Back to GetFilings.com
1
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
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, 2000
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
EL PASO ENERGY 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.)
EL PASO BUILDING 77002
1001 LOUISIANA STREET (Zip Code)
HOUSTON, TEXAS
(Address of Principal Executive Offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 420-2131
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common units representing limited partner interests New York Stock Exchange
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. [ ]
THE REGISTRANT HAD 34,042,814 COMMON UNITS OUTSTANDING AS OF MARCH 29,
2001. THE AGGREGATE MARKET VALUE ON SUCH DATE OF THE REGISTRANT'S COMMON UNITS
HELD BY NON-AFFILIATES WAS APPROXIMATELY $1,052 MILLION.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2
EL PASO ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
CAPTION PAGE
------- ----
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 12
Item 3. Legal Proceedings........................................... 12
Item 4. Submission of Matters to a Vote of Security Holders......... 12
PART II
Item 5. Market for Registrant's Units and Related Unitholder
Matters................................................... 13
Item 6. Selected Financial Data..................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 16
Risk Factors and Cautionary Statement for Purposes of the
"Safe Harbor" Provisions
of the Private Securities Litigation Reform Act of 1995... 22
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk...................................................... 29
Item 8. Financial Statements and Supplementary Data................. 30
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 62
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 62
Item 11. Executive Compensation...................................... 65
Item 12. Security Ownership of Management............................ 67
Item 13. Certain Relationships and Related Transactions.............. 67
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form
8-K....................................................... 68
Signatures.................................................. 238
i
3
PART I
ITEM 1. BUSINESS
GENERAL
We are one of the largest publicly-traded master limited partnerships in
terms of market capitalization and a gatherer of natural gas and oil in the Gulf
of Mexico. Formed in 1993, we provide midstream energy services both onshore and
offshore in the Gulf of Mexico, including gathering, transportation, storage and
other related services for producers of natural gas and oil. Through December
31, 2000, our subsidiaries and joint ventures owned or had interests in (i)
twelve natural gas and oil pipeline systems, (ii) seven offshore platforms,
including related production, processing, and dehydration facilities, (iii) five
producing oil and natural gas properties, (iv) one non-producing oil and natural
gas property, and (v) two natural gas storage facilities in Mississippi.
Our pipeline systems have a combined capacity of over 7.3 Bcf/d of natural
gas and over 340 MBbls/d of oil and include over 2,000 miles of pipeline. These
systems are strategically placed to serve production activities in some of the
most active drilling and development regions in the Gulf, including the offshore
regions of Texas, Louisiana, and Mississippi, and provide relatively low cost
access to long line transmission pipelines that access multiple markets in the
eastern half of the United States. In March 2000, we acquired El Paso
Intrastate-Alabama, or EPIA, a natural gas pipeline system in the coal bed
methane producing regions of Alabama from a subsidiary of El Paso Corporation.
The system consists of over 450 miles of pipeline and has a capacity of
approximately 200 MMcf/d. These systems handled an average of approximately 3.4
MMdth/d of natural gas from 1998 to 2000, as well as an average of approximately
176 MBbls/d of oil in 2000, 181 MBbls/d in 1999 and 97 MBbls/d in 1998.
Upon completion of the Prince tension leg platform, or TLP, our
multi-purpose offshore platforms will have a product handling capacity of over
710 Mcf/d of natural gas and over 120 MBbls/d of oil and condensate. Through
these facilities, we are able to provide a variety of producer and midstream
services to enhance deliverability and volumes into our pipeline systems.
Our producing properties have total proved reserves of approximately 11.5
Bcf of natural gas and over 1.2 MMBbls of oil. We also have an overriding
royalty interest in the Prince Field, a non-producing property in the Ewing Bank
region of the Gulf of Mexico to capitalize on future development efforts in that
region.
In August 2000, we acquired salt dome natural gas storage facilities
located in Mississippi which are well situated to serve the Northeast,
Mid-Atlantic and Southeast natural gas markets. These facilities have a combined
working capacity of 6.7 Bcf, and are capable of delivering in excess of 670
MMcf/d of natural gas into three interstate pipelines, Koch Gateway Pipeline,
Transcontinental Gas Pipeline, or Transco, and Tennessee Gas Pipeline. Each of
these facilities is capable of making deliveries at the high rates necessary to
satisfy peaking requirements in the electric generation industry.
- ---------------
As generally used in the energy industry and in this document, the following
terms have the following meanings:
Bbl(/d) = barrel (per day)
BBtu(/d) = billion British thermal units (per
day)
Bcf(/d) = billion cubic feet (per day)
MBbls(/d) = thousand barrels (per day)
MMBbls = million barrels
MMBtu = million British thermal units
Mcf(/d) = thousand cubic feet (per day)
MMcf(/d) = million cubic feet (per day)
MMdth(/d) = million dekatherms (per day)
Mdth(/d) = thousand dekatherms (per day)
When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Also, when we refer to cubic feet measurements, all measurements
are at 14.73 pounds per square inch.
1
4
In August 1998, El Paso acquired DeepTech International Inc., the parent
company of our General Partner. Following this acquisition, our General Partner
became an indirect wholly owned subsidiary of El Paso. Our General Partner and
other affiliates of El Paso perform all of our management and operational
functions and together own a 27.8 percent interest in our common units
consisting of 8,953,764 common units. They also own a one percent general
partner interest in us, an approximate one percent non-managing member interest
in many of our subsidiaries and $170 million of our Series B preference units.
For further information on our Series B preference units, see Item 5, Market for
Registrant's Units and Related Unitholder Matters.
BUSINESS STRATEGY
Our objective is to operate as a growth-oriented master limited partnership
with a focus on increasing our cash flow and distributions to our unitholders.
Our strategy is to combine our position as a provider of midstream services in
the deeper water regions of the Gulf of Mexico with an aggressive effort to
acquire and develop diversified onshore midstream energy assets. Accordingly, we
also expect a substantial portion of our growth to relate to onshore activities
and operations. Further, our strategy includes identifying opportunities that
create synergies with the other assets and operations of El Paso. We intend to
continue de-emphasizing our commodity-based activities, such as exploration and
production operations, in the future and concentrate on fee-based operations,
which tend to provide more stable cash flows. As part of our business strategy,
- we acquired EPIA, a natural gas pipeline system in the coal bed methane
producing regions of Alabama from a subsidiary of El Paso, in March 2000;
- we entered into an agreement with El Paso Production in March 2000
committing all natural gas and oil produced from the Prince Field to a
platform we are constructing at Ewing Bank 1003;
- we placed our East Breaks joint venture pipeline system in service in
June 2000;
- we acquired the salt dome natural gas storage businesses of Crystal Gas
Storage, Inc., a subsidiary of El Paso, in August 2000; and
- we acquired the south Texas fee-based natural gas liquids, or NGL,
transportation and fractionation assets from a subsidiary of El Paso in
February 2001.
In accordance with a Federal Trade Commission, or FTC, order related to El
Paso's merger with The Coastal Corporation, we divested a number of our Gulf of
Mexico assets in January 2001. These divestitures allow us to further our plan
to diversify and grow our sources of cash flow. For more information on these
asset divestitures, see Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations.
SEGMENTS
We segregate our business activities into three segments:
- Gathering, Transportation, and Platform Services;
- Oil and Natural Gas Production; and
- Gas Storage Services.
These segments are strategic business units that provide a variety of
energy related services. For information relating to operating revenues and
operating income of each segment, see Item 8, Financial Statements and
Supplementary Data, Note 11. Each of these segments is discussed more fully
below.
2
5
GATHERING, TRANSPORTATION, AND PLATFORM SERVICES
Pipeline Systems
We conduct a significant portion of our business activities through equity
investments, many of which are organized as limited liability companies with
subsidiaries of other substantial energy companies. Management decisions related
to these investees are made by committees comprised of representatives from each
member with authority appointed in proportion to the members' relative ownership
interests. The following table and discussions describe our network of
subsidiary and joint venture owned natural gas and crude oil pipelines as of
December 31, 2000:
DEEPWATER HOLDINGS
EL PASO ----------------------------------------
VIOSCA INTRASTATE- EAST GREEN
KNOLL(1) ALABAMA(2) HIOS BREAKS(3) UTOS(4) STINGRAY(4) CANYON(4) TARPON(4)
-------- ----------- ---- --------- ------- ----------- --------- ---------
Effective ownership
interest............... 100% 100% 50% 50% 50% 50% 100% 100%
Unregulated(U)/
regulated(R)........... U U R U R R U U
Operated(O)/Non-
operated(N)............ O O O(5) O(5) O(5) O O O
In-service date......... 1994 1972 1977 2000 1978 1975 1990 1978
Approximate
capacity(7)............ 1,000 200 1,800 400 1,200 1,120 220 80
Aggregate miles of
pipeline............... 125 450 204 85 30 417 68 40
Average net throughput
for the year ended:(8)
December 31, 2000...... 612 124 435 56 166 298 59 25
December 31, 1999...... 558 -- 371 -- 186 304 90 44
December 31, 1998...... 319 -- 359 -- 171 346 139 66
NEPTUNE AND
OCEAN BREEZE
-------------------------
MANTA
RAY
OFFSHORE(4) NAUTILUS(4) POSEIDON ALLEGHENY(3)
----------- ----------- -------- ------------
Effective ownership
interest............... 25.67% 25.67% 36% 100%
Unregulated(U)/
regulated(R)........... U R U U
Operated(O)/Non-
operated(N)............ N N N(6) O
In-service date......... 1987 1997 1996 1999
Approximate
capacity(7)............ 755 600 260 80
Aggregate miles of
pipeline............... 225 101 288 43
Average net throughput
for the year ended:(8)
December 31, 2000...... 105 78 57 18
December 31, 1999...... 109 75 61 12
December 31, 1998...... 80 42 35 --
- ---------------
(1) We acquired an additional 49 percent ownership interest in June 1999 and the
remaining 1 percent in September 2000 from a subsidiary of El Paso.
(2) We acquired the El Paso Intrastate-Alabama system in March 2000.
(3) The East Breaks system was placed in service in June 2000. The Allegheny
system was placed in service in October 1999.
