a broader gathering system that
serves shelf and deepwater production areas around Ewing Bank Block 1008 to the
east and Green Canyon Block 65 to the west. The Manta Ray Offshore 47-mile
expansion was completed and placed in service in November 1997. The Nautilus
system, including the related onshore facilities and platform connections, was
completed and placed in service in December 1997. Affiliates of Marathon and
Shell dedicated for transportation and gathering to each of the Nautilus and
Manta Ray Offshore systems significant deepwater acreage positions in the area
and provided substantially all of the capital funding for the new construction.
The Partnership provided $11.1 million of funding in the form of a newly
constructed compressor in addition to its contribution of the Manta Ray Offshore
system.
The Partnership anticipates that its capital expenditures and equity
investments for 1998 will relate to continuing acquisition and construction
activities, including the construction and installation of a new platform and
processing facilities at East Cameron Block 373. This platform, which the
Partnership anticipates will be placed in service during April 1998 at a
projected cost of approximately $32 million, will be strategically located to
exploit reserves in the East Cameron and Garden Banks area of the Gulf and will
be the terminus for an extension of the Stingray system. The Partnership
anticipates funding such cash requirements primarily with available cash flow
and borrowings under the Partnership Credit Facility.
Substantially all of the capital expenditures by POPCO, Viosca Knoll and
Stingray were funded by borrowings under their respective credit facilities, and
any future capital expenditures by POPCO, Viosca Knoll and Stingray are
anticipated to be funded by borrowings under their respective credit facilities.
In addition, substantially all of the capital requirements of Nautilus and Manta
Ray Offshore were funded by the equity contributions of affiliates of Shell and
Marathon. The Partnership's cash capital expenditures and equity investments for
the year ended December 31, 1997 were $42.0 million, including $11.1 million
related to the Nautilus/Manta Ray Offshore project discussed above. The
Partnership contributed existing assets to the Nautilus and Manta Ray Offshore
joint ventures as partial consideration for its ownership interest therein and
may in the future contribute existing assets to new joint ventures as partial
consideration for its ownership interest therein.
Interest costs incurred by the Partnership related to the Partnership
Credit Facility totaled $15.9 million for the year ended December 31, 1997. The
Partnership capitalized $1.7 million of such interest costs in connection with
construction projects and drilling activities in process during the year.
The Partnership has reviewed its costs related to the "Year 2000" issue and
anticipates that these costs will not materially affect its future results of
operations.
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<PAGE> 27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Financial Statements and Supplementary Data required hereunder are
included in this Annual Report as set in Item 14(a).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
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<PAGE> 28
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
GENERAL
The General Partner and the Partnership depend upon the employees of and
management services provided by DeepTech under the Management Agreement. The
Partnership reimburses the General Partner for reasonable general and
administrative expenses, and other reasonable expenses, incurred by the General
Partner and its affiliates, including DeepTech, for or on behalf of the
Partnership, including, without limitation, fees paid by the General Partner to
DeepTech pursuant to the Management Agreement.
Some of the officers and directors of the General Partner are also officers
and directors of DeepTech and its affiliates. Such officers and directors may
spend a substantial amount of time managing the business and affairs of the
General Partner and may face a conflict regarding the allocation of their time
between the Partnership and the other business interests of the General Partner,
DeepTech and its affiliates. Subject to its fiduciary duties to the Partnership
and its limited partners, the General Partner may retain, acquire and invest in
businesses that compete with the Partnership, subject to certain limitations.
DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER
The following table sets forth certain information as of March 16, 1998,
regarding the executive officers and directors of the General Partner who
provide services to the Partnership. The General Partner has appointed each of
its officers to serve the Partnership in the same office or offices each such
officer holds with the General Partner. Directors are elected annually by the
General Partner's sole stockholder, Leviathan Holdings Company ("Leviathan
Holdings"), 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 or her earlier
removal or resignation from office.
There is no family relationship among any of the executive officers or
directors of the General Partner, and no arrangement or understanding exists
between any executive officer and any other person pursuant to which he or she
was or is to be selected as an officer.
<TABLE>
<CAPTION>
Name Age Position(s)
---- --- -----------
<S> <C> <C>
Thomas P. Tatham 52 Chairman of the Board
Grant E. Sims 42 Director and Chief Executive Officer
James H. Lytal 40 Director and President
John H. Gray 56 Director and Chief Operating Officer
Donald V. Weir 56 Director and Secretary
Keith B. Forman 39 Director and Chief Financial Officer
Dennis A. Kunetka 48 Senior Vice President
Janet E. Sikes 44 Director
Charles M. Darling, IV 49 Director
Paul Thompson III 48 Director
George L. Ball 59 Director
William A. Bruckmann, III 46 Director
</TABLE>
Thomas P. Tatham has served as Chairman of the Board of Leviathan and
DeepTech since February 1989 and October 1989, respectively. Mr. Tatham served
as Chief Executive Officer of Leviathan from February 1989 through June 1995 and
has served as Chief Executive Officer of DeepTech since October 1989. In
addition, Mr. Tatham has served as Chairman of the Board and Director of Tatham
Offshore since its inception in 1988 and as Chief Executive Officer of Tatham
Offshore since November 1995. Mr. Tatham has over 28 years experience in the oil
and gas industry. He founded Mid American Oil Company in 1970 and served as
Chairman of the Board and Chief Executive Officer until he sold his interest
therein to Centex Corporation in 1979. In 1979, Mr. Tatham founded Tatham
Corporation to acquire Sugar Bowl Gas Corporation ("Sugar Bowl"), the second
largest intrastate pipeline system in Louisiana. He served as Chairman of the
Board of Tatham Corporation from 1979 to December 1983, at which time it
26
<PAGE> 29
sold the assets of Sugar Bowl to a joint venture between MidCon Corp. and Texas
Oil and Gas, Inc. From 1984 to 1988, Mr. Tatham pursued personal investments in
various industries, including the oil and gas industry.
Grant E. Sims served as President of Leviathan from March 1994 through June
1995 and as Chief Executive Officer of Leviathan since July 1995. In addition,
Mr. Sims has served as Senior Vice President of DeepTech since July 1993. Mr.
Sims has also served as a Director of DeepTech and Leviathan since July 1993 and
August 1994, respectively, and 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 gas activities. Mr. Sims
received a B.A. and Ph.D. in Economics from Texas A&M University.
James H. Lytal has served as a Director of Leviathan since August 1994 and
as Senior Vice President of Leviathan from August 1994 to June 1995 and as
President of Leviathan since July 1995. Prior to joining Leviathan, 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 gas exploration and production and gas pipeline industries with Texas
Oil and Gas, Inc. and American Pipeline Company from September 1980 to March
1991. Mr. Lytal holds a B.S. in Petroleum Engineering from the University of
Texas.
John H. Gray has served as a Director of Leviathan since September 1991, as
Chief Operating Officer of Leviathan since March 1994, and as President of
Leviathan from August 1991 to March 1994. From August 1990 to August 1991, Mr.
Gray was the owner of J.H. Gray Consulting, an oil and gas marketing consulting
company. Prior thereto, Mr. Gray served as President of Torch Energy Marketing,
Inc., an oil and gas marketing and natural gas pipeline company from August 1989
to August 1990, and Vice President of Oil and Gas Products of Tenneco Oil
Exploration and Production from May 1984 to August 1989. Mr. Gray has a B.S. in
Engineering from the Colorado School of Mines.
Donald V. Weir has served as a Director of Leviathan since 1989, Secretary
of Leviathan since March 1994 and served as Chief Operating Officer of Leviathan
from 1989 to March 1994. In addition, Mr. Weir has served as Chief Financial
Officer and a Director of DeepTech since June 1991, Vice President of DeepTech
since 1989, Secretary of DeepTech from 1989 to August 1993. In addition, Mr.
Weir has served as Secretary and a Director of Tatham Offshore from 1988 through
September 1995 and as Chief Financial Officer of Tatham Offshore from 1991
through September 1995. From 1988 until 1991, he served as a Vice President of
Tatham Offshore. Prior to joining Leviathan, Mr. Weir served in various
executive capacities with numerous entities owned and controlled by Mr. Tatham.
Prior to joining Mr. Tatham's organizations in 1980, Mr. Weir was with Price
Waterhouse LLP for 14 years.
Keith B. Forman has served as the Chief Financial Officer and as a Director
of Leviathan since January 1992 and July 1992, respectively. Prior to joining
Leviathan, 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 gas transmission companies and gas gathering
companies. Mr. Forman has a B.A. in Economics and Political Science from
Vanderbilt University.
Dennis A. Kunetka has served as Senior Vice President-Corporate Finance and
Investor Relations for DeepTech and Leviathan since August 1993 and as Chief
Financial Officer of Tatham Offshore since January 1998. Mr. Kunetka served as
Senior Vice President-Corporate Finance for Tatham Offshore from October 1993 to
December 1997. Prior to joining DeepTech, Mr. Kunetka served as Vice President
and Controller of United Gas Pipe Line Company and its parent company, United
Gas Holdings Corporation ("United"). Prior to joining United in 1984, Mr.
Kunetka spent 11 years with Getty Oil Company in various tax, financial and
regulatory positions. Mr. Kunetka holds B.B.A. and M.S.A. degrees from the
University of Houston and a J.D. degree from South Texas College of Law and is a
certified public accountant.
27
<PAGE> 30
Janet E. Sikes has served as a Director of Leviathan since September 1991
and as a Director of DeepTech since July 1993. Ms Sikes served as Treasurer of
DeepTech from May 1991 to December 1997 and as Secretary of DeepTech from August
1993 to December 1997. Ms. Sikes has managed accounting, treasury, cash
management and financial reporting functions for various entities owned and
controlled by Mr. Tatham since 1981. Prior thereto, Ms. Sikes worked in the
audit division of Price Waterhouse LLP, and for two years as the Assistant
Controller of Ocean Marine Services, Inc. Ms. Sikes holds a B.B.A. from Texas
A&M University and is a certified public accountant.
Charles M. Darling, IV has served as a Director of Leviathan and DeepTech
since October 1989 and February 1989, respectively, and as President and General
Counsel of DeepTech since May 1997. Prior to joining DeepTech, Mr. Darling was a
partner in the law firm of Baker & Botts, L.L.P. since 1980, originally joining
the firm in 1974. Mr. Darling represented companies in the oil and gas industry
for over 20 years and has been involved in vanguard projects in the natural gas
industry from a regulatory and business perspective.
Paul Thompson III has served as a Director of Leviathan and DeepTech since
July 1992. Mr. Thompson has served as a Managing Director of Donaldson, Lufkin &
Jenrette Securities Corporation ("DLJ") and the Chief Operating Officer of DLJ
Bridge Finance, Inc., an affiliate of DLJ since 1987. Prior thereto, Mr.
Thompson was a Vice President of The First Boston Corporation. Mr. Thompson is
currently a Director of E-Z Serve Corporation, which operates convenience
stores. Mr. Thompson received a B.S. degree from the University of Pennsylvania.
George L. Ball has served as a Director of Leviathan since June 1993. Mr.
Ball is Chairman of Sanders Morris Mundy Inc. Previously, Mr. Ball served as
Senior Executive Vice President at Smith Barney, Harris Upham & Co. Incorporated
("Smith Barney") and as a member of Smith Barney's Executive Committee and Board
of Directors. From August 1991 through October 1992, Mr. Ball served as a
consultant with J & W Seligman. Mr. Ball served as Chairman of the Board and
Chief Executive Officer of Prudential Capital and Investment Services, Inc. and
its primary subsidiary, Prudential Securities Incorporated, an investment
banking and brokerage firm (collectively, "Prudential") from July 1981 through
August 1991. Prior to joining Prudential, Mr. Ball was President of E.F. Hutton
Group Inc. and E.F. Hutton Inc. Mr. Ball holds a B.A. degree, with honors, from
Brown University.
William A. Bruckmann, III has served as a Director of Leviathan since June
1993. Mr. Bruckmann has served as Managing Director in the Global Oil and Gas
Group of Chase Securities Inc. since June 15, 1985. During his 18 years with
Chase Securities Inc. and predecessor companies (Chemical Bank and
Manufacturer's Hanover Trust Company), Mr. Bruckmann has principally focused on
financing domestic natural gas pipelines and independent oil and gas producing
companies. Mr. Bruckmann holds a B.A. degree from the University of Virginia.
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 of Directors or committees thereof.
Messrs. Thompson, Ball and Bruckmann are paid an annual fee of $36,000 plus
$1,000 per meeting attended. Officers are elected by, and serve at the
discretion of, the Board of Directors.
Pursuant to the Leviathan non-employee director compensation arrangements,
the Partnership is obligated to pay each non-employee director 2 1/2% of the
General Partners' Incentive Distribution as a profit participation fee. During
the year ended December 31, 1997, the Partnership paid the three non-employee
directors of Leviathan a total of $0.3 million as a profit participation fee.
CONFLICTS AND AUDIT COMMITTEE
Messrs. Thompson, Ball and Bruckmann, who are neither officers nor employees of
Leviathan nor any of its affiliates, serve as the Conflicts and Audit Committee
of the Board of Directors of the General Partner and of the Partnership (the
"Conflicts and Audit Committee"). The Conflicts and Audit 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
policies and practices of the General Partner and the Partnership. Second, the
Conflicts and Audit 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 the Partnership. The
Conflicts and Audit 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
28
<PAGE> 31
submit to such Committee. Any such matters approved by a majority vote of the
Conflicts and Audit Committee will be conclusively deemed (i) to be fair and
reasonable to the Partnership, (ii) approved by all limited partners of the
Partnership and (iii) not a breach by the General Partner of any duties it may
owe to the Partnership. However, it is possible that such procedure in itself
may constitute a conflict of interest.
COMPENSATION OF THE GENERAL PARTNER AND DEEPTECH
The General Partner receives no remuneration in connection with its
management of the Partnership other than: (i) distributions in respect of its
general and limited partner interests in the Partnership and its nonmanaging
interest in certain subsidiaries of the Partnership; (ii) Incentive
Distributions in respect of its general partner interest, as provided in the
Partnership Agreement and (iii) reimbursement for all direct and indirect costs
and expenses incurred on behalf of the Partnership, all selling, general and
administrative expenses incurred by the General Partner for or on behalf of the
Partnership and all other expenses necessary or appropriate to the conduct of
the business of, and allocable to, the Partnership, including, but not limited
to the management fees paid by the General Partner to DeepTech under the
Management Agreement.
LIMITATIONS ON DIRECTORS' AND OFFICERS' LIABILITY; INDEMNIFICATION
The Certificate of Incorporation of Leviathan limits the liability of the
directors of Leviathan to Leviathan or its stockholder (in their capacity as
directors but not in their capacity as officers) to the fullest extent permitted
by the Delaware General Corporation Law (the "DGCL"). Accordingly, pursuant to
the terms of the DGCL as presently in effect, directors of Leviathan will not be
personally liable for monetary damages for breach of a director's fiduciary duty
as a director, except for liability (i) for any breach of the director's duty of
loyalty to Leviathan or its stockholder, (ii) for acts or omissions not in good
faith or which involve intentional misconduct or a knowing violation of law,
(iii) for unlawful payments of dividends or unlawful stock repurchases or
redemptions as provided in Section 174 of the DGCL or (iv) for any transaction
from which the director derived an improper personal benefit. The Certificate of
Incorporation also provides that if the DGCL is amended after the approval of
the Certificate of Incorporation to authorize corporate action further
eliminating or limiting the personal liability of directors, then the liability
of a director of Leviathan will be eliminated to the full extent permitted by
the DGCL, as so amended.
In addition, the Amended and Restated Bylaws of Leviathan (as amended and
restated, the "Bylaws"), in substance, require Leviathan to indemnify each
person who is or was a director, officer, employee or agent of Leviathan to the
full extent permitted by the laws of the State of Delaware in the event he or
she is involved in legal proceedings by reason of the fact that he or she is or
was a director, officer, employee or agent of Leviathan, or is or was serving at
Leviathan's request as a director, officer, employee or agent of the Partnership
and its subsidiaries, another corporation, partnership or other enterprise.
Leviathan 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 or she is not entitled to be indemnified. In
addition, the Bylaws specifically provide that the indemnification rights
granted thereunder are non-exclusive.
Leviathan has entered into indemnification agreements with its directors
providing for indemnification to the full extent permitted by the laws of the
State of Delaware. These agreements provide for specific procedures to better
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.
