Item 1. Business
Change of Control
On February 14, 1997, Kinder Morgan, Inc., a Delaware corporation formerly known as KC Liquids Holding Corporation ("KMI"), acquired from Enron Liquids Holding Corporation, a Delaware corporation ("ELHC"), all of the issued and outstanding common stock of Enron Liquids Pipeline Company, the general partner of the Partnership and a Delaware corporation (the "General Partner"), for approximately $21.7 million. As a result of KMI's acquisition of the common stock of the General Partner, KMI indirectly acquired control of the Partnership. See Item 12 for information regarding the ownership of KMI.
In connection with the transaction, the name of the Partnership was changed to Kinder Morgan Energy Partners, L.P., the name of the General Partner was changed to Kinder Morgan G.P., Inc. and the address of the Partnership was changed to 1301 McKinney Street, Suite 3450, Houston, Texas 77010. The new telephone number of the Partnership is (713) 844-9500.
General
The Partnership was formed in June 1992 to acquire, own and operate three pipeline systems used to transport natural gas liquids ("NGLs"), refined petroleum products and carbon dioxide ("CO2") and to acquire and own an indirect interest in an NGL fractionation facility. In 1993, the Partnership acquired a coal terminaling and storage business, and in 1994, the Partnership acquired a natural gas processing plant and related facilities. Effective October 1, 1995, the Partnership took assignment of a gas processing agreement from Enron Gas Processing Company ("EGP") and subleased capacity at the EGP Bushton natural gas processing plant to perform the Partnership's obligations under the gas processing agreement.
Kinder Morgan G.P., Inc. serves as the sole general partner of the Partnership. In addition to its 2% general partner interest in the Partnership, the General Partner owns approximately 6.6% of the Common Units ("Common Units" represent limited partnership interests in the Partnership). The Partnership's operations are conducted through two operating partnerships of which the Partnership is the approximate 99% limited partner and the General Partner is the approximate 1% general partner. Kinder Morgan Operating L.P. "A" ("OLP-A") (formerly known as Enron Liquids Pipeline Operating Limited Partnership), which was created at the time of the Partnership's initial public offering of Common Units in August 1992 ("Initial Public Offering"), owns most of the assets relating to the transportation of NGLs, refined petroleum products and CO2. Through a subsidiary company, OLP-A has an indirect interest in a NGL fractionation facility located at Mont Belvieu, Texas. Kinder Morgan Operating L.P. "B" ("OLP-B") (formerly known as Enron Transportation Services, L.P.), which was created in 1993, owns a coal terminaling and storage facility in Illinois and a natural gas processing plant and related facilities in Wyoming. The Partnership may find it beneficial to create additional operating limited partnerships in the future in connection with acquisitions of additional assets. These operating limited partnerships are collectively referred to as the "Operating Partnerships." Unless the context otherwise requires, all references herein to the Partnership with respect to the operation and ownership of the Partnership's assets are also references to the Operating Partnerships and to their predecessors. The Partnership's business segments are Liquids Pipelines, Gas Processing and Fractionation, and Coal Transfer and Storage. See Note 11 of the Notes to the Consolidated Financial Statements of the Partnership included elsewhere in this report for additional information regarding the Partnership's business segments.
Although the Partnership's revenues derive from a wide customer base, Mobil Corporation and Amoco Corporation, including their subsidiaries, accounted for approximately 12% and 10%, respectively, of the Partnership's consolidated revenue in 1996. Additionally, in 1996, the two largest customers accounted for 12.3% and 11.1% of the revenues for the Liquids Pipelines business segment. In the Gas Processing and Fractionation business segment, the two largest customers accounted for 48.4% and 31.6% of the revenues. In the Coal Transfer and Storage business segment, the three largest customers accounted for 36.4%, 29.1% and 19.8% of the revenues of the business segment. See "--Liquids Pipelines," "--Gas Processing and Fractionation" and "--Coal Transfer and Storage" for a more complete discussion of customers.
Liquids Pipelines
The North System
General. The North System, which prior to its acquisition by the Partnership had been owned and operated by Enron Corp. ("Enron") since 1966, is an approximate 1,600 mile interstate common carrier NGL and refined petroleum products pipeline system that extends from South Central Kansas (Wichita, Hutchinson, McPherson, Conway, Bushton) to the Chicago area.
NGLs, which include ethane, propane, normal butane, isobutane and natural gasoline, are typically extracted from natural gas in liquid form under low temperature and high pressure conditions. Ethane, propane, normal butane and natural gasoline are used as feedstocks for petrochemical plants in the production of plastics, synthetic rubber and other products. Normal butane and natural gasoline are used by refineries in the blending of motor gasoline. Isobutane is used in the manufacturing process of motor gasoline and is also used in the production of methyl tertiary butyl ether ("MTBE"), which is used to produce cleaner burning motor gasoline. Propane is used as fuel for home heating and cooking, crop drying, industrial facilities and as an engine fuel for forklifts and other vehicles.
The North System, as an interstate common carrier pipeline, is subject to regulation by the Federal Energy Regulatory Commission ("FERC"). The Partnership offers interstate transportation services as a common carrier by means of the North System to any shipper of NGLs who requests such services, provided that the products transported satisfy the conditions and specifications contained in the applicable tariff. Through the North System, the Partnership transports, stores and delivers NGLs from South Central Kansas to markets in the midwest, including major refineries in the Chicago area, propane terminals in Nebraska, Iowa and Illinois, and to other pipeline systems, which in turn deliver NGLs to other midwestern and eastern markets. In addition, the North System receives NGL products into its system from a Canadian/U.S. pipeline originating in Western Canada. During the summer months, the North System transports refinery grade normal butane produced in the Chicago area to Bushton, Kansas for storage and transports the product back to the Chicago area on demand. The Partnership also owns a 50% interest in the Heartland Partnership, a partnership with Conoco Pipe Line Company ("Conoco"), that transports refined petroleum products on the North System from South Central Kansas to a Conoco terminal at Lincoln, Nebraska and a Heartland Partnership terminal at Des Moines, Iowa.