(4) In the first quarter of 2001, we entered into a series of transactions
involving the sale of our interests in the Green Canyon, Tarpon, Manta Ray
Offshore and Nautilus systems. Additionally, Deepwater Holdings sold their
interest in Stingray in the first quarter of 2001 and also agreed to sell
their interest in UTOS. Deepwater Holdings expects this sale to close in
April 2001. These sales are a result of a FTC order related to El Paso's
merger with The Coastal Corporation.
(5) We assumed operation of these systems in June 2000.
(6) We assumed operation of this system in January 2001.
(7) All capacity measures are on a MMcf/d basis except the Poseidon and
Allegheny systems which are measured on a MBbls/d basis.
(8) All average net throughput measures are on a Mdth/d basis except the
Poseidon and Allegheny systems which are measured on a MBbls/d basis.
Viosca Knoll. Viosca Knoll is a natural gas gathering system designed to
serve the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of
Mexico and consists of 125 miles of predominantly 20-inch natural gas pipeline
and a 7,000 horsepower compressor. Viosca Knoll provides its customers access to
the facilities of a number of major interstate pipelines, including pipelines
owned by Tennessee Gas Pipeline Company, Columbia Gulf Transmission Company,
Southern Natural Gas Company, Transco, and Destin Pipeline Company. During 1999,
we acquired an additional 49 percent interest in Viosca Knoll, and in 2000 we
acquired the remaining 1 percent from a subsidiary of El Paso, bringing our
total interest in Viosca Knoll to 100 percent.
El Paso Intrastate-Alabama. In March 2000, we acquired EPIA, a natural gas
pipeline system in the coal bed methane producing regions of Alabama. The system
consists of over 450 miles of pipeline. EPIA also provides marketing services
through the purchase and resale of natural gas by purchasing natural gas from
regional producers and others, and selling natural gas to local distribution
companies and others.
3
6
Deepwater Holdings. In June 1999, we acquired additional ownership
interests in the High Island Offshore System, or HIOS, U-T Offshore System, or
UTOS, and the East Breaks System. In September 1999, we reorganized our
interests with ANR Pipeline Company, or ANR, in these and other assets through
the formation of Deepwater Holdings, L.L.C. We have a 50 percent ownership
interest in Deepwater Holdings. Through El Paso's merger with The Coastal
Corporation, ANR became a subsidiary of El Paso. As a result of the
reorganization, Deepwater Holdings owns 100 percent of the HIOS, UTOS, East
Breaks and Stingray systems, as well as 100 percent of the West Cameron
dehydration facility.
- HIOS is a natural gas transmission system consisting of 204 miles of
pipeline which includes three supply laterals that connect to a 42-inch
diameter mainline. HIOS transports natural gas received from fields
located in the Galveston, Garden Banks, West Cameron and East Breaks
areas of the Gulf of Mexico to a junction platform owned by HIOS located
in West Cameron Block 167.
- East Breaks is a natural gas gathering system consisting of 85 miles of
18 to 20-inch diameter pipeline that connects HIOS to the Diana and
Hoover fields being developed by subsidiaries of ExxonMobil and BP Amoco
plc. Production from the Diana and Hoover properties has been committed
to this system. East Breaks began operating in June 2000, and has the
ability to expand its throughput capacity further, which would provide
HIOS with the ability to compete for the right to gather and transport
the substantial reserves associated with properties being, and expected
to be, developed in these deepwater frontier regions.
- UTOS is a natural gas transmission system consisting of 30 miles of
42-inch diameter pipeline extending from an interconnection with HIOS at
West Cameron Block 167 to the Johnson Bayou production handling facility,
owned by UTOS. The Johnson Bayou facility provides primarily natural gas
and natural gas liquids separation and dehydration services for natural
gas transported on HIOS and UTOS. Under a FTC order, Deepwater Holdings
agreed to sell its interest in UTOS. The sale is expected to close in
April 2001.
- Stingray is a natural gas gathering system consisting of (i) 361 miles of
6 to 36-inch diameter pipeline that transports natural gas from HIOS,
West Cameron, East Cameron and Vermilion lease areas in the Gulf of
Mexico to onshore transmission systems in Louisiana, (ii) 43 miles of 16
to 20-inch diameter pipeline connecting platforms and leases in the
Garden Banks Blocks 191 and 72 areas to Stingray, and (iii) 13 miles of
16-inch diameter pipeline connecting our platform at East Cameron Block
373 to Stingray at East Cameron Block 338. Under a FTC order, Deepwater
Holdings sold its interest in Stingray in January 2001.
Green Canyon. Green Canyon is a natural gas gathering system consisting of
68 miles of 10 to 20-inch diameter pipeline which transports natural gas from
the South Marsh Island, Eugene Island, Garden Banks, and Green Canyon areas in
the Gulf of Mexico to Transco's South Lateral in South Marsh Island Block 106.
Under a FTC order, we sold our interest in Green Canyon in January 2001.
Tarpon. Tarpon is a natural gas gathering system consisting of 40 miles of
16-inch diameter pipeline that extends from the Trunkline Gas Pipeline system at
Ship Shoal Block 274 to the Eugene Island area in the Gulf of Mexico. Under a
FTC order, we sold our interest in Tarpon in January 2001.
Neptune and Ocean Breeze. We own a 25.67 percent interest in both Neptune
Pipeline Company, L.L.C. and Ocean Breeze Pipeline Company, L.L.C. Together,
Neptune and Ocean Breeze own 100 percent of the Manta Ray Offshore and Nautilus
systems. Under a FTC order, we sold our interest in Neptune and Ocean Breeze in
January 2001.
- Manta Ray Offshore is a natural gas gathering system consisting of three
separate gathering lines in the offshore Louisiana area of the Gulf of
Mexico, including 76 miles of 12 to 24-inch diameter pipeline, each
interconnecting offshore with Transco's Southeast Louisiana Lateral,
which provides transportation to shore in eastern Louisiana and 149 miles
of 14 to 24-inch diameter pipeline extending from the Green Canyon and
South Timbalier areas to facilities located at Ship Shoal Block 207.
Affiliates of the other partners in the system, Shell Oil Company and
Marathon Oil Company, have dedicated production from over 110 lease
blocks in the area to the system.
4
7
- Nautilus is a natural gas transmission system consisting of 101 miles of
30-inch pipeline running downstream from Ship Shoal Block 207 connecting
to a natural gas processing plant in Louisiana and, through the
processing plant, facilitates deliveries into multiple interstate
pipelines. The Shell Oil Company and Marathon Oil Company production
dedicated to Manta Ray Offshore is also dedicated to Nautilus.
Poseidon. Poseidon, which we own a 36 percent interest in, is a major sour
crude oil pipeline system built in response to the increased demand for
additional sour crude oil pipeline capacity in the central Gulf of Mexico.
Poseidon consists of (i) 117 miles of 16 to 20-inch diameter pipeline extending
from our 50 percent owned Garden Banks 72 platform to our platform at Ship Shoal
Block 332, (ii) 122 miles of 24-inch diameter pipeline extending from the Ship
Shoal 332 platform to Houma, Louisiana, (iii) 32 miles of 16-inch diameter
pipeline extending from Ewing Bank Block 873 to the 24-inch pipeline in the area
of South Timbalier Block 212, and (iv) 17 miles of 16-inch pipeline extending
from Garden Banks Block 260 to South Marsh Island Block 205.
Allegheny. Allegheny is a crude oil system consisting of 43 miles of
14-inch diameter pipeline that connects the Allegheny field in the Green Canyon
area of the Gulf of Mexico with Poseidon at our Ship Shoal 332 platform. Oil
production from the Allegheny field is committed to this system.
Nemo. In August 1999, we formed Nemo Gathering Company L.L.C., or Nemo,
with Tejas Offshore Pipeline, L.L.C. to construct, own and operate a natural gas
gathering system extending from the Brutus and Glider deepwater development
properties to Manta Ray Offshore. Under a FTC order, we sold our interest in
Nemo in January 2001.
Offshore Platforms and Related Facilities
Our offshore platforms play a key role in the development of the oil and
natural gas offshore pipeline network. Platforms are used to:
- interconnect the offshore pipeline grid;
- provide an efficient means to perform pipeline maintenance;
- locate compression, separation, production handling and other facilities;
and
- conduct drilling operations during the initial development phase of a
natural gas and oil property.
In addition to numerous platforms owned by our joint ventures, we own seven
strategically-located platforms in the Gulf of Mexico, including six
multi-purpose hub-platforms and one TLP in the Prince Field, which is currently
under construction. These platforms were specifically designed to be used as
deepwater hubs and production handling and pipeline maintenance facilities. The
following table and discussions describe our offshore platforms as of December
31, 2000:
EAST GARDEN SHIP VIOSCA SHIP SOUTH
CAMERON BANKS SHOAL KNOLL PRINCE SHOAL TIMBALIER
373 72 331 817 TLP(1) 332(2) 292(2)
------- ------- ----- ------ ------ -------- ---------
Ownership interest........ 100% 50% 100% 100% 100% 100% 100%
In-service date........... 1998 1995 1994 1995 N/A(1) 1985 1984
Water depth (in feet)..... 441 518 376 671 1,500 438 283
Acquired (A) or
constructed (C)......... C C A C C A A
Approximate handling
capacity:
Natural gas (MMcf/d).... 110 80 --(3) 140 80 150(3) 150
Oil and condensate
(Bbls/d)............. 5,000 55,000 --(3) 5,000 50,000 12,000(3) 2,500
- ------------------
(1) We plan to place the Prince TLP platform, formerly known as the Ewing Bank
1003 platform, in service by mid 2001.
(2) We sold 50 percent of our interest in Ship Shoal 332 and all of our interest
in South Timbalier 292 in January 2001.
(3) The Ship Shoal 331 platform is currently used as a satellite landing area
and all products transported to the platform are processed on the Ship Shoal
332 platform.
5
8
East Cameron 373. The East Cameron 373 platform is located at the south end
of the central leg of Stingray. The platform serves as the host for Kerr-McGee
Corporation's East Cameron Block 373 production and as the landing site for
Garden Banks Blocks 108 and 152 production.
Garden Banks 72. The Garden Banks 72 platform is located at the south end
of the eastern leg of Stingray and serves as the western-most termination point
of Poseidon. The platform serves as a base for landing deepwater production from
Enterprise Oil Gulf of Mexico, Inc.'s and Devon Energy Inc.'s Garden Banks Block
161 development and will serve as the host for Mariner Energy Inc.'s development
in Garden Banks Block 73. We also use the platform as the host for our Garden
Banks Block 72 production and the landing site for production from our Garden
Banks Block 117 lease located in an adjacent lease block.
