ITEM 1. BUSINESS
GENERAL
El Paso Energy Partners, L.P. and its subsidiaries, or the Partnership, is one of the largest energy master limited partnerships in terms of market capitalization and a leading independent gatherer of natural gas and oil in the Gulf of Mexico. It also provides transportation, midstream and other related services primarily in the Gulf. Through its subsidiaries and joint ventures, the Partnership owns or has interests in (i) eleven natural gas and oil pipeline systems (ii) six offshore platforms, including related production, processing, and dehydration facilities, (iii) four producing oil and natural gas properties and (iv) overriding royalty interests in two non-producing oil and natural gas properties. The Partnership commenced operations in February 1993 in connection with the initial public offering of preference units representing limited partner interests in the Partnership. In June 1994, the Partnership completed a second public offering of preference units. In May 1998 and 1999, preference unitholders were given the opportunity to convert their preference units into common units of the Partnership. Through December 31, 1999, approximately 98 percent of these preference units had been converted.
In August of 1998, El Paso Energy Corporation, or El Paso Energy, acquired DeepTech International Inc., the parent company to the General Partner of the Partnership. Following this acquisition, the General Partner became an indirect wholly owned subsidiary of El Paso Energy and now performs all management and operational functions. El Paso Energy, through its subsidiaries, owns an effective 34.5 percent economic interest in the Partnership consisting of 8,953,764 common units, a one percent general partner interest, and an approximate one percent nonmanaging member interest in certain of the Partnership's subsidiaries.
In December 1999, the Partnership announced that it changed its name from Leviathan Gas Pipeline Partners, L.P. to El Paso Energy Partners, L.P. At that time, the Partnership's trading symbol for common units changed to "EPN," and the symbol for preference units changed to "EPN.P" on the New York Stock Exchange, or NYSE. The Partnership further announced that its growth strategy, while remaining committed to the deepwater region of the Gulf, will incorporate the acquisition and development of energy infrastructure assets in areas that previously had not been in the Partnership's core geographic areas of operation.
Over the past five years, the Partnership has acquired or developed assets that are strategically located to benefit from the growth of natural gas and oil production occurring in the deepwater regions of the Gulf. In 1995 and 1996, the Partnership finished the construction and installation of the Viosca Knoll Block 817 and Garden Banks Block 72 platforms, and completed its drilling programs at those two locations and Garden Banks Block 117. In 1997, the Partnership acquired a 25.67 percent indirect interest in each of Nautilus Pipeline Company, L.L.C. and Manta Ray Offshore Gathering Company, L.L.C. In 1998, the Partnership constructed a multi-purpose platform located in East Cameron Block 373 and acquired a 100 percent working interest in the Ewing Bank 958 Unit, a non-producing oil and natural gas property comprised of Ewing Bank Blocks 958, 959, 1002, and 1003. In 1999, the Partnership acquired an additional 49 percent ownership interest in Viosca Knoll Gathering Company, and additional indirect ownership interests in High Island Offshore System, L.L.C., East Breaks Gathering Company, L.L.C., and U-T Offshore System, L.L.C., bringing its overall ownership interest in Viosca Knoll to 99 percent and in HIOS, East Breaks and UTOS to 50 percent. In addition, the Partnership placed the Allegheny system in service and entered into an agreement to farm out its working interest in the Ewing Bank 958 Unit to a subsidiary of El Paso Energy. The Partnership will continue to look for opportunities in the future to enhance both its earnings and its ability to make cash distributions to its unitholders.
PARTNERSHIP OPERATIONS
The Partnership's principal operations include the transportation and gathering of natural gas and oil in the Gulf. It conducts these activities through its ownership of, or interests in, eleven pipeline systems. These systems have a combined capacity of over 7.2 billion cubic feet per day, or Bcf/d, of natural gas and over 480 thousand barrels per day, or MBbls/d, of oil and include over 1,600 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. During the years ended December 31, 1999, 1998, and 1997, these systems handled an average of approximately 3.4 million dekatherms per day, or MMdth/d, 3.4 MMdth/d, and 2.9 MMdth/d, respectively, of natural gas and approximately 181 MBbls/d, 97 MBbls/d, and 52 MBbls/d, respectively, of oil.
The Partnership also owns or has interests in six platforms which also include certain production, processing, and dehydration facilities. These facilities have a combined product handling capacity of over 630 thousand cubic feet per day, or Mcf/d, of natural gas and over 77 MBbls/d of oil and condensate. Through these facilities, the Partnership is able to provide a variety of producer and midstream services to enhance deliverability and volumes into its pipeline systems.
The Partnership conducts its oil and natural gas production activities through its interests in four producing properties having total proved reserves of over 17.5 Bcf of natural gas and over 1.5 million barrels, or MMBbls, of oil. The Partnership also has overriding royalty interests in non-producing properties in the Ewing Bank and Garden Banks region of the Gulf to capitalize on future development efforts in those regions.
SEGMENTS
The Partnership segregates its business activities into two segments: Gathering, Transportation, and Platform Services and Oil and Natural Gas Production. 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 12, which is incorporated herein by reference. Each of these segments is discussed more fully below.
GATHERING, TRANSPORTATION, AND PLATFORM SERVICES
Pipeline Systems
The Partnership conducts a significant portion of its 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 member's relative ownership interests. The following table describes the Partnership's network of subsidiary and joint venture owned natural gas and crude oil pipelines as of December 31, 1999:
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(1) The Partnership acquired an additional 49 percent ownership interest in June 1999 from a subsidiary of El Paso Energy. (2) The Partnership began operating this system in November 1999. (3) The Partnership will assume full operations of these systems no later than July 1, 2000. (4) The East Breaks system was completed in December 1999, and is expected to be placed in service by mid 2000. The Allegheny system was placed in service in October 1999. (5) All measures are on a million cubic feet per day, or MMcf/d, basis except the Poseidon and Allegheny systems which are measured on a MBbls/d basis. (6) All measures are on a thousand dekatherms per day, or Mdth/d, basis except the Poseidon and Allegheny systems which are measured on a MBbls/d basis.
Deepwater Holdings. In June 1999, the Partnership acquired additional ownership interests in the HIOS, UTOS and East Breaks systems. In September 1999, the Partnership and ANR Pipeline Company reorganized their interests in these and certain other pipeline systems through the formation of Deepwater Holdings, L.L.C. 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. The Partnership has a 50 percent ownership interest in Deepwater Holdings.
HIOS. The HIOS system is a natural gas transmission system consisting of approximately 204 miles of pipeline which includes three supply laterals that connect to a 42-inch diameter mainline. The HIOS system transports natural gas received from fields located in the Galveston, Garden Banks, West Cameron and East Breaks areas of the Gulf to a junction platform owned by HIOS located in West Cameron Block 167.
UTOS. The UTOS system is a natural gas transmission system consisting of approximately 30 miles of 42-inch diameter pipeline extending from an interconnection with the HIOS system at West Cameron Block 167 to the Johnson Bayou production handling facility, owned by UTOS. The UTOS system is essentially an extension of the HIOS system, as almost all the natural gas transported through the UTOS system comes from the HIOS system. The Johnson Bayou facility provides primarily natural gas and liquids separation and gas dehydration services for natural gas transported on the HIOS and UTOS systems.
East Breaks. The East Breaks system is a natural gas gathering system, substantially completed in December 1999, consisting of approximately 85 miles of 18 to 20-inch diameter pipeline that connects the HIOS system to the Diana and Hoover fields being developed by subsidiaries of Exxon Company USA and BP Amoco plc. Production from the Diana and Hoover properties has been committed to the East Breaks system. This system has the ability to expand its throughput capacity further, thereby providing the HIOS and UTOS systems with the ability to compete to gather and transport the substantial reserves associated with properties being, and expected to be, developed in these deepwater frontier regions.
Stingray. The Stingray system is a natural gas gathering system consisting of (i) approximately 361 miles of 6 to 36-inch diameter pipeline that transports natural gas from the HIOS system, West Cameron, East Cameron and Vermilion lease areas in the Gulf to onshore transmission systems in Louisiana, (ii) approximately 12 miles of 16-inch diameter pipeline and approximately 31 miles of 20-inch diameter pipeline connecting platforms and leases in the Garden Banks 191 and 72 areas, respectively, to the Stingray system, and (iii) approximately 13 miles of 16-inch diameter pipeline connecting the Partnership's platform at East Cameron Block 373 to the Stingray system at East Cameron Block 338.
Green Canyon. The Green Canyon system is a natural gas gathering system consisting of approximately 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 to Transcontinental Gas Pipeline Company's, or Transco's, South Lateral in South Marsh Island Block 106.
Tarpon. The Tarpon system is a natural gas gathering system consisting of approximately 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 of the Gulf.
Neptune and Ocean Breeze. The Partnership owns a 25.67 percent interest in 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.
Manta Ray Offshore. The Manta Ray Offshore system is a natural gas gathering system consisting of (i) three separate gathering lines in the offshore Louisiana area of the Gulf, including approximately 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 (ii) approximately 149 miles of 14, 16, and 24-inch diameter pipelines, 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.
Nautilus. The Nautilus system 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 the Manta Ray Offshore system is also dedicated to the Nautilus system.
Viosca Knoll. The Viosca Knoll system is a natural gas gathering system designed to serve the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf and consists of 125 miles of predominantly 20-inch natural gas pipeline and a 7,000 horsepower compressor. The system 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, the Partnership acquired an additional 49 percent interest in the Viosca Knoll system from a subsidiary of El Paso Energy.
Poseidon. Through its interest in Poseidon Oil Pipeline Company, L.L.C., or Poseidon, the Partnership has an interest in the Poseidon system, which 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. The Poseidon system consists of (i) approximately 117 miles of 16 to 20-inch diameter pipeline extending from the Partnership's 50 percent owned Garden Banks Block 72 platform to the Partnership's platform at Ship Shoal Block 332, (ii) approximately 122 miles of 24-inch diameter pipeline extending from the Ship Shoal Block 332 platform
to Houma, Louisiana, (iii) approximately 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) approximately 17 miles of 16-inch pipeline extending from Garden Banks Block 260 to South Marsh Island Block 205.
Allegheny. The Allegheny system is a crude oil system, completed in the fourth quarter of 1999, consisting of approximately 43 miles of 14-inch diameter pipeline that connects the Allegheny field in the Green Canyon area of the Gulf with the Poseidon system at the Partnership's Ship Shoal 332 platform. Oil production from the Allegheny field is committed to the system.
Nemo. In August 1999, the Partnership and Tejas Offshore Pipeline, L.L.C. formed Nemo Gathering Company L.L.C., or Nemo, to construct, own and operate a natural gas gathering system extending from the Brutus and Glider deepwater development properties to the Manta Ray Offshore system. The Nemo system, which will consist of approximately 24 miles of 20 -inch diameter pipeline with a capacity of 300 MMcf/d should be completed in late 2001.
Offshore Platforms and Related Facilities
The Partnership's offshore platforms play a key role in the development of the oil and natural gas offshore pipeline network. Platforms are used to interconnect the offshore pipeline grid; to provide an efficient means to perform pipeline maintenance; and to serve as a base for compression, separation, production handling, and other facilities. In addition to numerous platforms owned by the Partnership's pipeline investments, the Partnership owns six strategically-located platforms in the Gulf, including five multi-purpose hub-platforms. These platforms were specifically designed to be used as flextrend and deepwater landing sites and production handling and pipeline maintenance facilities. Information regarding the Partnership's platforms as of December 31, 1999, is set out below:
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(1) 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.
East Cameron 373. The East Cameron 373 platform is located at the south end of the central leg of the Stingray system. 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 the Stingray system and serves as the western-most termination point of the Poseidon system. The platform serves as a base for landing deepwater production from Enterprise Oil Gulf of Mexico, Inc., 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. The Partnership also uses the platform as the host for the Partnership's Garden Banks Block 72 production and the landing site for production from the Partnership's Garden Banks Block 117 lease located in an adjacent lease block.
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.
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 certain rights to utilize the platform pursuant to a production handling and use of space agreement.
South Timbalier 292. The South Timbalier 292 platform is located at the easternmost termination point of the Manta Ray Offshore system and serves as a landing site for natural gas production in the area and provides an interconnection to the Trunkline Gas Pipeline system.
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 Exxon Company USA, Shell Offshore Inc., 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 the Partnership's Viosca Knoll Block 817 lease.
Other Facilities. Through its 50 percent ownership interest in Deepwater Holdings, the Partnership also owns an interest in the West Cameron dehydration facility located at the northern termination point of the Stingray system in Louisiana.
Markets and Competition
Each of the Partnership's natural gas pipeline systems is located at or near natural gas production areas that are served by other pipelines. As a result, each of the Partnership's 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, and may have a lower cost structure than, the Partnership's natural gas pipeline systems. Other competing pipelines, such as long-haul transporters, may have rate design alternatives unavailable to the Partnership. Consequently, those competing pipelines may be able to provide service on more flexible terms and at rates significantly below those offered by the Partnership.
The Partnership's oil pipeline systems were built as a result of the need for additional crude oil capacity to transport new deepwater oil production to shore. These systems' 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. The Partnership's 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 the Partnership's pipelines to access future reserves will be subject to the ability of the Partnership or the producers to fund the significant capital expenditures required to connect to the new production.
A substantial portion of the revenues generated by the Partnership's pipeline systems is attributed to production from reserves committed under long-term contracts for the productive life of the relevant field. Nonetheless, these reserves and other reserves that may become available to the Partnership's pipeline systems are depleting assets and, as such, will be produced over a finite period. Each of the Partnership's 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 the Partnership charges for its services are dependent on (1) whether the relevant pipeline system is regulated or unregulated, (2) the quality of the service required by the customer, and (3) the amount and term of the reserve commitment by the customer. A majority of the Partnership's arrangements involve life-of-reserve commitments with both firm and interruptible components. Generally, the Partnership receives a price per dekatherm of natural gas or barrel of oil or water handled. Also, for firm arrangements, the Partnership often receives a monthly fixed fee which is paid by the customer regardless of the level of throughput, except under individually specified circumstances.
The Partnership's platforms are subject to similar competitive factors as its 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 those of the Partnership.
For a discussion of significant customers of the Partnership, see Item 8, Financial Statements and Supplementary Data, Note 11, which is incorporated herein by reference.
Regulatory Environment
The Partnership's natural gas pipeline systems are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, 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 the Partnership's 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, and the National Environmental Policy Act and other environmental legislation. Each of the systems has a continuing program of inspection designed to keep all of its facilities in compliance with pollution control and pipeline safety requirements. The Partnership believes that its systems are in substantial compliance with applicable requirements of the regulations under which the systems are governed.
The Partnership's 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 systems operates under separate FERC approved tariffs which establish rates, terms, and conditions under which each system provides services to its customers.
On December 1, 1998, Stingray filed for a general rate increase at the FERC. Pursuant to an order issued by FERC on December 30, 1998, the proposed rates became effective June 1, 1999, subject to refund. A hearing on the merits of Stingray's filing was held in December 1999. The rate case is still pending. Each of the HIOS, UTOS and Nautilus systems is currently operating under agreements with their respective customers which provide for rates that have been approved by the FERC.
Maintenance
Each of the Partnership's pipeline systems and platforms requires regular and thorough maintenance. The interior of the pipelines is maintained through the regular "pigging" of the lines to clean 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. Anodes 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 and Poseidon 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.
OIL AND NATURAL GAS PRODUCTION
Currently, the Partnership owns interests in four producing and two non-producing oil and natural gas properties located in waters offshore Louisiana. Production from these properties is gathered, transported, and processed through the Partnership's pipeline systems and platform facilities, and sold to an affiliate of El Paso Energy. The following is information regarding these properties as of December 31, 1999:
Producing Properties
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(1) The Partnership's working interest in this property 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, 1999, the unpaid portion of the production payment obligation totaled $10.4 million. (2) The West Delta Block 35 field commenced production in 1993, but the Partnership's interest in this field was acquired in connection with El Paso Energy's acquisition of the Partnership's general partner in 1998. (3) Production data is for the period from August 1998.
Acreage and Wells. The following table sets forth the Partnership's developed and undeveloped oil and natural gas acreage as of December 31, 1999. 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 the Partnership. The number of net acres is the Partnership's fractional ownership of the working interest in the gross acres.
The Partnership's gross and net ownership in producing wells at December 31, 1999, is as follows:
In 1999, the Partnership did not drill any exploratory or developmental wells. One developmental oil well was drilled during 1998 and no wells were drilled in 1997.
Net production, unit prices, and production costs. The following table sets forth certain information regarding the production volumes of, average unit prices received for, and average production costs for the Partnership's oil and natural gas properties for the periods indicated:
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(1) The information regarding net production and average sales prices excludes overriding royalty interests. (2) The components of average production costs may vary substantially among wells depending on the methods of recovery employed and other factors, but generally include third party transportation expenses, maintenance and repair, labor and utilities costs.
The relationship between average sales prices and average production costs depicted by the table above is not necessarily indicative of future results of operations expected by the Partnership.
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 Properties
Ewing Bank 958 Unit. Through October 1999, the Partnership owned a 100 percent working interest in the Ewing Bank 958 Unit, comprised of Ewing Bank Blocks 958, 959, 1002, and 1003 which were formerly referred to as the Sunday Silence Properties. The Ewing Bank 958 Unit was discovered in 1994 in approximately 1,500 feet of water in the Gulf. In October 1999, the Partnership executed an agreement with El Paso Production Company, or El Paso Production, a subsidiary of El Paso Energy, to farm out its working interest in the Ewing Bank 958 Unit. Under the terms of the farmout agreement, the Partnership increased its overriding royalty interest in the Ewing Bank 958 Unit from 5.3 percent to 7.4 percent convertible, at its option, into a 30 percent undivided working interest once El Paso Production has recouped the costs associated with its drilling and completion activities on the unit. El Paso Production began drilling on the Ewing Bank 958 Unit in November 1999.