South Central Kansas is a major hub for producing, gathering, storage, fractionation and transportation of NGLs extracted from natural gas produced in the Mid-Continent and Rocky Mountain areas of the United States and includes the third largest NGL extraction facility in the lower 48 states, which is located at Bushton and operated by EGP. The Bushton natural gas processing facility historically has, and continues to, account for a significant portion of the NGLs transported on the North System. Storage facilities along the North
System and at Bushton give shippers and other customers flexibility in meeting their seasonal demand and permit the Partnership to maintain system operating efficiencies.
Pipelines. The primary segment of the North System is its main line, which extends from Bushton, Kansas to Morris, Illinois (the "Main Line"). The Main Line is composed of approximately 1,400 miles of 8" and 10" pipelines and includes (i) two pipelines that begin at Bushton and are parallel with each other, with the exception of a 50-mile segment in Nebraska, to their destination point at a major storage and terminal area in Des Moines, Iowa, (ii) a third pipeline, which extends from Bushton to the Kansas City, Missouri area, where it intersects with a pipeline (the "Williams Pipeline") owned by Williams Pipe Line Company, an unaffiliated pipeline company, and (iii) a fourth pipeline that transports product to the Chicago area from Des Moines. A portion of the Williams Pipeline extends from Kansas City to Des Moines, where it again interconnects with the Main Line. The Partnership has entered into an agreement with the Williams Pipe Line Company that gives the Partnership defined sole carrier rights to use certain portions of the Williams Pipeline in exchange for guaranteed minimum payments of $2.2 million per year. The agreement expires June 30, 2001, but provides for two five year extensions at the option of the Partnership. In addition, the North System gathers liquids from, and delivers liquids to, other pipelines at Wichita, McPherson, Hutchison and Conway, Kansas. Seven propane loading terminals, a multi-terminal complex at Morris, Illinois capable of loading propane, normal butane, isobutane and natural gasoline and operating storage facilities (mined caverns and steel tanks) are strategically placed along the North System. Total storage capacity is approximately 1 million barrels ("MMBbls"). The Tampico, Illinois terminal, which is the Partnership's newest propane terminal, was placed in service in January, 1996. The North System currently has unit pumping power of 62,000 horsepower.
The North System interconnects with several other NGL common carrier pipeline systems, utilizes leased capacity of the Williams Pipeline and has joint tariffs with other pipelines.
Truck Loading Terminals. The North System includes seven propane truck loading terminals plus a multi-terminal complex at Morris, Illinois, in the Chicago area, capable of loading propane, normal butane, isobutane and natural gasoline. The propane terminals have an aggregate storage capacity of approximately 69 thousand barrels ("MBbls"). Additional propane storage of approximately 358 MBbls at Des Moines, Iowa and Morris and Lemont, Illinois, is provided by underground mined caverns and above-ground steel tanks. The loading terminals (for propane, normal butane, isobutane and natural gasoline) at Morris provide services to the aerosol, chemical and motor gasoline blending markets in the Chicago area.
Storage Facilities. The North System's available storage facilities give shippers flexibility in meeting their seasonal demand and allow the North System to maintain operating efficiencies and integrity of product specification. In addition to approximately 628 MBbls of pipeline line-fill available on the North System and 300 MBbls of storage capacity in dedicated third-party pipelines, the North System includes separate cavern and tank storage facilities with an aggregate usable capacity, including the propane storage discussed above, of approximately 1.0 MMBbls.
The Partnership also has an agreement to use a portion of the storage facilities of EGP, which consist of 98 large underground salt caverns with the combined capacity to store up to 12.8 MMBbls of NGLs. The Partnership's storage agreement became effective in January 1996, for a three year term with annual evergreen provisions thereafter. The agreement provides storage capacity of approximately 5.0 MMBbls. This agreement was a key factor in improved product availability for ultimate transportation on the North System in 1996.
Heartland Partnership. The Heartland System was completed in the fall of 1990 and is owned by the Heartland Partnership, a partnership shared equally between the Partnership and Conoco. The Heartland Partnership provides transportation of refined petroleum products from refineries in the Kansas and Oklahoma area to a Conoco terminal in Lincoln, Nebraska and Heartland's Des Moines terminal.
The core of the Heartland Partnership's system is one of the North System's Main Line sections that originates in Bushton, Kansas. The Heartland Partnership leases certain specified pipeline capacity to ship refined petroleum products on this line under a long term lease agreement that will expire in 2010. Heartland's Des Moines terminal has five main tanks that allow storage of approximately 200 MBbls of different grades of gasoline and fuel oils.
Under Heartland's organizational structure and partnership agreement, the Partnership operates the pipeline, and Conoco operates Heartland's Des Moines terminal and serves as the managing partner.
Refined petroleum products transported by the Heartland Partnership on the North System are supplied to the North System mainly from the National Cooperative Refinery Association crude oil refinery in McPherson, Kansas and the Conoco, Inc. crude oil refinery in Ponca City, Oklahoma. The Ponca City volumes move to the North System through interconnecting third-party pipelines, while the McPherson volumes are transported directly through the North System.
The volume of refined petroleum products transported by the Heartland Partnership is directly affected by the demand for, and supply of, refined petroleum products in the geographic regions served. The major portion of refined petroleum product volumes transported by the Heartland Partnership is motor gasoline, the demand for which is dependent on price, prevailing economic conditions and demographic changes in the markets served. The Heartland Partnership's business has experienced only minor seasonal fluctuations in demand.