Ship Shoal 331. The Ship Shoal 331 platform is a production facility
located approximately 75 miles off the coast of Louisiana. Pogo Producing
Company has rights to utilize the platform pursuant to a production handling and
use of space agreement.
Viosca Knoll 817. The Viosca Knoll 817 platform is centrally located on the
Viosca Knoll system. The platform serves as a base for landing deepwater
production in the area, including ExxonMobil's, Shell Offshore Inc.'s, and BP
Amoco plc's Ram Powell development. A 7,000 horsepower compressor on the
platform facilitates deliveries from the Viosca Knoll system to multiple
downstream interstate pipelines. The platform is also used as a base for oil and
natural gas production from our Viosca Knoll Block 817 lease.
Prince TLP. Prince TLP, is currently under construction with first
production anticipated to commence in mid 2001. The Prince TLP and its related
facilities initially will be capable of handling up to 50,000 Bbls/d of oil and
80 MMcf/d of natural gas.
Ship Shoal 332. The Ship Shoal 332 platform serves as a major junction
platform for pipelines in the Manta Ray Offshore, Allegheny and Poseidon
systems. The platform will also serve as the landing site for the Nemo system.
Under a FTC order, we sold 50 percent of our interest in Ship Shoal 332 in
January 2001.
South Timbalier 292. The South Timbalier 292 platform is located at the
easternmost termination point of Manta Ray Offshore and serves as a landing site
for natural gas production in the area and provides an interconnection to the
Trunkline Gas Pipeline system. Under a FTC order, we sold our interest in South
Timbalier 292 in January 2001.
Other Facilities. Through our 50 percent ownership interest in Deepwater
Holdings, we also own an interest in the West Cameron dehydration facility
located at the northern termination point of Stingray in Louisiana. Under a FTC
order, Deepwater Holdings sold its interest in the dehydration facility in
January 2001.
Markets and Competition
Each of our natural gas pipeline systems are located at or near natural gas
production areas that are served by other pipelines. Our natural gas pipeline
systems face competition from both regulated and unregulated systems. Some of
these competitors are not subject to the same level of rate and service
regulation as we are. Other competing pipelines, such as long-haul transporters,
may have rate design alternatives unavailable to ours. Consequently, those
competing pipelines may be able to provide service on more flexible terms and at
rates significantly below those we offer.
Our oil pipeline systems were built as a result of the need for additional
crude oil capacity to transport new deepwater oil production to shore. Our
principal competition includes other oil pipeline systems, built, owned and
operated by producers to handle their own production and, as capacity is
available, production for others. Our oil pipelines compete for new production
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 our pipelines to access future reserves will be subject
to our ability, or the producers' ability, to fund the significant capital
expenditures required to connect to the new production.
A substantial portion of the revenues generated by our offshore pipeline
systems are attributed to production from reserves committed under long-term
contracts for the productive life of the relevant field.
6
9
Nonetheless, these reserves and other reserves that may become available to our
pipeline systems are depleting assets and will be produced over a finite period.
Each of our pipeline systems must access additional reserves to offset the
natural decline in production from existing connected wells or the loss of any
other production to a competitor. Furthermore, the rates we charge for our
services are dependent on whether the relevant pipeline system is regulated or
unregulated, the quality of the service required by the customer, and the amount
and term of the reserve commitment by the customer. A majority of our offshore
arrangements involve life-of-reserve commitments with both firm and
interruptible components. Generally, we receive a price per barrel of oil or
water or dekatherm of natural gas handled. Also, for firm arrangements, we often
receive a monthly fixed fee which is paid by the customer regardless of the
level of throughput, except under individually specified circumstances.
Our platforms are subject to similar competitive factors as our pipeline
systems. These assets generally compete on the basis of proximity and access to
existing reserves and pipeline systems, as well as costs and rates. Furthermore,
competitors to these platforms may possess greater technical skill and capital
resources than us.
For a discussion of our significant customers see Item 8, Financial
Statements and Supplementary Data, Note 10.
Regulatory Environment
Our natural gas pipeline systems are subject to the Natural Gas Pipeline
Safety Act of 1968, which establishes pipeline and liquified natural gas plant
safety requirements. The Poseidon and Allegheny systems are subject to
regulations under the Hazardous Liquid Pipeline Safety Act. All of our offshore
pipeline systems are subject to the regulation under the Outer Continental Shelf
Lands Act, which calls for nondiscriminatory transportation on pipelines
operating in the outer continental shelf region of the Gulf of Mexico. All of
our pipeline systems are subject to the National Environmental Policy Act and
other environmental legislation. Each of the pipeline systems has a continuing
program of inspection designed to keep all of our facilities in compliance with
pollution control and pipeline safety requirements. We believe that our pipeline
systems are in compliance with the applicable requirements of these regulations.
Our HIOS, UTOS, Stingray and Nautilus pipeline systems are also subject to
the jurisdiction of the Federal Energy Regulatory Commission, or FERC, in
accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of
1978. Each of these pipeline systems operates under separate FERC approved
tariffs which establish rates, terms, and conditions under which each pipeline
system provides services to its customers. These pipeline systems operate under
agreements with their respective customers which provide for rates that have
been approved by FERC. Stingray's proposed rates became effective June 1, 1999,
subject to refund. A hearing on the merits of Stingray's filing was held in
December 1999 and the case was still pending before FERC at the time Deepwater
Holdings sold Stingray in January 2001.
Maintenance
Each of our pipeline systems and platforms requires regular and thorough
maintenance. The interior of the pipelines is maintained through the regular
cleaning of the line of liquids that collect in the pipeline. 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, anodes are
fastened to the pipeline itself at prescribed intervals, providing protection
from sea water. The platforms are painted to the waterline every three to five
years to prevent atmospheric corrosion. Corrosion protection devices are also
fastened to platform legs below the waterline to prevent corrosion. Remotely
operated vehicles or divers inspect the platforms below the waterline generally
every five years. The HIOS, Stingray, Manta Ray Offshore, Viosca Knoll,
Allegheny and Poseidon pipeline systems include platforms that are manned on a
continuous basis. The personnel onboard these platforms are responsible for site
maintenance, operations of the platform facilities, measurement of the oil or
natural gas stream at the source of production and corrosion control.
7
10
OIL AND NATURAL GAS PRODUCTION
Currently, we own interests in five producing and one non-producing oil and
natural gas properties located in waters offshore of Louisiana. Production from
these properties is gathered, transported, and processed through our pipeline
systems and platform facilities, and sold to an affiliate of El Paso. The
following is information regarding these properties as of December 31, 2000:
Producing Properties
GARDEN BANKS GARDEN BANKS GARDEN BANKS VIOSCA KNOLL WEST DELTA
BLOCK 72 BLOCK 73(1) BLOCK 117 BLOCK 817(2) BLOCK 35(3)
------------ ------------ ------------ ------------ -----------
Working interest................ 50% -- 50% 100% 38%
Net revenue interest............ 40.2% 2.5% 37.5% 80% 29.8%
In-service date................. 1996 2000 1996 1995 1993
Net acres....................... 2,880 -- 2,880 5,760 1,894
Distance offshore (in miles).... 120 115 120 40 10
Water depth (in feet)........... 518 743 1,000 671 60
Producing wells................. 5 1 2 7 2
Cumulative production:
Natural gas (MMcf)............ 3,979 143 1,886 58,766 1,859
Oil (Bbls).................... 1,241,884 -- 1,036,468 97,035 9,873
- ---------------
(1) We own a 2.5 percent overriding interest in Garden Banks Block 73, which
began producing in mid 2000.
(2) Our working interest in Viosca Knoll Block 817 is subject to a production
payment that entitles holders to 25 percent of the proceeds from the
production attributable to this working interest (after deducting all
leasehold operating expenses, including platform access and production
handling fees) until the holders have received the aggregate sum of $16
million. At December 31, 2000, the unpaid portion of the production payment
obligation totaled $9.8 million.
(3) The West Delta Block 35 field commenced production in 1993, but our interest
in this field was acquired in connection with El Paso's acquisition of our
general partner in 1998. Production data is for the period from August 1998.
Acreage and Wells. The following table sets forth our developed and
undeveloped oil and natural gas acreage as of December 31, 2000. Undeveloped
acreage refers to 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 natural gas, regardless of whether or not such acreage contains
proved reserves. Gross acres in the following table refer to the number of acres
in which a working interest is owned directly by us. The number of net acres is
our fractional ownership of the working interest in the gross acres.
GROSS NET
------ ------
Developed acreage........................................... 6,152 3,576
Undeveloped acreage......................................... 44,913 18,838
------ ------
Total acreage..................................... 51,065 22,414
====== ======
Our gross and net ownership in producing wells at December 31, 2000, is as
follows:
GROSS NET
----- ----
Natural gas................................................. 10.0 8.3
Oil......................................................... 6.0 3.0
---- ----
Total............................................. 16.0 11.3
==== ====
We did not drill any exploratory developmental wells in 1999 or 2000. One
developmental oil well was drilled during 1998.
8
11
Net Production, Unit Prices, and Production Costs. The following table sets
forth information regarding the production volumes of, average unit prices
received for, and average production costs for our oil and natural gas
properties for the years ended December 31:
OIL (MBBLS) NATURAL GAS (MMCF)
------------------------------ --------------------------
2000 1999 1998 2000 1999 1998
-------- -------- -------- ------ ------- -------
Net production(1)................. 306 357 540 6,897 12,211 11,324
Average sales price(1)().......... $ 25.26 $ 14.32 $ 15.69 $ 1.86 $ 2.02 $ 2.01
Average production costs(2)()..... $ 7.82 $ 2.38 $ 3.04 $ 1.30 $ 0.40 $ 0.51
- ---------------
(1) The information regarding net production and average sales prices excludes
overriding royalty interests.
(2) The components of average production costs, which consist of operating
expenses per unit of oil or natural gas produced, 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.
For a discussion of oil and natural gas reserve information and estimated
future net cash flows, see Item 8, Financial Statements and Supplementary Data,
Note 13, which is incorporated herein by reference.