Garden Banks Block 73. The Partnership maintains a 2.5 percent overriding royalty interest in the Garden Banks Block 73 property, located 115 miles offshore in approximately 743 feet of water. The property has one well and expects to begin production in the second quarter of 2000. As of December 31, 1999, the property had proved developed reserves of 653 barrels and 218 MMcf of oil and natural gas, respectively, net to the Partnership's interest.
Markets and Competition
The Partnership's focus is to maximize the production from its 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 the Partnership's operations. However, the oil and natural gas industry is intensely competitive and the Partnership does 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
The production and development operations of the Partnership 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 restoration of properties upon which wells are drilled; and the plugging and abandoning of wells. The
Partnership's production and development operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled, the levels of production, and the unitization or pooling of oil and natural gas properties.
The Partnership presently has interests in, or rights to, offshore leases located in federal waters. Federal leases are administered by the Minerals Management Service, 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 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
The Partnership's 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, the Partnership maintains broad insurance coverage with respect to potential losses resulting from these operating hazards.
MAJOR ENCUMBRANCES
Substantially all of the Partnership's assets are pledged as collateral to secure obligations under its existing credit facility. In addition, certain of the Partnership's 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 the Partnership's credit facilities, see Item 8, Financial Statements and Supplementary Data, Notes 6 and 9, which are incorporated herein by reference.
ENVIRONMENTAL
A description of the Partnership's environmental matters is included in Item 8, Financial Statements and Supplementary Data, Note 9, which is incorporated herein by reference.
EMPLOYEES
Employees of El Paso Energy, through the General Partner, perform all administrative and operational activities of the Partnership under a management agreement. Therefore, the Partnership had no direct employees at December 31, 1999. The Partnership reimburses the General Partner for all reasonable general and administrative expenses and other reasonable expenses incurred by the General Partner and its affiliates for, or on behalf of, the Partnership, including, but not limited to, expenses incurred by the General Partner under this management agreement.
ITEM 2.
ITEM 2. PROPERTIES
A description of the Partnership's properties is included in Item 1, Business, and is incorporated herein by reference.
The Partnership is of the opinion that it has satisfactory title to the properties owned and used in its 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 such property, or the interests therein, or the use of such properties in its businesses. The Partnership believes that its physical properties are adequate and suitable for the conduct of its business in the future.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Financial Statements and Supplementary Data, Note 9, which is incorporated herein by reference.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S UNITS AND RELATED UNITHOLDER MATTERS
The Partnership's common and preference units are traded on the NYSE under the symbol "EPN" for common units and "EPN.P" for preference units. As of March 15, 2000, there were approximately 525 and 59 holders of record of common and preference units, respectively.
The following table reflects the high and low sales prices for common and preference units, for the periods indicated, based on the daily composite listing of stock transactions for the NYSE and cash distributions declared during those periods.
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(1) Common units of the Partnership began trading on August 6, 1998. Therefore, no market price information exists before that date.
In January 2000, the Partnership declared a quarterly distribution of $0.525 per common unit and $0.275 per preference unit payable on February 15, 2000, to unitholders of record on January 31, 2000.
CASH DISTRIBUTIONS
The Partnership makes quarterly distributions of 100 percent of its available cash, as defined in the partnership agreement, to its unitholders and to the General Partner. Available cash consists generally of all the cash receipts of the Partnership plus reductions in reserves less all of its cash disbursements and net additions to reserves. The General Partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to provide for the proper conduct of the Partnership. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and the General Partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any agreement or obligation of the Partnership.
The distribution of available cash for each calendar quarter is subject to the preferential rights of the preference unitholders to receive a minimum quarterly distribution of $0.275 per unit for such quarter, plus arrearages for prior quarters before any distribution is made to holders of common units. The holders of common units and the General Partner are not entitled to arrearages of minimum quarterly distributions.
Distributions by the Partnership are effectively made 98 percent to limited unitholders and 2 percent to the General Partner, subject to the payment of incentive distributions to the General Partner if certain target cash distribution levels to unitholders are achieved. As an incentive, the General Partner's interest in the portion of quarterly cash distributions in excess of $0.325 per unit and less than or equal to $0.375 per unit is increased to 15 percent. For quarterly cash distributions over $0.375 per unit but less than or equal to $0.425 per unit, the General Partner receives 25 percent of such incremental amount, and for all quarterly cash distributions in excess of $0.425 per unit, the General Partner receives 50 percent of the incremental amount. For the year ended December 31, 1999, the Partnership paid the General Partner incentive distributions totaling $12.1 million and paid an incentive distribution of $3.2 million in February 2000.
CONVERSION OF PREFERENCE UNITS INTO COMMON UNITS
In May 1998, the Partnership notified the holders of its 18,075,000 then outstanding preference units of their right to convert their preference units into an equal number of common units within a 90-day period. On August 5, 1998, the first conversion period expired and holders of 17,058,094 preference units, representing approximately 94 percent of the preference units then outstanding, elected to convert their preference units to common units. Upon completion of the preference period, as defined in the partnership agreement, the common units, including the 6,291,894 common units held by the General Partner, became the primary listed security on the NYSE under the symbol "EPN." The preference units began trading as the Partnership's secondary listed security on the NYSE under the symbol "EPN.P." The Partnership reallocated partners' capital to reflect this conversion of preference units into common units.
In May 1999, the Partnership notified the holders of its 1,016,906 then outstanding preference units of their second opportunity to submit their preference units for conversion into common units. During that second 90-day conversion period, 727,207 preference units were converted into common units.
Until they are redeemed, the remaining preference units retain their distribution preferences over the common units; that is, holders of such preference units will be paid up to the minimum quarterly distribution of $0.275 per unit before any quarterly distributions are made to the common unitholders or the General Partner. However, holders of preference units will not receive any distributions in excess of the minimum quarterly distribution of $0.275 per unit. Only holders of common units and the General Partner will be eligible to receive any such excess distributions.
In accordance with the partnership agreement, holders of the remaining preference units will have a final 90-day opportunity to convert their preference units into common units beginning in May 2000. Thereafter, any remaining preference units will be subject to redemption for an amount equal to the unrecovered capital, as defined in the partnership agreement, of such preference units plus minimum quarterly distribution arrearages, if any.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
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(1) The increase in 1996 reflects the completion and commencement of production on the Garden Banks Blocks 72 and 117 properties in 1996 and the Viosca Knoll Block 817 property in December 1995. (2)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. (3)Reflects the Partnership's adoption, in 1999, of a different accounting method for allocating partnership income to the General Partner and the preference and common unitholders. See Item 8, Financial Statements and Supplementary Data, Note 1, for further information.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
Over the past three years, the Partnership's business activities have changed as a result of acquisitions and transactions designed to enhance its ability to compete effectively. In 1997, the Partnership acquired a 25.67 percent indirect ownership interest in each of Nautilus and Manta Ray Offshore. In 1998, the Partnership constructed a multi-purpose platform located in East Cameron Block 373 and acquired a 100 percent working interest in the Ewing Bank 958 Unit. In 1999, the Partnership acquired an additional 49 percent ownership interest in Viosca Knoll, and an additional indirect ownership interest in HIOS, East Breaks and UTOS bringing its overall ownership interest in Viosca Knoll to 99 percent and in HIOS, East Breaks and UTOS to 50 percent. Also, in 1999, the Partnership placed the Allegheny system in service and entered into an agreement to farm out its working interest in the Ewing Bank 958 Unit to a subsidiary of El Paso Energy. The Partnership will continue to look for opportunities in the future to enhance both its earnings and its ability to make cash distributions to its unitholders.
In addition, the Partnership issued $175 million of notes in May 1999 and amended its credit facility in September 1999 to extend its maturity to May 2002.
In March 2000, the Partnership acquired the El Paso Intrastate-Alabama pipeline system, or EPIA, a natural gas gathering system in the coal seam producing regions of Alabama for total consideration of $24.5 million from a subsidiary of El Paso Energy. This acquisition represents the first purchase of an onshore system by the Partnership.
The Partnership's business activities are segregated into two segments: Gathering, Transportation, and Platform Services, and Oil and Natural Gas Production. This structure reflects management's current view of the Partnership's activities and all historical periods have been presented on the basis of the current segment presentation. Each of the Partnership's segments is a strategic business unit that offers different services or products, and the Partnership manages each of these segments separately as they require different technology and marketing strategies. The analysis presented below is based on earnings before interest and taxes, or EBIT. In addition, because of the significance of the Partnership's equity investments on its segment results, earnings from these investees is included in operating revenues by segment.
In January 2000, an anchor from a submersible drilling rig in tow damaged a section of the Poseidon system north of the Partnership's 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 the Partnership's Ship Shoal 332 platform, and resulted in the shutdown of the system and certain surrounding facilities in which the Partnership has ownership interests. Poseidon estimates the cost to repair the damaged pipeline and clean up the crude oil released into the Gulf to be approximately $15 million, and has placed the rig's owner on notice for liability and expenses due to the incident. Management is currently evaluating the effects of the incident on the Partnership's operations and expects to complete its evaluation in the first quarter of 2000.
RESULTS OF OPERATIONS
To the extent possible, results of operations have been reclassified to conform to the current business segment presentation, although such results are not necessarily 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 sales and expenses which are eliminated in consolidation. For a further discussion of the individual segments, see Item 8, Financial Statements and Supplementary Data, Note 12, which is incorporated herein by reference.
The following table presents EBIT by segment and in total for each of the three years ended December 31:
EBIT year-to-year variances are discussed in the segment results below.
GATHERING, TRANSPORTATION, AND PLATFORM SERVICES
YEAR ENDED DECEMBER 31, 1999 COMPARED TO YEAR ENDED DECEMBER 31, 1998
Operating revenues for the year ended December 31, 1999, were approximately $25.0 million higher than 1998. The increase in gathering and transportation revenues is due to including the revenues of Viosca Knoll as a result of the acquisition of an additional 49 percent ownership interest in, and the consolidation of, Viosca Knoll beginning in June 1999. These revenues were included as equity investment earnings prior to June 1999. The increase in gathering and transportation revenues was also a result of the commencement of operations of the Allegheny system 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 is a result of new production processed at the Partnership's Garden Banks 72 platform, and a full year's operations at the East Cameron 373 platform. The increase in equity investment earnings is attributable to increased throughput on the Poseidon, Manta Ray Offshore and Nautilus systems, partially offset by lower volumes on the HIOS, UTOS, and Stingray systems and the impact of consolidating Viosca Knoll.
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 certain 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.
Other income for the year ended December 31, 1999, was approximately $9.7 million higher than 1998. The increase is primarily a result of a gain on the sale of a portion of the Partnership's interest in Deepwater Holdings.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Operating revenues for the year ended December 31, 1998, were approximately $3.1 million lower than 1997. The decrease in gathering and transportation revenues is primarily a result of the cessation of production in May 1997 from the Partnership's well connected to the Ewing Bank system, lower throughput on the Green Canyon system, and the contribution of a significant portion of the Manta Ray Offshore system to Manta Ray Offshore in January 1997, resulting in revenue from these assets being included in equity in earnings for the entire year ended December 31, 1998 as compared with a portion of the year ended December 31, 1997. In addition, throughput volumes for the Partnership's wholly-owned gathering systems decreased approximately eight percent for the year ended December 31, 1998, as compared with the same period in 1997. The increase in platform services revenues is a result of placing the Partnership's East Cameron 373 platform in service in April 1998 offset by lower oil and natural gas volumes processed on the Partnership's Viosca Knoll 817 platform caused by capacity constraints of the downstream transporter, which were alleviated during the third quarter of 1998. The decrease in equity investments earnings primarily reflects decreases related to nonrecurring start-up costs, changes in prior period estimates and a decrease in equity ownership of the Nautilus and Manta Ray Offshore systems along with increased maintenance costs related to the Stingray and HIOS systems. Total natural gas throughput volumes for the Partnership's equity investments increased from 1997 to 1998 primarily as a result of increased throughput on the Viosca Knoll, UTOS, Nautilus and Manta Ray Offshore systems. Oil volumes on the Poseidon system increased from 1997 to 1998. In addition, equity investment earnings were adversely impacted by two tropical storms and Hurricane Georges passing through the Gulf during the third quarter of 1998.
Operating expenses for the year ended December 31, 1998, were approximately $12.1 million lower than 1997 primarily as a result of the Partnership's abandonment of certain of its flowlines in 1997. In addition, depreciation was lower in 1998 as a result of these abandonments, partially offset by higher operating expenses on the East Cameron Block 373 platform placed in service in the second quarter of 1998.
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 is attributable to lower oil production due to natural depletion and lower realized oil prices, offset by higher natural gas sales from the acquisition of an additional 25 percent 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, along with a slight increase in realized natural gas prices.
Operating expenses for the year ended December 31, 1999, were approximately $4.2 million lower than 1998, primarily as a result of decreased depletion and abandonment rates related to the Partnership's oil and natural gas wells, along with cost reductions associated with the operations of those properties.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Total operating revenues for the year ended December 31, 1998, were approximately $26.7 million lower than 1997. The decrease is attributable to substantially lower realized oil and natural gas prices, decreased
production as a result of two tropical storms and Hurricane Georges passing through the Gulf during the third quarter of 1998, normal production declines from the Partnership's oil and natural gas properties and the lack of acceptable markets due to capacity constraints downstream of the Viosca Knoll system. These capacity constraints were alleviated during the third quarter of 1998.
Operating expenses for the year ended December 31, 1998, were approximately $26.2 million less than 1997 primarily as a result of lower depletion due to decreased production, and the establishment of an allowance on a long-term receivable related to the prepayment of demand charge obligations of certain leases in 1997.
INTEREST AND DEBT EXPENSE
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 attributable to higher average debt outstanding due to acquisitions and construction during 1999 and higher average 1999 interest rates primarily as a result of the issuance of $175 million of Senior Subordinated Notes in May of 1999 and an increase in the average interest rate on the Partnership's variable rate debt.
YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997
Interest and debt expense, net of capitalized interest, for the year ended December 31, 1998, was approximately $6.1 million higher than 1997. The increase is attributed to higher average debt outstanding in 1998 related to construction activities and higher average interest rates.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was approximately $50.8 million for the year ended December 31, 1999, compared to approximately $25.7 million for the same period in 1998. The increase in cash from operations resulted primarily from higher net income and increased distributed earnings from the Partnership's equity investments.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was approximately $67.1 million for the year ended December 31, 1999, due to the Partnership's acquisition of additional interests in the HIOS, UTOS, and East Breaks systems, the acquisition of an additional 49 percent interest in the Viosca Knoll system and increased capital expenditures, primarily related to the construction of the Allegheny system. Investing activities also included the receipt of proceeds from the sale of a portion of the Partnership's interest in Deepwater Holdings and a capital distribution from Deepwater Holdings.
The Partnership's planned capital and investment expenditures for 2000 of approximately $125 million are primarily intended for expansion of unregulated operations, pipeline systems and production activities.
Funding for capital expenditures, acquisitions, and other investing expenditures 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 $17.5 million for the year ended December 31, 1999. During 1999, the Partnership received approximately $168.9 million in net proceeds from the issuance of Subordinated Notes and borrowings under its revolving credit facilities, and partially repaid
amounts outstanding under its credit facility. The Partnership also made distributions to its unitholders and General Partner.
Future funding for long-term debt retirements, distributions, and other financing expenditures 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
The Partnership relies on cash generated from internal operations as its primary source of liquidity, supplemented by its available credit facility. The availability of borrowings under the Partnership's credit agreement is subject to specified conditions, which management believes the Partnership currently meets. These conditions include compliance with the financial covenants and 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 the Partnership's financing arrangements, see Item 8, Financial Statements and Supplementary Data, Notes 6 and 9, which are incorporated herein by reference.
COMMITMENTS AND CONTINGENCIES
See Item 8, Financial Statements and Supplementary Data, Note 9, for a discussion of the Partnership's commitments and contingencies which is incorporated herein by reference.
At December 31, 1999, the Partnership had capital and investment commitments of approximately $34 million which are expected to be funded through internally generated funds and/or incremental borrowings. The Partnership's other planned capital and investment projects are discretionary in nature, with no substantial commitments made in advance of the actual expenditures.
OTHER
In January 2000, El Paso Energy announced it had entered into an agreement to merge with The Coastal Corporation. Coastal is the parent Company of ANR Pipeline Company, which is the Partnership's joint venture partner in Deepwater Holdings, an equity investment of the Partnership. The merger is subject to certain conditions, including approval of the stockholders of both companies and receipt of certain required government approvals. If the merger is completed, ANR will become an affiliate of the Partnership.
YEAR 2000
To coordinate the phases of the Partnership's Year 2000 project, the Partnership established a project team to work with El Paso Energy's Year 2000 executive steering committee. The phases of the project were: (i) awareness; (ii) assessment; (iii) remediation; (iv) testing; (v) implementation of the necessary modifications, and (vi) contingency planning. The goal of the Year 2000 project was to ensure that all of the critical systems and processes under the Partnership's direct control remained functional. As of December 31, 1999, the Partnership had substantially completed the above phases for all critical systems. While the Year 2000 rollover date has passed with no apparent disruptions experienced by the Partnership's systems and processes, it remains possible that third parties, including the Partnership's joint ventures and equity investments, may have experienced disruptions which have not yet manifested any impact on the Partnership, but could in the future. Accordingly, the Partnership is prepared to implement any contingency plans should a disruption occur.