Pipeline Operations. Substantially all of the Partnership's operations on the North System constitute interstate common carrier pipeline operations. Common carrier operations are those under which transportation is available at tariff rates published and filed with the FERC to any shipper of NGLs that requests such services, provided that each NGL product satisfies the product specifications for shipment and meets the tariff shipping requirements. The Partnership does not normally engage in the merchant function of buying and selling NGLs for its own account and does not purchase or sell NGLs except for quantities of NGLs from system gains and losses, or use in connection with the ongoing operation of the North System. The Partnership, however, may engage in product exchange if there is opportunity to enhance pipeline revenues with little or no commodity risk, and will continue to evaluate any such future opportunities. The products shipped on the North System (line-fill) are owned by the shippers, and no loss allowance or shrinkage deduction is applied. Thus, the Partnership bears the responsibility for gains or losses.
Sources of Products Transported. NGLs extracted or fractionated at the Bushton natural gas processing plant operated by EGP have historically accounted for a significant portion of the NGL volumes transported through the North System. Other sources of NGLs transported in the North System include major and independent oil companies and natural gas processors that use interconnecting pipeline systems to transport hydrocarbons from major producing areas in Texas, Oklahoma, Kansas and the Rocky Mountain region into the market area in and around Bushton, known as Group 140 (Mid-Continent Region). Group 140 fractionators compete for NGL feedstock supply with fractionators in the Gulf Coast market area in Mont Belvieu, Texas. The North System's NGL supply is directly affected by the price differential, adjusted for relevant transportation costs, between these two markets because higher prices obtained in the Gulf Coast market area direct NGLs away from Group 140 to the Gulf Coast.
Principal Products and Markets. The North System's major operations are the transportation, storage and terminaling of NGLs and refined petroleum products along its Main Line. The North System currently serves approximately 50 shippers in the upper Midwest market, including both users and wholesale marketers of NGLs. These shippers include all four major refineries in the Chicago area. Wholesale marketers of NGLs primarily make direct large volume sales to major end-users, such as propane marketers, refineries, petrochemical plants and industrial concerns.
Market demand for NGLs varies in respect to the different end uses to which the NGL products delivered through the North System may be applied. For example, the demand for propane, which is used mainly in connection with residential heating and agricultural uses (agricultural facilities, crop-drying, operating farm equipment, etc.) is seasonal, with high demand occurring during the fall and winter months. The demand for butanes and natural gasoline, which are used primarily by refineries for either further processing or direct blending into gasoline motor fuel, depends in turn on the demand for motor gasoline, the price relationship between NGLs and motor gasolines, and vapor pressure limits. The demand for ethane and to a lesser extent propane and normal butane, which are feedstocks used by petrochemical plants in the production of numerous chemicals, depends on the demand for petrochemical products. Demand for transportation services is influenced not only by demand for NGLs, but also by the available supply of NGLs.
The North System transports refinery grade normal butane produced in the Chicago area to the Bushton, Kansas area (line reversal transport) during the summer months for storage and subsequent transportation north from Bushton back to Chicago area refineries during the winter gasoline blending season. These transportation volumes originating from Chicago area refineries result from more restrictive Environmental Protection Agency ("EPA") vapor pressure limits on motor gasoline during summer months. See "--Regulation--Environmental Matters." As EPA vapor pressure limits continue to force more normal butane out of the motor gasoline blending pool in the summer months, increased line reversal transportation and storage opportunities become available for the North System. To be properly positioned for these opportunities, significant modifications were made on the North System in late summer 1995 to increase the capability to transport additional line reversal volumes of refinery grade butane out of the Chicago area to Bushton for storage and subsequent redelivery in the winter. In 1996, additional storage caverns at Bushton were converted to refinery grade butane service, increasing refinery grade butane storage capacity by 1.65 MMBbls to a total capacity of 3.5 MMBbls.
The following table sets forth volumes of NGLs transported on the North System for delivery to the various markets for the periods indicated:
Year Ended December 31,
1992 1993(1) 1994 1995 1996 ---- ------- ---- ---- ----
(MBbls)
Petrochemicals 11,682 11,201 2,861(2) 1,125 684
Refineries & Line 10,532 9,676 10,478 9,765 9,536 Reversal
Fuels 10,394 8,957 10,039 7,763(3) 10,500
Other (4) 7,033 6,879 6,551 7,114 8,126 ------ ----- ------ ------ ------
Total 39,641 36,713 29,929 25,767 28,846 ====== ====== ====== ====== ======
(1)These volumes reflect the supply constrained conditions in the butane market during January and February 1993 and lower demand for propane in part as the result of warmer weather relative to 1992. (2)The 1994 volumes reflect the loss of the major petrochemical shipper as of February 28, 1994. (3)The 1995 volumes reflect the shut down of a synthetic natural gas plant in 1995. (4)NGL gathering systems and Chicago originations other than long-haul volumes of refinery butanes.
The North System operated at approximately 59% of capacity in 1995 and 66% of capacity in 1996, reversing a three year decline in NGL product moved on the North System. This gain in capacity utilization was caused by a 12.0% gain in NGL product moved on the North System in 1996. The Partnership is attempting to increase its revenues, and regain volumes lost during the past three years due to the loss of several major customers, by pursuing throughput incentive agreements, market development and other strategies. Under the incentive agreements, the applicable tariff rates decrease as the shipper substantially increases its volume on the North System over the term of the agreement. These contracts reflect management's current strategy of pursuing incremental increases in revenue and volumes on the North System through agreements with several shippers. Several of these transactions have been negotiated and placed into service. For instance, with the development and opening of the Tampico, Illinois propane terminal in early 1996, the Partnership entered into two incentive agreements with propane shippers for five-year terms. In addition, the North System also recently entered into three long-term transport agreements. The Partnership anticipates that these types of transactions will provide incremental revenue to the Partnership during 1997.