Non-producing Property
Ewing Bank 958 Unit (Prince Field). We own a 9 percent net overriding
royalty interest in the Prince Field, formerly the Ewing Bank 958 Unit. In
November 1999, we entered into an arrangement with El Paso Production to farmout
our working interest in the Prince Field in exchange for an overriding royalty
interest. Under the terms of the farmout agreement, we may convert our
overriding royalty interest in the Prince Field into a 30 percent working
interest once El Paso Production recoups the costs associated with its drilling
and completion activities on the Prince Field. Although four successful
delineation wells have been drilled in the Prince Field, and El Paso Production
has expanded the scope and size of the field development, there has been no
production to date. Production from the Prince Field is expected to commence in
mid 2001 and is committed to our Prince TLP.
Markets and Competition
Our focus is to maximize the production from our existing portfolio of oil
and natural gas properties. As a result, the competitive factors that would
normally impact exploration and production activities are not as pervasive to
our operations. However, the oil and natural gas industry is intensely
competitive, and we do compete with a substantial number of other companies,
including many with larger technical staffs and greater financial and
operational resources in terms of accessing transportation, hiring personnel,
marketing production and withstanding the effects of general and
industry-specific economic changes.
Regulatory Environment
Our production and development operations are subject to regulation at the
federal and state levels. Regulated activities include:
- requiring permits for the drilling of wells;
- maintaining bonds and insurance requirements in order to drill or operate
wells;
- drilling and casing wells;
- the surface use and restoring of properties upon which wells are drilled;
and
- plugging and abandoning of wells.
9
12
Our production and development operations are also subject to various
conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units, the density of wells that may be
drilled, the levels of production, and the pooling of oil and natural gas
properties.
We presently have interests in, or rights to, offshore leases located in
federal waters. Federal leases are administered by the Minerals Management
Service, or MMS. Individuals and entities must qualify with the MMS prior to
owning and operating any leasehold or right-of-way interest in federal waters.
Qualification with the MMS generally involves filing certain documents and
obtaining an area-wide performance bond and/or supplemental bonds representing
security for facility abandonment and site clearance costs.
Operating Environment
Our business is subject to all of the operating risks normally associated
with the production of oil and natural gas, including blowouts, cratering,
pollution, and fires, each of which could result in damage to life or property.
Offshore operations are subject to usual marine perils, including hurricanes and
other adverse weather conditions, and governmental regulations, including
interruption or termination by governmental authorities based on environmental
and other considerations. In accordance with customary industry practices, we
maintain broad insurance coverage with respect to potential losses resulting
from these operating hazards.
GAS STORAGE SERVICES
In August 2000, we acquired the natural gas storage businesses of Crystal
Gas Storage, Inc. These businesses include the Petal and Hattiesburg salt dome
natural gas storage facilities located in Mississippi. These facilities are well
situated to serve the Northeast, Mid-Atlantic and Southeast natural gas markets.
On a combined basis, these storage facilities currently have a natural gas
working capacity of 6.7 Bcf, and are capable of delivering in excess of 670
MMcf/d of natural gas into three interstate pipelines, Koch Gateway Pipeline,
Transco and Tennessee Gas Pipeline. Each of the Petal and Hattiesburg facilities
is capable of making deliveries at the high rates necessary to satisfy peaking
requirements in the electric generation industry. A 6.8 Bcf expansion is
underway at these facilities, all of which is contractually dedicated for the
next 20 years to a subsidiary of Southern Company, the largest producer of
electricity in the United States. The expansion of the storage space and
facilities has been approved by the FERC and is currently under construction.
Also currently waiting for FERC approval is a 60 mile pipeline addition which
will provide interconnects with various customers.
Markets and Competition
Competition for natural gas storage is primarily based on location and the
ability to deliver natural gas in a timely and reliable manner. Our Petal and
Hattiesburg natural gas storage facilities are located in an area in Mississippi
that can effectively service the Northeastern and Southeastern natural gas
markets, and have the ability to deliver all of its stored natural gas within a
short timeframe. The natural gas storage facilities compete with other forms of
natural gas storage including other salt dome storage facilities, depleted
reservoir facilities and pipelines.
We believe that the existence of the long-term contracts for storage,
proposed expansion of our operations and the location of our natural gas storage
facilities should allow us to compete effectively with other companies who
provide for natural gas storage services. In addition to long-term contracts, we
actively market interruptible storage services at the facilities to enhance our
revenue generating ability beyond the firm storage contracts. Once our firm
storage contracts have expired, we will experience greater competition for
providing storage services. Such competition will be dependent upon the nature
of the natural gas storage market existing at that time.
Regulatory Environment
Our Hattiesburg facility is a regulated utility under the jurisdiction of
the Mississippi Public Service Commission. Accordingly, the rates charged for
natural gas storage services are subject to approval from this agency. The
present rates of the firm long-term contracts for natural gas storage in the
Hattiesburg facility
10
13
were approved in 1990. Our Petal facility is subject to regulation under the
Natural Gas Act of 1938, as amended, and to the jurisdiction of FERC. The Petal
facility currently holds certificates of public convenience and necessity which
permit it to charge market based rates. A portion of our natural gas storage
business is also subject to a limited jurisdiction certificate issued by FERC.
The certificate authorizes us to provide natural gas storage services that may
be ultimately consumed outside of Mississippi.
The interstate natural gas industry has historically been heavily regulated
by federal and state government and we cannot predict what further actions FERC,
state regulators, or federal and state legislators may take in the future.
PURCHASE OF NGL AND FRACTIONATION ASSETS
In February 2001, we purchased NGL transportation and fractionation assets
from a subsidiary of El Paso. These assets include more than 600 miles of NGL
gathering and transportation pipelines and three fractionation plants located in
south Texas. The NGL pipeline system gathers and transports unfractionated and
fractionated products. The three fractionation plants have a capacity of
approximately 96 MBbls/d. These plants fractionate NGLs into ethane, propane,
and butane products, which are used by refineries and petrochemical plants along
the Texas Gulf Coast.
MAJOR ENCUMBRANCES
Substantially all of our assets, with the exception of one of our
subsidiaries, Argo II, L.L.C., are pledged as collateral under our existing
revolving credit facility. Substantially all of Argo's assets are pledged under
Argo's project finance loan, which is guaranteed in part by us. In addition,
certain of our investees currently have, and others are expected to have, credit
facilities under which substantially all of their assets are, or would be,
pledged. For a discussion of our credit facilities, see Item 8, Financial
Statements and Supplementary Data, Note 5.
ENVIRONMENTAL
A description of our environmental matters is included in Item 8, Financial
Statements and Supplementary Data, Note 8.
EMPLOYEES
Employees of El Paso, through our General Partner, perform all of our
administrative and operational activities under a management agreement.
Therefore, we had no direct employees at December 31, 2000. We reimburse our
General Partner for all reasonable general and administrative expenses and other
reasonable expenses incurred by our General Partner and its affiliates for, or
on our behalf, including, but not limited to, expenses incurred by our General
Partner under this management agreement.
11
14
ITEM 2. PROPERTIES
A description of our properties is included in Item 1, Business.
We believe we have satisfactory title to the properties owned and used in
our businesses, subject to liens for current taxes, liens incident to minor
encumbrances, and easements and restrictions that do not materially detract from
the value of the property, or the interests of the property, or the use of such
properties in our businesses. We believe that our physical properties are
adequate and suitable for the conduct of our business in the future.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Financial Statements and Supplementary Data, Note 8.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
12
15
PART II
ITEM 5. MARKET FOR REGISTRANT'S UNITS AND RELATED UNITHOLDER MATTERS
Our common units are traded on the New York Stock Exchange under the symbol
"EPN". As of March 15, 2001, there were approximately 688 holders of record of
common units.
Since 1998, we have given holders of our publicly held preference units the
opportunity to convert their preference units into common units, in accordance
with our partnership agreement. In October 2000, we redeemed the remainder of
our outstanding publicly held preference units.
The following table reflects the high and low sales prices for common units
based on the daily composite listing of stock transactions for the New York
Stock Exchange and cash distributions declared per common and preference units
during those periods.
DISTRIBUTIONS DECLARED
COMMON UNITS PER UNIT
------------------- -----------------------
HIGH LOW COMMON PREFERENCE(1)
-------- -------- ------- -------------
2000
Fourth Quarter............................................ $27.7500 $23.0000 $0.5500 $ --
Third Quarter............................................. 28.0000 22.5000 0.5375 0.2750
Second Quarter............................................ 26.0000 19.5000 0.5375 0.2750
First Quarter............................................. 21.3750 18.1250 0.5250 0.2750
1999
Fourth Quarter............................................ $24.7500 $16.7500 $0.5250 $0.2750
Third Quarter............................................. 25.1250 21.8750 0.5250 0.2750
Second Quarter............................................ 24.7500 21.3750 0.5250 0.2750
First Quarter............................................. 23.1250 19.5000 0.5250 0.2750
- ----------
(1) As of October 2000, all publicly held preference units have been converted
into common units or redeemed.
In January 2001, we declared a quarterly distribution of $0.5500 per common
unit payable on February 15, 2001, to unitholders of record on January 31, 2001.
In addition, we announced in January 2001, an increase of $0.10 per year in our
quarterly distributions to common unitholders, resulting in a quarterly
distribution of $0.575 per common unit effective for the distribution scheduled
to be paid in May 2001.
CASH DISTRIBUTIONS
We make quarterly distributions of 100 percent of our available cash, as
defined in the partnership agreement, to our unitholders and to our General
Partner. Our available cash consists generally of all cash receipts plus
reductions in reserves less all cash disbursements and net additions to
reserves. Our General Partner has broad discretion to establish cash reserves
that it determines are necessary or appropriate to properly conduct our
business. These can include cash reserves for future capital and maintenance
expenditures, reserves to stabilize distributions of cash to the unitholders and
our General Partner, reserves to reduce debt, or, as necessary, reserves to
comply with the terms of any of our agreements or obligations.
The holders of common units and our General Partner are not entitled to
arrearages of minimum quarterly distributions. Our distributions are effectively
made 98 percent to limited unitholders and 2 percent to our General Partner,
subject to the payment of incentive distributions to our General Partner if
certain target cash distribution levels to common unitholders are achieved.