ITEM 11. EXECUTIVE COMPENSATION
The executive officers of Leviathan are compensated by DeepTech and do not
receive compensation from Leviathan or the Partnership for their services in
such capacities with the exception of awards pursuant to the Unit Rights
Appreciation Plan discussed below. However, Leviathan does make certain payments
to DeepTech pursuant to the Management Agreement.
29
<PAGE> 32
UNIT RIGHTS APPRECIATION PLAN
In 1995, the Partnership adopted the Unit Rights Appreciation Plan (the
"Plan") to provide the Partnership with the ability of making awards of Unit
Rights, as hereinafter defined, to certain officers and key employees of the
Partnership or its affiliates as an incentive for these individuals to continue
in the service of the Partnership or its affiliates.
Under the Plan, the Partnership may grant to senior officers of the
Partnership or its affiliates, excluding the Chairman of the Board of Leviathan,
currently Mr. Tatham, the right to purchase, or realize the appreciation in, a
Preference Unit (a "Unit Right"), pursuant to the provisions of the Plan.
The Plan is administered by a committee of the Board of Directors of the
General Partner (the "Board") comprised of two or more non-employee directors as
defined by Rule 16 b-3 of the Exchange Act (the "Committee") provided that
during the periods in which no such committee is appointed and empowered under
the Plan, the Board shall be the Committee for all purposes under the Plan.
The aggregate number of Preference Units as to which Unit Rights may be
issued pursuant to the Plan shall not exceed 400,000 Preference Units per
calendar year and 4,000,000 Preference Units over the term of the Plan, subject
to adjustment as to both limitations under certain circumstances. No participant
may be granted more than 400,000 Unit Rights in any calendar year. The exercise
price of the Preference Units covered by the Unit Rights granted pursuant to the
Plan shall be the closing price of the Preference Units as reported on the NYSE
or, if the Preference Units are not traded on such exchange, as reported on any
other national securities exchange on which the Preference Units are traded, on
the date on which Unit Rights are granted pursuant to the Plan.
As of March 16, 1998, a total of 1,200,000 Unit Rights have been granted
under the Plan representing 400,000 Unit Rights for each of the calendar years
1995, 1996 and 1997.
SUMMARY COMPENSATION TABLE
The following table sets forth the compensation earned by Leviathan's
Chief Executive Officer and each of its four other most highly compensated
executive officers for the year ended December 31, 1997 (collectively, the
"Named Officers"):
<TABLE>
<CAPTION>
ANNUAL COMPENSATION (1) LONG-TERM
------------------------------------------------------- COMPENSATION
MARKET VALUE OTHER ANNUAL AWARDS ALL OTHER
NAME/PRINCIPAL FISCAL SALARY BONUS OF STOCK COMPENSATION OPTIONS COMPENSATION
<S> <C> <C> <C> <C> <C> <C> <C>
POSITION YEAR ($) ($) ISSUED ($) (#) ($)
Thomas P. Tatham.... 1997 -- -- -- -- -- --
Chairman 1996 -- -- -- -- -- --
1995 -- -- -- -- -- --
Grant E. Sims....... 1997 -- -- -- -- 125,000 --
Chief Executive 1996 -- -- -- -- 90,000 --
Officer 1995 -- -- -- -- -- --
James H. Lytal...... 1997 -- -- -- -- 125,000 --
President 1996 -- -- -- -- 90,000 --
1995 -- -- -- -- -- --
John H. Gray........ 1997 -- -- -- -- 125,000 --
Chief Operating 1996 -- -- -- -- 90,000 --
Officer 1995 -- -- -- -- -- --
Donald V. Weir...... 1997 -- -- -- -- -- --
Vice President 1996 -- -- -- -- -- --
1995 -- -- -- -- -- --
</TABLE>
- ----------------
(1) Other than awards made under the Plan, all other compensation was paid by
DeepTech.
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<PAGE> 33
OPTION GRANTS
The following table sets forth certain information with respect to option
grants made to the Named Officers during the year ended December 31, 1997:
<TABLE>
<CAPTION>
PERCENT OF
TOTAL
OPTIONS
GRANTED
NUMBER OF TO EXERCISE POTENTIAL REALIZABLE VALUE AT
SHARES OF COMMON EMPLOYEES OR ASSUMED ANNUAL RATES OF
STOCK UNDERLYING IN FISCAL BASE PRICE EXPIRATION STOCK PRICE APPRECIATION FOR
NAME OPTIONS GRANTED YEAR ($/SH) DATE OPTION TERM
5% ($) 10% ($)
<S> <C> <C> <C> <C> <C> <C>
Grant E. Sims 125,000 (1) 15.6% $21.50 2/17/2003 $ 1,094,000 $ 2,312,000
James H. Lytal 125,000 (1) 15.6% $21.50 2/17/2003 $ 1,094,000 $ 2,312,000
John H. Gray 125,000 (1) 15.6% $21.50 2/17/2003 $ 1,094,000 $ 2,312,000
</TABLE>
- --------------
(1) Issued under the Plan.
OPTION EXERCISES AND YEAR-END VALUE TABLE
The following table sets forth certain information regarding the
outstanding Unit Rights held by the Named Officers at December 31, 1997:
<TABLE>
<CAPTION>
NUMBER OF VALUE OF UNEXERCISED
UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT
SHARES ACQUIRED VALUE FISCAL YEAR-END (#) FISCAL YEAR-END
NAME ON EXERCISE (#) REALIZED ($) EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE
<S> <C> <C> <C> <C> <C> <C>
Thomas P. Tatham .......... -- -- -- / -- $ -- / $ --
Grant E. Sims.............. -- -- -- / 215,000 -- / 2,485,000
James H. Lytal............. -- -- -- / 215,000 -- / 2,485,000
John H. Gray............... -- -- -- / 215,000 -- / 2,485,000
Donald V. Weir............. -- -- -- / -- -- / --
</TABLE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All of Leviathan's outstanding common stock, par value $0.10 per share, is
owned by Leviathan Holdings. The common stock of Leviathan Holdings is owned
85.0% by DeepTech and 14.25% by directors of Leviathan as indicated in the
following table, with the remaining .75% of the outstanding stock being owned by
two individuals. In connection with the merger of El Paso and DeepTech, El Paso
will acquire the 15% minority interest in Leviathan not currently owned by
Leviathan Holdings. Leviathan Holdings has no other class of capital stock
outstanding.
31
<PAGE> 34
The following table sets forth, as of March 2, 1998, the beneficial
ownership of the outstanding equity securities of each of the Partnership,
Leviathan Holdings and DeepTech by (i) each person who is known to the
Partnership to beneficially own more than 5% of the outstanding Units of the
Partnership, (ii) each director of Leviathan and (iii) all directors and
executive officers of Leviathan as a group. A public trading market does not
currently exist for the capital stock of Leviathan or Leviathan Holdings.
<TABLE>
<CAPTION>
UNITS/SHARES OF CLASS BENEFICIALLY OWNED
------------------------------------------------------------------
LEVIATHAN
PARTNERSHIP HOLDINGS DEEP TECH
PREFERENCE UNITS COMMON STOCK(1) COMMON STOCK
------------------- ------------------ ----------------------
BENEFICIAL OWNER NUMBER PERCENT NUMBER PERCENT NUMBER PERCENT
- ---------------- --------- ------- ------- ------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
Leviathan(2) (2) (2) -- -- -- --
DeepTech(3) (3) (3) 850 85% -- --
Thomas P. Tatham(4) -- -- 30 3% 9,476,370(5) 37.9%
Grant E. Sims 24,000 * -- -- 770,000(6) 3.1%
Charles M. Darling, IV 6,000(7) * 50 5% 770,628(8) 3.1%
Keith B. Forman 600 * -- -- 42,015(9) *
John H. Gray -- -- 50 5% 113,631(10) *
Janet E. Sikes 1,345 * -- -- 289,544(11) 1.2%
Paul Thompson III 2,000 * -- -- 228,147(12) *
Donald V. Weir 20,000 * 12.5 1.25% 338,819(13) 1.4%
James H. Lytal 1,016 * -- -- 35,573(14) *
George L. Ball 1,000 * -- -- -- --
William A. Bruckmann, III -- -- -- -- -- --
Executive officers and
directors of Leviathan as
a group (12 persons) 56,961 * 142.5 14.25% 12,085,299(15) 47.1%
</TABLE>
- ---------------------
(1) Excludes each named person's indirect ownership interest, if any, in the
850 shares (85% of the outstanding shares) of Leviathan Holdings owned by
DeepTech.
(2) The address for Leviathan is 600 Travis Street, Suite 7200, Houston, Texas
77002. Leviathan through its ownership of all of the 6,291,894 Common
Units, its 1% general partner interest in the Partnership and its
approximate 1.0101% nonmanaging interest in certain of the Partnership
subsidiaries, owns a 27.3% effective interest in the Partnership.
(3) The address for DeepTech is 600 Travis Street, Suite 7500, Houston, Texas
77002. DeepTech owns an effective 23.2% interest in the Partnership through
its effective 85% ownership of Leviathan through Leviathan Holdings.
(4) Mr. Tatham's address is 600 Travis Street, Suite 7500, Houston, Texas
77002.
(5) Includes warrants to purchase 300,000 shares of DeepTech common stock held
in two foundations.
(6) Includes options to purchase 325,000 shares of DeepTech common stock.
(7) Includes 6,000 Preference Units held by Mr. Darling's wife.
(8) Includes 12,200 shares owned by Mr. Darling's children. Excludes 100,000
shares held in trust for Mr. Darling's children.
(9) Includes options to purchase 25,000 shares of DeepTech common stock.
(10) Includes options to purchase 100,000 shares of DeepTech common stock.
(11) Includes options to purchase 37,500 shares of DeepTech common stock.
(12) Includes 51,647 shares allocated to Mr. Thompson pursuant to merchant
banking plans of DLJ.
(13) Includes options to purchase 112,500 shares of DeepTech common stock.
(14) Includes options to purchase 25,000 shares of DeepTech common stock.
(15) Includes options to purchase 940,000 shares of DeepTech common stock.
* Less than 1%.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
A discussion of certain agreements, arrangements and transactions between
or among the Partnership, Leviathan, DeepTech, Tatham Offshore and certain other
related parties is summarized in the Partnership's "Notes to Consolidated
Financial Statements - Note 3 - Oil and Gas Properties", "- Note 5 - Impairment,
Abandonment and Other" and "- Note 10 - Related Party Transactions" located
elsewhere in this Annual Report. Also see "Directors and Executive Officers of
the Registrant - Conflicts and Audit Committee."
32
<PAGE> 35
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as part of this Annual Report or
incorporated by reference:
1. Financial Statements
As to financial statements and supplementary information,
reference is made to "Index to Consolidated Financial
Statements" on page F-1 of this Annual Report.
2. Financial Statement Schedules
None. All financial statement schedules are omitted because the
information is not required, is not material or is otherwise
included in the consolidated financial statements or notes
thereto included elsewhere in this Annual Report.
3.(a) Exhibits
Item
Number Description
------ -----------
3.1 - Certificate of Limited Partnership of the Partnership (filed as
Exhibit 3.1 to the Partnership's Registration Statement on Form
S-1, File No. 33-55642, and incorporated herein by reference).
3.2 - Amended and Restated Agreement of Limited Partnership of the
Partnership (filed as Exhibit 10.41 to Amendment No. 1 to
DeepTech's Registration Statement on Form S-1, File No. 33-73538,
and incorporated herein by reference).
3.3 - Amendment Number 1 to the Amended and Restated Agreement of
Limited Partnership of the Partnership (filed as Exhibit 10.1 to
the Partnership's Current Report on Form 8-K dated December 31,
1996, and incorporated herein by reference).
4.1 - Form of Certificate Evidencing Preference Units Representing
Limited Partner Interests (filed as Exhibit 4.1 to Amendment No.
2 to the Partnership's Registration Statement on Form S-1, File
No. 33-55642, and incorporated herein by reference).
4.2 - Form of Certificate Evidencing Common Units Representing
Limited Partner Interests (filed as Exhibit 4.2 to Amendment No.
2 to the Partnership's Registration Statement on Form S-1, File
No. 33-55642, and incorporated herein by reference).
10.01 - First Amended and Restated Management Agreement, effective as
of July 1, 1992, between the Partnership and Leviathan (filed as
Exhibit 10.1 to DeepTech's Annual Report on Form 10-K for the
fiscal year ended June 30, 1994, Commission File Number 0-23934
and incorporated herein by reference).
10.02 - Management Agreement, dated July 1, 1992, between DeepTech and
Leviathan (filed as Exhibit 10.10 to Amendment No. 1 to the
Partnership's Registration Statement on Form S-1, File No.
33-55642, and incorporated herein by reference).
10.03 - Agreement for Purchase and Sale by and between Tatham
Offshore, Inc., as Seller, and Flextrend Development Company,
L.L.C., as Buyer, dated June 30, 1995 (filed as Exhibit 6(a) to
the Partnership's Form 10-Q for the quarterly period ended June
30, 1995, and incorporated herein by reference).
33
<PAGE> 36
10.04 - Limited Liability Company Agreement of POPCO (filed as Exhibit
10.39 to the Partnership's Annual Report on Form 10-K for the
fiscal year ended December 31, 1995, and incorporated herein by
reference).
10.05 - Letter Agreement dated March 27, 1996, between the Partnership
and Tatham Offshore related to the settlement of certain demand
charges under transportation agreements (filed as Exhibit 10.40
to the Partnership's Annual Report on Form 10-K for the fiscal
year ended December 31, 1995, and incorporated herein by
reference).
10.06 - Second Amended and Restated Credit Agreement dated December
13, 1996 among Partnership, The Chase Manhattan Bank, as
administrative agent, ING (U.S.) Capital Corporation, as co
arranger, and the banks and other financial institutions from
time to time party thereto (filed as exhibit 10.24 to the
Partnership's Annual Report on Form 10-K for the fiscal year
ended December 31, 1996, and incorporated herein by reference).
10.07 - Fourth Amendment to First Amended and Restated Management
Agreement between DeepTech International Inc. and Leviathan Gas
Pipeline Company dated as of May 1, 1997 (filed as Exhibit 10.1
to the Partnership's Form 10-Q for the quarterly period ended
June 30, 1997, and incorporated herein by reference).
10.08 - Fifth Amendment to First Amended and Restated Management
Agreement between DeepTech International Inc. and Leviathan Gas
Pipeline Company (filed as Exhibit 10.1 to the Partnership's Form
10-Q for the quarterly period ended September 30, 1997, and
incorporated herein by reference).
10.09 - Leviathan Unit Rights Appreciation Plan.
21.1* - List of Subsidiaries of the Partnership.
24.1 - Power of Attorney (included on the signature pages of this
Annual Report on Form 10-K).
* Filed herewith.
3. (b) Reports on Form 8-K
None.
34
<PAGE> 37
POWERS OF ATTORNEY
The undersigned directors and executive officers of LEVIATHAN GAS PIPELINE
COMPANY, as General Partner of LEVIATHAN GAS PIPELINE PARTNERS, L.P. hereby
constitute and appoint Thomas P. Tatham, Donald V. Weir and Dennis A. Kunetka,
and each of them, with full power to act without the other and with full power
of substitution, our true and lawful attorneys-in-fact with full power to
execute in our name and behalf in the capacities indicated below any and all
amendments (including post-effective amendments and amendments thereto) to this
Annual Report, and to file the same, with all exhibits thereto and other
documents in connection therewith with the Securities and Exchange Commission
and hereby ratify and confirm all that such attorneys-in-fact, or either of
them, or their substitutes shall lawfully do or cause to be done by virtue
hereof.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Annual Report to be
signed on its behalf by the undersigned, thereunto duly authorized.
LEVIATHAN GAS PIPELINE PARTNERS, L.P.,
(Registrant)
By: LEVIATHAN GAS PIPELINE COMPANY,
its General Partner
By: /s/ GRANT E. SIMS
--------------------------------
Grant E. Sims
Chief Executive Officer
March 27, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date(s) indicated. All such
capacities are with Leviathan Gas Pipeline Company, General Partner of the
Registrant.