Competition. The Partnership's North System competes with other liquids pipelines and to a lesser extent rail transporters. In most cases, established pipelines are generally the lowest cost alternative for the transportation of NGLs and refined petroleum products. Therefore, the Partnership's primary competition is represented by pipelines owned and operated by others.
In the Chicago area, the North System competes with other NGL pipelines that deliver into the area and with rail car deliveries primarily from Canada. Other Midwest pipelines and area refineries compete with the North System for propane terminal deliveries. The North System also competes with pipelines that deliver product to markets not served by the North System, such as the Gulf Coast market area.
Rates charged for interstate common carrier NGL transportation are subject to regulation by the FERC. See "--Regulation." Because tariffs charged for transportation on the North System must be competitive with
those charged by other transporters, the Partnership's tariffs are determined based on competitive factors in addition to rate regulation considerations applicable to the North System.
Cypress Pipeline
General. Completed in April 1991, the Cypress Pipeline is an interstate common carrier pipeline, subject to regulation by FERC, that transports purity ethane and is capable of transporting other NGLs. The pipeline originates at storage facilities in Mont Belvieu, Texas and extends 104 miles east to the Lake Charles, Louisiana area. Mont Belvieu, located approximately 20 miles east of Houston, is the largest hub for NGL gathering, transportation, fractionation and storage in the United States and is located at the intersection of multiple long-haul NGL pipelines as well as NGL pipelines for transportation to the Port of Houston, the area with the largest concentration of major petrochemical plants and refineries in the United States. Mont Belvieu also has major storage and rail transportation facilities and access to import and export markets through the Port of Houston. The pipeline was built to service a major petrochemical producer in the Lake Charles, Louisiana area under a 20 year transportation agreement that expires in 2011.
Pipeline Operations. The Cypress Pipeline utilizes a single 1,000 horsepower pump located at Mont Belvieu, which has a current capacity of approximately 32 MBbls/d. A second 800 horsepower pump is available as a back-up. The two pumps can operate simultaneously with a capacity of 37 MBbls/d. Maximum allowable operating pressure of the line is 2,160 pounds per square inch. In 1996, the Partnership entered into an agreement with the petrochemical producer to expand the Cypress Pipeline's current capacity by 25 MBbls/d to 57 MBbls/d. The expansion is expected to be complete by the fourth quarter of 1997.
The petrochemical producer has elected to be an "investor shipper" and as such has the right, exercisable at the end of any year during the contract term, to purchase up to a 50% joint venture interest in the Cypress Pipeline at a price established in accordance with a formula contained in the transportation agreement. The Partnership believes, based on the formula purchase price and current market conditions, that it would be uneconomical for the investor shipper to exercise its buy-in option in the foreseeable future. However, no assurance can be given that the option will not be exercised.
Sources of Products Transported. The Cypress Pipeline originates in Mont Belvieu where it is able to receive ethane from local storage facilities. Mont Belvieu has facilities to fractionate NGLs received from several pipelines into ethane and other components. Additionally, ethane is supplied to Mont Belvieu through pipeline systems that transport specification NGLs from major producing areas in Texas, New Mexico, Louisiana, Oklahoma and the Mid-Continent Region.
Principal Products and Markets. As stated above, the pipeline was built to service a major petrochemical producer in the Lake Charles area. The initial base load for the line is a fixed tariff, ship-or-pay contract with the petrochemical producer for a minimum volume of 30 MBbls/d (on a monthly average) for an initial term of 20 years expiring in 2011. In connection with the expansion of the current capacity of the Cypress Pipeline, the petrochemical producer has entered into a five-year contract to ship or pay for an additional approximate 14 MBbls/d. The Partnership anticipates that the Cypress Pipeline will operate at or near capacity of 57 MBbls/d. In addition, the Cypress Pipeline can also provide transportation services for shippers serving markets east of Mont Belvieu and (through third-party pipelines) markets as distant as the Baton Rouge/Geismar area of Louisiana.
Competition. The Cypress Pipeline competes with several ethane and NGL pipelines in the Gulf Coast corridor and NGLs from other sources, in particular NGLs produced in Louisiana. Its competitive position is affected by the same general competitive factors that affect the North System.
As with the North System, the rates charged for the Cypress Pipeline's interstate common carrier ethane transportation are subject to regulation by the FERC. Because tariffs charged for transportation must be competitive with those charged by other transporters, the Partnership's tariffs are determined based on competitive factors in addition to rate regulation considerations applicable to the Cypress Pipeline.
Central Basin Pipeline
General. Placed in service in 1985, the Central Basin Pipeline consists of approximately 143 miles of 16" to 26" main pipeline and 157 miles of 4" to 12" lateral supply lines located in the Permian Basin between Denver City, Texas and McCamey, Texas. Pursuant to long-term agreements, the Partnership transports CO2 on the Central Basin Pipeline for two independent and 11 major oil companies for use primarily in enhanced oil recovery projects. The Partnership owns the CO2 line fill with the exception of line fill in the El Mar lateral, which is owned by the shipper; however, all shippers bear the benefit and risk of CO2 gains and losses up to 2%. Historically, gains and losses have been less than 2%.
CO2 is used in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. A typical project requires substantial capital expenditures by the producer at the beginning of the project. After the project has been initiated, CO2 generally will continue to be transported to the field for injection throughout the life of the project, which may be for many years. Typically the volumes of CO2 transported will peak after several years and then decline over the life of the project. The customer generally commits to a minimum CO2 ship-or-pay contract for the life of the project.
The Central Basin Pipeline's profitability is dependent on the demand from oil producers in the Permian Basin of Texas for CO2 used in connection with their enhanced oil recovery programs. The level of enhanced oil recovery programs is sensitive to the level of oil prices. The pipeline operated at 15%, 20% and 30% of current capacity during the years 1994, 1995 and 1996, respectively.