Incentive distributions to our General Partner increase to 15 percent, 25
percent and 50 percent based on incremental distribution thresholds. Since 1998,
quarterly distributions to common unitholders have been in excess of the highest
incentive threshold of $0.425 per unit, and as a result, our General Partner has
received 50 percent of the incremental amount. For the year ended December 31,
2000, we paid our General Partner incentive distributions totaling $15.5 million
and paid an incentive distribution of $4.6 million in February 2001.
13
16
PUBLIC OFFERING OF COMMON UNITS
In July 2000, we completed a public offering of 4,600,000 common units that
included 600,000 common units to cover over-allotments for the underwriters. We
used the net cash proceeds of approximately $101 million from the offering to
reduce the balance outstanding under our revolving credit facility. In addition,
our General Partner contributed $1.1 million to us in order to satisfy its one
percent capital contribution requirement.
In March 2001, we completed a public offering of 2,250,000 common units. We
used the net cash proceeds of $66.3 million from the offering to reduce the
balance outstanding under our revolving credit facility. In addition, our
General Partner contributed $0.7 million to us in order to satisfy its one
percent capital contribution requirement. If, within 30 days, the underwriters
exercise in full their over-allotment option covering an additional 337,500
common units, we expect to receive approximately $10 million in additional net
cash proceeds, all of which would be used to reduce the balance outstanding
under our revolving credit facility.
SERIES B PREFERENCE UNITS
In August 2000, we issued to an affiliate of El Paso, $170 million of
Cumulative Redeemable Series B preference units in exchange for the Crystal
natural gas storage businesses. These newly issued preference units are
non-voting and have rights to income allocations on a cumulative basis,
compounded semi-annually at an annual rate of 10%. We are not obligated to pay
cash distributions on these units until 2010. After 2010, the rate will increase
to 12% and distributions will be required to be paid on a current basis. The new
preference units contain no mandatory redemption obligation, but may be redeemed
at our option at any time. The issuance of these preference units was an exempt
transaction under Section 4(2) of the Securities Act of 1933 as amended.
14
17
ITEM 6. SELECTED FINANCIAL DATA
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998 1997 1996
-------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
Operating Results Data(1):
Operating revenues(2)................. $112,415 $63,659 $48,731 $75,435 $71,073
Net income (loss)(3).................. 20,497 18,817 746 (1,138) 38,692
Basic and diluted income (loss) per
unit(4)............................ (0.03) (0.34) 0.02 (0.06) 1.57
Distributions per common unit......... 2.15 2.10 2.075 1.75 1.35
Distributions per preference unit..... 0.825 1.10 1.825 1.75 1.35
AS OF DECEMBER 31,
----------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
(IN THOUSANDS)
Financial Position Data(1):
Total assets.......................... $879,259 $583,585 $442,726 $409,842 $453,526
Revolving credit facility............. 318,000 290,000 338,000 238,000 227,000
Project financing(5).................. 45,000 -- -- -- --
Long-term debt........................ 175,000 175,000 -- -- --
Partners' capital(6).................. 311,071 96,489 82,896 143,966 192,023
- ----------
(1) Our operating results and financial position reflect the acquisition in
March 2000 of EPIA and in August 2000 of the Crystal natural gas storage
businesses. These acquisitions were accounted for as purchases and therefore
operating results of these acquired entities are included in our results
prospectively from the purchase date.
(2) Operating revenues for prior years has been restated to exclude equity
investment earnings. The operating revenues in 1998 were effected by lower
realized prices on oil and natural gas and inclement weather conditions
which decreased production volumes.
(3) Reflects impairment charges for capitalized costs written off in 1997 as a
result of the abandonment of certain flow lines connecting to wells
abandoned by third party owners.
(4)Reflects our adoption, in 1999, of a different accounting method for
allocating partnership income to our General Partner and the preference and
common unitholders. See Item 8, Financial Statements and Supplementary Data,
Note 1, for further information.
(5)Project financing relates to a loan to build the Prince TLP on the Prince
Field.
(6)Reflects the issuance of the $170 million Series B Preference Units to an
affiliate of El Paso and the issuance of 4.6 million common units in 2000.
15
18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Over the past three years, our business activities have changed as a result
of strategic acquisitions and transactions designed to enhance our ability to
compete effectively and improve our overall financial condition. These changes
have expanded our operating scope, our ability to generate cash flows and our
needs for cash for investment opportunities. Consequently, we have substantially
expanded our credit facilities and created other financing structures to meet
our needs during this period. Significant milestones over the past three years
include:
YEAR TRANSACTION
- ---- -----------
1998 Constructed the East Cameron 373 platform;
Acquired a 100 percent working interest in the Ewing Bank
958 Unit, or the Prince Field;
1999 Increased our ownership interest in Viosca Knoll to 99
percent;
Increased our ownership interests in HIOS, East Breaks and
UTOS to 50 percent;
Placed the Allegheny oil pipeline system into service;
Exchanged our working interest in the Prince Field for a 9
percent overriding royalty interest, with a conditional
option to convert to a 30 percent working interest;
2000 Acquired the natural gas pipeline system of EPIA;
Placed the East Breaks joint venture pipeline system in
service;
Acquired the salt dome natural gas storage businesses of
Crystal; and
Increased our ownership interest in Viosca Knoll to 100
percent.
Sale of Gulf of Mexico Assets
In January 2001, we sold several of our offshore Gulf of Mexico assets to
third parties. The assets sold include our interests in the Tarpon system and
Green Canyon pipeline assets and the Neptune and Ocean Breeze entities, which
included our interests in Manta Ray Offshore and Nautilus. Along with these
entities we also sold our interests in the Nemo system and the South Timbalier
292 offshore platform as well as 50 percent of our interest in the Ship Shoal
332 offshore platform. These sales occurred as a result of a FTC order relating
to El Paso's merger with The Coastal Corporation. El Paso is the indirect parent
of our General Partner. We received approximately $108 million in cash from
these sales and used the proceeds to pay down our revolving credit facility. We
realized losses of approximately $11 million from these sales.
In addition to these sales, Deepwater Holdings, L.L.C., one of our
investees, sold its Stingray system and its West Cameron dehydration facility
for cash of approximately $50 million and used the proceeds to pay down its
credit facility. Our share of the loss realized by Deepwater Holdings on the
sale of its assets was approximately $8 million. Additionally, upon FTC
approval, Deepwater Holdings will sell its interest in UTOS. We expect this sale
to occur in April 2001 and the proceeds to approximate $4 million.
As additional consideration for the above transactions, El Paso will make
payments to us totaling $29 million. These payments will be made in quarterly
installments of $2.25 million, starting on or before March 31, 2001, for the
next three years and $2 million in the first quarter of 2004. From this
additional consideration, we will realize income of approximately $25.4 million
in the first quarter of 2001.
Following these sales, we will continue to own significant offshore
interests and will continue to operate HIOS, East Breaks, Viosca Knoll,
Allegheny, and Poseidon.
16
19
Purchase of NGL and Fractionation Assets
In February 2001, we purchased NGL transportation and fractionation assets
from a subsidiary of El Paso for approximately $133 million. We funded the
acquisition of these assets by borrowing from our revolving credit facility.
These assets include more than 600 miles of NGL gathering and transportation
pipelines. The NGL pipeline system gathers and transports unfractionated and
fractionated products. We also acquired three fractionation plants with a
capacity of approximately 96 MBbls/d. These plants fractionate NGLs into ethane,
propane, and butane products which are used by refineries and petrochemical
plants along the Texas Gulf Coast.
Other Matters
In January 2000, an anchor from a submersible drilling rig in tow damaged a
section of Poseidon north of our Ship Shoal 332 platform. The accident resulted
in the release of approximately 2,200 Bbls of crude oil in the waters
surrounding the area, caused damage to our Ship Shoal 332 platform, and resulted
in the shutdown of the system and surrounding facilities in which we have
ownership interests. Poseidon's costs to repair the damaged pipeline and clean
up the crude oil released into the Gulf of Mexico were approximately $18
million. Poseidon has filed a lawsuit against the rig's owner for these damages.
By the end of the first quarter of 2000, the pipeline was repaired and placed
back into service. To date, we have received approximately $6.7 million of
insurance proceeds for business interruption and property damage.
SEGMENT RESULTS OF OPERATIONS
Our business activities are segregated into three segments: Gathering,
Transportation, and Platform Services; Oil and Natural Gas Production; and Gas
Storage Services. This structure reflects management's current view of our
activities and all historical periods have been presented on the basis of the
current segment presentation. Each of our segments is a strategic business unit
that offers different services or products, and we manage each of these segments
separately as they require different technology and marketing strategies. Since
earnings on equity investments can be a significant source of earnings in our
segments, we evaluate segment performance based on earnings before interest
expense and taxes, or EBIT.
To the extent possible, results of operations have been reclassified to
conform to the current business segment presentation, although these results may
not be indicative of the results which would have been achieved had the revised
business segment structure been in effect during those periods. Operating
revenues and expenses by segment include intersegment revenues and expenses
which are eliminated in consolidation. For a further discussion of the
individual segments, see Item 8, Financial Statements and Supplementary Data,
Note 11.
In previous years, we have reported equity earnings as part of operating
revenues. We have changed this presentation as of December 31, 2000, to include
equity earnings as other income. This change has been reflected for all periods
presented and does not impact our reported net income.
The following table presents EBIT by segment and in total for each of the
three years ended December 31:
2000 1999 1998
------- ------- --------
(IN THOUSANDS)
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Gathering, transportation, and platform services......... $72,083 $61,070 $ 30,513
Oil and natural gas production........................... (7,402) (7,359) (10,140)
Gas storage services..................................... 2,191 -- --
------- ------- --------
Segment EBIT........................................... 66,872 53,711 20,373
Non-segment activity, net................................ 487 191 159
------- ------- --------
Consolidated EBIT...................................... $67,359 $53,902 $ 20,532
======= ======= ========
17
20
EBIT year to year variances are discussed in the segment results below.