/s/ GEORGE L. BALL /s/ KEITH B. FORMAN
- ------------------------------------ --------------------------------------
George L. Ball Keith B. Forman
Director Director and Chief Financial Officer
March 27, 1998 March 27, 1998
/s/ WILLIAM A. BRUCKMANN, III /s/ JOHN H. GRAY
- ------------------------------------ --------------------------------------
William A. Bruckmann, III John H. Gray
Director Director and Chief Operating Officer
March 27, 1998 March 27, 1998
/s/ CHARLES M. DARLING, IV /s/ JAMES H. LYTAL
- ------------------------------------ --------------------------------------
Charles M. Darling, IV James H. Lytal
Director Director and President
March 27, 1998 March 27, 1998
35
<PAGE> 38
/s/ JANET E. SIKES /s/ PAUL THOMPSON III
- ------------------------------------ --------------------------------------
Janet E. Sikes Paul Thompson III
Director Director
March 27, 1998 March 27, 1998
/s/ GRANT E. SIMS /s/ DONALD V. WEIR
- ------------------------------------ --------------------------------------
Grant E. Sims Donald V. Weir
Director and Chief Executive Officer Director, Vice President and Secretary
March 27, 1998 (Principal Accounting Officer)
March 27, 1998
/s/ THOMAS P. TATHAM
- ------------------------------------
Thomas P. Tatham
Chairman of the Board
March 27, 1998
36
<PAGE> 39
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES:
Report of Independent Accountants ................................................ F-2
Consolidated Balance Sheet as of December 31, 1997 and 1996....................... F-3
Consolidated Statement of Operations for the Years Ended December 31, 1997,
1996 and 1995 ................................................................. F-4
Consolidated Statement of Cash Flows for the Years Ended December 31, 1997,
1996 and 1995 ................................................................. F-5
Consolidated Statement of Partners' Capital for the Years Ended December 31, 1995,
1996 and 1997 ................................................................. F-6
Notes to Consolidated Financial Statements ....................................... F-7
VIOSCA KNOLL GATHERING COMPANY:
Report of Independent Accountants................................................. F-27
Balance Sheet as of December 31, 1997 and 1996.................................... F-28
Statement of Operations for the Years Ended December 31, 1997 and 1996............ F-29
Statement of Cash Flows for the Years Ended December 31, 1997 and 1996............ F-30
Statement of Partners' Capital for the Years Ended December 31, 1996 and 1997 .... F-31
Notes to Financial Statements .................................................... F-32
HIGH ISLAND OFFSHORE SYSTEM:
Independent Auditors' Report ..................................................... F-35
Statements of Financial Position as of December 31, 1997 and 1996 ................ F-36
Statements of Income and Statements of Partners' Equity for the Years Ended
December 31, 1997 and 1996 .................................................... F-37
Statements of Cash Flows for the Years Ended December 31, 1997 and 1996 .......... F-38
Notes to the Financial Statements for the Years Ended December 31, 1997 and 1996 . F-39
POSEIDON OIL PIPELINE COMPANY, L.L.C
Report of Independent Public Accountants.......................................... F-43
Balance Sheet as of December 31, 1997 and 1996 ................................... F-44
Statement of Income for the Year Ended December 31, 1997 and for the Period
of Inception (February 14, 1996) through December 31, 1996 .................... F-45
Statement of Members' Equity for the Year Ended December 31, 1997 and for
the Period of Inception (February 14, 1996) through December 31, 1996 ......... F-46
Statement of Cash Flows for the Year Ended December 31, 1997 and for the Period
of Inception (February 14, 1996) through December 31, 1996 .................... F-47
Notes to Financial Statements for the Years Ended December 31, 1997 and 1996 ..... F-48
</TABLE>
F-1
<PAGE> 40
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 at December 31, 1997 and 1996
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1997 in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Partnership'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.
PRICE WATERHOUSE LLP
Houston, Texas
March 2, 1998
F-2
<PAGE> 41
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In thousands)
<TABLE>
<CAPTION>
ASSETS December 31,
-------------------------
1997 1996
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 6,430 $ 16,489
Accounts receivable 1,953 6,237
Accounts receivable from affiliates 6,608 14,107
Other current assets 653 859
--------- ---------
Total current assets 15,644 37,692
--------- ---------
Equity investments 182,301 107,838
--------- ---------
Property and equipment:
Pipelines 78,244 151,253
Platforms and facilities 97,882 72,461
Oil and gas properties, at cost, using successful efforts method 120,296 109,047
--------- ---------
296,422 332,761
Less accumulated depreciation, depletion, amortization and impairment 95,783 46,206
--------- ---------
Property and equipment, net 200,639 286,555
--------- ---------
Investment in Tatham Offshore, Inc. 7,500 7,500
Other noncurrent receivable -- 8,531
Other noncurrent assets 3,758 5,410
--------- ---------
Total assets $ 409,842 $ 453,526
========= =========
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities $ 12,522 $ 17,769
Accounts payable to affiliates 1,032 3,504
--------- ---------
Total current liabilities 13,554 21,273
Deferred federal income taxes 1,399 1,722
Deferred revenue -- 8,913
Note payable 238,000 227,000
Other noncurrent liabilities 13,304 2,490
--------- ---------
Total liabilities 266,257 261,398
--------- ---------
Commitments and contingencies (Note 12)
Minority interest (381) 105
--------- ---------
Partners' capital:
Preference unitholders' interest 163,426 196,224
Common unitholder's interest (15,400) (3,969)
General partner's interest (4,060) (232)
--------- ---------
143,966 192,023
--------- ---------
Total liabilities and partners' capital $ 409,842 $ 453,526
========= =========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-3
<PAGE> 42
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per Unit amounts)
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------
1997 1996 1995
<S> <C> <C> <C>
Revenue:
Oil and gas sales $ 276 $ 772 $ 936
Oil and gas sales to affiliates 57,830 46,296 922
Gathering, transportation and platform services 10,029 13,974 10,696
Gathering, transportation and platform services to affiliates 7,300 10,031 9,851
Equity in earnings 29,327 20,434 19,588
-------- -------- --------
104,762 91,507 41,993
-------- -------- --------
Costs and expenses:
Operating expenses 11,352 9,068 4,092
Depreciation, depletion and amortization 46,289 31,731 8,290
Impairment, abandonment and other 21,222 -- --
General and administrative expenses 5,869 788 1,273
Management fee and general and administrative
expenses allocated from general partner 8,792 7,752 5,796
-------- -------- --------
93,524 49,339 19,451
-------- -------- --------
Operating income 11,238 42,168 22,542
Gains on sales of assets -- -- 1,247
Interest income and other 1,475 1,710 637
Interest and other financing costs (14,169) (5,560) (833)
Minority interest in income 7 (427) (251)
-------- -------- --------
(Loss) income before income taxes (1,449) 37,891 23,342
Income tax benefit (311) (801) (603)
-------- -------- --------
Net (loss) income $ (1,138) $ 38,692 $ 23,945
======== ======= ========
Weighted average number of Units outstanding 24,367 24,367 24,367
======== ======= ========
Basic and diluted net (loss) income per Unit (Note 2) $ (0.06) $ 1.57 $ 0.97
======== ======= ========
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-4
<PAGE> 43
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------------
1997 1996 1995
<S> <C> <C> <C>
Cash flows from operating activities:
Net (loss) income $ (1,138) $ 38,692 $ 23,945
Adjustments to reconcile net (loss) income to
net cash provided by operating activities:
Amortization of debt issue costs 960 1,351 687
Depreciation, depletion and amortization 46,289 31,731 8,290
Impairment, abandonment and other 21,222 -- --
Minority interest in income (7) 427 251
Equity in earnings (29,327) (20,434) (19,588)
Distributions from equity investments 27,135 36,823 24,642
Gains on sales of assets -- -- (1,247)
Deferred income taxes and other (323) (936) (640)
Other noncash items (1,596) (6,560) 152
Changes in operating working capital:
Decrease in short-term investments -- -- 2,000
Decrease (increase) in accounts receivable 4,284 (3,442) (1,663)
Decrease (increase) in accounts receivable
from affiliates 7,499 (7,512) (5,833)
Decrease (increase) in other current assets 206 (97) 67
(Decrease) increase in accounts payable and
accrued liabilities (5,247) (23,190) 44,858
(Decrease) increase in accounts payable to affiliates (2,472) 3,326 (1,035)
--------- --------- ---------
Net cash provided by operating activities 67,485 50,179 74,886
--------- --------- ---------
Cash flows from investing activities:
Acquisition and development of oil and gas properties (11,249) (59,599) (45,291)
Additions to pipelines, platforms and facilities (30,708) (30,095) (121,405)
Equity investments -- (12,027) (6,936)
Proceeds from sales of assets and other 188 -- 1,250
--------- --------- ---------
Net cash used in investing activities (41,769) (101,721) (172,382)
--------- --------- ---------
Cash flows from financing activities:
Decrease in restricted cash 716 -- --
Debt issue costs (93) (2,843) (4,363)
Proceeds from notes payable 11,000 89,220 129,780
Distributions to partners (47,398) (33,852) (29,837)
--------- --------- ---------
Net cash (used in) provided by financing activities (35,775) 52,525 95,580
--------- --------- ---------
Net (decrease) increase in cash and cash equivalents (10,059) 983 (1,916)
Cash and cash equivalents at beginning of year 16,489 15,506 17,422
--------- --------- ---------
Cash and cash equivalents at end of year $ 6,430 $ 16,489 $ 15,506
========= ========= =========
Supplemental disclosures to the statement of cash flows - see Note 13
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-5
<PAGE> 44
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
<TABLE>
<CAPTION>
Preference Common General
Unitholders Unitholders Partner Total
<S> <C> <C> <C> <C>
Partners' capital at December 31, 1994 $ 196,340 $ (3,960) $ 51 $ 192,431
Net income for the year
ended December 31, 1995 17,575 6,130 240 23,945
Cash distributions (21,690) (7,550) (295) (29,535)
--------- --------- --------- ---------
Partners' capital at December 31, 1995 192,225 (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 196,224 (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 $ 163,426 $ (15,400) $ (4,060) $ 143,966
========= ========= ========= =========
Limited Partnership Units outstanding at
December 31, 1995, 1996 and 1997 18,075 6,292 -- (a) 24,367
========= ========= ========= =========
</TABLE>
- ---------------------
(a) Leviathan Gas Pipeline Company owns a 1% general partner interest in
Leviathan Gas Pipeline Partners, L.P.
The accompanying notes are an integral part of this financial statement.
F-6
<PAGE> 45
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION:
Leviathan Gas Pipeline Partners, L.P. (the "Partnership"), a publicly held
Delaware limited partnership, is engaged in the gathering and transportation of
natural gas and crude oil through its pipeline systems located in the Gulf of
Mexico (the "Gulf") and in the development and production of oil and gas
reserves from its proved properties. The Partnership's assets include interests
in (i) eight natural gas pipelines, (ii) a crude oil pipeline system, (iii) five
strategically located multi-purpose platforms, (iv) three producing oil and gas
properties and (v) a dehydration facility.
Leviathan Gas Pipeline Company ("Leviathan"), a Delaware corporation and
wholly-owned subsidiary of Leviathan Holdings Company ("Leviathan Holdings"), an
85%-owned subsidiary of DeepTech International Inc. ("DeepTech"), is the general
partner of the Partnership, and as such, performs all management and operational
functions of the Partnership and its subsidiaries. The remaining 15% of
Leviathan Holdings is principally owned by members of the management of
DeepTech. DeepTech also owns and controls several other operating subsidiaries
which are engaged in various oil and gas related activities.
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 the Partnership. Leviathan's
approximate 1% nonmanaging interest in certain subsidiaries of the Partnership
represents the minority interest in the Partnership's consolidated financial
statements. Investments in which the Partnership 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.
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.
Property and equipment
Gathering pipelines, platforms and related facilities are recorded at cost and
are depreciated on a straight-line basis over their estimated useful lives
ranging from 7 to 30 years. Repair and maintenance costs are expensed as
incurred; additions, improvements and replacements are capitalized.
The Partnership accounts for its oil and 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 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.
F-7
<PAGE> 46
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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
gas properties. Other noncurrent liabilities at December 31, 1997 and 1996
include $9,158,0000 and $2,054,000, respectively, of accrued dismantlement,
restoration and abandonment costs.
The Partnership adopted 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", effective January 1, 1996. SFAS No. 121 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. Implementation of SFAS No. 121 did not have a material effect on the
Partnership's financial position or results of operations.
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.
Revenue recognition
Revenue from pipeline transportation of hydrocarbons is recognized upon receipt
of the hydrocarbons into the pipeline systems. Revenue from oil and 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
The Partnership and its subsidiaries other than Tarpon Transmission Company
("Tarpon") are not taxable entities. However, the taxable income or loss
resulting from the operations of the Partnership will ultimately be included in
the federal and state income tax returns of the general and limited partners and
may vary substantially from the income or loss reported for financial reporting
purposes.
Tarpon is, and Manta Ray Gathering Systems, Inc. ("Manta Ray") was, prior to its
liquidation in May 1996, a subsidiary of the Partnership subject to federal
corporate income taxation. The Partnership 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 the Partnership.
Net income per unit
During the three months ended December 31, 1997, the Partnership adopted SFAS
No. 128, "Earnings per Share". SFAS No. 128 establishes new guidelines for
computing earnings per share ("EPS") and requires dual presentation of basic and
diluted EPS for entities with complex capital structures. Basic EPS excludes
dilution and is computed by dividing net income (loss) by the weighted average
number of units outstanding during the period. Dilutive EPS reflects potential
dilution and is computed by dividing net income (loss) 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. All prior period EPS data has been restated to conform
with the provisions of SFAS No. 128.
Basic income (loss) per unit and diluted income (loss) per unit for the
Partnership are the same for the years ended December 31, 1997, 1996 and 1995.
For the year ended December 31, 1997, net income (loss) per Unit was calculated
based upon the quarterly net income (loss) of the Partnership less an allocation
of net income (loss) to the general partner proportionate to its share of
quarterly cash distributions which included Incentive Distributions (see Note
9). For the years ended December 31, 1996 and 1995, net income per Unit was
computed based upon the net income of the Partnership less an allocation of
approximately 1% of the Partnership's net income to the general partner. The
weighted average number of Units outstanding for each of the years ended
December 31, 1997, 1996 and 1995 was 24,366,894 Units.
F-8
<PAGE> 47
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Estimates
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles and the estimation of oil and 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 gas reserve
disclosure, (iii) estimated useful lives of depreciable assets and (iv)
potential environmental liabilities. Actual results could differ from those
estimates. Management believes that its estimates are reasonable.
Other
The fair values of the financial instruments included in the Partnership's
assets and liabilities approximate their carrying values.
The Partnership enters into commodity derivative transactions to hedge its
exposure to price fluctuations on anticipated natural gas and crude oil sales
transactions. Gains and losses on hedging activities are deferred and included
in the results of operations in the period in which the hedged production is
sold. See Note 12.
During June 1997, the Financial Accounting Standards Board issued 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 shareholders and requires related disclosures about products and services,
geographic areas and major customers. This statement is effective for fiscal
years beginning after December 15, 1997. The Partnership is currently evaluating
the disclosure requirements of this statement.
NOTE 3 - OIL AND GAS PROPERTIES:
Capitalized Costs
<TABLE>
<CAPTION>
December 31,
------------------------
1997 1996
(In thousands)
<S> <C> <C>
Proved properties $ 38,790 $ 38,681
Wells, equipment and related facilities 81,506 70,366
-------- --------
Total capitalized costs 120,296 109,047
Accumulated depreciation, depletion and amortization 53,684 17,673
-------- --------
Net capitalized costs $ 66,612 $ 91,374
======== ========
</TABLE>
Costs incurred in the Oil and Gas Acquisitions, Exploration and Development
Activities
<TABLE>
<CAPTION>
Year ended December 31,
------------------------
1997 1996
(In thousands)
<S> <C> <C>
Acquisitions of proved properties $ 1 $ (13)
Development 10,522 54,771
Capitalized interest 726 6,296
-------- --------
Total costs incurred $ 11,249 $ 61,054
======== ========
</TABLE>
On June 30, 1995, the Partnership entered into a purchase and sale agreement
(the "Purchase and Sale Agreement") with Tatham Offshore, Inc. ("Tatham
Offshore"), an approximately 94%-owned affiliate of DeepTech, pursuant to which
the Partnership 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 $30,000,000. The Partnership is entitled
to retain all of the revenue
F-9
<PAGE> 48
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
attributable to the Acquired Properties until it has received net revenue
equal to the Payout Amount (as defined below), whereupon Tatham Offshore is
entitled to receive a reassignment of the Acquired Properties, subject to
reduction and conditions as discussed below. Prior to December 10, 1996, "Payout
Amount" was defined as an amount equal to all costs incurred by the Partnership
with respect to the Acquired Properties (including the $30,000,000 acquisition
cost paid to Tatham Offshore) plus interest thereon at a rate of 15% per annum.