Pipeline Operations. The Central Basin Pipeline has a current unpowered capacity in excess of 600 million cubic feet per day ("MMcf/d"). All of the laterals are unpowered, except at Dollarhide, Texas where a 400 horsepower pump boosts the pressure at the delivery end of the lateral. Fifteen delivery points are currently active, including 14 oil field floods (including the addition of deliveries to the South Cowden Unit, East Pennwell Unit, North Cross Unit and Goldsmith San Andres Unit in 1996), and one CO2 trucking operation.
In 1996, revenues increased $3.2 million from 1995 to $9.8 million, and the 1996 average daily volume increased to 171 MMcf/d as compared to volumes of 121 MMcf/d in 1995. The increase in volumes resulted from the start up of four new CO2 floods. The South Cowden and the East Pennwell projects were initiated in the third quarter of 1996 and the North Cross and Goldsmith projects were initiated in the fourth quarter of 1996. Although the operator of the Yates Unit ceased its use of CO2 late in the year, these volumes were offset by an increase in CO2 use by the operator of the Sacroc Unit. The operator of the Sacroc Unit has indicated to the Partnership its intention to further increase its volume by 50 MMcf/d by the end of 1997. However, there can be no assurance that such increase will occur. Additionally, the Partnership entered into a transportation agreement in February 1997 that provides for transportation of CO2 to the Mid Cross Unit, which project is anticipated to commence in the second quarter of 1997.
The South Cowden Unit flood project required construction of a lateral to connect the unit to the Central Basin Pipeline. The lateral is owned by Morgan Associates, Inc. ("MAI"), which is owned by William V. Morgan, an officer and director of the General Partner. MAI also owns approximately 48% of the voting stock of KMI. MAI and the Partnership entered into agreements that provided for construction and operation
of the proposed lateral by the Partnership, and a transportation agreement that allows for the Partnership's use of the lateral and requires the Partnership to ship certain minimum quantities of CO2 on the lateral. See "Certain Relationships and Related Transactions."
Sources of Products Transported. At its origination point in Denver City, the Central Basin Pipeline interconnects with all three major CO2 supply pipelines from Colorado and New Mexico, namely the Cortez, Bravo and Sheep Mountain pipelines (operated by affiliates of Shell, Amoco and ARCO, respectively). These pipelines provide significant purchasing flexibility for shippers on the Central Basin Pipeline and operational flexibility for the Central Basin Pipeline. The mainline terminates near McCamey, where it interconnects with the Canyon Reef Carriers, Inc. pipeline. The eight lateral pipelines terminate in the various oil fields that are being flooded by Central Basin Pipeline shippers.
Principal Markets. The Central Basin Pipeline primarily serves major integrated oil companies and independent producers conducting enhanced oil recovery operations in the Permian Basin of West Texas. To a lesser extent, the Central Basin Pipeline delivers CO2 to a truck terminal located in the North Cowden field, which is operated by a company that delivers CO2 to operators for oil well servicing purposes. The four largest shippers on the Central Basin Pipeline accounted for approximately 51% of the revenues from the Central Basin Pipeline in 1996.
Competition. The Central Basin Pipeline is well located in the heart of the Permian Basin near existing and potential CO2 floods. It nevertheless competes with other CO2 pipelines for supply and sales. Competitive factors include access to CO2 supply, proximity to oil fields amenable to CO2 injection and amounts charged for transportation services. There are alternative processes for enhanced oil recovery projects, including those that use natural gas, nitrogen or surfactants rather than CO2.
Gas Processing and Fractionation
Mont Belvieu Fractionator
General. The Partnership owns an indirect 25% interest in the Mont Belvieu Fractionator, located approximately 20 miles east of Houston in Mont Belvieu, Texas. The Mont Belvieu Fractionator is a full service Y-grade fractionating facility that produces a range of specification products, including ethane, propane, normal butane, isobutane and natural gasoline. The facility was built in 1980 and is operated by Enterprise Products Company ("Enterprise") pursuant to an operating agreement among the owners of the fractionator, including Enterprise. The fractionator has access to virtually all major liquids pipelines and storage facilities located in the Mont Belvieu area. The Partnership owns the stock of Kinder Morgan Natural Gas Liquids Corp. ("KMNGL"). KMNGL owns a 50% interest in Mont Belvieu Associates, which in turn owns a 50% interest in the Mont Belvieu Fractionator. Mont Belvieu Associates is a Texas general partnership owned equally by KMNGL and Enterprise; KMNGL serves as the managing partner. The Partnership's cash flow from its indirect interest in the Mont Belvieu Fractionator depends on the difference between fractionation revenues and fractionation costs (including the level of capital expenditures), as well as demand for fractionation services. The Mont Belvieu Fractionator has two major components: NGL (Y-grade) fractionating and butane splitting. The NGL fractionating component consists of two trains: the West Texas train and the Seminole train. Each train consists of a de-ethanizer, a de-propanizer and a de- butanizer. Each major unit has an associated reboiler and related control equipment. The fractionation process uses heat recovery equipment and cogeneration. Because of the multiple facilities owned by various entities within the perimeter of the plant, there are facilities-sharing agreements for such equipment as the flare, fire control system, roads, laboratory and cogeneration facilities. In December 1996, the total capacity of the fractionator was expanded by approximately 45 MBbls/d to approximately 200 MBbls/d. The
Partnership anticipates that the fractionator will operate at or near the 200 MBbls/d of capacity for 1997. The butane splitter is fed a mix of normal butane and iso-butane by the West Texas and Seminole trains and has a capacity of approximately 42 MBbls/d. A natural gasoline water wash system was approved for installation and was placed in service in the first quarter of 1996. The water wash system is necessary to maintain quality natural gasoline deliveries to the fractionator's customers.