While the total cost of the Partnership's Year 2000 project continues to be accumulated, the Partnership does not expect to incur any remaining material costs in 2000. As of December 31, 1999, the Partnership has incurred expenses of less than $1 million.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE." To the extent that any reader of the above Year 2000 Readiness Disclosure is other than an investor or potential investor in the
Partnership's -- or an affiliate's -- equity or debt securities, this disclosure is made for the SOLE PURPOSE of communicating or disclosing information aimed at correcting, helping to correct and/or avoiding Year 2000 failures.
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 which is incorporated herein by reference.
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 the Partnership 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
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 certain information about the holder's nationality, citizenship or other related status. If the record holder fails to furnish the information or if the general partner determines, on the basis of the information furnished by the holder in response to the request, that the cancellation or forfeiture of any property in which we have an interest may occur, the general partner may be substituted as a 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, under certain circumstances 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 ENERGY AND ITS AFFILIATES MAY HAVE CONFLICTS OF INTEREST WITH THE PARTNERSHIP
Although El Paso Energy controls our general partner and has financial incentives to protect its investment by encouraging our success, and it plans to use us when practical as its principal offshore gathering and transportation growth vehicle in the Gulf, El Paso Energy is not contractually bound to do so and may reconsider at any time, without notice. Additionally, El Paso Energy is not required to pursue a business strategy that will favor our business opportunities over the business opportunities of El Paso Energy or any of its affiliates (or any other competitor of ours acquired by El Paso Energy, including Coastal, with whom El Paso Energy is pursuing a merger). In fact, El Paso Energy may have financial motives to favor our competitors. El Paso Energy and its subsidiaries (many of which are wholly owned) operate in some of the same lines of business and in some of the same geographic areas in which we operate. El Paso Energy continues to own pipelines and related facilities located in the Gulf, including the Bluewater and Seahawk Shoreline systems. The extent we continue to acquire interests in oil and natural gas properties may compete with the exploration, development and marketing activities conducted by El Paso Energy.
The Partnership 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 the Partnership. Officers of the 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 the Partnership on the other. In addition, we have, and we expect to enter into other, significant business relationships with El Paso Energy, our general partner and their affiliates in which conflicts of interest could arise.
RISKS RELATED TO OUR LEGAL STRUCTURE
THE INTERRUPTION OF DISTRIBUTIONS TO THE PARTNERSHIP FROM OUR SUBSIDIARIES AND JOINT VENTURES MAY AFFECT OUR ABILITY TO MAKE CASH DISTRIBUTIONS
The Partnership is a holding company. As such, our primary assets are the capital stock and other equity interests in our subsidiaries and joint ventures. Consequently, our ability to make cash distributions depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us. Distributions from our joint ventures are subject to the discretion of their respective management committees. In addition, several of our joint ventures have credit arrangements that contain various restrictive covenants. Among other things, those covenants limit or restrict such joint ventures' ability to make distributions to us under certain circumstances. Further, the joint venture charter documents typically vest in their management committees sole discretion regarding distributions. We cannot assure you that our joint ventures will continue to make distributions to us at current levels or at all.
Moreover, pursuant to some of the joint venture credit arrangements, we have agreed to return a limited amount of the distributions made to us by the applicable joint venture if certain conditions exist.
WE CANNOT CAUSE OUR JOINT VENTURES TO TAKE OR NOT TO TAKE CERTAIN ACTIONS UNLESS SOME OR ALL OF OUR JOINT VENTURE PARTNERS AGREE
Due to the nature of joint ventures, each partner (including the Partnership) 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 the Partnership.
WE DO NOT HAVE THE SAME FLEXIBILITY AS OTHER TYPES OF ORGANIZATIONS TO ACCUMULATE CASH AND EQUITY TO PROTECT AGAINST ILLIQUIDITY IN THE FUTURE
Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our common units will decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.
CHANGES OF CONTROL OF OUR GENERAL PARTNER MAY ADVERSELY AFFECT YOU
Our results of operations and, thus, our ability to make cash distributions could be adversely affected if there is a change in management resulting from a change of control of our general partner. Although such an action would result in a change of control under the terms of the indenture governing our publicly-held debt, El Paso Energy is not restricted from selling the general partner or any of the common units it holds. As a result, El Paso Energy could sell control of our general partner to another company with less familiarity and experience with our businesses and with different business philosophies and objectives. We cannot assure you that any such acquiror would continue our current business strategy, or even a business strategy economically compatible with our current business strategy.
RISKS RELATED TO OUR BUSINESS
OUR INDUSTRY IS HIGHLY COMPETITIVE
The hydrocarbons that we transport, gather, and process 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, 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, 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, transportation, and processing operations in the Gulf 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.
If there are reductions in the average volume of the natural gas we transport, 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.
THE USE OF DERIVATIVE FINANCIAL INSTRUMENTS COULD RESULT IN FINANCIAL LOSSES
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 Risks and Item 8, Financial Statements and Supplementary Data, Note 9.
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 9.
OUR ACTIVITIES INVOLVE OPERATING HAZARDS AND UNINSURED RISKS
While we maintain insurance against certain of 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.
OUR INDEBTEDNESS MAY RESTRICT OUR ABILITY TO OPERATE
We must comply with various affirmative and negative covenants related to our senior subordinated notes and our revolving credit facility. 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 agreement or under arrangements that we believe have terms and conditions at least as restrictive as those contained in our existing credit agreements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership may utilize derivative financial instruments for purposes other than trading to manage its exposure to movements in interest rates and commodity prices. In accordance with procedures established by the General Partner, management monitors current economic conditions and evaluates its expectations of future prices and interest rates when making decisions with respect to risk management.
INTEREST RATE RISK
The Partnership utilizes both fixed and variable rate long-term debt, and is exposed to market risk due to the floating interest rate under its credit facility. Under the Partnership's credit facility, as amended, the remaining principal and the final interest payment are due in May 2002. As of December 31, 1999, the Partnership's credit facility had a principal balance of $290 million at an average floating interest rate of 9.0% per annum. A one percent increase in interest rates would result in a $2.9 million annual increase in interest expense on the existing principal balance. The Partnership is exposed to similar risk under the various joint venture credit facilities and loan agreements.
COMMODITY PRICE RISK
The Partnership hedges a portion of its oil and natural gas production to reduce its exposure to fluctuations in the market prices of oil and natural gas, and to meet certain requirements under its revolving credit facility. The Partnership uses commodity price swap transactions whereby monthly settlements are based on differences between the prices specified in the commodity price swap agreements and the settlement prices of certain futures contracts quoted on the New York Mercantile Exchange, or NYMEX, or certain other indices. The Partnership settles the commodity price swap transactions by paying the negative difference or receiving the positive difference between the applicable settlement price and the price specified in the contract. The commodity price swap transactions used by the Partnership 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 the Partnership's price swap contracts is derived from the counterparty to the transaction, typically a major financial institution. Management does not require collateral and does not anticipate non-performance by this counterparty, which does not transact a sufficient volume of transactions with the Partnership 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. If the Partnership had settled its open natural gas hedging positions as of December 31, 1999 and 1998, based on the applicable settlement prices of the NYMEX futures contracts, the Partnership would have recognized a loss of approximately $3.8 million and $2.6 million, respectively. For the year ended December 31, 1999, the Partnership recorded a net loss of $2.3 million related to its hedging activities.
At December 31, 1999, the Partnership had two outstanding natural gas sales swap transactions for the calendar year 2000. Under one of the swaps, the Partnership will receive a fixed price of $1.6686 on 10,000 MMbtu/d, and pay the monthly natural gas futures contract price on NYMEX. The second swap provides for similar pricing terms, notional quantity and contract period. On January 18, 2000, the Partnership fixed the contract price under the swap whereby it will receive $1.8050 on 10,000 MMbtu/d from February through December 2000 and pay the monthly NYMEX settlement price.
ITEM 8.
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)
The accompanying notes are an integral part of these financial statements. EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
The accompanying notes are an integral part of these financial statements.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
The accompanying notes are an integral part of these financial statements.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL (IN THOUSANDS)
- --------------- (1) El Paso Energy Partners Company owns a one percent general partner interest in the Partnership.
The accompanying notes are an integral part of these financial statements.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
The Partnership is a publicly held Delaware master limited partnership that provides energy services, including natural gas and oil gathering, transportation, midstream and other related services, primarily in the Gulf. In August 1998, El Paso Energy acquired, through a series of transactions, DeepTech International Inc., or DeepTech. As a result, El Paso Energy acquired 100 percent of the General Partner's interest in the Partnership and an overall 27.3 percent effective interest in the Partnership. In June 1999, additional common units were issued to El Paso Energy in connection with the sale of a portion of the Viosca Knoll system to the Partnership, bringing El Paso Energy's overall effective interest in the Partnership to 34.5 percent. See Note 2 for further discussion of this transaction.
In December 1999, the Partnership changed its name to El Paso Energy Partners, L.P. At that date, the Partnership's trading symbol for common units was changed to "EPN" and the symbol for preference units was changed to "EPN.P" on the NYSE.
Basis of Presentation and Principles of Consolidation
The consolidated financial statements of the Partnership include the accounts of all majority-owned, controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. Investments in companies where the Partnership has the ability to exert significant influence over, but not control operating and financial policies, are accounted for using the equity method. The General Partner's approximate one percent non-managing interest in certain subsidiaries of the Partnership represents the minority interest in the Partnership's consolidated financial statements. The consolidated financial statements for previous periods include certain reclassifications that were made to conform to the current year presentation. Such reclassifications have no impact on reported net income or partners' capital.
Cash and cash equivalents
Short-term investments with an original maturity of three months or less are considered cash equivalents.
Property and equipment
Gathering pipelines, platforms and related facilities are recorded at cost and are depreciated on a straight-line basis over the estimated useful lives of the assets which generally range from 5 to 30 years for the gathering pipelines and from 18 to 30 years for platforms and related facilities. Repair and maintenance costs are expensed as incurred, while additions, improvements and replacements are capitalized.
The Partnership accounts for its oil and natural gas exploration and production activities using the successful efforts method of accounting. Under this method, costs of successful exploratory wells, development wells and acquisitions of mineral leasehold interests are capitalized. Production, exploratory dry hole and other exploration costs, including geological and geophysical costs and delay rentals, are expensed as incurred. Unproved properties are assessed periodically and any impairment in value is recognized currently as depreciation, depletion and amortization expense.
Depreciation, depletion, and amortization of the capitalized costs of producing oil and natural gas properties, consisting principally of tangible and intangible costs incurred in developing a property and costs of productive leasehold interests, are computed on the unit-of-production method. Unit-of-production rates are based on annual estimates of remaining proved developed reserves or proved reserves, as appropriate, for each property.
Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining depreciation provisions for gathering pipelines, platforms, related facilities
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
and oil and natural gas properties. Other noncurrent liabilities at December 31, 1999 and 1998, include approximately $11.7 million and $10.7 million, respectively, of accrued dismantlement, restoration and abandonment costs.
Retirements, sales and disposals of assets are recorded by eliminating the related costs and accumulated depreciation, depletion and amortization of the disposed assets with any resulting gain or loss reflected in income.
The Partnership evaluates impairment of its regulated and non-regulated property, plant, and equipment in accordance with Statement of Financial Accounting Standards, or SFAS, No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
Capitalization of interest
Interest and other financing costs are capitalized in connection with construction and drilling activities as part of the cost of the asset and amortized over the related asset's estimated useful life.
Debt issue costs
Debt issue costs are capitalized and amortized over the life of the related indebtedness. Any unamortized debt issue costs are expensed at the time the related indebtedness is repaid or otherwise terminated.
Revenue recognition
Revenue from pipeline transportation of hydrocarbons is recognized upon receipt of the hydrocarbons into the pipeline systems. Revenue from oil and natural gas sales is recognized upon delivery in the period of production. Revenue from platform access and processing services is recognized in the period the services are provided.
Income taxes
The Partnership and its subsidiaries, other than Tarpon Transmission Company, or Tarpon, are not taxable entities. However, the taxable income or loss resulting from the operations of the Partnership will ultimately be included in the federal and state income tax returns of the general and limited partners. Individual partners will have different investment bases depending upon the timing and price of acquisition of partnership units. Further, each partner's tax accounting, which is partially dependent upon his/her tax position, may differ from the accounting followed in the consolidated financial statements. Accordingly, there could be significant differences between each individual partner's tax basis and his/her share of the net assets reported in the consolidated financial statements. The Partnership does not have access to information about each individual partner's tax attributes in the Partnership, and the aggregate tax bases cannot be readily determined.
Tarpon is subject to federal corporate income taxation. The Partnership utilizes SFAS No. 109, Accounting for Income Taxes, to account for income taxes. The income tax benefit reported in the Partnership's Consolidated Statements of Operations for the years ending 1999, 1998, and 1997, relates solely to Tarpon's book loss at the effective statutory income tax rate for the respective period since no material differences exist between book and taxable income. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities at each year end. Resulting tax liabilities, if any, are borne by the Partnership.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Actual results are likely to differ from those estimates.
Unit Options
The Partnership applies the provisions of Accounting Principles Board Opinion No. 25 and related interpretations in accounting for its unit compensation plans, including options issued to employees of the General Partner. Accordingly, compensation expense is not recognized for unit options unless the options were granted at an exercise price lower than the market price of common units on the grant date. The Partnership uses fixed and variable plan accounting for its fixed and variable compensation plans, respectively.
Environmental Costs
Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated.
Price Risk Management Activities
The Partnership enters into commodity price swap instruments for non-trading purposes to manage its exposure to price fluctuations on anticipated natural gas and crude oil sales transactions. To qualify for hedge accounting, the transactions must reduce the price risk of the underlying hedged items, be designated as hedges at inception, and result in cash flows and financial impacts which are inversely correlated to the position being hedged. If correlation ceases to exist, hedge accounting is terminated and mark-to-market accounting is applied. Gains and losses resulting from hedging activities and the termination of any hedging instruments are initially deferred and included as an increase or decrease to oil and natural gas sales in the period in which the hedged production is sold.
Income (Loss) Per Unit
Basic income per unit excludes dilution and is computed by dividing net income (loss) attributable to the limited partners by the weighted average number of units outstanding during the period. Dilutive income per unit reflects potential dilution and is computed by dividing net income (loss) attributable to the limited partners by the weighted average number of units outstanding during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been issued.
Basic income (loss) per unit and diluted income (loss) per unit for the Partnership are the same for the years ended December 31, 1999, 1998 and 1997, as no dilutive potential units were outstanding during the respective periods. The Partnership includes the outstanding preference units in the basic and diluted net income (loss) per unit calculation as if the preference units had been converted into common units.
Cumulative Effect of Accounting Change
In the fourth quarter of 1999, the Partnership changed its method of allocating net income to its partners' capital accounts from a method where income was allocated based on percentage ownership and proportionate share of cash distributions, to a method whereby income is allocated to the partners based upon the change from period to period in their respective claims on the Partnership's book value capital. Management believes EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
that the new income allocation method is preferable because it more accurately reflects the income allocation provisions called for under the partnership agreement and the resulting partners' capital accounts are more reflective of a partner's claim on the Partnership's book value capital at each period end. This change in accounting had no impact on the Partnership's consolidated net income (loss) or its consolidated total partners' capital for any period presented. Furthermore, the change is not expected to impact the declaration of future cash distributions or affect an individual partner's tax basis in the Partnership.
The impact of this change in accounting has been recorded as a cumulative effect adjustment in the Partnership's income allocation for the year ended December 31, 1999. The effect of adopting this change in accounting, excluding the cumulative adjustment, was to reduce basic and diluted net income per limited partner unit by $0.33 for the year ended December 31, 1999. In addition, had this change been in effect for the years ended December 31, 1998 and 1997, the loss allocated to limited partners would have been $11.2 million and $5.0 million, respectively, and basic and diluted net loss per limited partner unit would have been $0.46 and $0.20, respectively.
Recent Pronouncements
In June 1998, SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, was issued by the Financial Accounting Standards Board to establish accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This pronouncement requires that an entity classify all derivatives as either assets or liabilities and measure those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as (i) a hedge of the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment, (ii) a hedge of the exposure to variable cash flows of a forecasted transaction, or (iii) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security or a foreign-currency-denominated forecasted transaction. The accounting for the changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. This standard was amended by Statement of Financial Accounting Standards No. 137 issued in June 1999. The amendment defers the effective date to fiscal years beginning after June 15, 2000. The Partnership is currently evaluating the effects of this pronouncement.
2. ACQUISITIONS
Deepwater Holdings
In June 1999, the Partnership acquired additional interests in the HIOS, East Breaks and UTOS systems through its acquisition of Natoco, Inc. and Naloco, Inc. for $51 million. As part of the transaction, the Partnership also assumed operations of the Stingray system, the Stingray Offshore separation facility and the West Cameron dehydration facility in November 1999. The purchase price exceeded the book value of net assets acquired by approximately $48 million. This excess cost is being amortized on a straight line basis over the estimated lives of the acquired assets, which approximates 30 years.