Effective February 1, 1996, the Partnership entered into an agreement with
Tatham Offshore regarding certain transportation agreements that increases the
amount recoverable from the Payout Amount by $7,500,000 plus interest (Note 10).
Effective December 10, 1996, the Partnership exercised its option to permanently
retain 50% of the working interest in the Acquired Properties in exchange for
forgiving 50% of the then-existing Payout Amount exclusive of the $7,500,000
plus interest added to the Payout Amount in connection with the restructuring of
certain transportation agreements discussed above. The Partnership remains
obligated to fund any further development costs attributable to Tatham
Offshore's portion of the working interests, such costs to be added to the
Payout Amount. The Partnership's election to retain 50% of the working interest
in the Acquired Properties reduced the Payout Amount from $94,020,000 to
$50,760,000. Subsequent to December 10, 1996, only 50% of the development and
operating costs attributable to the Acquired Properties are added to the Payout
Amount and 50% of the net revenue from the Acquired Properties reduce the Payout
Amount. As of December 31, 1997, the Payout Amount totaled $41,425,000. See Note
5 and 16.
NOTE 4 - EQUITY INVESTMENTS:
The Partnership 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 ("HIOS"),
33 1/3% in U-T Offshore System ("UTOS") and 50% in West Cameron Dehydration
Company, L.L.C. ("West Cameron Dehy").
Leviathan contributed the equity interests in Stingray, HIOS and UTOS to the
Partnership at its carrying value on February 19, 1993. 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, 1997 is $44,233,000.
Leviathan accounted for its acquisition of its interest in Stingray, HIOS and
UTOS using the purchase method of accounting. The difference between the cost of
the investments accounted for on the equity method and the underlying equity in
net assets of Stingray, HIOS and UTOS at acquisition was assigned to property,
plant and equipment and favorable firm transportation contracts and is being
depreciated on a straight-line basis over the estimated 20-year lives of such
property, plant and equipment and the lives of the related contracts,
respectively. The majority of such contracts expired by December 1993. The
20-year depreciable life used for the regulated pipeline assets may be impacted
by future rates approved by the FERC.
In January 1997, the Partnership and affiliates of Marathon Oil Company
("Marathon") and Shell Oil Company ("Shell") formed Nautilus to construct and
operate a new interstate natural gas pipeline system. In addition, the same
parties formed Manta Ray Offshore to acquire an existing gathering system from
the Partnership. The gathering system was extended and is currently delivering
gas to several downstream pipelines, including the Nautilus system. The Nautilus
and Manta Ray Offshore systems are located to serve growing production areas in
the Green Canyon area of the Gulf and are indirectly owned 50% by Shell, 24.3%
by Marathon and 25.7% by the Partnership. The capital costs associated with the
construction of the Nautilus interstate pipeline system and the expansion of the
Manta Ray Offshore gathering system, including the value of existing assets
contributed by the partners, totaled approximately $250 million. The Nautilus
system consists of 101 miles of 30-inch pipeline downstream from Ship Shoal
Block 207 connecting to a gas processing plant, onshore Louisiana, operated by
Exxon Company USA ("Exxon"), plus certain facilities downstream of the Exxon
plant to effect deliveries into multiple interstate pipelines. Upstream of the
Ship Shoal 207 platform, the existing Manta Ray Offshore gathering system was
extended into a broader gathering system that serves shelf and deepwater
production areas around Ewing Bank Block 873 to the east and Green Canyon Block
65 to the west. The Manta Ray Offshore 47-mile expansion was completed and
placed in service in November 1997. The Nautilus system, including the related
onshore facilities and platform connections, was completed and placed in service
in December 1997. Affiliates of Marathon and Shell dedicated for transportation
and gathering to each of the Nautilus and Manta Ray Offshore systems significant
deepwater acreage positions in the area and provided substantially all of the
capital funding for the new construction. The Partnership provided $11,144,000
of funding in the form of a newly constructed compressor in addition to the
contribution of the Manta Ray Offshore system.
F-10
<PAGE> 49
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 1997
(In thousands)
<TABLE>
<CAPTION>
West
Viosca Cameron Manta Ray
HIOS Knoll Stingray POPCO Dehy UTOS Offshore Nautilus Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $ 45,569 $ 23,128 $ 23,630 $ 26,161 $ 2,451 $ 3,785 $ 6,263 $ 54
Other income 348 39 970 209 29 61 1,564 6,489 (a)
Operating expenses (17,101) (2,115) (15,612) (5,782) (164) (2,472) (2,223) (435)
Depreciation (4,774) (2,473) (7,216) (6,463) (16) (566) (1,823) (233)
Other expenses -- (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 (b) 845 -- 959 (120) -- 35 -- --
- - Contract
amortization(b) (105) -- (350) -- -- -- -- --
- - Other (228) -- (49) (263) -- (24) 3,082 (c) 733
-------- -------- -------- -------- -------- -------- -------- --------
Equity in earnings $ 10,129 $ 8,310 $ 754 $ 2,779 $ 1,150 $ 292 $ 3,672 $ 2,241 $ 29,327
======== ======== ======== ======== ======== ======== ======== ======== ========
Distributions(d) $ 12,200 $ 9,650 $ 1,375 $ -- $ 1,150 $ 200 $ 2,560 $ -- $ 27,135
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
- -----------------------
(a) Includes $6,431,000 related to an allowance for funds used during
construction ("AFUDC") which represents the estimated costs, during the
construction period, of funds used for construction purposes. 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.
(b) Adjustments result from purchase price adjustments made in accordance
with Accounting Principles Board ("APB") No. 16 "Business Combinations".
(c) Represents additional net earnings specifically allocated to the
Partnership related to the assets contributed by the Partnership to the
Manta Ray Offshore joint venture. Pursuant to the terms of the joint venture
agreement, the Partnership 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.
(d) Future distributions could be restricted by the terms of the equity
investees' respective credit agreements.
F-11
<PAGE> 50
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 Cameron
HIOS Viosca Knoll Stingray POPCO Dehy UTOS Total
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenue $ 47,175 $ 13,923 $ 24,146 $ 7,819 $ 1,686 $ 3,476
Other income 266 -- 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 96 (90) (1,679) (269) -- --
-------- -------- -------- -------- -------- --------
Net earnings 27,079 11,140 2,336 2,671 1,518 453
Effective 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 No. 16, "Business Combinations".
SUMMARIZED HISTORICAL OPERATING RESULTS
YEAR ENDED DECEMBER 31, 1995
(In thousands)
<TABLE>
<CAPTION>
Viosca
HIOS Stingray Knoll UTOS Total
<S> <C> <C> <C> <C> <C>
Operating revenue $ 53,428 $ 26,020 $ 7,107 $ 5,195
Other income 659 1,306 -- 53
Operating expenses (19,360) (13,993) (520) (2,828)
Depreciation (4,898) (6,663) (2,224) (731)
Other expenses (151) (1,245) -- (18)
-------- -------- -------- --------
Net earnings 29,678 5,425 4,363 1,671
Effective ownership percentage 40% 50% 50% 33.3%
-------- -------- -------- --------
11,871 2,712 2,181 557
Adjustments:
Depreciation (a) 854 899 -- 59
Contract amortization (a) (198) -- -- --
Rate refund reserve 417 -- -- --
Other 168 57 (b) -- 11
-------- -------- -------- --------
Equity in earnings $ 13,112 $ 3,668 $ 2,181 $ 627 $ 19,588
======== ======== ======== ======== ========
Distributions $ 15,200 $ 5,750 $ 2,825 $ 867 $ 24,642
======== ======== ======== ======== ========
</TABLE>
- -----------------------
(a) Adjustments result from purchase price adjustments made in accordance with
APB No. 16, "Business Combinations".
(b) Includes the results of West Cameron Dehy for December 1995 (inception of
operations).
F-12
<PAGE> 51
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
SUMMARIZED HISTORICAL BALANCE SHEETS
(In thousands)
<TABLE>
<CAPTION>
HIOS Viosca Knoll Stingray POPCO
December 31, December 31, December 31, December 31,
------------------ ------------------ ------------------ ------------------
1997 1996 1997 1996 1997 1996 1997 1996
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Current assets $ 5,587 $ 8,215 $ 3,354 $ 4,549 $ 20,184 $ 35,117 $ 31,763 $ 39,787
Noncurrent assets 12,081 14,985 98,004 71,408 42,541 48,917 226,055 174,922
Current liabilities 3,380 2,153 11,280 2,502 21,787 35,495 35,864 38,038
Long-term debt -- -- 52,200 33,300 11,600 17,400 120,500 84,000
Other noncurrent liabilities 199 500 257 173 5,289 2,321 -- --
</TABLE>
<TABLE>
<CAPTION>
West Cameron Dehy UTOS Manta Ray Offshore Nautilus
December 31, December 31, December 31, December 31,
-------------------- ------------------- ------------------ ------------
1997 1996 1997 1996 1997 1997
<S> <C> <C> <C> <C> <C> <C>
Current assets $ 455 $ 424 $ 3,955 $ 4,211 $ 31,714 $ 924
Noncurrent assets 663 679 2,803 3,305 127,731 120,074
Current liabilities 43 28 2,900 3,899 32,601 3,699
</TABLE>
NOTE 5 - IMPAIRMENT, ABANDONMENT AND OTHER:
Pursuant to the Ewing Bank Agreement discussed in Note 10, Tatham Offshore
dedicated all natural gas and crude oil produced from eight of its Ewing Bank
leases for gathering and redelivery by the Partnership and was obligated to pay
a demand rate as well as a commodity charge equal to 4% of the market price of
production actually transported. Pursuant to the Ewing Bank Agreement, the
Partnership constructed gathering facilities connecting Tatham Offshore's Ewing
Bank 914 #2 well to a third party platform at Ewing Bank Block 826.
The Partnership and Tatham Offshore entered into the Ship Shoal Agreement, also
discussed in Note 10, pursuant to which the Partnership constructed a gathering
line from Tatham Offshore's Ship Shoal Block 331 lease to interconnect with a
third-party pipeline at the Partnership's processing facilities located on its
Ship Shoal Block 332 platform. Pursuant to the terms of the Ship Shoal
Agreement, and in consideration for constructing the interconnect, refurbishing
the platform and providing access to the processing facilities, Tatham Offshore
was required to pay the Partnership demand charges and has dedicated all
production from its Ship Shoal Block 331 lease and eight additional surrounding
leases for gathering and processing by the Partnership for additional commodity
fees.
As discussed in Note 10, effective February 1, 1996, the Partnership agreed to
release Tatham Offshore from all remaining demand charge payments under the
Ewing Bank and Ship Shoal Agreements, a total of $17,800,000. Tatham Offshore
remained obligated to pay all commodity charges related to production from these
properties. In exchange, the Partnership received 7,500 shares of Tatham
Offshore 9% Senior Preferred Stock, which was valued at $7,500,000, and added
$7,500,000 to the Payout Amount under the Purchase and Sale Agreement. See Note
16.
In May 1997, the Ewing Bank 914 #2 well was shut-in as a result of a downhole
mechanical problem. Although Tatham Offshore is evaluating potential workover or
recompletion possibilities for this well, it has announced its intent to reserve
the remaining costs associated with the Ewing Bank 914 #2 well given its current
non-productive status. Production related problems resulting from the
completions of the three wellbores at Ship Shoal Block 331 have resulted in only
a minimal amount of production from the property and Tatham Offshore has decided
not to pursue further recompletion operations at this time. See Note 16.
In addition, the Partnership has determined that the designated revenue from the
Acquired Properties is not likely to be sufficient to satisfy the Payout Amount.
Under these circumstances, the Partnership would retain 100% of the revenue from
its working interests in the Acquired Properties, would bear all abandonment
obligations related to these properties and would not realize the $7,500,000
plus accrued interest that had been recorded as a noncurrent receivable related
to the settlement of the demand charge obligations under the Ewing Bank and Ship
Shoal Agreements. Accordingly in June 1997, the Partnership recorded as
impairment, abandonment and other expense on the
F-13
<PAGE> 52
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, to fully accrue its abandonment obligations associated with
the gathering facilities serving these properties, to reserve its noncurrent
receivable related to the prepayment of the demand charge obligations under the
Ewing Bank and Ship Shoal Agreements and to accrue certain abandonment
obligations associated with its oil and gas properties.
NOTE 6 - 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 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. The
Partnership'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 policy and
precedent, the Partnership 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, Poseidon has not filed
tariffs with the FERC.
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 and that will remain in effect until at least the fourth
quarter of 1998. Stingray, HIOS and UTOS have each agreed to file a new rate
case in the fourth quarter of 1998.
NOTE 7 - INDEBTEDNESS:
In February 1993, the Partnership entered into a revolving credit facility with
a syndicate of commercial banks that provided a maximum $50 million commitment
for borrowings, subject to certain borrowing base limitations (the "Partnership
Credit Facility"). The Partnership Credit Facility was amended and restated in
March 1995, February 1996, March 1996 and December 1996 and currently provides
up to $300 million of available credit, subject to certain incurrence
limitations. As of December 31, 1997 and 1996, the Partnership had $238,000,000
and $227,000,000, respectively, outstanding under its credit facility. At the
election of the Partnership, interest under the Partnership Credit Facility is
determined by reference to the reserve-adjusted London interbank offer rate
("LIBOR"), the prime rate or the
F-14
<PAGE> 53
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
90-day average certificate of deposit. The interest rate at December 31, 1997
and 1996 was 6.6% per annum. 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 is currently 0.25% per annum. Amounts advanced
under the Partnership Credit Facility were used (i) to finance the Partnership's
capital expenditures, including construction of platforms and pipelines,
investments in equity investees and the acquisition and development of oil and
gas properties and (ii) to repay all of the indebtedness incurred under the
Flextrend Credit Facility (discussed below). Amounts remaining under the
Partnership Credit Facility are available to the Partnership for general
partnership purposes, including financing capital expenditures, for working
capital, and subject to certain limitations, for paying distributions to
Unitholders. The Partnership 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 Partnership Credit Facility matures in
December 1999; is guaranteed by Leviathan and each of the Partnership's
subsidiaries; and is secured by the management agreement with Leviathan (Note
10), substantially all of the assets of the Partnership and Leviathan's 1%
general partner interest in the Partnership and approximate 1% interest in
certain subsidiaries of the Partnership.
Interest costs incurred by the Partnership totaled $15,890,000, $17,470,000 and
$6,082,000 for the years ended December 31, 1997, 1996 and 1995, respectively.
During the years ended December 31, 1997, 1996 and 1995, the Partnership
capitalized $1,721,000, $11,910,000 and $5,269,000, respectively, of such
interest costs in connection with construction projects and drilling activities
in progress during such periods. At December 31, 1997 and 1996, the unamortized
portion of debt issue costs totaled $3,749,000 and $4,616,000, respectively.
NOTE 8 - PARTNERS' CAPITAL:
In 1995, the Partnership adopted the Unit Rights Appreciation Plan (the "Plan")
to provide the Partnership with the ability of making awards of Unit Rights, as
hereinafter defined, to certain officers and key employees of the Partnership or
its affiliates as an incentive for these individuals to continue in the service
of the Partnership or its affiliates. Under the Plan, the Partnership may grant
to senior officers of the Partnership or its affiliates, excluding the Chairman
of the Board of Leviathan, currently Mr. Thomas P. Tatham, with the right to
purchase, or realize the appreciation of, a Preference Unit (a "Unit Right"),
pursuant to the provisions of the Plan. The aggregate number of Preference Units
as to which Unit Rights may be issued pursuant to the Plan shall not exceed
400,000 Preference Units per calendar year and 4,000,000 Preference Units over
the term of the Plan, subject to adjustment as to both limitations under certain
circumstances. No participant may be granted more than 400,000 Unit Rights in
any calendar year. The exercise price of the Preference Units covered by the
Unit Rights granted pursuant to the Plan shall be the closing price of the
Preference Units as reported on the New York Stock Exchange or, if the
Preference Units are not traded on such exchange, as reported on any other
national securities exchange on which the Preference Units are traded, on the
date on which Unit Rights are granted pursuant to the Plan. As of December 31,
1997, a total of 1,200,000 Unit Rights have been granted under the Plan
representing 400,000 Unit Rights for each of the calendar years 1995, 1996 and
1997. For the years ended December 31, 1997 and 1996, the Partnership accrued
$3,710,000 and $436,000, respectively, related to the appreciation and vestiture
of these Unit Rights.