The Mont Belvieu Fractionator operated at approximately 96%, 96% and 100% of capacity, respectively, during 1994, 1995 and 1996.
Sources of Products Fractionated. The Mont Belvieu Fractionator is fed by six major Y-grade pipelines (the Attco, Chevron, Black Lake, Seminole, Chaparral and Panola pipelines). Through several pipeline interconnects and unloading facilities, the Mont Belvieu Fractionator also can access supply from a variety of other sources. Supply can either be brought directly into the facility or directed into underground salt dome storage. The Chaparral and Seminole pipelines gather Y-grade from a variety of natural gas processing plants in Texas, New Mexico, Oklahoma and the Mid-Continent area. The Chevron line transports NGLs from Chevron's East Texas and Central Texas facilities. Black Lake draws its supply from the Northern Louisiana region. The Attco Pipeline draws its supply from South Texas and the Panola pipeline transports NGLs from East Texas. Additionally, import barrels can be brought to the Mont Belvieu Fractionator from locations on the Port of Houston.
Principal Markets. The Mont Belvieu Fractionator is located in proximity to major end-users of its specification products, ensuring consistent access to the largest domestic market for NGL products. In addition, the Mont Belvieu hub has access to deep-water port loading facilities via the Port of Houston, allowing access to import and export markets.
Product is delivered from the tailgate of the Mont Belvieu Fractionator either directly to pipelines or to underground storage. There are numerous delivery lines owned by third parties, including the ARCO Junction, which provide connections throughout the Gulf Coast refinery, storage and petrochemical areas, plus direct connections to TEPPCO, Diamond Shamrock and other outlets. Owners of the facility and third parties using the Mont Belvieu Fractionator have storage contracts with operators of salt dome facilities at Mont Belvieu. Products are delivered to storage at Enterprise, Enron, Warren, Diamond Shamrock and other facilities. Products, as well as Y-Grade, can also be loaded into, and unloaded from, jumbo rail cars nearby.
Competition. The Mont Belvieu Fractionator competes for volumes of Y-grade with three other fractionators located in the Mont Belvieu hub and surrounding areas. Competitive factors for customers include primarily the level of fractionation fees charged and the relative amount of available capacity.
Painter Gas Processing Plant
On June 30, 1994, the Partnership, through OLP-B, acquired the Painter Plant from Enron Gas Processing Company (the "Painter Plant"). The Painter Plant is located near Evanston, Wyoming and consists of a natural gas processing plant, a nitrogen rejection unit, a fractionator, an NGL terminal and interconnecting pipelines with truck and rail loading facilities. The processing plant is a conventional refrigeration-type natural gas processing unit that separates NGLs from the gas. The remaining gas, which contains primarily methane and nitrogen, is then processed to remove the majority of the nitrogen in a nitrogen rejection unit. The nitrogen is used in secondary recovery operations in the producer's oil fields, and the residue gas is delivered into an unaffiliated interstate natural gas pipeline. The Y-grade extracted in the natural gas processing plant is fractionated into propane, mixed butane and natural gasoline products. In
addition, Y-grade from the nearby Amoco Painter Complex Gas Plant ("Amoco Plant") is delivered to the Painter Plant for fractionation. The fractionation facility has a capacity of approximately 6 MBbls/d that varies, depending on the feedstock composition. After fractionation, the propane, mixed butanes and natural gasoline are delivered through three interconnecting NGL pipelines to the Partnership's Millis Terminal and Storage Facility ("Millis"), which is located approximately seven miles from the Painter Plant. Truck and rail loading of fractionated products is provided at Millis, where there is approximately 14 MBbls of above- ground storage for all products.
In 1996, under a contract that was to extend through December 1998, Chevron, USA ("Chevron") was the only gas processing customer at the Painter Plant. In April 1996, the Partnership was notified by Chevron that it was exercising its right to terminate the gas processing agreement at the Painter Plant effective as of August 1, 1996. The gas processing agreement with Chevron allowed for early termination by Chevron, subject to an approximate $2.9 million one time termination payment. On June 14, 1996, a force majeure event occurred and the Painter Plant gas processing facilities were shut down. Chevron subsequently disputed its obligation to pay the early termination payment. The Partnership negotiated with Chevron to settle all claims between the two parties under the gas processing agreement. The Partnership agreed in September 1996 to accept $2.7 million as full and final settlement of all claims. This amount was reduced to $2.5 million in connection with the settlement of certain disputed receivables. Historically, approximately 56% of the revenues from the Painter Plant were generated from processing Chevron gas. Management estimates that the Chevron contract would have generated approximately $3.9 million of revenue during each of the remaining two years of the contract.
On February 14, 1997, the Partnership executed an operating lease agreement with Amoco Oil Company ("Amoco") for Amoco's use of the Painter Plant fractionator and the Millis facilities with the nearby Amoco Painter Complex Gas Plant. The lease will generate approximately $1.0 million of cash flow in 1997 with annual escalations thereafter. The primary term of the lease expires February 14, 2007, with evergreen provisions at the end of the primary term. Amoco will take assignment of all of the commercial arrangements currently in place, and will assume all day to day operations, maintenance, repairs, and replacements, and all expenses (other than minor easement fees), taxes and charges associated with the fractionator and the Millis facilities. After lease year seven, Amoco may elect to purchase the fractionator and Millis facilities under certain terms. A portion of the gas processing facilities and the nitrogen rejection unit at the Painter Plant remain operationally idle. The Partnership continues to assess its alternatives for these idled facilities.