In September 1999, the Partnership and ANR Pipeline Company, or ANR, formed Deepwater Holdings to reorganize their interests in certain joint ventures. In the transaction, the Partnership and ANR contributed their interests in certain pipeline systems and facilities to Deepwater Holdings. Following this reorganization, Deepwater Holdings owns 100 percent of the East Breaks, HIOS, UTOS, and Stingray systems, along with the West Cameron dehydration facility. In exchange for its contribution, the Partnership received a 59.66 percent interest in Deepwater Holdings. The Partnership subsequently sold a 9.66 percent members' interest in Deepwater Holdings to ANR for $26.1 million to effect a 50/50 ownership position. The Partnership realized a $10.1 million gain associated with the sale. In conjunction with the transaction, the Partnership will become the full operator of the UTOS, HIOS, and East Breaks systems no later than July 1, 2000.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In connection with its formation, Deepwater Holdings established a $175 million credit facility to retire existing debt of Stingray and Western Gulf, the parent company of East Breaks and HIOS, to fund a one-time distribution of $20 million to each of the equity partners, to provide funds for the remaining construction costs of the East Breaks system and any future system expansions, and to provide for other working capital needs of Deepwater Holdings.
The following selected unaudited pro forma information represents the Partnership's consolidated results of operations on a pro forma basis for the years ended December 31, 1999 and 1998, assuming the transactions relating to Deepwater Holdings discussed above had occurred on January 1, 1998:
In January 2000, El Paso Energy announced it had entered into an agreement to merge with The Coastal Corporation. Coastal is the parent Company of ANR Pipeline Company, which is the Partnership's joint venture partner in Deepwater Holdings, an equity investment of the Partnership. The merger is subject to certain conditions, including approval of the stockholders of both companies and receipt of certain required government approvals. If the merger is completed, ANR will become an affiliate of the Partnership.
Viosca Knoll
In June 1999, the Partnership acquired an additional 49 percent interest in Viosca Knoll from El Paso Field Services Company, or EPFS. In the transaction, EPFS contributed $33.4 million to Viosca Knoll and then sold a 49 percent interest to the Partnership in exchange for $19.9 million and 2,661,870 common units. The Partnership paid closing costs of $0.9 million in connection with the acquisition and the General Partner contributed $0.6 million to the Partnership in order to maintain its one percent capital account balance. In addition, during the six months commencing June 1, 2000, the Partnership has an option to acquire EPFS's remaining one percent interest in profits and capital of Viosca Knoll for $1.6 million plus any additional distributions which would have been paid, accrued, or been in arrears if the Partnership had acquired the remaining one percent of Viosca Knoll on June 1, 1999. As a result of the acquisition, the Partnership began consolidating Viosca Knoll effective June 1999.
The acquisition was accounted for as a purchase and the purchase price was assigned to the assets and liabilities acquired based upon their estimated fair value as of the acquisition date. These fair value allocations are preliminary and may be revised after the completion of an independent appraisal. The following is summary information related to the acquisition (in thousands):
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following selected unaudited pro forma information represents the Partnership's consolidated results of operations on a pro forma basis for the years ended December 31, 1999 and 1998, assuming the Viosca Knoll acquisition had occurred on January 1, 1998:
Ewing Bank 958 Unit
In October 1998, the Partnership purchased a 100 percent working interest in the Ewing Bank 958 Unit from a wholly-owned indirect subsidiary of El Paso Energy for $12.2 million. In December 1998, the Partnership completed the drilling of a successful delineation well on the Ewing Bank 958 Unit. In October 1999, the Partnership executed an agreement with El Paso Production Company, or El Paso Production, a subsidiary of El Paso Energy, to farm out its working interest in the Ewing Bank 958 Unit at which time the Partnership's investment in the unit totaled $32.8 million. Under the terms of the farmout agreement, the Partnership increased its overriding royalty interest in the Ewing Bank 958 Unit from 5.3 percent to 7.4 percent convertible, at its option, into a 30 percent undivided working interest once El Paso Production has recouped the costs associated with its drilling and completion activities on the unit. El Paso Production began drilling on the Ewing Bank 958 Unit in November 1999.
El Paso Intrastate-Alabama Pipeline System
In March 2000, the Partnership acquired the El Paso Intrastate-Alabama pipeline system, or EPIA, a natural gas gathering system in the coal seam producing regions of Alabama for total consideration of $24.5 million from a subsidiary of El Paso Energy. This acquisition represents the first purchase of an onshore system by the Partnership.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. EQUITY INVESTMENTS
The Partnership holds equity investments which are accounted for using the equity method of accounting. Summarized financial information for these investments is as follows:
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999 (IN THOUSANDS)
- ---------------
(a) These investees are indirect investees of the Partnership. However, because the Partnership believes separate data on each of these investees is more meaningful, results have been reflected separately. (b) Deepwater Holdings was formed in September 1999 and owns 100 percent of HIOS, East Breaks, UTOS, Stingray, and West Cameron Dehy. Prior to September 1999, the Partnership had a direct ownership interest in each of these investees. Information included herein is for the periods and dates in which the Partnership had a direct investment in these entities. (c) Information on Viosca Knoll is through May 31, 1999. On June 1, 1999, the Partnership began consolidating Viosca Knoll as a result of acquiring an additional 49 percent ownership interest therein. (d) Adjustments result primarily from purchase price adjustments recorded by the Partnership in accordance with Accounting Principles Board Opinion No. 16, "Business Combinations", except for $0.9 million on Stingray which results from changes in prior period estimates of reserves for uncollectible revenues.
As of December 31, 1999, the carrying amount of the Partnership's equity investments exceeded the underlying equity in net assets by approximately $84 million. This difference is being amortized on a straight-line basis over the estimated lives of the underlying net assets of the respective investee.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998 (IN THOUSANDS)
- ---------------
(a) These investments are indirect investees of the Partnership. However, because the Partnership believes the separate data for each of these investees is more meaningful, results have been reflected separately. (b) Adjustments result from purchase price adjustments recorded by the Partnership in accordance with APB Opinion No. 16 except for the $0.7 million reduction on Nautilus related to a revision of the allowance for funds used during construction, or AFUDC, which represents the estimated costs, during the construction period, of funds used for construction purposes.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31, 1997 (IN THOUSANDS)
- ---------------
(a) These investments are indirect investees of the Partnership. However, because the Partnership believes the separate data for each of these investees is more meaningful, results have been reflected separately. (b) Includes approximately $6.4 million related to AFUDC. Recognition of this allowance is appropriate because it constitutes an actual cost of construction. For regulated activities, Nautilus is permitted to earn a return on and recover AFUDC through its inclusion in the rate base and the provision for depreciation. The rate employed for the equity component of AFUDC is the equity rate of return stated in Nautilus' FERC tariff. (c) Adjustments result from purchase price adjustments recorded by the Partnership in accordance with APB Opinion No. 16 except for the $3.1 million for Nautilus which represents additional net earnings specifically allocated to the Partnership related to the assets contributed by the Partnership to the Manta Ray Offshore joint venture. Pursuant to the terms of the joint venture agreement, the Partnership managed the operations of the assets contributed to Manta Ray Offshore and was permitted to retain approximately 100% of the net earnings from such assets during the construction phase of the expansion to the Manta Ray Offshore system (January 17, 1997 through December 31, 1997). Effective January 1, 1998, Manta Ray Offshore began allocating all net earnings in accordance with the ownership percentages of the joint venture.
4. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
In June 1998, Tatham Offshore, Inc., or Tatham Offshore, an affiliate of the Partnership prior to the acquisition of DeepTech by El Paso Energy, canceled its reversionary interests in certain oil and natural gas properties owned by the Partnership. In addition, in August 1998, Tatham Offshore transferred its remaining
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
assets located in the Gulf to the Partnership in exchange for 7,500 shares of its Series B Senior Preferred Stock, then owned by the Partnership.
5. REGULATORY MATTERS
FERC has jurisdiction over the Nautilus, Stingray, HIOS and UTOS systems with respect to transportation of natural gas, rates and charges, construction of new facilities, extension or abandonment of service and facilities, accounts and records, depreciation and amortization policies, and certain other matters.
On December 1, 1998, Stingray filed for a general rate increase at the FERC. Pursuant to an order issued by FERC on December 30, 1998, the increased rates became effective June 1, 1999, subject to refund. A hearing on the merits of Stingray's filing was held in December 1999. Management does not expect the outcome of these proceedings to have a material effect on the rates charged by Stingray under its FERC order. Each of Nautilus, HIOS, and UTOS are currently operating under agreements with their respective customers that provide for rates that have been approved by the FERC. The Partnership's remaining systems are gathering facilities and, as such, are not currently subject to rate and certificate regulation by FERC.
All of the Partnership's pipelines are subject to FERC's administration of the "equal access" requirements of the Outer Continental Shelf Lands Act. In addition, the Poseidon and Allegheny systems are subject to regulation under the Hazardous Liquid Pipeline Safety Act. Operations in offshore federal waters are regulated by the Department of the Interior.
6. FINANCING TRANSACTIONS
Senior Subordinated Notes
In May 1999, the Partnership entered into an indenture with Chase Bank of Texas, under which it issued $175 million in aggregate principal amount of Senior Subordinated Notes, or the Subordinated Notes. The Partnership capitalized $6.1 million of debt issue costs related to the issuance and registration of the Subordinated Notes. The Subordinated Notes bear interest at a rate of 10 3/8% per annum, payable semi-annually, on June 1 and December 1, and mature on June 1, 2009. The Partnership's subsidiaries have guaranteed its obligations under the Subordinated Notes. In addition, the Partnership could be required to repurchase the Subordinated Notes if certain circumstances relating to change of control or asset disposition exist. None of such circumstances currently exist at the Partnership. The terms of the Subordinated Notes include, among other things, certain financial tests and covenants, all of which the Partnership currently meets. In September 1999, the Partnership exchanged all of its Subordinated Notes for registered debt securities with identical terms. The proceeds from the Senior Subordinated Notes were used to fund the cost requirements of the Viosca Knoll acquisition and to pay down the Partnership's revolving credit facility.
Partnership Credit Facility
The Partnership has a revolving credit facility with a syndicate of commercial banks to provide up to $375 million of available credit, subject to certain limitations. As of December 31, 1999 and 1998, the Partnership had $290 million and $338 million, respectively, outstanding under this facility and $56.5 million available at December 31, 1999. At the election of the Partnership, interest under this facility is determined by reference to the reserve-adjusted London Interbank Offer Rate, or LIBOR, the prime rate, or the 90-day average certificate of deposit rate. The interest rate at December 31, 1999 and 1998 was 9.0 percent and 7.1 percent per annum, respectively. A commitment fee is charged on the unused and available portion of the credit facility. This fee varies between 0.25% and 0.5% per annum and was 0.5% per annum at December 31, 1999. The Partnership's credit facility matures in May 2002; is guaranteed by the Partnership and each of the Partnership's subsidiaries; and is collateralized by the management agreement with the Partnership, substantially all of the assets of the Partnership, the General Partner's one percent general partner
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
interest in the Partnership and its approximate one percent nonmanaging interest in certain subsidiaries of the Partnership. The Partnership may borrow money under this facility for capital expenditures, investment and working capital purposes as well as to make capital distributions under certain circumstances.
During the years ended December 31, 1999, 1998 and 1997, the Partnership capitalized approximately $1.8 million, $1.1 million, and $1.7 million, respectively, of interest expense in connection with construction projects and drilling activities during such periods. At December 31, 1999 and 1998, the unamortized portion of debt issue costs totaled approximately $11.0 million and $2.5 million, respectively.
7. PARTNERS' CAPITAL
General
As of December 31, 1999, the Partnership had 26,739,065 common units and 289,699 preference units outstanding. Preference units and common units totaling 18,075,000 are owned by the public, representing a 65.5 percent effective limited partner interest in the Partnership. El Paso Energy has an effective 34.5 percent interest in the Partnership, consisting of a 32.5 percent limited partner interest in the form of 8,953,764 common units, a one percent general partner interest in the Partnership and an approximate one percent non-managing interest in certain subsidiaries of the Partnership.
Conversion of Preference Units into Common Units
In May 1998, and again in May 1999, the Partnership notified its preference unitholders of their opportunity to convert their preference units into an equal number of common units. To date, 98 percent of the preference units, which were outstanding in May 1998, have been converted into common units consisting of 17,058,094 converted in 1998 and 727,207 converted in 1999. The holders of the remaining 289,699 preference units will have a final 90-day conversion opportunity beginning in May 2000. These units will retain their distribution preferences over the common units; that is, holders of such preference units will be paid up to the minimum quarterly distribution of $0.275 per unit plus any distribution in arrears before any quarterly distributions are made to the common unitholders or the General Partner. Following this conversion period, remaining preference units may, under certain circumstances, be subject to mandatory redemption for an amount equal to the unrecovered capital, as defined in the partnership agreement, of such preference units plus minimum quarterly distribution arrearages, if any. The Partnership reallocated the partners' capital accounts in the conversion period to reflect these conversions of preference units into common units.
Cash Distributions
The Partnership makes quarterly distributions of 100 percent of its available cash, as defined in the partnership agreement, to its unitholders and to the General Partner. Available cash consists generally of all the cash receipts of the Partnership plus reductions in reserves less all of its cash disbursements and net additions to reserves. The General Partner has broad discretion to establish cash reserves that it determines are necessary or appropriate to provide for the proper conduct of the Partnership. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and the General Partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of any agreement or obligation of the Partnership.
The distribution of available cash for each calendar quarter is subject to the preferential rights of the preference unitholders to receive a minimum quarterly distribution of $0.275 per unit for such quarter, plus arrearages for prior quarters before any distribution is made to holders of common units. Cash distributions on common units and to the General Partner are discretionary in nature and are not entitled to arrearages of minimum quarterly distributions.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Distributions by the Partnership are effectively made 98 percent to limited unitholders and 2 percent to the General Partner, subject to the payment of incentive distributions to the General Partner if certain target cash distribution levels to unitholders are achieved. As an incentive, the General Partner's interest in the portion of quarterly cash distributions in excess of $0.325 per unit and less than or equal to $0.375 per unit is increased to 15 percent. For quarterly cash distributions over $0.375 per unit but less than or equal to $0.425 per unit, the General Partner receives 25 percent of such incremental amount, and for all quarterly cash distributions in excess of $0.425 per unit, the General Partner receives 50 percent of the incremental amount. For the year ended December 31, 1999, 1998, and 1997, the Partnership paid the General Partner incentive distributions totaling $12.1 million, $11.1 million, and $3.9 million, respectively, and paid an incentive distribution of $3.2 million in February 2000.
Unit Rights Appreciation Plan
Prior to 1997, the Partnership maintained a unit rights appreciation plan under which employees of the General Partner were granted a right to market appreciation on the Partnership's common and/or preference units. A total of 1,200,000 of these rights were granted to officers and employees of the General Partner and its affiliates. For the year ended December 31, 1997, expenses incurred under the plan totaled $3.7 million. As a result of the "change in control" occurring upon the closing of El Paso Energy's acquisition of DeepTech in 1998, these rights fully vested and the holders elected to be paid $8.6 million, the amount equal to the difference between the grant price of these rights and the average of the high and the low sales price of the common units on the date of exercise. Upon the exercise of all of the rights outstanding, this plan was terminated. The Partnership replaced this plan with the Omnibus Plan discussed below.
Option Plans
In August 1998, the Partnership adopted the 1998 Omnibus Compensation Plan, or the Omnibus Plan, to provide the General Partner with the ability to issue unit options to attract and retain the services of knowledgeable officers and key management personnel. Unit options to purchase a maximum of 3 million common units of the Partnership may be issued pursuant to the Omnibus Plan. Unit options granted pursuant to the Omnibus Plan are not immediately exercisable. One-half of the unit options are considered vested and exercisable one year after the date of grant and the remaining one-half of the unit options are considered vested and exercisable one year after the first anniversary of the date of grant. The unit options expire ten years from such grant date, but shall be subject to earlier termination under certain circumstances.
In August 1998, the Partnership adopted the 1998 Unit Option Plan for Non-Employee Directors, or the Director Plan, to provide the General Partner with the ability to issue unit options to attract and retain the services of knowledgeable directors. Unit options to purchase a maximum of 100,000 common units of the Partnership may be issued pursuant to the Director Plan. Each unit option granted under the Director Plan vests immediately at the date of grant and the grant expires ten years from such date. The expiration date is subject to earlier termination if the director ceases to be a director of the General Partner, in which case the unit options expire 36 months after such date. In the case of death, the unit options expire 12 months after such date.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes activity under the Omnibus Plan and Director Plan as of and for the years ended December 31, 1999 and 1998. No unit options were granted by the Partnership prior to August 1998.
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(1) Includes the accelerated vesting of approximately 215,000 unit options under certain employment agreements as a result of a defined change in control within El Paso Energy following its merger with Sonat Inc.
The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions:
The Black-Scholes weighted average fair value of options granted during 1999 and 1998 was $3.14 and $4.59 per option, respectively.
Options outstanding as of December 31, 1999, are summarized below:
Had the compensation expense for the Partnership's stock-based compensation plans been determined applying the provisions of SFAS No. 123, Accounting for Stock Based Compensation, using the Black-Scholes
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
weighted average fair value of options granted, the Partnership's net income allocated to the limited partners and net income per common unit for 1999 and 1998 would approximate the pro forma amounts below:
The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts.
8. RELATED PARTY TRANSACTIONS
Transactions with related parties and affiliates for each of the three years ended December 31, are as follows:
Revenues received from related parties
The Partnership has agreed to sell all of its oil and natural gas production to an affiliate of the Partnership, on a month to month basis. The agreement provides fees equal to 2 percent of the sales value of crude oil and condensate and $0.015 per dekatherm of natural gas for selling the Partnership's production. During the years ended December 31, 1999, 1998 and 1997, oil and natural gas sales to the affiliate totaled approximately $29.8 million, $31.2 million, and $57.8 million, respectively.