GATHERING, TRANSPORTATION, AND PLATFORM SERVICES
YEAR ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
Gathering and transportation........................... $ 37,903 $ 23,005 $ 6,852
Platform services...................................... 26,563 23,882 21,141
Natural gas sales...................................... 34,531 -- --
-------- -------- --------
Total operating revenues............................. 98,997 46,887 27,993
Purchased natural gas costs............................ (28,160) -- --
Operating expenses..................................... (23,745) (28,932) (24,806)
Equity earnings........................................ 22,931 32,814 26,724
Other income........................................... 2,060 10,301 602
-------- -------- --------
EBIT................................................. $ 72,083 $ 61,070 $ 30,513
======== ======== ========
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Operating revenues for the year ended December 31, 2000, were $52.1 million
higher than 1999, primarily due to revenues from EPIA which was acquired in
March 2000. In addition to providing transportation services, EPIA provides
marketing services through the purchase of natural gas from regional producers
and others, and the sale of natural gas to local distribution companies and
others. The revenue from the sale of natural gas is reflected above as "natural
gas sales" and the cost of natural gas acquired for resale is reflected as
"purchased natural gas costs." Revenues were also higher due to the additional
demand charges on our East Cameron 373 platform, a full year of revenues in 2000
from the Allegheny system, which went into service in the fourth quarter of
1999, and the consolidation of Viosca Knoll in June 1999.
Operating expenses for the year ended December 31, 2000, were $5.2 million
lower than 1999 due to the favorable resolution of litigation with Transco in
the second quarter of 2000 and cost recoveries under our operating agreement
with Deepwater Holdings relative to actual costs incurred.
Equity earnings for the year ended December 31, 2000, were $9.9 million
lower than 1999, primarily due to consolidating Viosca Knoll beginning in June
1999 and lower earnings from Poseidon due to the pipeline rupture in the first
quarter 2000.
Other income for the year ended December 31, 2000, was $8.2 million lower
than 1999, primarily due to the $10.1 million gain related to the sale of a
portion of our interest in Deepwater Holdings in 1999. This was offset by $1.7
million of business interruption insurance proceeds relating to the Poseidon
pipeline rupture in January 2000.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Operating revenues for the year ended December 31, 1999, were approximately
$18.9 million higher than 1998. The increase in gathering and transportation
revenues was primarily due to the consolidation of Viosca Knoll beginning in
June 1999 and the Allegheny system which was placed in service in the fourth
quarter of 1999, partially offset by decreased transportation volumes on the
Green Canyon and Tarpon systems due to natural depletion. The increase in
platform services revenues was a result of new production processed at our
Garden Banks 72 platform and a full year of operations at the East Cameron 373
platform.
Operating expenses for the year ended December 31, 1999, were approximately
$4.1 million higher than 1998 primarily as a result of the acquisition of an
additional 49 percent ownership interest in, and the consolidation of, Viosca
Knoll beginning in June 1999, the accrual of costs relating to various
regulatory and operational issues, and higher depreciation as a result of the
Allegheny system being placed into service in the fourth quarter of 1999 and the
East Cameron 373 platform being in service for a full year in 1999.
18
21
Equity earnings for the year ended December 31, 1999, were $6.1 million
higher than 1998, primarily due to increased throughput on Poseidon, Manta Ray
Offshore and Nautilus, partially offset by lower volumes on HIOS, UTOS, and
Stingray and the impact of consolidating Viosca Knoll in June 1999.
Other income for the year ended December 31, 1999, includes a gain on the
sale of a portion of our interest in Deepwater Holdings of $10.1 million.
OIL AND NATURAL GAS PRODUCTION
YEAR ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
Natural gas $ 12,819 $ 24,829 $ 22,941
Oil, condensate and liquids 7,733 5,136 8,470
-------- -------- --------
Total operating revenues 20,552 29,965 31,411
Operating expenses (27,954) (37,324) (41,551)
-------- -------- --------
EBIT $ (7,402) $ (7,359) $(10,140)
======== ======== ========
Volumes
Natural gas sales (MMcf) 7,185 12,211 11,324
======== ======== ========
Oil, condensate, and liquid sales (MBbls) 295 357 540
======== ======== ========
Weighted average realized prices
Natural Gas ($/Mcf) $ 1.86 $ 2.02 $ 2.01
======== ======== ========
Oil, condensate, and liquids ($/Bbl) $ 25.26 $ 14.32 $ 15.69
======== ======== ========
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Oil and natural gas sales for the year ended December 31, 2000, were $9.4
million lower than 1999. The decrease was a result of lower oil and natural gas
production due to normal production declines of existing reserves, the permanent
shut-in of two wells at Viosca Knoll Block 817, the temporary shut-in of Garden
Banks Blocks 72 and 117 as a result of the Poseidon rupture, and lower realized
prices for natural gas, offset by higher realized prices for oil. Realized
prices were affected by hedges in place during the period.
Operating expenses for the year ended December 31, 2000, were $9.4 million
lower than 1999 due to lower depletion from lower oil and natural gas
production.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Total operating revenues for the year ended December 31, 1999, were
approximately $1.4 million lower than 1998. The decrease was primarily due to
lower oil production from natural depletion and lower realized oil prices,
partially offset by higher natural gas sales from the acquisition of an
additional 25 percent working interest in Viosca Knoll Block 817 and the
acquisition of a 38 percent working interest in the West Delta Block 35 in the
third quarter of 1998.
Operating expenses for the year ended December 31, 1999, were approximately
$4.2 million lower than 1998, due to decreased depletion and abandonment rates
related to our oil and natural gas wells, and cost reductions associated with
the operations of those properties.
19
22
GAS STORAGES SERVICES
YEAR ENDED
DECEMBER 31, 2000
-----------------
(IN THOUSANDS)
Gas storage services........................................ $ 6,205
-------
Total operating revenues.......................... 6,205
Operating expenses, net..................................... (4,014)
-------
EBIT.............................................. $ 2,191
=======
In August 2000, we acquired the natural gas storage businesses of Crystal
Gas Storage Inc. For the four months ended December 31, 2000, the revenues from
these businesses consisted primarily of the fixed reservation fees for natural
gas storage capacity. Natural gas storage capacity revenues are recognized and
due during the month in which capacity is reserved by the customer regardless of
the amount of capacity actually used. Operating expenses consist of management
and operating fees and depreciation on the storage facilities.
INTEREST AND DEBT EXPENSE
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Interest and debt expense, net of capitalized interest, for the year ended
December 31, 2000, was approximately $11.7 million higher than 1999. The
increase is due to higher average interest rates and higher average debt
outstanding related to construction activities and the acquisition of EPIA.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Interest and debt expense, net of capitalized interest, for the year ended
December 31, 1999, was approximately $15.1 million higher than 1998. The
increase is due to higher average interest rates and higher average debt
outstanding related to construction activities and acquisitions during 1999.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was approximately $48.4 million
for the year ended December 31, 2000, compared to approximately $50.8 million
for the same period in 1999. The decrease was primarily associated with lower
distributions from equity investments offset by an increase in earnings.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was approximately $126.2 million for
the year ended
December 31, 2000. Our investing activities included the acquisition of EPIA,
additional expenditures for the Prince TLP and increases in our equity
investments.
Funding for capital expenditures, acquisitions, and other investing
activities is expected to be provided by internally generated funds, available
capacity under existing credit facilities, and/or the issuance of other long-
term debt or equity.
CASH FROM FINANCING ACTIVITIES
Net cash flows provided by financing activities totaled approximately $93.9
million for the year ended December 31, 2000. During 2000, we issued 4.6 million
common units in a public offering for approximately $101 million of net
proceeds. We also received approximately $70.6 million in net proceeds from a
project finance loan and borrowings under our revolving credit facility. During
2000, we made distributions to our unitholders and our General Partner of
approximately $79.3 million.
20
23
Future funding for long-term debt retirements, distributions, and other
financing activities is expected to be provided by internally generated funds,
available capacity under existing credit facilities, and/or the issuance of
other long-term debt or equity.
LIQUIDITY
We are in the process of amending and restating our revolving credit
facility with a syndicate of commercial banks to increase our available credit
from $500 million to $600 million subject to borrowing base limitations. We are
also in the process of refinancing Poseidon's revolving credit facility, which
matures on April 30, 2001.
We rely on cash generated from internal operations, including distributions
from our equity investees, as our primary source of liquidity, supplemented by
our available credit facility. The availability of borrowings under our credit
agreement is subject to specified conditions, which management believes we
currently meet. These conditions include compliance with the financial
covenants, ratios and borrowing bases required by such agreements, absence of
default under such agreements, and continued accuracy of the representations and
warranties contained in such agreements, including the absence of any material
adverse changes since the specified dates. For a discussion of our financing
arrangements, see Item 8, Financial Statements and Supplementary Data, Note 5.
COMMITMENTS AND CONTINGENCIES
See Item 8, Financial Statements and Supplementary Data, Note 8, for a
discussion of our commitments and contingencies.
At December 31, 2000, we had capital and investment commitments of
approximately $72.4 million primarily related to the construction of the Prince
TLP, which are expected to be funded through internally generated funds and/or
incremental borrowings. Our other planned capital and investment projects are
discretionary in nature, with no substantial commitments made in advance of the
actual expenditures.
OTHER
In January 2001, El Paso merged with The Coastal Corporation, the parent
company of ANR Pipeline Company, which is our joint venture partner in Deepwater
Holdings. As a result of the merger, ANR has became our affiliate.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Item 8, Financial Statements and Supplementary Data, Note 1, for a
discussion relating to new accounting pronouncements not yet adopted.
21
24
RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and made in good
faith, assumed facts or bases almost always vary from the actual results, and
the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, such expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe", "expect", "estimate", "anticipate" and similar expressions may
identify forward-looking statements.
With this in mind, you should consider the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf.
RISKS INHERENT IN AN INVESTMENT IN OUR LIMITED PARTNER INTERESTS
YOU WILL HAVE LIMITED VOTING RIGHTS AND WILL NOT CONTROL OUR GENERAL PARTNER
Unlike the holders of capital stock in a corporation, you only have limited
voting rights on matters affecting our business. Our General Partner, whose
directors you do not elect, manages our activities. In addition, absent
voluntary withdrawal, our unitholders will not have the right to elect the
general partner on an annual or any other continuing basis. Furthermore, the
general partner may not be removed as our general partner except upon the
affirmative vote of the holders of at least 55 percent of our outstanding
limited partner interests, including units owned by the general partner and its
affiliates.