Gas Processing Agreement and Subleased Capacity from EGP
General. On October 1, 1995, Enron Gas Processing Company ("EGP") assigned to the Partnership its rights and duties under a gas processing contract with Mobil Natural Gas, Inc. (the "Mobil Agreement"). Under the Mobil Agreement, the Partnership is obligated to process dedicated volumes of natural gas produced by Mobil from a prolific geological formation located in Kansas and commonly known as the Hugoton Embayment. Also on October 1, 1995, the Partnership subleased from EGP a portion of the capacity at the Bushton gas processing plant located in Ellsworth County, Kansas (the "Bushton Plant"). The leased capacity at the Bushton Plant enables the Partnership to fulfill the processing obligations it assumed in the Mobil Agreement. The Mobil Agreement and the sublease agreement are coterminous with primary terms ending April 30, 2005. As a result of these transactions, the Partnership receives processing fees from Mobil and makes sublease payments to EGP. It is anticipated that the fees generated under the Mobil Agreement will be greater than the sublease payments.
Agreements. Under the terms of the Mobil Agreement, the Partnership is paid a processing fee for extracting NGLs from the "wet" gas received from Mobil into its constituent components. Mobil retains legal
title to the natural gas delivered to the plant and to the contractually specified volumes of extracted NGLs and the resulting residue gas at the outlet of the plant. Furthermore, Mobil provides the fuel to power the processing of its gas at Bushton and bears the loss for the shrinkage of the natural gas stream experienced during such processing. Under the Mobil Agreement, the Partnership does not provide the storage or transportation of any NGLs generated as a result of processing.
The Mobil Agreement provides that Mobil is entitled to receive specified volumes of NGLs attributable to the processing of Mobil's gas based upon the NGLs contained in one thousand cubic feet of natural gas processed. The Partnership is allowed to retain any NGLs produced in excess of the contractually specified volumes. For any NGLs that are retained, however, the Partnership is obligated to reimburse Mobil with a quantity of natural gas containing an equivalent BTU content. Additionally, the Partnership must bear the cost of the plant fuel for the retained NGLs. Typically, this exchange of natural gas for NGLs is profitable for the Partnership, because normally NGLs have a higher market value than natural gas.
The Mobil Agreement requires the Partnership to redeliver Mobil's residue gas at applicable minimum pipeline heating value specifications. The Partnership accomplishes this by obtaining additional volumes of natural gas to blend with Mobil's residue gas to achieve such minimum pipeline heating value specifications. In consideration for this blending service, the Partnership retains an equivalent thermal quantity of propane extracted from Mobil's gas. The Partnership acquires the additional volumes of natural gas needed for blending through a physical requirements swap transaction whereby the Partnership receives physical volumes of natural gas needed, if any, in exchange for a thermally equivalent volume of propane equal to the quantity retained under the Mobil Agreement.
Both gas composition and plant operation can affect NGL recovery. The difference between actual plant recoveries and the fixed recoveries specified in the Mobil Agreement is borne by the Partnership. The Partnership believes that, while plant recoveries vary, they are consistent over time and that gas composition from this production area is stable. Therefore, plant recoveries and gas composition should result in only minimal uncertainty, although the Partnership cannot guarantee this result.
Under the terms of the sublease agreement, the Partnership pays EGP a monthly sublease payment consisting of a variable and a fixed component. The variable component is based on actual gallons of NGLs recovered from Mobil's gas. The fixed component is an agreed amount that is paid even if Mobil fails to deliver gas for processing. Mobil's failure to deliver gas for processing would result from either a depletion of Mobil's gas reserves, a decision by Mobil to shut-in gas production or an election by Mobil to not process its gas. The Partnership believes that these risks are minimal based on history, economics, operating factors and other ancillary matters. No assurance can be given, however, that the monthly fees generated from the Mobil Agreement will exceed the monthly sublease payments.
Coal Transfer and Storage
Cora Terminal--Coal Transfer and Storage
Terminal. On September 30, 1993, the Partnership acquired, through OLP-B, a high-speed, rail-to-barge coal transfer and storage facility from Cora Dock Corporation ("Cora"), an indirect wholly-owned subsidiary of Enron. The terminal (the "Cora Terminal") is located on approximately 480 acres of land along the upper Mississippi River at mile marker 98.5, near Cora, Illinois, about 80 miles south of St. Louis. It was built in 1980 at an initial cost of approximately $24 million. Its equipment includes 3.5 miles of railroad track, a rotary dumping station and train indexer, a multi-directional coal stacker/reclaimer, approximately 4,000 feet of conveyor belts and an anchored terminaling facility on the Mississippi River that takes advantage of
approximately five miles of owned and leased available riverfront access with approximately 7,000 feet developed. The terminal has a throughput capacity of about 12 million tons per year, and it can be expanded to 20 million tons with certain capital additions. The facility's equipment permits it continuously to unload 115-car unit trains at a rate of 3,500 tons per hour. The terminal can transfer the coal to a storage yard or unload to barges at a rate up to 5,700 tons per hour. The railroad track can accommodate two 115-car trains simultaneously. The riverfront access permits the fleeting of up to 100 barges at once. The terminal also has automatic sampling, programmable controls, certified belt scales, computerized inventory control and the ability to blend different types of coal. The terminal currently is equipped to store up to 500,000 tons of coal, which gives customers the flexibility to coordinate their supplies of coal with the demand at power plants. Anticipated capital expenditures for 1997 include expanding the storage yard to store up to 1.0 million tons of coal and to improve the terminal's blending capacity.
Terminal Operations. Cora Terminal generates revenue from transloading coal from rail cars and trucks to river barges, storage of coal, blending of coal and harbor services. Cora is operated on three shifts per day with an experienced, full-time staff of 29 persons employed by the General Partner, including seven non- union employees and 22 hourly personnel who are represented by the International Union of Operating Engineers under a collective bargaining agreement that expires September 1998. Operations at the facility are directed by a lead manager who participated in the design and construction of the facility. The General Partner considers its relations with the union to be good.