As of December 31, 1997, 1996 and 1995, the Partnership had 18,075,000
Preference Units and 6,291,894 Common Units outstanding. All of the Preference
Units of the Partnership are owned by the public, representing a 72.7% effective
limited partner interest in the Partnership. Leviathan, through its ownership of
all of the Common Units, its 1% general partner interest in the Partnership and
its approximate 1% nonmanaging interest in certain of the Partnership
subsidiaries, owns a 27.3% effective interest in the Partnership.
NOTE 9 - CASH DISTRIBUTIONS:
The Partnership makes quarterly distributions of 100% of its Available Cash, as
defined in the Amended and Restated Agreement of Limited Partnership (the
"Partnership Agreement"), to the Unitholders and Leviathan. Available Cash
consists generally of all the cash receipts of the Partnership plus reductions
in reserves less all of its cash disbursements and net additions to reserves.
Leviathan has broad discretion to establish cash reserves that it determines are
necessary or appropriate to provide for the proper conduct of the business of
the Partnership including cash reserves for future capital expenditures, to
stabilize distributions of cash to the Unitholders and Leviathan, to reduce debt
or as necessary to comply with the terms of any agreement or obligation of the
Partnership. The Partnership 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.
F-15
<PAGE> 54
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
The distribution of Available Cash of the Partnership for each quarter within
the Preference Period, as defined in the Partnership Agreement, is subject to
the preferential rights of the holders of Preference Units to receive the
Minimum Quarterly Distribution, as defined in the Partnership Agreement, for
such quarter, plus any arrearages in the payment of the Minimum Quarterly
Distribution for prior quarters, before any distribution of Available Cash is
made to holders of Common Units for such quarter. The Common Units are not
entitled to arrearages in the payment of the Minimum Quarterly Distribution. In
general, the Preference Period is defined to mean the period commencing on
February 19, 1993 and continuing through at least March 31, 1998.
Since commencement of operations on February 19, 1993 through December 31, 1997,
the Partnership has made distributions to the Unitholders equal to and in excess
of the Minimum Quarterly Distribution of $0.275 per Unit.
See Note 18.
Distributions by the Partnership of its Available Cash are effectively made 98%
to Unitholders and 2% to Leviathan, as general partner, subject to the payment
of incentive distributions to Leviathan 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, 1997 and 1996, Leviathan received Incentive
Distributions totaling $3,885,000 and $285,000, respectively. In February 1998,
the Partnership paid a cash distribution of $0.50 per Preference and Common Unit
and an Incentive Distribution of $2,362,000 to Leviathan.
NOTE 10 - 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 the Partnership are
employed by DeepTech. DeepTech entered into management agreements with each of
its subsidiaries including Leviathan in its capacity as general partner of the
Partnership. The management fee charged to Leviathan is intended to approximate
the amount of resources allocated by DeepTech in providing various operational,
financial, accounting and administrative services on behalf of Leviathan and the
Partnership. 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, Leviathan is entitled to reimbursement of all
reasonable general and administrative expenses and other reasonable expenses
incurred by Leviathan and its affiliates for or on behalf of the Partnership
including, but not limited to, amounts payable by Leviathan to DeepTech under
the management agreement.
In connection with the completion of the offering of additional Preference Units
in June 1994, Leviathan amended its management agreement with DeepTech effective
July 1, 1994 in consideration for the increase in management services associated
with the planned expansion of facilities and to more accurately provide for the
reimbursement of expenses incurred by DeepTech in providing management services
to Leviathan and the Partnership. As amended, the management agreement provided
for a management fee of $2,000,000 a year plus 40% of DeepTech's unreimbursed
selling, general and administrative expenses. Effective November 1, 1995, July
1, 1996 and July 1, 1997, primarily as a result of the increased activities of
the Partnership, Leviathan amended its management agreement with DeepTech to
provide for an annual management fee of 45.3%, 54% and 52%, respectively, of
DeepTech's overhead. Leviathan charged the Partnership $8,080,000, $6,590,000
and $5,796,000 pursuant to its management agreement with DeepTech for the years
ended December 31, 1997, 1996 and 1995, respectively.
Leviathan is also required to reimburse DeepTech 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 second public
offering) and (ii) the investment of such proceeds in additional acquisitions or
construction projects. During the years ended December 31, 1997 and 1996,
Leviathan charged the Partnership $713,000 and $1,162,000, respectively, to
compensate DeepTech for additional taxable income allocated to Leviathan.
F-16
<PAGE> 55
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Sales, Transportation and Platform Access Agreements
General. In December 1993, the Partnership 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
Garden Banks, Viosca Knoll, Ewing Bank and Ship Shoal leases as well as certain
adjoining areas of mutual interest to the Partnership for transportation. In
exchange, the Partnership 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 with Tatham Offshore (Note 3), a subsidiary of the
Partnership assumed all of Tatham Offshore's obligations under the Master
Dedication Agreement and certain ancillary agreements with respect to the
Acquired Properties.
Ewing Bank Gathering System. Pursuant to a gathering agreement (the "Ewing Bank
Agreement") among Tatham Offshore, DeepTech, and a subsidiary of the
Partnership, Tatham Offshore dedicated all natural gas and crude oil produced
from eight of its Ewing Bank leases for gathering and redelivery by the
Partnership and was obligated to pay a demand and a commodity rate for shipment
of all oil and gas under this agreement. The Ewing Bank Agreement requires
Tatham Offshore to pay certain demand charges and a commodity charge equal to 4%
of the market price of production actually transported. For the years ended
December 31, 1997, 1996 and 1995, Tatham Offshore paid the Partnership demand
and commodity charges of $54,000, $349,000 and $7,626,000, respectively, under
this agreement. The Partnership also receives revenue from the oil and gas
production from the Ewing Bank 914 #2 well as a result of its 7.13% overriding
royalty interest in the well. In March 1996, the Partnership 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, the Partnership and
Tatham Offshore have entered into a gathering and processing agreement (the
"Ship Shoal Agreement") pursuant to which the Partnership constructed a
gathering line from Tatham Offshore's Ship Shoal Block 331 lease to interconnect
with a third-party pipeline at the Partnership's platform located on Ship Shoal
Block 332. In addition, the Partnership is operating the refurbished platform
located at Ship Shoal Block 332 to process production from Ship Shoal Block 331.
Pursuant to the terms of the Ship Shoal Agreement, and in consideration for
constructing the interconnect, refurbishing the platform and for providing
access to the processing facilities, Tatham Offshore was required to pay the
Partnership a demand charge of $113,000 per month over a five-year period ending
June 1999 and dedicated all production from its Ship Shoal 331 lease and eight
additional surrounding leases for gathering and processing by the Partnership.
The Ship Shoal Agreement remains in effect for the productive life of the
reserves or, if earlier, the expiration of 20 years from date of first
production. During late 1994, all of Tatham Offshore's wells at Ship Shoal 331
experienced completion and production problems. As a result, the Partnership
received only demand charges under this agreement during 1995. For the year
ended December 31, 1995, the Partnership received $1,360,000 from Tatham
Offshore for fees related to the Ship Shoal Agreement. In March 1996, the
Partnership settled all remaining unpaid demand charge obligations under this
transportation agreement in exchange for certain consideration as discussed
below.
VK 817 Platform. Tatham Offshore is also obligated to pay certain platform
access and processing fees to the Partnership. For the years ended December 31,
1997, 1996 and 1995, the Partnership received $1,973,000, $1,896,000 and
$823,000, respectively, from Tatham Offshore as platform access and processing
fees related to the Partnership's platform located in Viosca Knoll Block 817.
For the years ended December 31, 1997 and 1996, the Partnership charged Viosca
Knoll $2,116,000 and $249,000, respectively, for expenses and platform access
fees related to the Viosca Knoll 817 platform.
In addition, for the years ended December 31, 1997 and 1996, Viosca Knoll
reimbursed $47,000 and $254,000, respectively, to the Partnership for costs
incurred by the Partnership in connection with the acquisition and installation
of a booster compressor on the Partnership's Viosca Knoll 817 platform.
Transportation Agreements Settled. Tatham Offshore was obligated to make demand
charge payments to the Partnership pursuant to certain transportation agreements
discussed above. Under these agreements, the Partnership was entitled to receive
demand charges of $8,100,000 in 1996, $6,000,000 in 1997, $3,000,000 in 1998 and
$700,000
F-17
<PAGE> 56
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
in 1999. In addition to the demand charges, Tatham Offshore is obligated to pay
commodity charges, based on the volume of oil and gas transported or processed,
under these agreements.
Production problems at Ship Shoal Block 331 and reduced oil production from 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, the Partnership agreed to release Tatham Offshore
from all remaining demand charge payments under the Ewing Bank Gathering
Agreement and the Ship Shoal Agreement, a total of $17,800,000. Tatham Offshore
remains obligated to pay the commodity charges under these agreements as well as
all platform access and processing fees associated with the Viosca Knoll Block
817 lease. In exchange, the Partnership received 7,500 shares of Tatham Offshore
Senior Preferred Stock (the "Senior Preferred Stock"), which is presented on the
accompanying consolidated balance sheet at December 31, 1996 as investment in
affiliate. The Senior Preferred Stock has a liquidation preference of $1,000 per
share, is senior in liquidation preference to all other classes of Tatham
Offshore stock and has a 9% cumulative dividend, payable quarterly. Commencing
on October 1, 1998 and for a period of 90 days thereafter, the Partnership has
the option to exchange the remaining liquidation preference amount and accrued
but unpaid dividends for shares of Tatham Offshore's Series A 12% Convertible
Exchangeable Preferred Stock (the "Series A Preferred Stock") with an equivalent
market value. Further, the Partnership has made an irrevocable offer to Tatham
Offshore to sell all or any portion of the Senior Preferred Stock to Tatham
Offshore or its designee at a price equal to $1,000 per share, plus interest
thereon at 9% per annum less the sum of any dividends paid thereon. The Series A
Preferred Stock is convertible into Tatham Offshore common stock based on a
fraction, the numerator of which is the liquidation preference value plus all
accrued but unpaid dividends and the denominator of which is $6.53 per share. In
addition, the sum of $7,500,000 was added to the Payout Amount under the
Purchase and Sale Agreement. By adding $7,500,000 to the Payout Amount, the
Partnership is entitled to an additional $7,500,000 plus interest at the rate of
15% per annum from revenue attributable to the Acquired Properties prior to
reconveying any interest in the Acquired Properties to Tatham Offshore. In
addition, Tatham Offshore waived its remaining option to prepay the
then-existing Payout Amount and receive a reassignment of its working interests.
Tatham Offshore and the Partnership also agreed that in the event Tatham
Offshore furnishes the Partnership with a financing commitment from a lender
with a credit rating of BBB- or better covering 100% of the then outstanding
Payout Amount, then the interest rate utilized to compute the Payout Amount
shall be adjusted from and after the date of such commitment to the interest
rate specified in such commitment. Tatham Offshore granted the Partnership the
right to utilize the Ship Shoal Block 331 platform and related facilities at a
rental rate of $1.00 per annum for such period as the platform is owned by
Tatham Offshore and located on Ship Shoal Block 331, provided such use does not
interfere with lease operations or other activities of Tatham Offshore. In
addition, Tatham Offshore granted the Partnership a right of first refusal
relative to a sale of the platform.
Oil and gas sales. The Partnership has agreed to sell all of its oil and gas
production to Offshore Gas Marketing, Inc. ("Offshore Marketing"), an affiliate
of the Partnership, 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 the
Partnership's production. During the years ended December 31, 1997, 1996 and
1995, oil and gas sales to Offshore Marketing totaled $57,830,000, $46,296,000
and $922,000, respectively.
Other. During the years ended December 31, 1997, 1996 and 1995, Viosca Knoll
charged the Partnership $3,921,000, $3,229,000 and $86,000, respectively, for
transportation services related to transporting production from the Viosca Knoll
Block 817 lease. During the years ended December 31, 1997 and 1996, POPCO
charged the Partnership $2,003,000 and $1,056,000, respectively, for
transportation services related to transporting production from the Garden Banks
Block 72 and 117 leases.
Other
During the years ended December 31, 1997 and 1996, the Partnership 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 is owned by an affiliate of DeepTech
and managed by Sedco Forex.
F-18
<PAGE> 57
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
POPCO entered into certain additional agreements with a subsidiary of the
Partnership which provide 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.
Poseidon LLC managed the construction and installation of the initial 117 mile
segment of the Poseidon pipeline, which was placed in service in April 1996.
Texaco Trading managed the construction and installation of the remaining
pipelines and facilities comprising the Poseidon system, which were placed in
service in December 1996 and December 1997. Poseidon LLC was paid a performance
fee of $1,400,000 for managing the construction of the initial segment of the
Poseidon pipeline.
Pursuant to a management agreement between Viosca Knoll and the Partnership, the
Partnership 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, 1997, 1996 and 1995,
Leviathan charged Viosca Knoll $100,000 in accordance with this management
agreement.
For the year ended December 31, 1997, the Partnership charged Manta Ray Offshore
$287,000 pursuant to management and operations agreements.
Mr. Charles M. Darling IV, a director of Leviathan and DeepTech, was a partner
in a law firm until April 1997 that provides legal services to the Partnership.
During the years ended December 31, 1997, 1996 and 1995, the Partnership
incurred $55,000, $203,000 and $116,000, respectively, for these services.
Pursuant to the Leviathan non-employee director compensation arrangements, the
Partnership is obligated to pay each non-employee director 2 1/2% of the general
partners' Incentive Distribution as a profit participation fee. During the year
ended December 31, 1997, the Partnership paid the three non-employee directors
of Leviathan a total of $313,000 as a profit participation fee.
Dover Technology, Inc., which is 50% owned by DeepTech, performed certain
technical and geophysical services for the Partnership in the aggregate amount
of $240,000 and $58,000 for the years ended December 31, 1996 and 1995,
respectively.
NOTE 11 - INCOME TAXES:
The Partnership (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 the Partnership 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.
The tax attributes of the Partnership's net assets flow directly to each
individual partner. 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.
The Partnership utilizes the liability method under which deferred tax assets
and liabilities are recognized for the estimated future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. The Partnership
does not have access to information about each individual partner's tax
attributes in the Partnership, and the aggregate tax bases cannot be readily
determined. Accordingly, management does not believe that, in the Partnership's
circumstances, the aggregate difference would be meaningful information.
Tarpon is and Manta Ray was, prior to its liquidation in May 1996, a subsidiary
of the Partnership that files separate federal income tax returns. The income
tax benefit recorded for the years ended December 31, 1997, 1996, and 1995
equals $311,000, $801,000 and $603,000, respectively, and is entirely related to
Tarpon. The benefit equals Tarpon's
F-19
<PAGE> 58
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
book loss times the effective statutory rate for such period. The Partnership's
deferred income tax liability at December 31, 1997 and 1996 of $1,399,000 and
$1,722,000, 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 the Partnership. Manta Ray had no taxable income
for the respective periods prior to its liquidation.
NOTE 12 - COMMITMENTS AND CONTINGENCIES:
Credit Facilities
Each of Stingray, POPCO and Viosca Knoll are parties to a credit agreement under
which it has outstanding obligations that may restrict the payment of
distributions to its owners.
In December 1995, Stingray amended an existing term loan agreement (the
"Stingray Credit Agreement") to provide for aggregate outstanding borrowings of
up to $29 million in principal amount. The Stingray Credit Agreement requires
the payment of principal by Stingray of $1,450,000 per quarter. This term loan
agreement is principally secured by current and future gas transportation
contracts between Stingray and its customers. As of December 31, 1997, Stingray
had $17,400,000 outstanding under the Stingray Credit Agreement bearing interest
at an average floating rate of 6.53% per annum. On the earlier to occur of
December 31, 2000 or the accelerated due date pursuant to the Stingray Credit
Agreement, if Stingray has not settled all amounts due under the Stingray Credit
Agreement, the Partnership is obligated to pay the lesser of (i) $8,500,000,
(ii) the aggregate amount of distributions received by the Partnership from
Stingray subsequent to October 1, 1994, or (iii) 50% of any then outstanding
amounts due pursuant to the Stingray Credit Agreement.
In April 1996, POPCO entered into a revolving credit facility (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 secured by a substantial portion of POPCO's assets
and matures on April 30, 2001. As of December 31, 1997, POPCO had $120,500,000
outstanding under the POPCO Credit Facility bearing interest at an average
floating rate of 7.2% per annum. As of December 31, 1997, approximately
$27,900,000 of additional funds were available under the POPCO Credit Facility.