For the years ended December 31, 1998 and 1997, the Partnership received approximately $1.1 million and $2.0 million, respectively, from Tatham Offshore as platform access and processing fees related to the Partnership's platform located in Viosca Knoll Block 817.
For the five months ended May 31, 1999, and the years ended December 31, 1998 and 1997, the Partnership charged Viosca Knoll approximately $1.0 million, $2.4 million and $2.1 million, respectively, for expenses and platform access fees related to the Viosca Knoll Block 817 platform. The Partnership began consolidating Viosca Knoll following its acquisition of an additional 49 percent ownership interest in June 1999. As a result, charges after this period were eliminated in consolidation.
Expenses paid to related parties
Management Fees. Substantially all of the individuals who perform the day-to-day financial, administrative, accounting and operational functions for the Partnership, as well as those who are responsible for the direction and control of the Partnership, are currently employed by El Paso Energy. Pursuant to a management agreement between El Paso Energy and the General Partner, a management fee is charged to the General Partner which is intended to approximate the amount of resources allocated by El Paso Energy in
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
providing various operational, financial, accounting and administrative services on behalf of the General Partner and the Partnership. The management agreement expires on June 30, 2002, and may be terminated thereafter upon 90 days notice by either party. Pursuant to the terms of the partnership agreement, the General Partner is entitled to reimbursement of all reasonable general and administrative expenses and other reasonable expenses incurred by the General Partner and its affiliates for, or on behalf of, the Partnership including, but not limited to, amounts payable by the General Partner to El Paso Energy under its management agreement.
Prior to its acquisition by El Paso Energy in August 1998, DeepTech had a similar management agreement with the General Partner. Management fees were based on a percentage of DeepTech's overhead. However, in connection with El Paso Energy's acquisition of the General Partner, the General Partner amended its management agreement to provide for a monthly management fee of $775,000. The General Partner charged the Partnership $9.3 million, $9.3 million, and $8.1 million pursuant to its management agreement for the years ended December 31, 1999, 1998 and 1997, respectively.
The General Partner is also required to reimburse El Paso Energy, and its predecessor, DeepTech for certain tax liabilities resulting from, among other things, additional taxable income allocated to the General Partner due to (i) the issuance of additional preference units and (ii) the investment of such proceeds in additional acquisitions or construction projects. During the years ended December 31, 1998 and 1997, the General Partner charged the Partnership approximately $0.5 million and $0.7 million, respectively, to compensate DeepTech for additional taxable income allocated to the General Partner.
During the five months ended May 31, 1999, and the years ended December 31, 1998 and 1997, Viosca Knoll charged the Partnership approximately $0.8 million, $1.9 million and $3.9 million, respectively, for transportation services related to transporting production from the Viosca Knoll Block 817 lease.
Garden Banks. During the years ended December 31, 1999, 1998 and 1997, Poseidon charged the Partnership approximately $0.9 million, $1.4 million and $2.0 million, respectively, for transportation services related to transporting production from the Garden Banks Block 72 and 117 leases.
Other. Pursuant to a management agreement between Viosca Knoll and the Partnership, the Partnership charges Viosca Knoll a base fee of $100,000 annually in exchange for the Partnership providing financial, accounting and administrative services on behalf of Viosca Knoll. For the five months ended May 31, 1999, and each of the years ended December 31, 1998 and 1997, the Partnership charged Viosca Knoll approximately $42,000, $100,000 and $100,000, respectively, in accordance with this management agreement. In addition, for the years ended December 31, 1998 and 1997, Viosca Knoll reimbursed the Partnership approximately $152,000 and $47,000, respectively, for costs incurred by the Partnership in connection with the acquisition and installation of a booster compressor on the Partnership's Viosca Knoll Block 817 platform.
For the years ended December 31, 1999, 1998 and 1997, the Partnership charged Manta Ray Offshore a management fee of approximately $0.5 million, $1.3 million, and $0.3 million, respectively, pursuant to its management and operations agreements.
Pursuant to former non-employee director compensation arrangements, the Partnership was obligated to pay each non-employee director 2 1/2 percent of the general partners' incentive distribution as a profit participation fee. During the years ended December 31, 1998 and 1997, the Partnership paid three non-employee directors of the Partnership a total of $0.6 million and $0.3 million, respectively, as a profit participation fee. As a result of El Paso Energy's acquisition of Deep Tech, these non-employee directors resigned and these arrangements were terminated.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Farmout
In October 1999, the Partnership executed an agreement with El Paso Production Company, or El Paso Production, a subsidiary of El Paso Energy, to farm out its working interest in the Ewing Bank 958 Unit. Under the terms of the farmout agreement, the Partnership increased its overriding royalty interest in the Ewing Bank 958 Unit from 5.3 to 7.4 percent convertible, at its option, into a 30 percent undivided working interest once El Paso Production has recouped the costs associated with its drilling and completion activities on the unit. El Paso Production began drilling on the Ewing Bank 958 Unit in November 1999.
Other
In 1997, Tatham Offshore announced its intent to reserve its remaining costs associated with certain of its wells as a result of production problems. Accordingly, the Partnership recorded a charge totaling $21.2 million in the consolidated statements of operations. This charge consisted of approximately $6.4 million to reserve the Partnership's investment in certain gathering facilities and other assets associated with these properties, approximately $3.8 million to fully accrue its abandonment obligations associated with the gathering facilities serving these properties, approximately $9.1 million to reserve its noncurrent receivable related to the prepayment of the demand charge obligations under certain agreements, and approximately $1.9 million to accrue certain abandonment obligations associated with its Viosca Knoll and Garden Banks properties. During 1998, the Partnership abandoned its Ewing Bank flowlines at a cost of $2.9 million and recorded a credit to impairment, abandonment and other of $1.1 million, which represented the excess of the accrued costs over the actual costs incurred associated with the abandonment of the flowlines.
During the year ended December 31, 1997, the Partnership was charged approximately $3.4 million by Sedco Forex Division of Schlumberger Technology Corporation for contract drilling services rendered by the semisubmersible drilling rig, the FPS Laffit Pincay, at its Garden Banks Block 117 project. The FPS Laffit Pincay was owned by an affiliate of DeepTech and managed by Sedco Forex during such period.
In addition, see Note 2 relating to the formation of Deepwater Holdings and the Partnership's acquisition of an additional ownership interest in Viosca Knoll.
9. COMMITMENTS AND CONTINGENCIES
Credit Facilities
Deepwater Holdings and Poseidon are parties to a credit agreement under which they have an outstanding obligation that may restrict the payment of distributions to their respective owners.
In connection with its formation, Deepwater Holdings assumed Western Gulf Holdings' obligations under its $100 million revolving credit facility entered into in February 1999, and amended and restated that facility to, among other things, increase the commitment amount to $175 million. Deepwater Holdings' ability to borrow money under this credit facility is subject to certain customary terms and conditions, including borrowing base limitations. The credit facility is collateralized by substantially all of the material contracts and agreements of East Breaks, West Cameron Dehy and Deepwater Holdings, including Deepwater Holdings' ownership in Stingray, UTOS, West Cameron Dehy, and Western Gulf, and its subsidiaries HIOS and East Breaks, and matures in February 2004. As of March 15, 2000, Deepwater Holdings had $147 million outstanding under its credit facility bearing interest at an average floating rate of 7.2 percent and had $13.2 million available.
Poseidon has a revolving credit facility, as amended, with a syndicate of commercial banks to provide up to $150.0 million for the construction and expansion of the Poseidon system and for other working capital needs. Poseidon's ability to borrow money under this facility is subject to certain customary terms and conditions, including borrowing base limitations. The facility is collateralized by a substantial portion of
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Poseidon's assets and matures on April 30, 2001. As of December 31, 1999, 1998 and 1997, Poseidon had $150.0 million, $131.0 million and $120.5 million, respectively, outstanding under its credit facility bearing interest at an average floating rate of 7.8 percent, 6.9 percent, and 7.2 percent per annum, respectively.
In June 1999, the Viosca Knoll revolving credit facility was repaid and cancelled concurrent with the closing of the Partnership's acquisition of the additional interest in Viosca Knoll.
The Stingray credit facility was paid off and cancelled concurrent with the formation of Deepwater Holdings. Funds from the Deepwater Holdings credit facility were used to pay off the Stingray credit facility.
Borrowings under the above mentioned credit facilities may be used for capital expenditures, investment and working capital purposes, as well as to make capital distributions in certain circumstances.
Hedging Activities
The Partnership hedges a portion of its oil and natural gas production to reduce its exposure to fluctuations in market prices of oil and natural gas and to meet certain requirements under its revolving credit facility. The Partnership uses commodity price swap instruments whereby monthly settlements are based on differences between the prices specified in the commodity price swap agreement and the settlement prices of certain futures contracts quoted on the NYMEX or certain other indices. The Partnership settles the commodity price swap transactions by paying the negative difference or receiving the positive difference between the applicable settlement price and the price specified in the contract. The commodity price swap transactions used by the Partnership differ from futures contracts in that there is no contractual obligation which requires or allows for the future delivery of the product. The credit risk from the Partnership's price swap contracts is derived from the counterparty to the transaction, typically a major financial institution. Management does not require collateral and does not anticipate non-performance by this counterparty, which does not transact a sufficient volume of transactions with the Partnership to create a significant concentration of credit risk. Gains or losses on 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, 1999, 1998 and 1997, the Partnership recorded a net (gain) loss of $2.3 million, $(2.5) million and $6.3 million, respectively, from such activities.
As of December 31, 1998, the Partnership maintained two natural gas sales swap transactions, one covering the calendar year 1999, and one covering the calendar year 2000. Each of these swaps carried a notional amount of 10,000 MMbtu/d. Under these transactions, the Partnership receives a fixed price and pays a variable price based on the monthly natural gas futures contract settlement price as set by NYMEX. In January 1999, the Partnership elected to change the term of its 1999 swap to calendar year 2000. In January 1999 and 2000, under the terms of this transaction, the Partnership fixed its contract price at $1.6686 per MMbtu and $1.8050 per MMbtu, respectively, for each swap.
If the Partnership had settled its open natural gas hedging positions as of December 31, 1999 and 1998 based on the applicable settlement prices of the NYMEX futures contracts, the Partnership would have recognized a loss of approximately $3.8 million and $2.6 million, respectively.
In February 2000, the Partnership also entered into a swap transaction whereby the Partnership will receive $24.05 per barrel of oil in exchange for the monthly Oil Futures Contract NYMEX settlement for 12,000 barrels per month for February and March 2000 and 15,000 barrels per month for each month in the following three quarters of calendar year 2000.
Legal Proceedings
The Partnership is a defendant in a lawsuit filed by Transco in the 157th Judicial District Court, Harris County, Texas on August 30, 1996. Transco alleges that, pursuant to a platform lease agreement entered into on June 28, 1994, it had the right to expand its facilities and operations on the offshore platform by connecting EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
additional pipeline receiving and appurtenant facilities. Management denied Transco's request to expand its facilities and operations because the lease agreement does not provide for such expansion, and because Transco's activities would have interfered with the Manta Ray Offshore system and the Partnership's existing and planned activities on the platform. The case is set for trial on April 3, 2000. It is the opinion of management that adequate defenses exist and that the final disposition of this suit will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Partnership.
In January 2000, an anchor from a submersible drilling rig in tow damaged a section of the Poseidon system north of the Partnership's Ship Shoal 332 platform. The accident resulted in the release of approximately 2,200 barrels of crude oil in the waters surrounding the system, caused damage to the Partnership's Ship Shoal 332 platform, and resulted in the shutdown of the system and certain surrounding facilities in which the Partnership has ownership interests. Poseidon estimates the cost to repair the damaged pipeline and clean up the crude oil released into the Gulf to be approximately $15 million, and has placed the rig's owner on notice for liability and expenses due to the incident. Management is currently evaluating the effects of the accident on the Partnership's operations and expects to complete its evaluation in the first quarter of 2000.
The Partnership, along with several subsidiaries of El Paso Energy, have been named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, the complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Indian lands, thereby depriving the United States Government of royalties. The Partnership believes the complaint to be without merit.
The Partnership, along with several subsidiaries of El Paso Energy, have been named defendants in a class action suit, Quinque Operating Company v. Gas Pipelines. The plaintiff alleges that the defendants have mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands. This suit is similar to the action brought by Jack Grynberg on behalf of the United States Government. The Partnership believes the complaint to be without merit.
The Partnership is also a named defendant in numerous lawsuits and a named party in numerous governmental proceedings arising in the ordinary course of its business.
Other
In July 1999, the Partnership entered into a contract with MODEC International, L.L.C. for the design, construction, fabrication and installation of the hull, tendons, pilings and production risers for a tension-leg platform, or TLP, to be used as part of the Ewing Bank 958 Unit development. Upon the farm out of the Ewing Bank 958 Unit, the Partnership suspended the construction of the TLP and is currently discussing its use at a different location with several major producers. The Partnership expects to incur up to $10 million of costs related to the TLP which is expected to be recovered through the Ewing Bank 958 Unit farmout agreement. As a result, management does not expect the ultimate resolution of this matter to have a material adverse effect on the Partnership's consolidated financial position, results of operations or cash flows.
While the outcome of the matters discussed above cannot be predicted with certainty, management currently does not expect the ultimate resolution of these matters to have a material adverse effect on the Partnership's consolidated financial position, results of operations, or cash flows.
Environmental
The Partnership is subject to extensive federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations require the Partnership to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
It is possible that new information or future developments could require the Partnership to reassess its potential exposure related to environmental matters. The Partnership may incur significant costs and liabilities in order to comply with existing 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 current or discontinued operations, could result in substantial costs and liabilities in the future. As such information becomes available, or other relevant developments occur, related accrual amounts will be adjusted accordingly. While there are still uncertainties relating to the ultimate costs which may be incurred, based upon the Partnership's evaluation and experience to date, the Partnership believes the recorded reserves are adequate.
10. SUPPLEMENTAL DISCLOSURES TO THE STATEMENT OF CASH FLOWS
Cash paid for interest, net of amounts capitalized, and taxes were as follows:
Noncash investing and financing activities excluded from the statement of cash flows were as follows:
11. MAJOR CUSTOMERS
As discussed in Note 8, the Partnership sells all of its oil and natural gas production to an affiliated company. The percentage of gathering, transportation and platform services revenue from major customers was as follows:
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. BUSINESS SEGMENT INFORMATION:
The Partnership's business activities are segregated into two segments: Gathering, Transportation, and Platform Services, and Oil and Natural Gas Production. This structure reflects management's current view of the Partnership's activities and all historical periods have been presented on the basis of the current segment presentation. Each of the Partnership's segments is a strategic business unit that offers different services or products. The Partnership manages each of these segments separately as each requires different technology and marketing strategies. Management of the Partnership measures performance based on an asset's or investment's ability to generate cash flow to the Partnership, or performance cash flow. Performance cash flow is earnings before interest, taxes, and depreciation, depletion, and amortization, plus cash distributions from equity investments less earnings attributable to equity investments and, as appropriate, other non-cash items. This measurement is used as a supplemental financial measurement in the evaluation of the Partnership's business and should not be considered as an alternative to EBIT, as an indicator of our operating performance or as an alternative to cash flows from operating activities as a measure of liquidity. In addition, it may not be a comparable measurement among different companies. Performance cash flow is presented here to provide additional information about the Partnership. The accounting policies of the individual segments are the same as those of the Partnership, as a whole, as described in Note 1. The following table summarizes certain financial information for each business segment:
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(1) Represents income or assets not associated with segment activities.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED):
Oil and natural gas reserves
The following table represents the Partnership's net interest in estimated quantities of developed and undeveloped reserves of crude oil, condensate and natural gas and changes in such quantities at fiscal year end 1999, 1998 and 1997. Estimates of the Partnership's reserves at December 31, 1999, 1998 and 1997, have been made by the independent engineering consulting firm, Netherland, Sewell & Associates, Inc. Net proved reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserve volumes that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserve volumes that are expected to be recovered from new wells on undrilled acreage or from existing wells where a significant expenditure is required for recompletion.
Estimates of reserve quantities are based on sound geological and engineering principles, but, by their very nature, are still estimates that are subject to substantial upward or downward revision as additional information regarding producing fields and technology becomes available.
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(1) Includes the Partnership's net interest in proved reserves on Garden Banks Block 73 totaling 653 barrels of oil and 218 MMcf of natural gas.
The following are estimates of the Partnership's total proved developed and proved undeveloped reserves of oil and natural gas by producing property as of December 31, 1999.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In general, estimates of economically recoverable oil and natural gas reserves and of the future net revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the subject properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs and future plugging and abandonment costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The meaningfulness of such estimates is highly dependent upon the assumptions upon which they are based.
Estimates with respect to proved undeveloped reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than upon actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. A significant portion of the Partnership's reserves is based upon volumetric calculations.
Future net cash flows
The standardized measure of discounted future net cash flows relating to the Partnership's proved oil and natural gas reserves is calculated and presented in accordance with SFAS No. 69, Disclosures About Oil and Gas Producing Activities. Accordingly, future cash inflows were determined by applying year-end oil and natural gas prices, as adjusted for hedging and other fixed price contracts in effect, to the Partnership's estimated share of future production from proved oil and natural gas reserves. The average prices utilized in the calculation of the standardized measure of discounted future net cash flows at December 31, 1999, were $21.04 per barrel of oil and $2.18 per Mcf of gas. Actual future prices and costs may be materially higher or lower. Future production and development costs were computed by applying year-end costs to future years. As the Partnership is not a taxable entity, no future income taxes were provided. A prescribed 10 percent discount factor was applied to the future net cash flows.