WE MAY ISSUE ADDITIONAL SECURITIES, DILUTING YOUR INTERESTS
We can issue additional common units, preference units and other capital
securities representing limited partner interests, including securities with
rights to distributions and allocations or in liquidation equal or superior to
the securities held by you, for any amount and on any terms and conditions
established by the general partner. If we issue more limited partner interests,
it will reduce your proportionate ownership interest in us. This could cause the
market price of your securities to fall and reduce the cash distributions paid
to our limited partners. Further, we have the ability to issue partnership
interests with voting rights superior to yours. If we issued any such
securities, it could adversely affect your voting power.
YOU MAY NOT HAVE LIMITED LIABILITY IN THE CIRCUMSTANCES DESCRIBED BELOW AND MAY
BE LIABLE FOR THE RETURN OF WRONGFUL DISTRIBUTIONS
You will not be liable for assessments in addition to your initial capital
investment in our securities. However, you may be required to repay to us
amounts wrongfully returned or distributed to you under some circumstances.
Delaware law provides that a limited partner who receives a distribution that
results in liabilities of the partnership exceeding the fair value of the assets
of the partnership and knows at the time of the distribution that the
distribution violates the law will be liable to the limited partnership for the
amount of the distribution for three years from the date of the distribution.
OUR EXISTING UNITS ARE SUBJECT TO RESTRICTIONS ON TRANSFER
All purchasers of our existing units who wish to become holders of record
must deliver an executed transfer application in which the purchaser or
transferee must certify that, among other things, he, she or it is eligible to
purchase those securities before the purchaser or transferee of those securities
will be registered on our records, and before cash distributions can be made and
federal income tax information furnished to the purchaser or transferee. A
person purchasing our existing units, who does not execute a transfer
application
22
25
and certify that the purchaser is eligible to purchase those securities,
acquires no rights in those securities other than the right to resell those
securities. Further, our general partner may request each record holder to
furnish information about the holder's nationality, citizenship or other related
status. If the record holder fails to furnish the information or if our general
partner determines, based on the information furnished by the holder in response
to the request, that the cancellation or forfeiture of any property in which we
have an interest may occur, our general partner may be substituted as a holder
for the record holder, who will then be treated as a non-citizen assignee, and
we will have the right to redeem those securities held by the record holder. As
a result of these restrictions, your ability to transfer your limited partner
interests may be adversely affected.
OUR GENERAL PARTNER HAS A LIMITED CALL RIGHT THAT MAY REQUIRE YOU TO SELL YOUR
LIMITED PARTNER INTERESTS AT AN UNDESIRABLE TIME OR PRICE
If, at any time, our general partner and its affiliates hold 85 percent or
more of any class or series of our issued and outstanding limited partner
interests, the general partner will have the right to purchase all, but not less
than all, of the outstanding securities of that class or series held by
nonaffiliates. Accordingly, you may be required to sell your limited partner
interests against your will, and the price you receive for those securities may
be less than you would like to receive.
RISKS RELATED TO CONFLICTS OF INTEREST
EL PASO AND ITS AFFILIATES MAY HAVE CONFLICTS OF INTEREST WITH US
Although El Paso controls our general partner and has financial incentives
to protect its investment by encouraging our success, and it plans to use us
when practical as its principal growth vehicle for acquiring and developing
midstream onshore and offshore assets and providing related services and
solutions, El Paso is not contractually bound to do so and may reconsider at any
time, without notice. Additionally, El Paso is not required to pursue a business
strategy that will favor our business opportunities over the business
opportunities of El Paso or any of its affiliates (or any other competitor of
ours acquired by El Paso, including Coastal, with whom El Paso just completed a
merger). In fact, El Paso may have financial motives to favor our competitors.
El Paso and its subsidiaries (many of which are wholly owned) operate in some of
the same lines of business and in some of the same geographic areas in which we
operate. El Paso continues to own pipelines and related facilities located in
the Gulf, including the Bluewater and Seahawk Shoreline systems. To the extent
we continue to acquire interests in oil and natural gas properties, we may
compete directly with the exploration, development and marketing activities
conducted by El Paso.
We and our general partner and its affiliates share and, therefore, will
compete for, the time and effort of general partner personnel who provide
services to us. Officers of our general partner and its affiliates do not, and
will not be required to, spend any specified percentage or amount of time on our
business. Since these shared officers function as both our representatives and
those of our general partner and its affiliates, conflicts of interest could
arise between our general partner and its affiliates, on the one hand, and ours
on the other. In addition, we have, and we expect to enter into other,
significant business relationships with El Paso, our general partner and their
affiliates in which conflicts of interest could arise.
23
26
RISKS RELATED TO OUR LEGAL STRUCTURE
THE INTERRUPTION OF DISTRIBUTIONS TO US FROM OUR SUBSIDIARIES AND JOINT VENTURES
MAY AFFECT OUR ABILITY TO MAKE CASH DISTRIBUTIONS
We are a holding company. As such, our primary assets are the capital stock
and other equity interests in our subsidiaries and joint ventures. Consequently,
our ability to make cash distributions depends upon the earnings and cash flow
of our subsidiaries and joint ventures and the distribution of that cash to us.
Distributions from our joint ventures are subject to the discretion of their
respective management committees. In addition, our Argo subsidiary and several
of our joint ventures have credit arrangements that contain various restrictive
covenants. Among other things, those covenants may limit or restrict such
entities' ability to make distributions to us. Further, the entity charter
documents typically vest in their management committees sole discretion
regarding distributions. We cannot assure you that our Argo subsidiary or our
joint ventures will continue to make distributions to us at current levels or at
all.
Moreover, pursuant to some of the those credit arrangements, we have
conditionally agreed to return a limited amount of the distributions made to us
by the applicable entity.
WE CANNOT CAUSE OUR JOINT VENTURES TO TAKE OR NOT TO TAKE ACTIONS UNLESS SOME OR
ALL OF OUR JOINT VENTURE PARTNERS AGREE
Due to the nature of joint ventures, each partner (us included) in each of
our joint ventures has made substantial contributions and other commitments to
that joint venture and, accordingly, has required that the relevant charter
documents contain certain features designed to provide each partner with the
opportunity to protect its investment in that joint venture, as well as any
other assets which may be substantially dependent on or otherwise affected by
the activities of that joint venture. These protective features include a
corporate governance structure which requires at least a majority in interest
vote to authorize many basic activities and requires a greater voting interest
(sometimes up to 100 percent) to authorize more significant activities.
Depending on the particular joint venture, these more significant activities
might involve large expenditures or contractual commitments, the construction or
acquisition of assets, borrowing money, transactions with affiliates of a joint
venture partner, litigation and/or transactions not in the ordinary course of
business, among others. Thus, without the concurrence of joint venture partners
with enough voting interests, we cannot cause any of our joint ventures to take
or not to take certain actions, even though such actions may be in the best
interest of the particular joint venture or us.
WE DO NOT HAVE THE SAME FLEXIBILITY AS OTHER TYPES OF ORGANIZATIONS TO
ACCUMULATE CASH AND EQUITY TO PROTECT AGAINST ILLIQUIDITY IN THE FUTURE
Unlike a corporation, our partnership agreement requires us to make
quarterly distributions to our unitholders of all available cash reduced by any
amounts reserved for commitments and contingencies, including capital and
operating costs and debt service requirements. The value of our common units
will decrease in direct correlation with decreases in the amount we distribute
per unit. Accordingly, if we experience a liquidity problem in the future, we
may not be able to issue more equity to recapitalize.
CHANGES OF CONTROL OF OUR GENERAL PARTNER MAY ADVERSELY AFFECT YOU
Our results of operations and, thus, our ability to make cash distributions
could be adversely affected if there is a change in management resulting from a
change of control of our general partner. Although such an action would result
in a change of control under the terms of the indenture governing our
publicly-held debt, El Paso is not restricted from selling the general partner
or any of the common units it holds. As a result, El Paso could sell control of
our general partner to another company with less familiarity and experience with
our businesses and with different business philosophies and objectives. We
cannot assure you that any such acquiror would continue our current business
strategy, or even a business strategy economically compatible with our current
business strategy.
24
27
RISKS RELATED TO OUR BUSINESS
OUR INDUSTRY IS HIGHLY COMPETITIVE
The hydrocarbons that we transport, gather, process, and store are, in many
cases, owned by third parties. As a result, the volume of hydrocarbons involved
in these activities depends on the actions of those third parties, and is beyond
our control. Further, the following factors, most of which are beyond our
control, impact our ability to maintain or increase current transmission,
gathering, processing, storage and sales volumes and rates, renegotiate existing
contracts as they expire or to remarket unsubscribed capacity at levels and
rates currently in place:
- future weather conditions, including those that favor alternative energy
sources;
- price competition;
- drilling activity and supply availability; and
- service area competition.
Our future profitability may be affected by our ability to compete with
services offered by other energy enterprises which may be larger, offer more
services, and possess greater resources.
The ongoing profitability of our pipeline systems depends upon having in
place long-term firm transportation contracts for a major portion of their
capacity. Our ability to negotiate new contracts and to renegotiate existing
contracts could be harmed by factors we cannot control, including:
- the proposed construction by other companies of additional pipeline
capacity in markets served by our pipelines;
- reduced demand due to higher oil and natural gas prices;
- actions by regulators that may impact the competitiveness of short-term
and long-term capacity markets;
- the availability of alternative energy sources; and
- the viability of our expansion projects.
FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS
Revenues generated by our gathering, storage, transportation and processing
contracts depend on volumes and rates, both of which can be affected by the
prices of oil and natural gas. The success of our expanding gathering, storage,
transportation, and processing operations is subject to continued development of
additional oil and natural gas reserves in the vicinity of our facilities, and
our ability to access such additional reserves to offset the natural decline
from existing wells connected to our systems. A decline in energy prices could
precipitate a decrease in these development activities and could cause a
decrease in the volume of reserves available for gathering, transportation and
processing through our offshore facilities. Fluctuations in energy prices, which
may impact gathering rates and investments by third parties in the development
of new oil and natural gas reserves connected to our facilities, are caused by a
number of factors, including:
- regional, domestic and international supply and demand;
- availability and adequacy of transportation and platform facilities;
- energy legislation;
- federal or state taxes, if any, on the sale or transportation of natural
gas and natural gas liquids; and
- abundance of supplies of alternative energy sources.
25
28
If there are reductions in the average volume of the natural gas we
transport, store, gather and process for a prolonged period, our results of
operations and financial position could be significantly, negatively affected.