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 to the Viosca Knoll system
and for other working capital needs of Viosca Knoll, including funds for a
one-time distribution of $25,000,000 to its partners. In December 1996, the
Partnership received a $12,500,000 distribution from Viosca Knoll as a result of
its 50% working interest. Viosca Knoll's ability to borrow money under the
Viosca Knoll Credit Facility is subject to certain customary terms and
conditions, including borrowing base limitations. The Viosca Knoll Credit
Facility is secured by a substantial portion of Viosca Knoll's assets 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, the
Partnership 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, 1997, Viosca Knoll has $52,200,000 outstanding
under the Viosca Knoll Credit Facility bearing interest at an average floating
rate of 6.7% per annum. As of December 31, 1997, approximately $24,800,000 of
additional funds were available under the Viosca Knoll Credit Facility.
Hedging Activities
The Partnership hedges a portion of its oil and natural gas production to reduce
the Partnership's exposure to fluctuations in market prices of oil and natural
gas and to meet certain requirements of the Partnership Credit Facility. The
Partnership uses various financial 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. The Partnership 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 the Partnership differ from futures
contracts in that there is no contractual obligation which requires or allows
for the future delivery of the product. Gains or losses on hedging activities
are recognized as oil and gas sales in the period in which the hedged production
is sold.
F-20
<PAGE> 59
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
At December 31, 1997, the Partnership had open sales hedges on approximately
27,465 million British thermal units ("MMbtu") of natural gas per day for
calendar 1998 at an average price of $2.42 per MMbtu and open purchase hedges on
approximately 27,180 MMbtu of natural gas per day for calendar 1998 at an
average price of $2.28 per MMbtu. Subsequent to December 31, 1997, the
Partnership entered into commodity swap transactions for calendar 1999 totaling
5,000 MMbtu per day at a fixed price to be determined at the Partnership's
option equal to the January 1999 Natural Gas Futures Contract on NYMEX as quoted
at any time during 1998 to and including the last three trading days of the
January 1999 contract minus $0.25 per MMbtu.
At December 31, 1997, the Partnership had open crude oil hedges on approximately
990 barrels per day for calendar 1998 at an average price of $20.43 per barrel.
Subsequent to December 31, 1997, the Partnership entered into purchase hedge
contracts totaling 1,000 barrels of oil per day for calendar 1998 at an average
price of $17.29 per barrel.
If the Partnership had settled its open natural gas and crude oil hedging
positions as of December 31, 1997 based on the applicable settlement prices of
the NYMEX futures contracts, the Partnership would have recognized income of
approximately $2.2 million.
North Atlantic Pipeline Project. Tatham Offshore Canada Limited ("Tatham
Offshore Canada"), a wholly-owned subsidiary of Tatham Offshore, is the Canadian
representative of North Atlantic Pipeline Partners, L.P. ("North Atlantic"), the
sponsor of a proposal to build an approximately 2,500 kilometer pipeline from
offshore Newfoundland and Nova Scotia to the eastern seaboard of the United
States. The Partnership has entered into a letter agreement with Tatham Offshore
Canada regarding participation in the North Atlantic pipeline project. Under
such agreement, Tatham Offshore Canada is responsible for pre-development costs
of up to $10 million. Such agreement contains certain termination rights,
contemplates the negotiation, execution and delivery of definitive agreements
and provides that the Partnership would hold a pro rata partnership interest of
up to 20% in North Atlantic. The Partnership has no financial commitment to the
project until and unless an application is approved by the appropriate Canadian
and United States regulatory authorities. In the event the Partnership was to
terminate its participation in North Atlantic after the date North Atlantic
receives regulatory approval of an application but prior to the in-service date
of the first phase of the North Atlantic pipeline, the Partnership, under
certain conditions, would be obligated to pay Tatham Offshore Canada an amount
equal to 150% of the Partnership's pro rata share of the "success fee" earned by
Tatham Offshore Canada related to the first phase of construction. For a period
of one year after the effective date of the merger discussed in Note 16, the
Partnership shall have the right to terminate this agreement without incurring
the liability for the above-mentioned "success fee". During October 1997, North
Atlantic filed applications with the FERC and its Canadian counterpart, the
National Energy Board, for approval of its proposed pipeline. Tatham Offshore
Canada is seeking additional participants on similar terms as that offered to
the Partnership.
Other
In the ordinary course of business, the Partnership 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
the Partnership. Various legal actions which have arisen in the ordinary course
of business are pending with respect to the pipeline interests and other assets
of the Partnership. 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 or operations of the
Partnership.
NOTE 13 - SUPPLEMENTAL DISCLOSURES TO THE STATEMENTS OF CASH FLOWS:
Cash paid, net of amounts capitalized, during each of the periods presented
<TABLE>
<CAPTION>
Year ended December 31,
-----------------------------------------
1997 1996 1995
(In thousands)
<S> <C> <C> <C>
Interest $12,965 $ 2,890 $ --
Taxes $ 11 $ 20 $ 13
</TABLE>
F-21
<PAGE> 60
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
Supplemental disclosures of noncash investing and financing activities
<TABLE>
<CAPTION>
Year ended December 31,
--------------------------------------
1997 1996 1995
(In thousands)
<S> <C> <C> <C>
Increase in investment in affiliate $ -- $ (7,500) $ --
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 72,080 -- --
-------- -------- --------
$ 72,080 $ 29,758 $ --
======== ======== ========
</TABLE>
NOTE 14 - MAJOR CUSTOMERS:
The percentage of gathering, transportation and platform services revenue from
major customers was as follows:
<TABLE>
<CAPTION>
Year ended December 31,
-------------------------------
1997 1996 1995
(In thousands)
<S> <C> <C> <C>
Shell Gas Trading Company -- 17% 19%
Tatham Offshore (affiliated company) -- 30% 45%
Texaco Gas Marketing, Inc. 13% -- --
Walter Oil & Gas Corporation 13% -- --
</TABLE>
NOTE 15 - BUSINESS SEGMENT INFORMATION
The Partnership's operations consist of two segments: (i) pipeline gathering,
transportation and platform services and (ii) development and production of
proved oil and gas reserves. All of the Partnership's operations are conducted
in the Gulf. The following table summarizes certain financial information for
each business segment (in thousands):
<TABLE>
<CAPTION>
Gathering,
Transportation
and Platform Consolidating
Services Oil and Gas Subtotal Eliminations Total
-------------- ---------- ---------- ------------- ----------
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1997: (a)
Operating revenue $ 28,491 $ 58,106 $ 86,597 $ (11,162) $ 75,435
Operating expenses (3,221) (19,293) (22,514) 11,162 (11,352)
Depreciation, depletion and
amortization (9,831) (36,389) (46,220) -- (46,220)
Impairment, abandonment and other
(10,268) (10,954) (21,222) -- (21,222)
---------- ---------- ---------- ---------- ----------
Operating income $ 5,171 $ (8,530) $ (3,359) $ -- $ (3,359)
========== ========== ========== ========== ==========
Year Ended December 31, 1996: (a)
Operating revenue $ 34,057 $ 47,068 $ 81,125 $ (10,052) $ 71,073
Operating expenses (4,270) (14,850) (19,120) 10,052 (9,068)
Depreciation, depletion and
amortization (15,002) (16,729) (31,731) -- (31,731)
---------- ---------- ---------- ---------- ----------
Operating income $ 14,785 $ 15,489 $ 30,274 $ -- $ 30,274
========== ========== ========== ========== ==========
</TABLE>
- ----------------------
(a) The Partnership's activities related to the production of oil and gas
reserves commenced in December 1995 and therefore financial information for
each business segment is only presented for the years ended December 31,
1997 and 1996.
F-22
<PAGE> 61
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 16 - SUBSEQUENT EVENTS:
On March 2, 1998, DeepTech announced that its Board of Directors and a majority
of its stockholders have approved entering into a definitive merger agreement
with El Paso Natural Gas Company ("El Paso"). As a result of this merger and
through a series of transactions, El Paso will own 100% of Leviathan's general
partner interest in the Partnership and an overall 27.3% effective interest in
the Partnership. The merger is subject to customary regulatory approvals, the
consummation of certain related transactions and is expected to be completed by
the end of the second quarter of 1998.
In connection with the merger of DeepTech and El Paso, Tatham Offshore has
agreed to relinquish its reversionary rights relating to the Acquired Properties
and the Partnership has agreed to exchange 7,500 shares of Tatham Offshore
Senior Preferred Stock currently held by the Partnership for 100% of Tatham
Offshore's right, title and interest in and to Viosca Knoll Blocks 772, 773,
774, 817, 818 and 861, West Delta Block 35, Ewing Bank Blocks 871, 914, 915 and
916 and the platform located at Ship Shoal Block 331. At the closing, the
Partnership will receive from/pay to Tatham Offshore an amount equal to the net
cash generated from/required by such properties from January 1, 1998 through the
closing date. In addition, the Partnership has agreed to assume all abandonment
and restoration obligations associated with the platform and leases. This
transaction has been approved by the Board of Directors of each of Tatham
Offshore and Leviathan and is expected to close in July 1998.
NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
Oil and gas reserves
The following table represents the Partnership'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 1997, 1996 and
1995. Estimates of the Partnership's reserves at December 31, 1997, 1996 and
1995 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 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.
F-23
<PAGE> 62
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
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, 1994 561 815
Revisions of previous estimates (14) (24)
Purchase of reserves in place 3,822 60,975
Production (46) (474)
----- ------
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
===== ======
Proved developed reserves - December 31, 1995 187 30,671
===== ======
Proved developed reserves - December 31, 1996 3,149 44,075
===== ======
Proved developed reserves - December 31, 1997 2,119 28,324
===== ======
</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 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, the Partnership'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 the
Partnership's reserves is based upon volumetric calculations.
Future net cash flows
The standardized measure of discounted future net cash flows relating to the
Partnership's proved oil and 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 gas prices, as adjusted for hedging and other fixed price
contracts in effect, to the Partnership's estimated share of future production
from proved oil and gas reserves. The average prices utilized in the calculation
of the standardized measure of discounted future net cash flows at December 31,
1997 were $17.54 per barrel of oil and $2.49 per Mcf of gas. Future production
and development costs were computed by applying year-end costs to future years.
As the Partnership is not a taxable entity, no future income taxes were
provided. A prescribed 10% discount factor was applied to the future net cash
flows.
F-24
<PAGE> 63
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
In the Partnership's opinion, this standardized measure is not a
representative measure of fair market value, and the standardized measure
presented for the Partnership's proved oil and 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,
---------------------------------------
1997 1996 1995
(In thousands)
<S> <C> <C> <C>
Future cash inflows $104,192 $206,311 $193,593
Future production costs 15,895 13,019 12,004
Future development costs 10,463 5,328 33,007
Future income tax expenses -- -- --
-------- -------- --------
Future net cash flows 77,834 187,964 148,582
Annual discount at 10% rate 10,468 32,326 33,412
-------- -------- --------
Standardized measure of discounted future net cash flows $ 67,366 $155,638 $115,170
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
December 31, 1997
------------------------------------
Proved Proved
Developed Undeveloped Total
--------- ------------ --------
(In thousands)
<S> <C> <C> <C>
Undiscounted estimated future net cash flows from
proved reserves before income taxes $ 75,635 $ 2,199 $ 77,834
======== ========= ========
Present value of estimated future net cash flows from
proved reserves before income taxes, discounted at 10% $ 65,688 $ 1,678 $ 67,366
======== ========= ========
</TABLE>
The following are the principal sources of change in the standardized
measure (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Beginning of year $155,638 $115,170 $ 6,734
Sales and transfers of oil and gas produced,
net of production costs (53,492) (40,420) (1,685)
Net changes in prices and production costs (35,645) 45,358 (156)
Extensions, discoveries and improved recovery,
less related costs -- 17,077 --
Oil and gas development costs incurred
during the year 11,140 57,501 12,865 (a)
Changes in estimated future development costs (12,439) (29,421) --
Revisions of previous quantity estimates (3,817) (19,686) (176)
Purchase of reserves in place -- -- 97,188 (b)
Accretion of discount 15,564 11,517 673
Changes in production rates, timing and other (9,583) (1,458) (273)
-------- -------- --------
End of year $ 67,366 $155,638 $115,170
======== ======== ========
</TABLE>
- -------------------------------
(a) Excludes aggregate capital costs of $62,900,000 attributable to multipurpose
platforms completed during 1995 at Viosca Knoll Block 817 and Garden Banks
Block 72 which are to function as both drilling and production platforms as
well as pipeline junction platforms for the Partnerships' transportation
operations.
(b) See Note 3 for discussion of Purchase and Sale Agreement with Tatham
Offshore.
F-25
<PAGE> 64
LEVIATHAN GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
NOTE 18 - SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (unaudited):
<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)
Net income (loss) per Unit $ 0.32(b) $ (0.58)(b) $ 0.12(b) $ 0.08 $ (0.06)
Weighted average number of Units outstanding 24,367 24,367 24,367 24,367 24,367
Distributions declared per 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 $ 10,910 $ 9,161 $ 10,006 $ 8,615 $ 38,692
Net income 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 Unit $ 0.325 $ 0.35 $ 0.375 $ 0.40 $ 1.45
</TABLE>
<TABLE>
<CAPTION>
Year 1995
-----------------------------------------------------------
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 $ 8,475 $ 10,800 $ 12,266 $ 10,452 $ 41,993
Gross profit (a) $ 5,415 $ 7,873 $ 9,372 $ 6,951 $ 29,611
Net income $ 3,932 $ 7,130 $ 7,255 $ 5,628 $ 23,945
Net income per Unit $ 0.16 $ 0.29 $ 0.29 $ 0.23 $ 0.97
Weighted average number of Units outstanding 24,367 24,367 24,367 24,367 24,367
Distributions declared per Unit $ 0.30 $ 0.30 $ 0.30 $ 0.30 $ 1.20
</TABLE>
- ---------------------------
(a) Represent revenue less operating and depreciation, depletion and
amortization expenses.
(b) Restated to properly reflect the allocation of net income (loss) resulting
from Incentive Distributions to the general partner. Previously, the
Partnership had reported net income (loss) of $0.36 per Unit, ($0.64) per
Unit and $0.13 per Unit for the quarters ended March 31, June 30 and
September 30, respectively.
F-26
<PAGE> 65
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) as of December 31, 1997 and 1996, and the results
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 in accordance with generally accepted auditing standards which require
that we plan and perform the audits 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.