In the Partnership's opinion, this standardized measure is not a representative measure of fair market value, and the standardized measure presented for the Partnership's proved oil and natural gas reserves is not representative of the reserve value. The standardized measure is intended only to assist financial statement users in making comparisons between companies.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Estimated future net cash flows for proved developed and proved undeveloped reserves as of December 31, 1999, are as follows:
The following are the principal sources of change in the standardized measure (in thousands):
Development, Exploration, and Acquisition Expenditures
The following table details certain information regarding costs incurred in the Partnership's development, exploration, and acquisition activities during the years ended December 31:
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Capitalized Costs
Capitalized costs relating to the Partnership's natural gas and oil producing activities and related accumulated depreciation, depletion and amortization were as follows as of December 31:
14. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
As discussed in Note 1, the Partnership changed its method for allocating net income among the partners. The change was adopted during the fourth quarter of 1999, effective as of January 1, 1999. The information that follows for the year 1999 has been restated to reflect this change as if it were in effect for all periods presented.
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
REPORT OF INDEPENDENT ACCOUNTANTS
To the Unitholders of El Paso Energy Partners, L.P. and the Board of Directors and Stockholder of El Paso Energy Partners Company, as General Partner
In our opinion, the accompanying consolidated balance sheets and related consolidated statements of operations, of cash flows and of partners' capital present fairly, in all material respects, the financial position of El Paso Energy Partners, L.P. and its subsidiaries (the "Partnership") at December 31, 1999 and 1998 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Partnership's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
As disclosed in Note 1 to the consolidated financial statements, the Partnership changed its method for allocating net income to its partners in 1999.
[PRICEWATERHOUSECOOPERS]
Houston, Texas March 24, 2000
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
GENERAL
The General Partner and the Partnership utilize the employees of and management services provided by El Paso Energy under a management agreement. The Partnership reimburses the General Partner for reasonable general and administrative expenses, and other reasonable expenses, incurred by the General Partner and its affiliates, for or on behalf of the Partnership.
DIRECTORS AND EXECUTIVE OFFICERS OF THE GENERAL PARTNER
The following table sets forth certain information as of March 24, 2000, regarding the executive officers and directors of the General Partner. Each executive officer of the General Partner serves the Partnership in the same office or offices each such officer holds with the General Partner. Directors are elected annually by the General Partner's sole stockholder, El Paso Energy Partners Holding Company, and hold office until their successors are elected and qualified. Each executive officer named in the following table has been elected to serve until his successor is duly appointed or elected or until his earlier removal or resignation from office.
In November 1999, the Partnership's Board of Directors accepted the resignation of its chief executive officer, Grant E. Sims. Robert G. Phillips, current president of EPFS and a director of the Partnership, assumed the additional role of chief executive officer of the Partnership.
There is no family relationship among any of the executive officers or directors of the General Partner, and, other than described herein, no arrangement or understanding exists between any executive officer and any other person pursuant to which he was or is to be selected as an officer.
Mr. Wise has served as Director and Chairman of the Board of the General Partner since August 1998. He has served as Chief Executive Officer of El Paso Energy since January 1990 and was Chairman of El Paso Energy's board of directors from January 1994 until October 1999. Mr. Wise was President of El Paso Energy from January 1990 to April 1996 and from July 1998 to present. He served as President and Chief Operating Officer of El Paso Energy from April 1989 to December 1989. From March 1987 until April 1989, Mr. Wise was an Executive Vice President of El Paso Energy and a Senior Vice President of El Paso Energy from January 1984 to February 1987. Mr. Wise is a member of the Board of Directors of Battle Mountain Gold Company and is Chairman of the Board of El Paso Tennessee Pipeline Co.
Mr. Phillips has served as a Director of the General Partner since August 1998. He has served as Chief Executive Officer of the Partnership and the General Partner since November 1999. He served as Executive
Vice President from August 1998 to October 1999. Mr. Phillips has served as President of El Paso Field Services Company since June 1997. He served as President of El Paso Energy Resources Company from December 1996 to June 1997, President of El Paso Field Services Company from April 1996 to December 1996 and Senior Vice President of El Paso Energy from September 1995 to April 1996. For more than five years prior thereto, Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc.
Mr. Lytal has served as a Director of the General Partner since August 1994 and as President of the Partnership and the General Partner since July 1995. He served as Senior Vice President of the Partnership and the General Partner from August 1994 to June 1995. Prior to joining the Partnership, Mr. Lytal was Vice President -- Business Development for American Pipeline Company from December 1992 to August 1994. From March 1991 to December 1992, Mr. Lytal served as Vice President -- Business Development for United Gas Pipe Line Company. Prior to March 1991, Mr. Lytal has served in various capacities in the oil and gas exploration and production and gas pipeline industries with Texas Oil and Gas, Inc. and American Pipeline Company.
Mr. Austin has served as a Director of the General Partner and as Executive Vice President of the Partnership and the General Partner since August 1998. Mr. Austin has served as an Executive Vice President and Chief Financial Officer of El Paso Energy since May 1995 and as the Chief Financial Officer of El Paso Energy since April 1992. He served as the Senior Vice President of El Paso Energy from April 1992 to April 1995. He served as the Vice President, Planning and Treasurer of Burlington Resources Inc. from November 1990 to March 1992 and Assistant Vice President, Planning of Burlington from January 1989 to October 1990. Mr. Austin is a member of the Board of Directors of El Paso Tennessee Pipeline Co.
Mr. Forman has served as the Chief Financial Officer of the Partnership and the General Partner since January 1992 and served as a Director of the General Partner from July 1992 to August 1998. Prior to 1982, Mr. Forman served as Vice President of the Natural Gas Pipeline Group of Manufacturers Hanover Trust Company.
Mr. Leland has served as Vice President and Controller of the Partnership and the General Partner since August 1998 and as Vice President of El Paso Field Services Company since September 1997. He served as Director of Business Development for El Paso Field Services Company from September 1994 to September 1997. For more than five years prior thereto, Mr. Leland served in various capacities in the finance and accounting functions of El Paso Energy.
Mr. Bracy has served as a Director of the General Partner since October 1998. From January 1993 to August 1997, Mr. Bracy served as a Director, Executive Vice President and Chief Financial Officer of NorAm Energy Corp. and as Executive Vice President and Chief Financial Officer of NorAm from December 1991 to January 1993. For seven years prior thereto, Mr. Bracy served in various executive capacities with NorAm. From December 1977 to October 1984, Mr. Bracy held various executive financial positions with El Paso Energy. Prior to December 1977, Mr. Bracy served in various capacities with The Chase Manhattan Bank. Mr. Bracy is a member of the Board of Directors of Itron, Inc.
Mr. Church has served as a Director of the General Partner since January 1999. From January 1994 to December 1998, Mr. Church served as the Senior Vice President, Transmission, Engineering and Environmental for a subsidiary of Duke Energy Corporation, Texas Eastern Transmission Company. For thirty-two years prior thereto, Mr. Church served in various engineering and operating capacities with Texas Eastern Transmission Company, Panhandle Eastern Corporation and Transwestern Pipeline Company. Mr. Church is a past member of the Board of Directors of Southern Gas Association and Boys and Girls Country of Houston, Inc. (Chairman).
Mr. Wallop has served as a Director of the General Partner since August 1998 and as a Director of El Paso Energy since January 1995. Since January 1995, Mr. Wallop has served as President for Frontiers of Freedom Foundation, a political foundation. For eighteen years prior to 1995, Mr. Wallop was a member of the United States Senate. He is a member of the Board of Directors of Hubbell Inc. and Sheridan State Bank.
COMPENSATION OF DIRECTORS
Directors of the General Partner are entitled to reimbursement for their reasonable out-of-pocket expenses in connection with their travel to and from, and attendance at, meetings of the Board or committees thereof.
In August 1998, the Partnership adopted the 1998 Unit Option Plan for Non-Employee Directors, or the Director Plan, to provide the General Partner with the ability to issue unit options to attract and retain the services of knowledgeable directors. Unit options to purchase a maximum of 100,000 common units of the Partnership may be issued pursuant to the Director Plan. Under the Director Plan, each non-employee director receives a grant of 1,500 unit options upon initial election to the Board of Directors and an annual unit option grant of 1,000 upon each re-election to the Board of Directors. Each unit option that is granted will vest immediately at the date of grant and will expire ten years from such date, but will be subject to earlier termination in the event that such non-employee director ceases to be a director of the General Partner for any reason, in which case the unit options expire 36 months after such date except in the case of death, in which case the unit options expire 12 months after such date. The Director Plan is administered by a management committee consisting of the Chairman of the Board and such other senior officers of the General Partner or its affiliates as the Chairman of the Board may designate.
In 1998, the Partnership granted 3,000 unit options to purchase an equal number of common units with an exercise price of $27.185 per unit and, in 1999, granted 4,500 unit options to purchase an equal number of common units with an exercise price of $21.575 under this plan. At March 15, 2000, all those options remain outstanding.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Partnership does not currently have a compensation committee or another committee performing similar functions, and all such matters which would be considered by such committee are acted upon by the full Board of Directors of the General Partner. Employees of El Paso Energy, through the General Partner, are the individuals who work on Partnership matters. Accordingly, the only compensation addressed by the Partnership relates to issuance of unit options under the various Partnership option plans. The Board of Directors administers and interprets the Omnibus Plan. See Item 11, Executive Compensation.
AUDIT AND CONFLICTS COMMITTEE
Currently, Messrs. Bracy and Church, who are neither officers nor employees of the General Partner nor any of its affiliates, serve as the Audit and Conflicts Committee of the Board of Directors of the General Partner and of the Partnership. The Audit and Conflicts Committee provides two primary services. First, it advises the Board of Directors in matters regarding the system of internal controls and the annual independent audit, and reviews policies and practices of the General Partner and the Partnership. Second, the Audit and Conflicts Committee, at the request of the General Partner, reviews specific matters as to which the General Partner believes there may be a conflict of interest in order to determine if the resolution of such conflict proposed by the General Partner is fair and reasonable to the Partnership. Except as otherwise required by the rules of the NYSE, the Audit and Conflicts Committee only reviews matters concerning potential conflicts of interest at the request of the General Partner, which has sole discretion to determine which matters to submit for review. Any such matters approved by a majority vote of the Audit and Conflicts Committee will be conclusively deemed (i) to be fair and reasonable to the Partnership, (ii) approved by all limited partners of the Partnership and (iii) not a breach by the General Partner of any duties it may owe to the Partnership. However, it is possible that such procedure in itself may constitute a conflict of interest.
COMPENSATION OF THE GENERAL PARTNER
The General Partner receives no remuneration in connection with its management of the Partnership other than: (i) distributions on its general and limited partner interests in the Partnership and its nonmanaging interest in certain subsidiaries of the Partnership; (ii) incentive distributions on its general partner interest, as
provided in the partnership agreement, and (iii) reimbursement for all direct and indirect costs and expenses incurred, all selling, general and administrative expenses incurred, and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, the Partnership, including, but not limited to the management fees paid by the General Partner to El Paso Energy under its management agreement.
LIMITATIONS ON DIRECTORS' AND OFFICERS' LIABILITY; INDEMNIFICATION
The Certificate of Incorporation of the General Partner limits the liability of the directors of the General Partner to the General Partner or its stockholder (in their capacity as directors but not in their capacity as officers) to the fullest extent permitted by the Delaware General Corporation Law, or the DGCL. Accordingly, pursuant to the terms of the DGCL as presently in effect, directors of the General Partner will not be personally liable for monetary damages for breach of a director's fiduciary duty as a director, except for liability (i) for any breach of the director's duty of loyalty to the General Partner or its stockholder, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the DGCL or (iv) for any transaction from which the director derived an improper personal benefit. The Certificate of Incorporation also provides that if the DGCL is amended after the approval of the Certificate of Incorporation to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of a director of the General Partner will be eliminated to the full extent permitted by the DGCL, as so amended.
In addition, the Amended and Restated By-laws of the General Partner, in substance, require the General Partner to indemnify each person who is or was a director, officer, employee or agent of the General Partner to the full extent permitted by the laws of the State of Delaware if he is involved in legal proceedings because he is or was a director, officer, employee or agent of the General Partner, or is or was serving at the General Partner's request as a director, officer, employee or agent of the General Partner and its subsidiaries, another corporation, partnership or other enterprise. The General Partner is also required to advance to such persons payments incurred in defending a proceeding to which indemnification might apply, provided the recipient provides an undertaking agreeing to repay all such advanced amounts if it is ultimately determined that he is not entitled to be indemnified. In addition, the By-laws specifically provide that the indemnification rights granted thereunder are non-exclusive.
The General Partner has entered into indemnification agreements with certain of its current and past directors providing for indemnification to the full extent permitted by the laws of the State of Delaware. These agreements provide for specific procedures to assure the directors' rights to indemnification, including procedures for directors to submit claims, for determination of directors' entitlement to indemnification (including the allocation of the burden of proof and selection of a reviewing party) and for enforcement of directors' indemnification rights.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the Partnership or the General Partner pursuant to the foregoing, the Partnership and the General Partner have been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities and Exchange Act of 1933 and is therefore unenforceable.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
The General Partner's directors, certain officers and beneficial owners of more than 10 percent of a registered class of the Partnership's equity securities are required to file reports of ownership and reports of changes in ownership with the Securities and Exchange Commission and the NYSE. Directors, officers and beneficial owners of more than 10 percent of the Partnership's equity securities are also required to furnish the Partnership with copies of all such reports that are filed. Based on the Partnership's review of copies of such forms and amendments, the Partnership believes its directors, executive officers and greater than 10 percent beneficial owners complied with all filing requirements during the year ended December 31, 1999.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The executive officers of the General Partner and the Partnership are compensated by El Paso Energy and do not receive compensation from the General Partner or the Partnership for their services in such capacities with the exception of awards pursuant to Omnibus Plan discussed below. However, the General Partner does make certain payments to El Paso Energy pursuant to its management agreement. See Item 10, Directors and Executive Officers of the Registrant -- Compensation of Directors.
In August 1998, Mr. Lytal entered into an employment agreement with a five year term with El Paso Energy, pursuant to which he would continue to serve as President of the General Partner and the Partnership. However, pursuant to the terms of his employment agreement, Mr. Lytal has the right to terminate such agreement upon 30 days notice and El Paso Energy has the right to terminate such agreement under certain circumstances.
OMNIBUS PLAN
In August 1998, the Partnership adopted the 1998 Omnibus Compensation Plan, or the Omnibus Plan, to provide the General Partner with the ability to issue unit options to attract and retain the services of knowledgeable officers and key management personnel. Unit options to purchase a maximum of 3 million common units may be issued pursuant to the Omnibus Plan. The Omnibus Plan is administered by the General Partner's Board of Directors. The Board of Directors shall interpret the Omnibus Plan, shall prescribe, amend and rescind rules relating to it, select eligible participants, make grants to participants who are not Section 16 insiders pursuant to the Securities Exchange Act, and shall take all other actions necessary for the Omnibus Plan administration, which actions shall be final and binding upon all the participants.
In August 1998, the Partnership granted 930,000 unit options to employees of the General Partner to purchase an equal number of common units at $27.1875 per unit pursuant to the Omnibus Plan. All these unit options remain outstanding as of March 15, 2000. No grants of unit options were made in 1999.
REPORT FROM COMPENSATION COMMITTEE REGARDING EXECUTIVE COMPENSATION
Because the Partnership does not have a compensation committee or another committee performing similar functions, this report is presented by the full Board of Directors of the General Partner. The Board of Directors is responsible for establishing appropriate compensation goals for the knowledgeable officers and key management personnel working for us and evaluating the performance of such officers and personnel in meeting such goals.
The goals of the Board of Directors in administering the Omnibus Plan are as follows:
(1) To fairly compensate the knowledgeable officers and key management personnel working for us and our affiliates for their contributions to our short-term and long-term performance.
(2) To allow us to attract, motivate and retain the management personnel necessary to our success by providing an Omnibus Plan comparable to that offered by companies with which we compete for such management personnel.
The elements of the Omnibus Plan described above are implemented and periodically reviewed and adjusted by the Board of Directors. The awards made under the Omnibus Plan are determined based on individual performance, experience and comparison with awards made by our industry peers and other companies in similar industries with comparable revenue while linking such awards to our achievement of certain financial goals.
SUMMARY COMPENSATION TABLE
The following table sets forth information concerning the annual compensation earned by the Partnership's Chief Executive Officer and each of its other four most highly compensated executive officers whose annual salary and bonus during the year ended December 31, 1999, exceeded $100,000 (collectively, the Named Officers):
- ---------------
(1) Mr. Sims, former Chief Executive Officer, resigned his position effective September 30, 1999. (2) Other than awards made under the Partnership's incentive arrangements, all other compensation was paid by El Paso Energy or subsidiaries of El Paso Energy. (3) Issued pursuant to the Omnibus Plan. (4) Issued pursuant to the Unit Appreciation Rights Plan, the previous plan to the Omnibus Plan.
OPTION GRANTS
None of the Named Officers received any unit options grants under the Omnibus Plan during the year ended December 31, 1999:
OPTION EXERCISES AND YEAR-END VALUE TABLE
The following table sets forth certain information concerning the unit options held by the Named Officers at December 31, 1999 or exercised by the Named Officers during the year then ended:
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth, as of March 1, 2000, the beneficial ownership of the outstanding equity securities of each of the Partnership, by (i) each person who is known to the Partnership to beneficially own more than 5 percent of the outstanding units of the Partnership, (ii) each director of the General Partner and (iii) all directors and executive officers of the General Partner as a group.