FLUCTUATIONS IN PRODUCTION ACTIVITIES COULD HARM OUR BUSINESS
The success of our production activities could be adversely affected by
factors we can not control, including:
- fluctuations in prices of crude oil and natural gas;
- future production and development costs; and
- risks incident to the operation of oil and natural gas wells.
NATURAL GAS PRICE STABILITY COULD HAVE AN ADVERSE EFFECT ON REVENUES AND CASH
FLOW FROM OUR STORAGE ASSETS.
Prices for natural gas have historically been seasonal and volatile, which
has enhanced demand for our storage services. The storage business has benefited
from large price swings and peaking resulting from seasonal price sensitivity
through increased withdrawal charges and demand for non-storage hub services.
You cannot be certain that the market for natural gas will continue to
experience volatility and seasonal price sensitivity in the future at the levels
previously seen. If volatility and seasonality in the natural gas industry
decrease, because of increased storage capacity throughout the pipeline grid,
increased production capacity or otherwise, the demand for our storage services
and, therefore, the prices that we will be able to charge for those services,
may decline.
PERSONAL INJURY, MECHANICAL FAILURE AND DAMAGE TO THE STORAGE AND RELATED
FACILITIES COULD HAVE AN ADVERSE EFFECT ON REVENUES AND CASH FLOW FROM OUR
STORAGE ASSETS.
Our storage operations are subject to all of the risks generally associated
with the storage of natural gas, a highly volatile product, including personal
injuries and damage to storage facilities, related equipment and surrounding
properties caused by hurricanes, weather and other acts of God, fires and
explosions, subsidence, as well as leakage of natural gas and spills of liquids
and condensate. Our storage facilities incorporate certain primary and backup
equipment which, in the event of mechanical failure, might take some time to
replace. Any prolonged disruption to the operations of our storage facilities,
whether due to mechanical failure, labor difficulties, destruction of or damage
to such facilities, severe weather conditions, interruption of transportation or
utilities service or other reasons, could have a material adverse effect on our
business, results of operations and financial condition. Additionally, some of
our storage contracts obligate us to indemnify the customer for any damage or
injury occurring during the period in which the customer's natural gas is in our
possession. In order to minimize the effects of any such incident, we maintain
insurance coverage which includes property and business interruption insurance.
We believe that this insurance coverage is adequate; however, you cannot be sure
that the proceeds of any such insurance would be paid in a timely manner or be
in an amount sufficient to meet our needs if such an event were to occur.
OUR STORAGE BUSINESS DEPENDS ON NEIGHBORING PIPELINES TO TRANSPORT NATURAL GAS.
To obtain natural gas, our storage business depends on the pipelines to
which it has access. Many of these pipelines are owned by parties not affiliated
with us. Any interruption of service on those pipelines or adverse change in
their terms and conditions of service could have a material adverse effect on
our ability (and the ability of our customers) to transport natural gas to and
from our facilities and a corresponding material adverse effect on our storage
revenues. In addition, the rates charged by those interconnected pipelines for
transportation to and from our facilities affect the utilization and value of
our storage services. Significant changes in the rates charged by those
pipelines or the rates charged by other pipelines with which the interconnected
pipelines compete could also have a material adverse effect on our storage
revenues.
26
29
THE USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES
At times, we enter into derivative financial instruments to reduce our
exposure to short-term volatility in changes in energy commodity prices. In
these activities, we could incur financial losses in the future as a result of
volatility in the market values of the underlying commodities or if one of our
counterparties fails to perform under a contract. For additional information
concerning our derivative financial instruments, see item 7A, Quantitative and
Qualitative Disclosures About Market Risk and Item 8, Financial Statements and
Supplementary Data, Note 8.
ATTRACTIVE ACQUISITION AND INVESTMENT OPPORTUNITIES MAY NOT BE AVAILABLE
Our ability to grow will depend, in part, upon our ability to identify and
complete attractive acquisition and investment opportunities. Opportunities for
growth through acquisitions and investments in joint ventures, and the future
operating results and success of these acquisitions and joint ventures within
the United States may be subject to the effects of, and changes in, the
following:
- United States monetary policies;
- laws and regulations;
- political and economic developments;
- inflation rates;
- taxes; and
- operating conditions.
WE COULD INCUR SUBSTANTIAL ENVIRONMENTAL LIABILITIES
We may incur significant costs and liabilities in order to comply with
existing and future environmental laws and regulations. It is also possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies thereunder, and claims for damages to property,
employees, other persons and the environment resulting from our operations could
result in substantial costs and liabilities in the future. For additional
information concerning our environmental matters, see Item 8, Financial
Statements and Supplementary Data, Note 8.
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS
While we maintain insurance against the risks normally associated with the
gathering, transportation, processing, exploration and production of oil and
natural gas, including, but not limited to explosions, pollution and fires, the
occurrence of a significant event against which we are not fully insured could
have a significant negative effect on our business.
OUR SUBSTANTIAL INDEBTEDNESS COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION AND
PREVENT US FROM MAKING DISTRIBUTIONS TO OUR UNITHOLDERS
We have a significant amount of indebtedness and the ability to incur more
indebtedness. Furthermore, our indebtedness is collateralized by guarantees of
our subsidiaries. Our substantial indebtedness could have important consequences
to our unitholders. For example, it could:
- limit our ability to make distributions to our unitholders;
- increase our vulnerability to general adverse economic and industry
conditions;
- prevent us from running our businesses as planned;
- limit our ability to pursue acquisition opportunities; and
- place us at a competitive disadvantage as compared to our competitors
that have less debt.
27
30
OUR INDEBTEDNESS MAY RESTRICT OUR ABILITY TO OPERATE
We must comply with various affirmative and negative covenants related to
our senior subordinated notes, our revolving credit facility and our project
finance loan. These restrictions may prevent us from engaging in transactions
beneficial to us. Specifically, these covenants limit our ability to:
- incur additional indebtedness or liens;
- make payments in respect of, redeem or acquire any debt or equity issued
by us;
- sell assets;
- make loans or investments;
- acquire or be acquired by other companies; and
- amend some of our contracts.
Any additional indebtedness we incur in the future will be under our
existing credit agreements or under arrangements that we believe have terms and
conditions at least as restrictive as those contained in our existing credit
agreements.
28
31
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We may utilize derivative financial instruments for purposes other than
trading to manage market risks associated with energy commodities and interest
rates. In accordance with procedures established by our General Partner, we
monitor current economic conditions and evaluate our expectations of future
prices and interest rates when making decisions with respect to risk management.
COMMODITY PRICE RISK
We occasionally hedge a portion of our oil and natural gas production to
reduce our exposure to fluctuations in the market prices of oil and natural gas,
and to meet requirements under our revolving credit facility. We use commodity
price swap transactions whereby monthly settlements are based on differences
between the prices specified in the commodity price swap agreements and the
settlement prices of our futures contracts quoted on the New York Mercantile
Exchange, or NYMEX, or other indices. We settle the commodity price swap
transactions by paying the negative difference or receiving the positive
difference between the applicable settlement price and the price specified in
the contract. The commodity price swap transactions we use differ from futures
contracts in that there are no contractual obligations which require or allow
for the future delivery of the product. The credit risk from our price swap
contracts is derived from the counterparty to the transaction, typically a major
financial institution. We do not require collateral and do not anticipate
non-performance by this counterparty, which does not transact a sufficient
volume of transactions with us to create a significant concentration of credit
risk. Gains or losses resulting from hedging activities and the termination of
any hedging instruments are initially deferred and included as an increase or
decrease to oil and natural gas sales in the period in which the hedged
production is sold. For the years ended December 31, 2000, 1999, and 1998, we
recorded a net (loss) gain of $(15.0) million, $(2.3) million and $2.5 million,
respectively, from such activities.
At December 31, 1999, we had two outstanding natural gas sales swap
transactions for the calendar year 2000. Under one of the swaps, we received a
fixed price of $1.6686 on 10,000 MMbtu/d, and paid the monthly natural gas
futures contract price on NYMEX. The second swap provided for similar pricing
terms, notional quantity and contract period. On January 18, 2000, we fixed the
contract under the swap whereby we received $1.8050 on 10,000 MMbtu/d from
February to December 2000 and paid monthly NYMEX settlement price.
Each of our derivative instruments expired in December 2000, and we have
not entered into any new hedging activities in 2001.
INTEREST RATE RISK
We utilize both fixed and variable rate long-term debt, and are exposed to
market risk due to the floating interest rate under our credit facility. Under
our amended credit facility, the remaining principal and the final interest
payment are due in May 2002. As of December 31, 2000, our credit facility had a
principal balance of $318 million with an average floating interest rate of 9.1%
per annum. A one percent increase in interest rates would result in a $3.2
million annual increase in interest expense on the existing principal balance.
We are exposed to similar risks under the various joint venture credit
facilities and loan agreements.
29
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
YEAR ENDED DECEMBER 31,
------------------------------
2000 1999 1998
------- -------- -------
Operating revenues
Gathering and transportation services..................... $71,806 $ 22,311 $ 6,852
Oil and natural gas sales................................. 20,552 29,965 31,411
Platform services......................................... 13,875 11,383 10,468
Gas storage services...................................... 6,182 -- --
------- -------- -------
112,415 63,659 48,731
------- -------- -------
Operating expenses
Purchased natural gas costs............................... 28,842 -- --
Operation and maintenance, net............................ 13,779 22,402 27,558
Depreciation, depletion and amortization.................. 27,743 30,630 29,267
Impairment, abandonment and other......................... -- -- (1,131)
------- -------- -------
70,364 53,032 55,694
------- -------- -------
Operating income (loss)..................................... 42,051 10,627 (6,963)
------- -------- -------
Other income
Equity investment earnings................................ 22,931 32,814 26,724
Gain on sale of assets.................................... -- 10,103 311
Other..................................................... 2,377 358 460
------- -------- -------
25,308 43,275 27,495
------- -------- -------
Income before interest, income taxes and other charges...... 67,359 53,902 20,532
Interest and debt expense................................... 47,072 35,323 20,242
Minority interest........................................... 95 197 15
------- -------- -------
Income before income taxes.................................. 20,192 18,382 275
Income tax benefit.......................................... 305 435 471