Price Waterhouse LLP
Houston, Texas
March 2, 1998
F-27
<PAGE> 66
VIOSCA KNOLL GATHERING COMPANY
(a Delaware general partnership)
BALANCE SHEET
<TABLE>
<CAPTION>
ASSETS
December 31,
-----------------------------------
1997 1996
<S> <C> <C>
Current assets:
Cash $ 134,815 $ 417,193
Accounts receivable 2,657,576 2,998,388
Accounts receivable from affiliates 561,439 1,133,709
------------- -------------
Total current assets 3,353,830 4,549,290
------------- -------------
Property, plant and equipment:
Pipelines 103,121,527 67,253,786
Construction-in-progress 1,448,519 8,326,390
Other 23,645 23,645
------------- -------------
104,593,691 75,603,821
Less: Accumulated depreciation (6,885,744) (4,495,656)
------------- -------------
Property, plant and equipment, net 97,707,947 71,108,165
------------- -------------
Debt issue costs, net 296,119 300,000
------------- -------------
Total assets $ 101,357,896 $ 75,957,455
============= =============
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable $ 3,841,394 $ 1,904,472
Accounts payable to affiliates 850,452 337,504
Accrued liabilities 6,587,999 260,262
------------- -------------
Total current liabilities 11,279,845 2,502,238
Provision for negative salvage 256,515 173,175
Notes payable 52,200,000 33,300,000
------------- -------------
63,736,360 35,975,413
------------- -------------
Commitments and contingencies (Note 5)
Partners' capital:
VK-Deepwater 18,810,768 19,991,021
EPEC Deepwater 18,810,768 19,991,021
------------- -------------
37,621,536 39,982,042
------------- -------------
Total liabilities and partners' capital $ 101,357,896 $ 75,957,455
============= =============
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-28
<PAGE> 67
VIOSCA KNOLL GATHERING COMPANY
(a Delaware general partnership)
STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
Year ended December 31,
---------------------------------
1997 1996
<S> <C> <C>
Revenue:
Transportation services $ 23,127,864 $ 13,923,172
------------ ------------
Costs and expenses:
Operating expenses 1,990,062 298,465
Depreciation 2,473,428 2,268,755
General and administrative expenses 124,960 126,276
------------ ------------
4,588,450 2,693,496
------------ ------------
Operating income 18,539,414 11,229,676
Interest income 39,195 --
Interest and other financing costs (1,959,355) (90,034)
------------ ------------
Net income $ 16,619,254 $ 11,139,642
============ ============
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-29
<PAGE> 68
VIOSCA KNOLL GATHERING COMPANY
(a Delaware general partnership)
STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Year ended December 31,
----------------------------------
1997 1996
<S> <C> <C>
Cash flows from operating activities:
Net income $ 16,619,254 $ 11,139,642
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation 2,473,428 2,268,755
Amortization of debt issue costs 74,028 --
Changes in operating working capital:
Decrease (increase) in accounts receivable 340,812 (1,462,130)
Decrease (increase) in accounts receivable
from affiliates 572,270 (1,045,670)
Increase in accounts payable 1,936,922 1,557,033
Increase (decrease) in accounts payable to affiliates 512,948 (2,311,682)
Increase (decrease) in accrued liabilities 6,327,737 (250,738)
------------ ------------
Net cash provided by operating activities 28,857,399 9,895,210
------------ ------------
Cash flows from investing activities:
Additions to pipeline assets (27,541,351) (5,219,180)
Construction-in-progress (1,448,519) (3,410,462)
------------ ------------
Net cash used in investing activities (28,989,870) (8,629,642)
------------ ------------
Cash flows from financing activities:
Proceeds from note payable 18,900,000 33,300,000
Contributions from partners 320,240 3,018,936
Distributions to partners (19,300,000) (36,900,000)
Debt issue costs (70,147) (300,000)
------------ ------------
Net cash used in financing activities (149,907) (881,064)
------------ ------------
Net (decrease) increase in cash (282,378) 384,504
Cash at beginning of year 417,193 32,689
------------ ------------
Cash at end of year $ 134,815 $ 417,193
============ ============
Cash paid for interest, net of amounts capitalized $ 1,877,521 $ --
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-30
<PAGE> 69
VIOSCA KNOLL GATHERING COMPANY
(a Delaware general partnership)
STATEMENT OF PARTNERS' CAPITAL
<TABLE>
<CAPTION>
VK EPEC
Deepwater Deepwater Total
------------ ------------ ------------
<S> <C> <C> <C>
Partners' capital at
December 31, 1995 $ 31,361,732 $ 31,361,732 $ 62,723,464
Contributions 1,509,468 1,509,468 3,018,936
Distributions (18,450,000) (18,450,000) (36,900,000)
Net income 5,569,821 5,569,821 11,139,642
------------ ------------ ------------
Partners' capital at
December 31, 1996 19,991,021 19,991,021 39,982,042
Contributions 160,120 160,120 320,240
Distributions (9,650,000) (9,650,000) (19,300,000)
Net income 8,309,627 8,309,627 16,619,254
------------ ------------ ------------
Partners' capital at
December 31, 1997 $ 18,810,768 $ 18,810,768 $ 37,621,536
============ ============ ============
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-31
<PAGE> 70
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"), a subsidiary of El Paso
Tennessee Pipeline Co. 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 an approximate 125-mile gathering system extending
from the Main Pass area of the Gulf of Mexico (the "Gulf") through the Viosca
Knoll area and terminating at points of interconnection with existing interstate
pipelines in the South Pass area of the Gulf offshore Louisiana. The Viosca
Knoll System, originally designed to transport 400 million cubic feet ("MMcf")
of gas per day, began gathering activities in November 1994. During 1996, Viosca
Knoll installed a 6,000 horsepower compressor on Leviathan's platform to
increase throughput capacity to approximately 700 MMcf of gas per day. In
December 1997, Viosca Knoll placed in service an expansion to its system of
approximately 25 miles of 20-inch pipe which enables Viosca Knoll to transport
additional gas volumes from producing areas near the eastern end of the system.
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, plant 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 are capitalized.
Viosca Knoll adopted 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", effective January 1, 1996. SFAS No. 121 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. Implementation of
SFAS No. 121 did not have a material effect on Viosca Knoll's financial position
or results of operations.
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.
F-32
<PAGE> 71
VIOSCA KNOLL GATHERING COMPANY
(a Delaware general Partnership)
NOTES TO FINANCIAL STATEMENTS - (continued)
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.
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 $100.0 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 $25,000,000 to its partners.
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 secured by all of Viosca Knoll's material contracts and
agreements, receivables and inventory and matures on December 20, 2001. As of
December 31, 1997 and 1996, Viosca Knoll had $52,200,000 and $33,300,000,
respectively, outstanding under the Viosca Knoll Credit Facility bearing
interest at an average floating rate of 6.7% and 6.69% per annum. As of December
31, 1997, approximately $24,800,000 of additional funds are available under the
Viosca Knoll Credit Facility. See Note 7.
Interest and other financing costs incurred by Viosca Knoll totaled $2,636,799
and $90,034 for the years ended December 31, 1997 and 1996, respectively. During
the year ended December 31, 1997, Viosca Knoll capitalized $677,444 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,
1997 and 1996, Leviathan charged Viosca Knoll $100,000 in accordance with this
management agreement.
Viosca Knoll and EPEC Gas Services, Inc. ("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, 1997 and 1996, EPEC Gas charged Viosca Knoll $215,800 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, 1997 and
1996, Viosca Knoll reimbursed EPEC Gas $1,282,309 and $8,072,264, respectively,
for construction related costs. For the years ended December 31, 1997 and 1996,
Viosca Knoll reimbursed VK Main Pass $47,409 and $254,127, respectively, for
construction related items.
F-33
<PAGE> 72
VIOSCA KNOLL GATHERING COMPANY
(a Delaware general Partnership)
NOTES TO FINANCIAL STATEMENTS - (continued)
Included in transportation services revenue during the years ended December 31,
1997 and 1996 is $3,920,909 and $3,229,338, 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, 1997 and 1996 is $2,116,213 and $248,816, 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,
--------------------------------------------
1997 1996
------------------- ---------------------
Amount % Amount %
<S> <C> <C> <C> <C>
Shell Offshore, Inc. $11,198,478 48 $ 5,140,714 37
Flextrend Development Company, L.L.C 3,920,909 17 3,229,338 23
Snyder Oil Company (formerly Delmar
Operating, Inc.) 3,653,387 16 3,274,945 24
Other 4,355,090 19 2,278,175 16
----------- --- ----------- ---
$23,127,864 100 $13,923,172 100
=========== === =========== ===
</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 years ended December 31, 1997 and 1996, Viosca Knoll
paid distributions of $19,300,000 and $36,900,000, respectively, to its
partners. The distributions paid during 1996 include $25,000,000 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.
F-34
<PAGE> 73
INDEPENDENT AUDITORS' REPORT
To the Management Committee
High Island Offshore System
Detroit, Michigan
We have audited the accompanying statements of financial position of High Island
Offshore Systems as of December 31, 1997 and 1996, and the related statements of
income, changes in partners' equity, and cash flows for the years then ended.
These financial statements are the responsibility of the High Island Offshore
System'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 audits 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 as of December
31, 1997 and 1996, and the results of its operations and its cash flows for the
years then ended in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
February 18, 1998
F-35
<PAGE> 74
HIGH ISLAND OFFSHORE SYSTEM
STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 1997 AND 1996
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996
----------------- ------------------
ASSETS
CURRENT ASSETS
<S> <C> <C>
Cash and cash equivalents $ 876,845 $ 3,285,926
Accounts receivable 4,709,918 4,717,178
Prepayments -- 211,842
----------------- ------------------
Total current assets 5,586,763 8,214,946
----------------- ------------------
GAS TRANSMISSION PLANT 371,321,033 370,130,378
Less - accumulated depreciation 359,830,332 355,589,997
----------------- ------------------
Net gas transmission plant 11,490,701 14,540,381
----------------- ------------------
DEFERRED CHARGES 590,189 444,895
----------------- ------------------
TOTAL ASSETS $ 17,667,653 $ 23,200,222
================= ==================
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 3,077,779 $ 1,850,780
Unamortized rate reductions for excess deferred
Federal income taxes 302,021 302,021
----------------- ------------------
Total current liabilities 3,379,800 2,152,801
----------------- ------------------
NON CURRENT LIABILITIES
Unamortized rate reductions for excess deferred
federal income taxes 198,510 500,334
----------------- ------------------
COMMITMENTS AND CONTINGENCIES (Note 6) -- --
PARTNERS' EQUITY 14,089,343 20,547,087
----------------- ------------------
TOTAL LIABILITIES AND PARTNERS' EQUITY $ 17,667,653 $ 23,200,222
================= ==================
</TABLE>
SEE NOTES TO THE FINANCIAL STATEMENTS.
F-36
<PAGE> 75
HIGH ISLAND OFFSHORE SYSTEM
STATEMENTS OF INCOME AND STATEMENTS OF PARTNERS' EQUITY
YEARS ENDED DECEMBER 31, 1997 AND 1996
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
STATEMENTS OF INCOME 1997 1996
----------------- ------------------
OPERATING REVENUES
<S> <C> <C>
Transportation services $ 45,414,839 $ 47,052,978
Other 502,111 387,764
----------------- ------------------
Total operating revenues 45,916,950 47,440,742
----------------- ------------------
OPERATING EXPENSES
Operation and maintenance 16,975,738 15,548,824
Depreciation 4,773,588 4,775,405
Property taxes 125,368 133,662
----------------- ------------------
Total operating expenses 21,874,694 20,457,891
----------------- ------------------
NET OPERATING INCOME 24,042,256 26,982,851
----------------- ------------------
OTHER DEDUCTIONS
Interest on rate refund obligation -- 96,624
----------------- ------------------
Total other deductions -- 96,624
----------------- ------------------
NET INCOME $ 24,042,256 $ 27,079,475
================= ==================
STATEMENTS OF PARTNERS' EQUITY
BALANCE AT BEGINNING OF PERIOD $ 20,547,087 $ 21,967,612
Net income 24,042,256 27,079,475
Distributions to partners (30,500,000) (28,500,000)
----------------- ------------------
BALANCE AT END OF PERIOD $ 14,089,343 $ 20,547,087
================= ==================
</TABLE>
SEE NOTES TO THE FINANCIAL STATEMENTS.
F-37
<PAGE> 76
HIGH ISLAND OFFSHORE SYSTEM
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1997 AND 1996
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996
----------------- ------------------
CASH FLOWS FROM OPERATING ACTIVITIES
<S> <C> <C>
Net income $ 24,042,256 $ 27,079,475
Adjustments to reconcile net income to cash
provided by operating activities
Depreciation 4,773,588 4,775,405
Decrease (increase) in accounts receivable 7,260 (353,633)
Decrease in prepayments 211,842 91,444
(Increase) decrease in deferred charges and other (145,294) 67,173
Decrease in provision for regulatory matters -- (1,050,623)
Increase (decrease) in accounts payable 23,821 (1,515,481)
----------------- ------------------
Cash provided by operating activities 28,913,473 29,093,760
----------------- ------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (822,554) (209,863)
----------------- ------------------
Cash used in investing activities (822,554) (209,863)
----------------- ------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to partners (30,500,000) (28,500,000)
----------------- ------------------
Cash used in financing activities (30,500,000) (28,500,000)
----------------- ------------------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS DURING PERIOD
(2,409,081) 383,897
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,285,926 2,902,029
----------------- ------------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 876,845 $ 3,285,926
================= ==================
</TABLE>
SEE NOTES TO THE FINANCIAL STATEMENTS.
F-38
<PAGE> 77
HIGH ISLAND OFFSHORE SYSTEM
NOTES TO THE FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997 AND 1996
- --------------------------------------------------------------------------------
1. FORMATION AND OWNERSHIP STRUCTURE
Description and Business Purpose
High Island Offshore System ("HIOS" or the "Company" ) is a Delaware
partnership. The partners, each of which has a 20% interest in HIOS, are
companies affiliated with three pipeline companies as follows:
<TABLE>
<CAPTION>
Partner Affiliated Pipeline Company
------- ---------------------------
<S> <C>
American Natural Offshore Company ANR Pipeline Company
NATOCO, Inc. Natural Gas Pipeline Company of America
Texam Offshore Gas Transmission, L.L.C. Leviathan Gas Pipeline Partners, L.P.
Texas Offshore Pipeline System, Inc. ANR Pipeline Company
Transco Offshore Pipeline Company, L.L.C. Leviathan Gas Pipeline Partners, L.P.
</TABLE>
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 partner 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 ($11.4 million for 1997 and
$9.6 million for 1996).
F-39
<PAGE> 78
HIGH ISLAND OFFSHORE SYSTEM
NOTES TO THE FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The Company is regulated by and subject to the regulations and accounting
procedures of 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 1997 and
1996 which include a provision for negative salvage of .2% for offshore
facilities.
Income Taxes
Income taxes are the responsibility of the partners and, therefore, are not
reflected in the financial statements of partnership.
Statement of Cash Flows
For purposes of these financial statements, the Company considers
short-term investments to be cash equivalents. The Company had short-term
investments in the amount of $.9 million and $3.1 million at December 31, 1997
and 1996 respectively. The Company made no cash payments for interest in 1997 or
1996.
F-40
<PAGE> 79
HIGH ISLAND OFFSHORE SYSTEM
NOTES TO THE FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
Reclassifications
Certain reclassifications have been made to the 1996 financial statements
and notes to the financial statements to conform to the 1997 presentation,
including removing the presentation of income taxes from the partnership
financial statements. The effect of the reclassifications was not material to
the Company's results of operations or financial position.
3. REGULATORY MATTERS
The settlement of Docket No. RP92-50 on December 28, 1992, provided that
HIOS was obligated to refund to its shippers certain reimbursements it received
from U-T Offshore System (UTOS) and from ANR related to charges HIOS paid for
liquid separation, dehydration and natural gas measurement facilities at UTOS'
Cameron Meadows plant and ANR's Grand Chenier plant. UTOS is equally owned by
affiliates of ANR, Natural Gas Pipeline Company of America, and Leviathan Gas
Pipeline Partners L.P. The disposition of reimbursements received by HIOS in
1993 was subject to a revised refund plan filed by HIOS with the FERC. As a
result of a settlement reached in September 1996, HIOS made refunds of $442,000.
On June 11, 1993, HIOS filed a settlement with the FERC to recover the cost
of purchasing line pack gas owned by HIOS's firm shippers to assist it in
complying with FERC Order No. 636. The settlement was approved by the FERC on
October 12, 1993. Under the terms of the settlement, HIOS compensated the firm
shippers who previously owned the line pack through periodic payments totaling
$1,129,834 which HIOS collected from the current shippers via a limited term
surcharge which was placed in effect on November 1, 1993. On April 22, 1996,
HIOS filed with the FERC final reports of line pack surcharge collections and
payments which reflect the completion of the line pack cost recovery and
disbursement process. Revised tariff sheets were also filed to reflect the
removal of the line pack commodity surcharge provisions contained in Section 15
of the General Terms and Conditions and related provisions of HIOS' tariff.
F-41
<PAGE> 80
HIGH ISLAND OFFSHORE SYSTEM
NOTES TO THE FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
4. 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.
5. RELATED PARTY TRANSACTIONS
Transportation revenues derived from affiliated pipeline companies were
$6.2 million for 1997 and $16.7 million for 1996. Accounts receivable balances
due from these affiliates for transportation services amounted to $0 at December
31, 1997, and $1.5 million at December 31, 1996.
Both ANR and UTOS provide separation, dehydration and measurement services
to HIOS. HIOS incurred charges for these services of $2.5 million in 1997 and
$2.8 million in 1996 from ANR and $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 $1,794,000 and $27,000 at December 31, 1997 and
1996, respectively, and amounts due to UTOS were $134,000 and $86,000 at
December 31, 1997 and 1996, respectively.
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.
F-42
<PAGE> 81
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, 1997
and 1996, and the related statements of income, members' equity and cash flows
for the year ended December 31, 1997 and 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, 1997 and 1996, and the results of its operations and
its cash flows for the year ended December 31, 1997 and the period from
inception (February 14, 1996) through December 31, 1996, in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Denver, Colorado,
February 20, 1998.
F-43
<PAGE> 82
POSEIDON OIL PIPELINE COMPANY, L.L.C.