- --------------- * Less than 1 percent. (1) The address for the General Partner and El Paso Energy is El Paso Energy Building, 1001 Louisiana Street, Houston, Texas 77002. All of the General Partner's outstanding common stock, par value $0.10 per share, is indirectly owned by El Paso Energy. The General Partner has no other class of capital stock outstanding. El Paso Energy, through its subsidiaries, owns an effective 34.5 percent economic interest in the Partnership consisting of 8,953,764 common units, a one percent general partner interest and an approximate one percent non-managing member interest in certain of the Partnership's subsidiaries. (2) The amount reflected for Mr. Lytal excludes 34 common units owned by his son, a minor. (3) Includes the option to acquire 2,500 common units pursuant to the Director Plan. See Item 10, Directors and Executive Officers of the Registrant -- Compensation of Directors. (4) Includes the option to acquire 215,000 common units pursuant to the 1998 Omnibus Plan. (5) Mr. Wise disclaims beneficial ownership of 2,500 common units held by spouse and 6,900 common units held by daughters. (6) Includes the option to acquire 107,500 common units pursuant to the 1998 Omnibus Plan.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
A discussion of certain agreements, arrangements and transactions between or among the Partnership, the General Partner, and certain other related parties is summarized in Part II, Item 8, Financial Statements and Supplementary Data, Note 8. Also see Item 10, Directors and Executive Officers of the Registrant.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Annual Report or incorporated by reference:
1. Financial Statements
The following consolidated financial statements of the Partnership are included in Part II, Item 8 of this report:
The following consolidated financial statements of certain of the Partnership's equity investments are included on the following pages of this report:
2. Financial Statement Schedules
None. All financial statement schedules are omitted because the information is not required, is not material or is otherwise included in the consolidated financial statements or notes thereto included elsewhere in this Annual Report.
3.(a) Exhibits
Each exhibit identified below is filed as a part of this Annual Report. Exhibits included in this filing are designated by an asterisk; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a "+" constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
3.(b) Reports on Form 8-K
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, El Paso Energy Partners, L.P. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 29th day of March 2000.
EL PASO ENERGY PARTNERS, L.P. (Registrant)
By: EL PASO ENERGY PARTNERS COMPANY, its General Partner
By: /s/ ROBERT G. PHILLIPS ------------------------------------- Robert G. Phillips Chief Executive Officer
EL PASO ENERGY PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
WESTERN GULF HOLDINGS, L.L.C.
CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 1999
INDEPENDENT AUDITORS' REPORT
To the Management Committee Western Gulf Holdings, L.L.C. Detroit, Michigan
We have audited the accompanying consolidated balance sheet of Western Gulf Holdings, L.L.C. as of December 31, 1999, and the related statements of income, member's equity, and cash flows for the year then ended. These financial statements are the responsibility of the Western Gulf Holdings, L.L.C.'s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Western Gulf Holdings, L.L.C. as of December 31, 1999, and the results of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Detroit, Michigan March 24, 2000
WESTERN GULF HOLDINGS, L.L.C.
CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1999
ASSETS
See notes to the consolidated financial statements.
WESTERN GULF HOLDINGS, L.L.C.
CONSOLIDATED STATEMENTS OF INCOME AND MEMBER'S EQUITY
See notes to the consolidated financial statements.
WESTERN GULF HOLDINGS, L.L.C.
CONSOLIDATED STATEMENT OF CASH FLOWS
Supplemental Disclosure of Non-Cash Financing Activities:
On September 30, 1999 the Company's loan agreement was amended and restated and consolidated in the name of Deepwater. As a result, the Company no longer has the primary debt obligation.
See notes to the consolidated financial statements.
WESTERN GULF HOLDINGS, L.L.C.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER 31, 1999
1. FORMATION AND OWNERSHIP STRUCTURE
Description and Business Purpose
Western Gulf Holdings, L.L.C. ("Western Gulf" or "the Company"), a Delaware Limited Liability Company organized December 11, 1998, was formed to own and operate High Island Offshore System, L.L.C. ("HIOS") and East Breaks Gathering Company, L.L.C. ("East Breaks"). East Breaks was also organized as a Delaware Limited Liability Company on December 11, 1998.
Effective January 1, 1999, the members of the Company, each of which then held a 20% interest in the Company, contributed their capital accounts in HIOS to the Company in the amount of $14,972,141 in exchange for equivalent ownership interests in the Company. As a result, the Company now owns a 100% interest in HIOS.
Effective September 30, 1999, the members of the Company contributed their capital accounts in the Company to Deepwater Holdings, L.L.C. ("Deepwater"). As a result, Deepwater owns 100% of the Company. Deepwater is equally owned by affiliates of ANR Pipeline Company ("ANR"), an indirect subsidiary of The Coastal Corporation ("Coastal") and El Paso Energy Partners Deepwater, L.L.C., an affiliate of El Paso Energy Corporation ("El Paso").
On January 18, 2000 Coastal and El Paso entered into a merger agreement under which, if the merger is completed, Coastal would be merged into El Paso.
HIOS owns a 203.4 mile undersea gas transmission system in the Gulf of Mexico which provides transportation services as authorized by the Federal Energy Regulatory Commission ("FERC"). HIOS' major transportation customers include natural gas marketers and producers, and interstate natural gas pipeline companies. The Company extends credit for transportation services provided to these customers. The concentrations of customers, described above, may affect the Company's overall credit risk in that the customers may be similarly affected by changes in economic, regulatory and other factors.
East Breaks is a "development stage company" which is building an 85 mile pipeline and related facilities extending from HIOS connecting the deep water Diana/Hoover prospects developed by Exxon Company USA ("Exxon") and BP Amoco Plc ("BP Amoco") in Alaminos Canyon Block 25 in the Gulf of Mexico. The new line is scheduled to be in service in July 2000 and is projected to cost approximately $90 million. East Breaks entered into long-term agreements with Exxon and BP Amoco involving gathering of production from the Diana/Hoover prospects.
The Company is managed by a committee consisting of representatives from El Paso and ANR. The Company has no employees. ANR is currently the operator of HIOS and provides services at cost ($11.4 million in 1999). El Paso will replace ANR as operator of HIOS during 2000.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation
The accompanying consolidated financial statements include the accounts of the Company and all of the accounts of HIOS and East Breaks. Intercompany transactions and balances have been eliminated in consolidation.
Basis of Presentation
HIOS is regulated by the FERC. HIOS meets the criteria and, accordingly, follows the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71 for regulated enterprises. Western Gulf and East Breaks are non jurisdictional.
WESTERN GULF HOLDINGS, L.L.C.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ from those estimates.
Depreciation
Annual depreciation and negative salvage provisions for HIOS are computed on a straight-line basis using rates of depreciation, which vary by type of property. The annual composite depreciation rate is approximately 1.26%, which includes a provision for negative salvage of .2% for offshore facilities.
Interest Cost
The Company capitalizes interest and other borrowing costs incurred as a component of its property, plant, and equipment during the construction of the East Breaks pipeline and related facilities. The Company has capitalized $.6 million of initial debt issue costs and $2.6 million of interest costs incurred in 1999, which includes $.8 million of interest costs incurred by Deepwater and charged to Western Gulf.
Income Taxes
For tax filing purposes the Company has elected partnership status and therefore, income taxes are the responsibility of the Members and are not reflected in the financial statements of the Company.
Statement of Cash Flows
For purposes of these financial statements, the Company considers short-term investments purchased with an original maturity of three months or less to be cash. The Company had short-term investments in the amount of $5.1 million at December 31, 1999. The Company made cash payments for interest in the amount of $1.7 million for the year 1999. The accounts of HIOS as of January 1, 1999 have been eliminated from the statement of consolidated cash flows for 1999.
Accounting Pronouncements
The Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No.133, "Accounting for Derivative Instruments and Hedging Activities," ("FAS 133"), as amended by Statement of Financial Accounting Standards No. 137, to be effective for all fiscal years beginning after June 15, 2000. FAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting for changes in the fair value of a derivative will depend on the intended use of the derivative and the resulting designation. The Company is currently evaluating the impact, if any, of FAS 133.
3. REGULATORY MATTERS
By letter order issued September 18, 1995 the FERC approved the settlement of HIOS's rate filing at Docket No. RP94-162, which required that HIOS file a new rate case within three years of such date. On October 8, 1998, the FERC granted a request filed by HIOS for an extension of time for the filing of its next general rate case until January 1, 2003. Costs incurred in connection with the extension of the rate case settlement have been deferred and are being amortized on a straight-line basis through the period ending December 31, 2002.
WESTERN GULF HOLDINGS, L.L.C.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. LONG TERM DEBT
On September 30, 1999, as a result of the restructuring of the ownership interests of the Company, the Company's $100 million revolving credit facility ("Credit Facility") was amended and restated and consolidated in the name of Deepwater.
5. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of cash invested on a temporary basis at short-term market rates of interest approximates the fair market value of the investments.
6. RELATED PARTY TRANSACTIONS
Transportation revenues derived from affiliated pipeline companies were $3.1 million for 1999. Accounts receivable balances due from affiliates for transportation services were $.5 million at December 31, 1999.
Both ANR and U-T Offshore System, L.L.C. ("UTOS") provide separation, dehydration and measurement services to HIOS. UTOS is owned by Deepwater. HIOS incurred charges for these services of $2.5 million in 1999 from ANR and $1.5 million in 1999 from UTOS. There were no amounts due to ANR for these services at December 31, 1999. Amounts due from UTOS for over-estimated billings were $.4 million at December 31, 1999.
In February 1996, HIOS reached an agreement with ANR, which was approved by the FERC, which provides that rates charged by ANR for separation, dehydration, and measurement services would be $2.5 million for 1999 and $2.2 million for calendar year 2000. The rate would be negotiated for calendar year 2001 and thereafter.
In 1999 HIOS implemented "cash-out" accounting for volume imbalances in the shipper accounts. In addition, HIOS entered into operational balancing agreements ("OBA") with ANR, UTOS, and Stingray Pipeline Company, L.L.C. ("Stingray"). Stingray is owned by Deepwater. Amounts due from shippers for transportation services, historical and current imbalances, and under the OBA at December 31, 1999 were $6.5 million. Amounts due to shippers for historical and current imbalances, and under the OBA at December 31, 1999 were $4.5 million, which includes $3.3 million due to ANR.
Amounts due to ANR for operating and construction cost reimbursements were $.4 million at December 31, 1999.
7. COMMITMENTS AND CONTINGENCIES
In the ordinary course of business, the Company is subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position or the results of operations of the Company.
8. LEGAL PROCEEDINGS
Two legal proceedings, one in federal court and the other in state court, have been instituted against a number of gas pipeline companies and their affiliates, including HIOS. The plaintiffs in each suit seek damages for the alleged undermeasurement of the heating value and the volume of natural gas. In the federal proceeding, Jack Grynberg filed 77 separate False Claim Act suits in September 1997 against transmission companies and producers, gatherers, and processors of natural gas, seeking unspecified damages which could include treble damages for the maximum period permitted by law (potentially as much as 10 years) and penalties of up to $10,000 per false claim. In addition to the measurement claims, these suits also allege that the defendants undervalued the gas in paying royalties. HIOS was sued in the U.S. District Courts of Colorado and the Eastern District of Michigan. In April 1999, the United States Department of Justice
WESTERN GULF HOLDINGS, L.L.C.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
notified HIOS that the United States will not intervene in these cases at this time. The MultiDistrict Litigation Panel has consolidated the Grynberg suits with several other Grynberg cases for pre-trial proceedings in Wyoming. The defendants have filed a motion to dismiss which will be argued in March of 2000.
In the state proceedings, the Quinque Operating Company, on behalf of itself and subclasses of gas producers, royalty owners and state taxing authorities, in May 1999 instituted a legal proceeding in State Court, Stevens County, Kansas against over 200 gas pipeline companies, including HIOS. The Quinque suit seeks unspecified actual, punitive and treble damages, for the alleged undermeasurement of all natural gas measured in the United States from non-federal and non-Indian lands since 1974. The plaintiffs are seeking certification of a national class of all similarly situated gas producers, royalty owners, overriding royalty owners, and state taxing authorities. The suit has been removed to the U.S. District Court for the District of Kansas. The plaintiffs have filed a motion to remand the case back to the state court, and several defendants have filed a motion under the MultiDistrict Litigation rules to have the suit transferred to Wyoming and consolidated with the Grynberg proceedings for pre-trial proceedings.
Although no assurances can be given and no determination can be made at this time as to the outcome of any particular lawsuit or proceeding, HIOS believes there are meritorious defenses to substantially all such claims and that any liability which may be finally determined should not have a material adverse effect on HIOS' financial position or results of operations.
POSEIDON OIL PIPELINE COMPANY, L.L.C.
FINANCIAL STATEMENTS AS OF DECEMBER 31, 1999 TOGETHER WITH AUDITORS' REPORT
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Members of Poseidon Oil Pipeline Company, L.L.C.:
We have audited the accompanying balance sheets of Poseidon Oil Pipeline Company, L.L.C. (a Delaware limited liability company), as of December 31, 1999 and 1998, and the related statements of income, members' equity and cash flows for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Poseidon Oil Pipeline Company, L.L.C., as of December 31, 1999 and 1998, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas March 17, 2000
POSEIDON OIL PIPELINE COMPANY, L.L.C. BALANCE SHEETS -- DECEMBER 31, 1999 AND 1998
The accompanying notes are an integral part of these financial statements.
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
The accompanying notes are an integral part of these financial statements.
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF MEMBERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
The accompanying notes are an integral part of these financial statements.
POSEIDON OIL PIPELINE COMPANY, L.L.C.
STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
The accompanying notes are an integral part of these financial statements.
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 1999 AND 1998
1. ORGANIZATION AND NATURE OF BUSINESS:
Poseidon Oil Pipeline Company, L.L.C. (the Company), is a Delaware limited liability company formed on February 14, 1996, to design, construct, own and operate the unregulated Poseidon Pipeline extending from the Gulf of Mexico to onshore Louisiana. The original members of the Company were Texaco Trading and Transportation, Inc. (TTTI), and Poseidon Pipeline Company, L.L.C. (Poseidon), a subsidiary of Leviathan Gas Pipeline Partners, L.P. TTTI contributed $36,399,660 in cash, and Poseidon contributed property, plant and equipment, valued by the two parties (TTTI and Poseidon) at $36,399,660, at the formation of the Company. Each member received a 50 percent ownership interest in the Company. Subsequently, $2,799,320 in cash was equally distributed to TTTI and Poseidon, leaving $70 million of equity in the Company as of April 23, 1996.
On July 1, 1996, Marathon Pipeline Company (MPLC) and Texaco Pipeline, Inc. (TPLI), through their 66 2/3 percent and 33 1/3 percent respectively owned venture, Block 873 Pipeline Company (Block 873), contributed property, plant and equipment valued by the parties (Block 873, TTTI and Poseidon) at $30,000,000. In return, they received a 33 1/3 percent interest in the Company. Immediately after the contribution, MPLC and TPLI transferred their pro rata ownership interests in the Company to Marathon Oil Company (Marathon) and TTTI, respectively. Marathon then contributed an additional $5.2 million in cash, and distributions of $12.6 million and $2.6 million in cash were made to TTTI and Poseidon, respectively. Upon completion of this transaction, TTTI, Poseidon and Marathon owned 36 percent, 36 percent and 28 percent of the Company, respectively, and total equity was $90,000,000.
Effective January 1, 1998, Shell Oil Company and Texaco Inc. (Texaco) formed Equilon Enterprises LLC (Equilon). Equilon is a joint venture which combines both companies' western and midwestern U.S. refining and marketing businesses and both companies' nationwide trading, transportation and lubricants businesses. Under the formation agreement, Shell Oil Company and Texaco assigned, or caused to be assigned, the economic benefits and obligations of certain regulated and unregulated pipeline assets, including TTTI's beneficial interest in the Company. As a result of the joint venture, Equilon became operator of the Company on January 1, 1998.
The Company purchased crude oil line-fill and began operating Phase I of the pipeline in April 1996. Phase I consists of 16-inch and 20-inch sections of pipe extending from the Garden Banks Block 72 to Ship Shoal Block 332. Phase II of the pipeline is a 24-inch section of pipe from Ship Shoal Block 332 to Caillou Island. Line-fill was purchased for Phase II in late December 1996 and operations began in January 1997. Construction of Phase III of the pipeline consisting of a section of 24-inch line extending from Caillou Island to the Houma, Louisiana, area was completed during 1997, and operations began in December 1997.
The Company is in the business of transporting crude oil in the Gulf of Mexico in accordance with various purchase and sale contracts with producers served by the pipeline. The Company buys crude oil at various points along the pipeline and resells the crude oil at a destination point in accordance with each individual contract. Net sales revenue is earned based upon the differential between the sale price and purchase price. Differences between purchased and sold volumes in any period are recorded as changes in line-fill.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Basis of Accounting
The accompanying financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States.
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Property, Plant and Equipment
Contributed property, plant and equipment is recorded at fair value as agreed to by the members at the date of contribution. Acquired property, plant and equipment is recorded at cost. Pipeline equipment is depreciated using a composite, straight-line method over estimated useful lives of three to 30 years. Line-fill is not depreciated as management of the Company believes the cost of all barrels is fully recoverable. Major renewals and betterments are capitalized in the property accounts while maintenance and repairs are expensed as incurred. No gain or loss is recognized on normal asset retirements under the composite method.
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Debt Reserve Fund
In connection with the Company's revolving credit facility (see Note 4), the Company is required to maintain a debt reserve account as security on the outstanding balance. At December 31, 1999, the balance in the account totaled approximately $4,783,000 and was comprised of funds earning interest at a money market rate.
Fair Value of Financial Instruments
The Company's financial instruments consist of cash and cash equivalents, short-term receivables, payables and long-term debt. The carrying values of cash and cash equivalents, short-term receivables and payables approximate fair value. The fair value for long-term debt is estimated based on current rates available for similar debt with similar maturities and securities and, at December 31, 1999, approximates the carrying value.
3. PROPERTY, PLANT AND EQUIPMENT:
Property, plant and equipment consisted of the following at December 31, 1999 and 1998:
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS
Management evaluates the carrying value of the pipeline in accordance with the guidelines presented under Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 121 establishes standards for measuring the impairment of long-lived assets to be held and used and of those to be disposed. Management believes no impairment of assets exists as of December 31, 1999.
During 1999 and 1998, the Company did not capitalize interest cost into property, plant and equipment.
4. DEBT:
The Company maintains a $150,000,000 revolving credit facility with a group of banks. The outstanding balance at December 31, 1999, is $150,000,000. Under the terms of the related credit agreement, the Company has the option to either draw or renew amounts at various maturities ranging from one to 12 months if a Eurodollar interest rate arrangement is selected (7.75 percent at December 31, 1999). These borrowings can then be renewed assuming no event of default exists. Alternatively, the Company may select to borrow under a base interest rate arrangement, calculated in accordance with the credit agreement. The revolving credit facility matures on April 30, 2001.
At December 31, 1999, the entire outstanding balance had been borrowed under the Eurodollar alternative, and it is the Company's intent to extend repayment beyond one year, thus the entire balance has been classified as long-term.
The debt is secured by various assets of the Company including accounts receivable, inventory, pipeline equipment and investments. The Company has used the funds drawn on the revolver primarily for construction costs associated with Phases II and III of the pipeline.
The revolving credit agreement requires the Company to meet certain financial and nonfinancial covenants. The Company must maintain a tangible net worth, calculated in accordance with the credit agreement, of not less than $80,000,000. Beginning April 1, 1997, the Company is required to maintain a ratio of earnings before interest, taxes, depreciation and amortization to interest paid or accrued, as calculated in accordance with the credit agreement, of 2.50 to 1.00. In addition, the Company is required to maintain a debt reserve fund (see Note 2) with a balance equal to two times the interest payments made in the previous quarter under the credit facility.
5. INCOME TAXES:
A provision for income taxes has not been recorded in the accompanying financial statements because such taxes accrue directly to the members. The federal and state income tax returns of the Company are prepared and filed by the operator.
6. TRANSACTIONS WITH RELATED PARTIES:
The Company derives a significant portion of its gross sales and gross purchases from its members and other related parties. The Company generated approximately $520,632,000 in gross affiliated sales and approximately $479,850,000 in gross affiliated purchases for 1999. During 1998 and 1997, the Company generated approximately $37,688,000 and $19,790,000 of net sales revenue from related parties.
The Company paid approximately $1,203,000 to Equilon in 1999 and $558,000 and $454,000 in 1998 and 1997, respectively, for management, administrative and general overhead. In 1999, 1998 and 1997, the Company paid construction management fees of $-, $2,134,000 and $1,091,000, respectively, to Equilon in connection with the completion of Phase II and Phase III. As of December 31, 1999 and 1998, the Company had outstanding advances to Equilon of approximately $4,000 and $1,234,000, respectively, in connection with construction work in progress.
POSEIDON OIL PIPELINE COMPANY, L.L.C.
NOTES TO FINANCIAL STATEMENTS
7. COMMITMENTS AND CONTINGENCIES:
In the normal course of business, the Company is involved in various legal actions arising from its operations. In the opinion of management, the outcome of these legal actions will not significantly affect the financial position or results of operations of the Company.
In February 1998, Poseidon entered into an oil purchase and sale agreement with Pennzoil Exploration and Production (Pennzoil). The agreement provides that if Pennzoil delivers at least 7.5 million barrels by September 2002, Poseidon will refund $.51 per barrel for all barrels delivered plus interest at 8 percent. Based on barrels delivered, the Company has accrued a potential refund of contingent revenues of $322,242 at December 31, 1999.
8. SUBSEQUENT EVENTS (UNAUDITED):
On January 21, 2000, an anchor from the Transocean 96 Semi-Submersible Drilling Unit (Transocean) hit the Poseidon 24-inch crude oil pipeline and ruptured a section of the pipeline. The estimated cost to repair the damaged pipeline and clean up approximately 2,240 barrels of crude oil that were released into the ocean is $15,000,000. Poseidon has placed Transocean on notice for liability and expenses due to the incident. The impact of lost revenue and other related expenses due to this incident is not available as of March 17, 2000.
NEPTUNE PIPELINE COMPANY
CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 1999 AND 1998
PRICEWATERHOUSECOOPERS LETTERHEAD
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Members of Neptune Pipeline Company, L.L.C.
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, of members' capital and of cash flows present fairly, in all material respects, the financial position of Neptune Pipeline Company, L.L.C. and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
[PRICEWATERHOUSECOOPERS]
March 10, 2000
NEPTUNE PIPELINE COMPANY, L.L.C.
CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1999 AND 1998
ASSETS
The accompanying notes are an integral part of these statements.
NEPTUNE PIPELINE COMPANY, L.L.C.
CONSOLIDATED STATEMENT OF INCOME FOR THE YEARS ENDED DECEMBER 31, 1999 AND 1998
The accompanying notes are an integral part of these statements.
NEPTUNE PIPELINE COMPANY, L.L.C.
CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 1999 AND 1998
The accompanying notes are an integral part of these statements.
NEPTUNE PIPELINE COMPANY, L.L.C.
CONSOLIDATED STATEMENT OF MEMBERS' CAPITAL AS OF DECEMBER 31, 1999 AND 1998
The accompanying notes are an integral part of these statements.
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999
1. ORGANIZATION AND CONTROL
Neptune Pipeline Company, L.L.C. (Neptune) owns a 99% member interest in Manta Ray Offshore Gathering Company, L.L.C. (Manta Ray) and Nautilus Pipeline Company, L.L.C. (Nautilus). Neptune is owned as follows: Tejas Offshore Pipeline, LLC (Tejas), an affiliate of Shell Oil Company owns a 49.9% member interest; Shell Seahorse Company (Shell Seahorse), an affiliate of Shell Oil Company owns a 0.1% member interest; Marathon Gas Transmission Inc. (Marathon) owns a 24.33% member interest; Sailfish Pipeline Company, L.L.C. (Sailfish) owns a 25.67% member interest.
Tejas acquired its 49.9% interest from Shell Seahorse on February 2, 1998.
Agreements between the member companies address the allocation of income and capital contributions and distributions amongst the respective members' capital accounts. As a result of these agreements, the ratio of members' equity accounts per the Statement of Members' Capital differs from the members' ownership interests in Neptune.
Neptune was formed to acquire, construct, own and operate through Manta Ray and Nautilus, the Manta Ray System and the Nautilus System and any other natural gas pipeline systems approved by the members. As of December 31, 1999 the Manta Ray System and the Nautilus System are the only pipelines owned by Manta Ray and Nautilus, respectively.
The formation of Manta Ray was accomplished through cash and fixed asset contributions from the member companies. Fixed asset contributions, which accounted for approximately 50% of all contributions, consisted of the Manta Ray System and various compressor equipment (contributed by Sailfish) and the Boxer-Bullwinkle System (contributed by Shell Seahorse). Because both cash and fixed assets were contributed, the Manta Ray System and related compressor equipment and the Boxer-Bullwinkle System were recorded at $64,342,716, which represented their fair value on the date of contribution.
The Manta Ray System consists of a 169 mile gathering system located in the South Timbalier and Ship Shoal areas of the Gulf of Mexico. An additional segment, 47 miles of 24 inch pipeline and associated facilities, extending from Green Canyon Block 65, offshore Louisiana, to Ship Shoal Block 207, offshore Louisiana, was constructed during 1997 and first provided natural gas transportation service on December 15, 1997. This newly constructed pipeline is referred to as Phase II Facilities elsewhere in these notes.
The Nautilus System consists of a 30-inch natural gas pipeline and appurtenant facilities extending approximately 101 miles from Ship Shoal Block 207, offshore Louisiana, to six delivery point interconnects downstream of the outlet of the Garden City Gas Processing Plant in St. Mary Parish, Louisiana. The Nautilus System was constructed during 1997 and first provided natural gas transportation service on December 15, 1997.
Neptune, Manta Ray and Nautilus (collectively referred to as the Companies) have no employees and receive all administrative and operating support through contractual arrangements with affiliated companies. These services and agreements are outlined in Note 3, Related Party Transactions.
2. SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Neptune and its subsidiaries. All intercompany transactions and balances have been eliminated in consolidation. Neptune has accounting policies that conform to generally accepted accounting principles.
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Regulation
Nautilus, as an interstate pipeline, is subject to regulation by the Federal Energy Regulatory Commission (FERC). Nautilus has accounting policies that conform to generally accepted accounting principles, as applied to regulated enterprises and are in accordance with the accounting requirements and ratemaking practices of the FERC.
Cash and Cash Equivalents
All highly liquid investments with a maturity of three months or less when purchased are considered to be cash equivalents.
Pipelines and Equipment
Newly constructed pipelines are recorded at historical cost. Regulated pipelines and equipment includes an Allowance for Funds Used During Construction (AFUDC). The rates used in the calculation of AFUDC are determined in accordance with guidelines established by FERC. The Manta Ray pipeline and related facilities are depreciated on a straight-line basis over their estimated useful life of 30 years, while the Nautilus pipeline and related facilities are depreciated on a straight line basis over their estimated useful life of 20 years. Maintenance and repair costs are expensed as incurred while additions, improvements and replacements are capitalized.
Income Taxes
Neptune is treated as a tax partnership under the provisions of the Internal Revenue Code. Accordingly, the accompanying financial statements do not reflect a provision for income taxes since Neptune's results of operations and related credits and deductions will be passed through to and taken into account by its members in computing their respective tax liabilities.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standard (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" requires recognition of impairment losses on long-lived assets if the carrying amount of such assets, grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows from other assets, exceeds the estimated undiscounted future cash flows of such assets. Measurement of any impairment loss is based on the fair value of the asset. At December 31, 1999 and 1998 there were no impairments.
Revenue Recognition
Revenue from Manta Ray's and Nautilus' transportation of natural gas is recognized upon receipt of natural gas into the pipeline systems.
In the course of providing transportation services to customers, Nautilus and Manta Ray may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. These transactions result in imbalances which are settled in cash on a monthly basis. In addition, certain imbalances may occur with interconnecting facilities when the Companies deliver more or less than what is nominated (scheduled). The settlement of these imbalances is governed by Operational Balancing Agreements (OBA). Certain OBAs stipulate that settlement will occur through delivery of physical quantities in subsequent months. The Companies record the net of all imbalances as Transportation Revenue or Other Revenue and carry the net position as a payable or a receivable, as appropriate.
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Fair Value of Financial Instruments
The reported amounts of financial instruments such as cash and cash equivalents, receivables, and current liabilities approximate fair value because of their maturities.
Use of Estimates and Significant Risks
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the related reported amounts of revenue and expenses during the reporting period. Such estimates and assumptions include those made in areas of FERC regulations, fair value of financial instruments, future cash flows associated with assets, useful lives for depreciation and potential environmental liabilities. Actual results could differ from those estimates. Management believes that the estimates are reasonable.
Development and production of natural gas in the service area of the pipelines are subject to, among other factors, prices for natural gas and federal and state energy policy, none of which are within the Companies' control.
Reclassification
Certain prior period amounts in the financial statements and notes thereto have been reclassified to conform with the current year presentation.
3. RELATED PARTY TRANSACTIONS
Construction Management Agreements
On January 17, 1997, Nautilus entered into a Construction Management Agreement (the Agreement) with Marathon under which Marathon agreed to construct the Nautilus System. As of December 31, 1999 and 1998 respectively, Nautilus had incurred $113,190,864, and $113,127,385 of costs under the Agreement. Of these amounts, $0 and $309,238 were recorded as liabilities to affiliates at December 31, 1999 and 1998, respectively.
On January 17, 1997, Manta Ray entered into a Construction Management Agreement with Shell Seahorse under which Shell Seahorse agreed to construct the Phase II Facilities. Also on January 17, 1997, Manta Ray entered into a Construction Management Agreement with Marathon under which Marathon agreed to construct a slug catcher. On August 1, 1998, Manta Ray entered into a Construction Management Agreement with Marathon under which Marathon agreed to construct condensate stabilization facilities. As of December 31, 1999 and 1998, Manta Ray had incurred $85,830,156 and $83,388,913, respectively, under these agreements. On March 26, 1999, Manta Ray entered into a Construction Management Agreement with Tejas Offshore Pipeline, LLC under which Tejas agreed to construct the Grand Isle 116 Lateral Facility. As of December 31, 1999, Manta Ray had incurred $4,421,792 under this agreement. On September 1, 1999, Manta Ray entered into a Construction Management Agreement with Manta Ray Gathering Company, L.L.C. under which Manta Ray Gathering agreed to construct ST292 Hickory Facilities. As of December 31, 1999, Manta Ray had incurred $25,000. Of these amounts, $4,367,815 and $4,236,507 were recorded as liabilities to affiliates at December 31, 1999 and 1998, respectively.
Transportation Services
During 1999 and 1998, $7,705,731 and $3,881,667, respectively, of transportation revenues for Nautilus were derived from related parties. All transactions were at rates pursuant to the existing tariff. At December 31, 1999 and 1998 respectively, Nautilus had affiliate receivables of $744,274 and $596,090 relating
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to transportation and gas imbalances. At December 31, 1999 and 1998, respectively, Nautilus had affiliate payables of $310,134 and $230,730 relating to transportation and gas imbalances.
During 1999 and 1998, $9,975,728 and $4,902,613, respectively, of transportation revenues for Manta Ray were derived from related parties. All transactions were at negotiated rates. At December 31, 1999 and 1998 respectively, Manta Ray had affiliate receivables of $1,781,506 and $1,857,320 relating to transportation and gas imbalances.
At December 31, 1998, Manta Ray also had a receivable from Sailfish of $297,348 relating to accumulated transportation and gas balancing activity associated with the assets contributed by Sailfish.
Leases
Effective December 1, 1997, Manta Ray, as lessor, and Nautilus, as lessee, entered into a lease agreement for usage of offshore platform space located at Ship Shoal Block 207. The term of the lease is for the life of the platform, subject to certain early termination conditions, and requires minimum lease payments of $225,000 per year adjusted annually for inflation. The associated lease revenue and expense have been eliminated in consolidation.
Operating and Administrative Expense
Since the Companies have no employees, operating, maintenance and general and administrative services are provided to the Companies under service agreements with Manta Ray Gathering Company, L.L.C., Marathon, and Shell Seahorse, all of which are affiliates of the Companies. Substantially all operating and administrative expenses were incurred through services provided under these agreements. Shell Seahorse assigned the operating agreements to Tejas Offshore Pipeline, LLC effective February 2, 1998.
Other Affiliate Transactions
Included in Owing from Related Parties at December 31, 1998 is a receivable from an affiliate for $129,698 relating to the sale of land during the fourth quarter of 1998 by Nautilus. No gain or loss was recognized on the sale.
4. PIPELINES AND EQUIPMENT
Pipelines and equipment at December 31, 1999 and 1998 is comprised of the following (in thousands):
During 1998, Nautilus entered into interconnection agreements with certain other parties in which Nautilus agreed to construct interconnection facilities whereby the parties agreed to contribute $619,000 as partial reimbursement for construction costs. Nautilus was reimbursed $419,000 during 1998 and the remaining balance will be paid monthly based on throughput. The receivable balance at December 31, 1998
NEPTUNE PIPELINE COMPANY, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
was $200,000, the current portion of which is $40,000. The remaining balance at December 31, 1999 was $157,173, all of which is considered current.
5. REGULATORY MATTERS
The FERC has jurisdiction over the Nautilus System with respect to transportation of gas, rates and charges, construction of new facilities, extension or abandonment of service facilities, accounts and records, depreciation and amortization policies and certain other matters.
An annual charge (ACA) totaling $137,171 was paid to the FERC for fiscal year 1999. This charge, to be recovered from customers through rates, was recorded as a regulatory asset and will be amortized over twelve months. At the end of 1999, the balance of this account was $102,878.
6. COMMITMENTS AND CONTINGENCIES
In the ordinary course of business, the Companies are subject to various laws and regulations. In the opinion of management, compliance with existing laws and regulations will not materially affect the financial position, the results of operations or cash flows of the Companies.
Various legal actions, which have arisen in the ordinary course of business, are pending with respect to the assets of the Companies. Management believes that the ultimate disposition of these actions, either individually or in aggregate, will not have a material adverse effect on the financial position, the results of operations or the cash flows of the Companies.
Pursuant to the terms of a construction agreement entered into in 1995, Manta Ray agreed to pay liquidated damages to various parties if Manta Ray did not complete an interconnect by May 31, 1998 between the Manta Ray System and the system operated by Trunkline Gas Pipeline Company. Manta Ray incurred $150,000 in 1998 and $100,000 in 1999, which was recorded in Other Expense. Under the provision, Manta Ray will be obligated to pay an additional $50,000 if the interconnect is not completed by May 31, 2000.
INDEX TO EXHIBITS
Each exhibit identified below is filed as a part of this Annual Report. Exhibits included in this filing are designated by an asterisk; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. Exhibits designated with a "+" constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.