BALANCE SHEETS--DECEMBER 31, 1997 AND 1996
<TABLE>
<CAPTION>
1997 1996
---- ----
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents .............................. $ 1,671,451 $ 730,480
Crude oil receivable-
Related parties ..................................... 21,729,130 27,681,528
Other ............................................... 7,316,566 3,873,550
Construction advances to operator (Note 6) ............. -- 7,407,710
Materials, supplies and other .......................... 1,045,937 93,643
------------- -------------
Total current assets ...................... 31,763,084 39,786,911
DEBT RESERVE FUND (Notes 2 and 4) .......................... 3,717,627 --
PROPERTY, PLANT AND EQUIPMENT, net of
accumulated depreciation (Note 3) ...................... 222,337,758 174,922,387
------------- -------------
Total assets .............................. $ 257,818,469 $ 214,709,298
============= =============
LIABILITIES AND MEMBERS' EQUITY
CURRENT LIABILITIES:
Accounts payable-
Related parties ..................................... $ 2,602,133 $ 1,556,443
Other ............................................... 5,516,554 622,607
Crude oil payable-
Related parties ..................................... 22,534,661 32,195,796
Other ............................................... 5,139,391 3,576,343
Other .................................................. 70,922 87,032
------------- -------------
Total current liabilities ................. 35,863,661 38,038,221
------------- -------------
LONG-TERM DEBT (Note 4) .................................... 120,500,000 84,000,000
------------- -------------
CONTINGENCIES (Note 7)
MEMBERS' EQUITY (Note 1):
Capital contributions .................................. 107,999,320 107,999,320
Capital distributions .................................. (17,999,320) (17,999,320)
Retained earnings ...................................... 11,454,808 2,671,077
------------- -------------
Total members' equity ..................... 101,454,808 92,671,077
------------- -------------
Total liabilities and members' equity ..... $ 257,818,469 $ 214,709,298
============= =============
</TABLE>
The accompanying notes are an integral part of these balance sheets.
F-44
<PAGE> 83
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1997 AND FOR THE PERIOD
FROM INCEPTION (FEBRUARY 14, 1996) THROUGH DECEMBER 31, 1996
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
CRUDE OIL SALES ........................ $ 310,828,794 $ 176,849,075
CRUDE OIL PURCHASES .................... (284,667,502) (169,030,526)
------------- -------------
Net sales revenue ........ 26,161,292 7,818,549
------------- -------------
OPERATING COSTS:
Transportation costs ............... 3,146,736 858,229
Operating expenses ................. 2,635,717 2,183,375
Depreciation ....................... 6,463,327 2,176,157
------------- -------------
Total operating costs .... 12,245,780 5,217,761
------------- -------------
OPERATING INCOME ....................... 13,915,512 2,600,788
OTHER INCOME (EXPENSE):
Interest income .................... 208,961 339,452
Interest expense ................... (5,340,742) (269,163)
------------- -------------
NET INCOME ............................. $ 8,783,731 $ 2,671,077
============= =============
</TABLE>
The accompanying notes are an integral part of these statements.
F-45
<PAGE> 84
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF MEMBERS' EQUITY
FOR THE YEAR ENDED DECEMBER 31, 1997 AND FOR THE PERIOD
FROM INCEPTION (FEBRUARY 14, 1996) THROUGH DECEMBER 31, 1996
<TABLE>
<CAPTION>
Poseidon Texaco
Marathon Pipeline Trading and
Oil Company, Transportation,
Company L.L.C. 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
============= ============= ============= =============
</TABLE>
The accompanying notes are an integral part of these statements.
F-46
<PAGE> 85
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1997 AND FOR THE PERIOD
FROM INCEPTION (FEBRUARY 14, 1996) THROUGH DECEMBER 31, 1996
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 8,783,731 $ 2,671,077
Adjustments to reconcile net income to net cash
provided by operating activities-
Depreciation 6,463,327 2,176,157
Changes in operating assets and liabilities-
Crude oil receivable 2,509,382 (31,555,078)
Materials, supplies and other (952,294) (93,643)
Accounts payable 5,939,637 2,179,050
Crude oil payable (8,098,087) 35,772,139
Other current liabilities (16,110) 87,032
------------- -------------
Net cash provided by operating activities 14,629,586 11,236,734
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (54,024,948) (110,698,884)
Construction advances to operator, net 7,407,710 (7,407,710)
Proceeds from the sale of property, plant and equipment 146,250 --
------------- -------------
Net cash used in investing activities (46,470,988) (118,106,594)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt 38,000,000 107,000,000
Cash contributions -- 41,599,660
Repayments of long-term debt (1,500,000) (23,000,000)
Cash distributions -- (17,999,320)
Increase in debt reserve fund (3,717,627) --
------------- -------------
Net cash provided by financing activities 32,782,373 107,600,340
------------- -------------
INCREASE IN CASH AND CASH EQUIVALENTS 940,971 730,480
CASH AND CASH EQUIVALENTS, beginning of year 730,480 --
------------- -------------
CASH AND CASH EQUIVALENTS, end of year $ 1,671,451 $ 730,480
============= =============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest (net of amounts capitalized) $ 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 statements.
F-47
<PAGE> 86
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 1997 AND 1996
(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 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% 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% and 33 1/3%, 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% 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,
F-48
<PAGE> 87
Poseidon and Marathon owned 36%, 36% and 28% of the Company, respectively, and
total equity was $90,000,000.
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.
In April 1996, the Company purchased crude oil line-fill and began operating
Phase I of the pipeline. Phase I consists of 16" and 20" sections of pipe
extending from the Garden Banks Block 72 to Ship Shoal Block 332. Phase II of
the pipeline is a 24" 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" line extending from Caillou Island to the Houma,
Louisiana area, was completed during 1997 and began operations in December 1997.
(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.
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
F-49
<PAGE> 88
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 3 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 (Note 4), the Company
is required to maintain a debt reserve account as security on the outstanding
balance. At December 31, 1997 the balance in the account totaled $3,717,627 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
F-50
<PAGE> 89
based on current rates available for similar debt with similar maturities and
securities, and at December 31, 1997, approximates the carrying value.
Reclassifications
The Company reclassified the 1996 crude oil inventory balance related to
line-fill to conform to the long-term presentation used in the current year and
to fairly reflect the long-term nature of the asset.
(3) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consisted of the following at December 31:
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
Rights-of-way $ 3,218,788 $ 21,824
Line-fill 11,160,410 12,137,729
Line pipe, line pipe fittings and pipeline
construction 206,041,256 95,571,124
Pumping and station equipment 4,584,563 3,730,325
Office furniture, vehicles and other equipment 67,609 64,000
Construction work-in-progress 5,904,616 65,573,542
------------- -------------
230,977,242 177,098,544
Accumulated depreciation (8,639,484) (2,176,157)
------------- -------------
$ 222,337,758 $ 174,922,387
============= =============
</TABLE>
During 1996 and 1997, the Company considered two alternatives for completing
Phase III of the pipeline; 1) purchasing the Texas Eastern Pipeline which
extends from Caillou Island to Larose, Louisiana, or 2) constructing a segment
of line from Caillou Island to Houma, Louisiana. At December 31, 1996, the
Company capitalized approximately $5.9 million in costs associated with Phase
III of the pipeline. These costs were incurred primarily to evaluate the two
alternatives
F-51
<PAGE> 90
discussed above. During 1997, the Company's management decided to construct
Phase III of the pipeline rather than purchase the Texas Eastern Pipeline. At
December 31, 1997, approximately $6.4 million is included in property, plant and
equipment as capitalized costs related to the evaluation of the Phase III
alternatives.
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,
1997.
During 1997 and 1996, the Company capitalized approximately $2,151,000 and
$2,597,000, respectively of interest expense into property, plant and equipment.
(4) DEBT
The Company maintains a $150,000,000 revolving credit facility with a group of
banks. The outstanding balance at December 31, 1997 is $120,500,000. 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 twelve months if a
Eurodollar interest rate arrangement is selected (7.19% - 7.22% at December 31,
1997). 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.
F-52
<PAGE> 91
At December 31, 1997, 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
primarily used the funds drawn on the revolver for construction costs associated
with Phases II and III of the pipeline.
The revolving Credit Agreement requires the Company to meet certain financial
and non-financial 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 (Note 2) with a balance equal to two times the interest payments made in
the previous quarter under the credit facility. At December 31, 1997, the
Company is in compliance with all covenants.
(5) INCOME TAXES
A provision for income taxes has not been recorded in the accompanying financial
statements because taxes accrue directly to the members. The federal and state
income tax returns of the Company are prepared and filed by the operator.
(6) TRANSACTIONS WITH RELATED PARTIES
The Company derives a significant portion of its net sales revenue from its
members and other related parties. During 1997 and 1996, the Company generated
approximately $19,790,000 and $4,086,000, respectively of net sales revenue from
related parties.
F-53
<PAGE> 92
The Company paid approximately $454,000 and $401,000 to TTTI in 1997 and 1996,
respectively for management, administrative and general overhead. During 1996,
the Company paid TTTI and Poseidon approximately $1,034,000 and $1,330,000 for
construction management fees for the construction of Phase II and Phase I,
respectively. In 1997, the Company paid construction management fees to TTTI in
connection with the completion of Phase II and Phase III of $1,091,000. As of
December 31, 1997 and 1996, the Company had outstanding advances to TTTI of
approximately $0 and $7,408,000, respectively, in connection with construction
work-in-progress.
During 1996, the Company leased a section of pipe that connected Phase I of the
pipeline into the Eugene Island Pipeline System from a related party. The line
was leased for $100,000 per month. Effective with the operation of Phase II in
January 1997, the Company no longer utilized this section of line. The Company
paid costs of approximately $752,000 associated with restoring this section of
line to its original condition in accordance with the lease agreement during
1997. Of these costs, $592,000 and $160,000 are included in operating expenses
in the accompanying statement of operations for the years ended December 31,
1997 and 1996, respectively.
(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-54
<PAGE> 93
INDEX TO EXHIBITS
Item
Number Description
------ -----------
3.1 - Certificate of Limited Partnership of the Partnership (filed as
Exhibit 3.1 to the Partnership's Registration Statement on Form
S-1, File No. 33-55642, and incorporated herein by reference).
3.2 - Amended and Restated Agreement of Limited Partnership of the
Partnership (filed as Exhibit 10.41 to Amendment No. 1 to
DeepTech's Registration Statement on Form S-1, File No. 33-73538,
and incorporated herein by reference).
3.3 - Amendment Number 1 to the Amended and Restated Agreement of
Limited Partnership of the Partnership (filed as Exhibit 10.1 to
the Partnership's Current Report on Form 8-K dated December 31,
1996, and incorporated herein by reference).
4.1 - Form of Certificate Evidencing Preference Units Representing
Limited Partner Interests (filed as Exhibit 4.1 to Amendment No.
2 to the Partnership's Registration Statement on Form S-1, File
No. 33-55642, and incorporated herein by reference).
4.2 - Form of Certificate Evidencing Common Units Representing
Limited Partner Interests (filed as Exhibit 4.2 to Amendment No.
2 to the Partnership's Registration Statement on Form S-1, File
No. 33-55642, and incorporated herein by reference).
10.01 - First Amended and Restated Management Agreement, effective as
of July 1, 1992, between the Partnership and Leviathan (filed as
Exhibit 10.1 to DeepTech's Annual Report on Form 10-K for the
fiscal year ended June 30, 1994, Commission File Number 0-23934
and incorporated herein by reference).
10.02 - Management Agreement, dated July 1, 1992, between DeepTech and
Leviathan (filed as Exhibit 10.10 to Amendment No. 1 to the
Partnership's Registration Statement on Form S-1, File No.
33-55642, and incorporated herein by reference).
10.03 - Agreement for Purchase and Sale by and between Tatham
Offshore, Inc., as Seller, and Flextrend Development Company,
L.L.C., as Buyer, dated June 30, 1995 (filed as Exhibit 6(a) to
the Partnership's Form 10-Q for the quarterly period ended June
30, 1995, and incorporated herein by reference).
<PAGE> 94
10.04 - Limited Liability Company Agreement of POPCO (filed as Exhibit
10.39 to the Partnership's Annual Report on Form 10-K for the
fiscal year ended December 31, 1995, and incorporated herein by
reference).
10.05 - Letter Agreement dated March 27, 1996, between the Partnership
and Tatham Offshore related to the settlement of certain demand
charges under transportation agreements (filed as Exhibit 10.40
to the Partnership's Annual Report on Form 10-K for the fiscal
year ended December 31, 1995, and incorporated herein by
reference).
10.06 - Second Amended and Restated Credit Agreement dated December
13, 1996 among Partnership, The Chase Manhattan Bank, as
administrative agent, ING (U.S.) Capital Corporation, as co
arranger, and the banks and other financial institutions from
time to time party thereto (filed as exhibit 10.24 to the
Partnership's Annual Report on Form 10-K for the fiscal year
ended December 31, 1996, and incorporated herein by reference).
10.07 - Fourth Amendment to First Amended and Restated Management
Agreement between DeepTech International Inc. and Leviathan Gas
Pipeline Company dated as of May 1, 1997 (filed as Exhibit 10.1
to the Partnership's Form 10-Q for the quarterly period ended
June 30, 1997, and incorporated herein by reference).
10.08 - Fifth Amendment to First Amended and Restated Management
Agreement between DeepTech International Inc. and Leviathan Gas
Pipeline Company (filed as Exhibit 10.1 to the Partnership's Form
10-Q for the quarterly period ended September 30, 1997, and
incorporated herein by reference).
10.09 - Leviathan Unit Rights Appreciation Plan.
21.1* - List of Subsidiaries of the Partnership.
24.1 - Power of Attorney (included on the signature pages of this
Annual Report on Form 10-K).
27* - Financial Statement Data.
* Filed herewith.
<PAGE> 1
EXHIBIT 21.1
LEVIATHAN SUBSIDIARIES
Delos Offshore Company, L.L.C., a Delaware limited liability company
Ewing Bank Gathering Company, L.L.C., a Delaware limited liability company
Flextrend Development Company, L.L.C., a Delaware limited liability company
Green Canyon Pipe Line Company, L.L.C., a Delaware limited liability company
West Cameron Dehydration Company, L.L.C., a Delaware limited liability
company (50%)
Leviathan Oil Transport Systems, L.L.C., a Delaware limited liability company
Manta Ray Gathering Company, L.L.C., a Delaware limited liability company
Poseidon Pipeline Company, L.L.C., a Delaware limited liability company
Poseidon Oil Pipeline Company, L.L.C., a Delaware limited liability
company (36%)
Sailfish Pipeline Company, L.L.C., a Delaware limited liability company
Neptune Pipeline Company, L.L.C., a Delaware limited liability
company (25.67%)
Ocean Breeze Pipeline Company, L.L.C., a Delaware limited liability
company (25.67%)
Manta Ray Offshore Gathering Company, L.L.C., a Delaware limited
liability company
Nautilus Pipeline Company, L.L.C., a Delaware limited liability company
Stingray Holding, L.L.C., a Delaware limited liability company
Stingray Pipeline Company, a Louisiana partnership (50%)
Tarpon Transmission Company, a Texas corporation
Texam Offshore Gas Transmission, L.L.C., a Delaware limited liability company
High Island Offshore System, a Delaware partnership (20%)
Transco Hydrocarbons Company, L.L.C., a Delaware limited liability company
U-T Offshore System, a Delaware partnership (33 1/3%)
Transco Offshore Pipeline Company, a Delaware limited liability company
High Island Offshore System, a Delaware partnership (20%)
VK Deepwater Gathering Company, L.L.C., a Delaware limited liability company
Viosca Knoll Gathering Company, a Delaware partnership (50%)
VK-Main Pass Gathering Company, L.L.C., a Delaware limited liability company
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM LEVIATHAN
GAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED FINANCIAL STATEMENTS
AT DECEMBER 31, 1997 INCLUDED IN ITS FORM 10-K FOR THE PERIOD ENDED DECEMBER 31,
1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FORM 10-K
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<EXCHANGE-RATE> 1
<CASH> 6,430
<SECURITIES> 0
<RECEIVABLES> 8,561
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 15,644
<PP&E> 296,422
<DEPRECIATION> 95,783
<TOTAL-ASSETS> 409,842
<CURRENT-LIABILITIES> 13,554
<BONDS> 238,000
0
0
<COMMON> 0
<OTHER-SE> 0
<TOTAL-LIABILITY-AND-EQUITY> 409,842
<SALES> 58,106
<TOTAL-REVENUES> 104,762
<CGS> 11,352
<TOTAL-COSTS> 11,352
<OTHER-EXPENSES> 67,511
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 14,169
<INCOME-PRETAX> (1,449)
<INCOME-TAX> (311)
<INCOME-CONTINUING> (1,138)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (1,138)
<EPS-PRIMARY> (0.06)
<EPS-DILUTED> (0.06)
</TABLE>