Sources of Products Transferred. Historically, the Cora Terminal has moved coal that originated in the mines of southern Illinois. Many shippers, however, particularly in the East, are now using western coal loaded at the Cora Terminal or a mixture of western coal and Illinois coal as a means of meeting environmental restrictions. The General Partner believes that Illinois coal producers and shippers will continue to be important customers in the terminal's business, but anticipates that the real growth in volume through the terminal will be western coal originating in Wyoming, Colorado and Utah.
The Cora Terminal sits on the mainline of the Union Pacific Railroad ("Union Pacific"). Mines in southern Illinois and in Wyoming (Hanna and Powder River basins) are within the Union Pacific's service area and its connecting lines. With the recent merger of the Union Pacific and Southern Pacific Railroads, coal mined in the Colorado and Utah basins can now be shipped through the Cora Terminal. Union Pacific is one of only two major rail lines connected to the western mines that ship coal to the East. It serves major coal companies that have substantial developed and undeveloped reserves.
Principal Markets. Three major customers ship approximately 80% of all the coal loaded through the terminal: Franklin Coal Company ("Franklin"), Indiana-Kentucky Electric Corporation ("IKEC") and Carboex International Limited ("Carboex"). The agreement with Franklin was entered into in 1981 and will terminate in December 2004. The IKEC agreement was entered into in 1994 and will also terminate in December 2004. The agreement with Carboex was entered into in 1995 and will expire in December of 1998, but includes an option for Carboex to extend through December of 2001. The Partnership recently entered into an agreement in principle to ship western coal for a major Southeastern utility.
Coal still dominates as a fuel for electric generation, holding more than 55% of the capacity. Forecasts of overall coal usage and power plant usage for the next 20 years show an increase of about 1.5% per year. Current domestic supplies are predicted to last for more than 300 years. Most of the Cora Terminal's volume is destined for use in coal-fired electric generation. The market for southern Illinois coal is stagnant and not expected to grow because of changing supply and demand conditions in domestic and international markets. The Partnership believes that obligations to comply with the Clean Air Act Amendments of 1990 will drive shippers to increase the use of the low-sulfur coal from the western United States. Approximately 80% of
the coal loaded through the Cora Terminal originates from mines located in the Western United States' Hanna and Powder River basins. During the three years ended December 31, 1996, 1995 and 1994, the Cora Terminal handled approximately 6.0 million tons, 6.5 million tons and 4.5 million tons of coal, respectively. The Partnership is actively marketing the services of the Cora Terminal and anticipates that the terminal will handle approximately 10 million tons in 1997. However, the Partnership does not currently have commitments with respect to all of these volumes and there can be no assurance that the Partnership will achieve such volumes.
Competition. The Cora Terminal competes with six other terminal facilities. Two of these are located in St. Louis; one is connected to the Burlington Northern Railroad and the other to the Union Pacific Railroad. Both compete with Cora for western coal. A third terminal, located at Metropolis, Illinois, is primarily a private use terminal and is owned by a consortium of electric power companies. The fourth terminal, located on the Tennessee River, is connected to the Paducah and Louisville Railroad and competes with Cora for southern Illinois coal moving to power plants on the Tennessee and Cumberland Rivers. The fifth terminal, situated 25 miles north of the Cora Terminal, is connected to the Union Pacific Railroad. This terminal is primarily a private use facility. The sixth terminal is located north of St. Louis on the Mississippi River and is connected to the Burlington Northern Railroad. The Partnership believes that the Cora Terminal can compete successfully with these other terminals because of its favorable location, independent ownership, available capacity, modern equipment and large storage area.
No new coal terminals have been constructed on the Mississippi and Ohio rivers in the last 10 years. The Partnership believes that there are significant barriers to entry for the construction of new coal terminals, including the requirement for significant capital expenditures and restrictive environmental permitting requirements.
The Partnership plans to expand its market position in coal terminaling, loading and storage and continues to evaluate the potential acquisition of other terminaling operations to enhance its position of moving western coal into the export and eastern utility markets.
Regulation
Interstate Common Carrier Regulation
The Partnership's North System and Cypress Pipeline are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act ("ICA"). As interstate common carriers, these pipelines provide service to any shipper who requests transportation services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The ICA requires the Partnership to maintain tariffs on file with the FERC, which tariffs set forth the rates the Partnership charges for providing transportation services on the interstate common carrier pipelines as well as the rules and regulations governing these services.
The ICA gives the FERC authority to regulate the rates the Partnership charges for service on the interstate common carrier pipelines. The ICA requires, among other things, that such rates be "just and reasonable" and nondiscriminatory. The ICA permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively.
Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
On October 24, 1992, Congress passed the Energy Policy Act of 1992 ("Energy Policy Act"). The Energy Policy Act deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the ICA (i.e., "grandfathered"). The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. The rates the Partnership charges for transportation service on its North System and Cypress Pipeline were not suspended or subject to protest or complaint during the relevant 365-period established by the Energy Policy Act. For this reason, the Partnership believes these rates should be grandfathered under the Energy Policy Act.
The Energy Policy Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines (including NGL pipelines), and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561, which, among other things, adopted a new indexing rate methodology for petroleum pipelines. Under the regulations, which became effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made within the ceiling levels will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates and settlement as alternatives to the indexing approach, which alternatives may be used in certain specified circumstances. FERC Order No. 561-A, affirming and clarifying Order No. 561, expands the circumstances under which petroleum pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. In 1995 and 1996, application of the indexing methodology did not significantly affect the Partnership's rates.
Although the grandfathering of base rates and the automatic indexing of rate changes to inflation provides relative certainty regarding the maximum lawful rates, the rates charged for transportation must be competitive with those charged by other transporters.
State and Local Regulation
The Partnership's activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, pollution, protection of the environment, safety and other matters.
Safety Regulation
The Liquids Pipelines and the pipelines connecting the Millis to the Painter Plant are subject to regulation by the United States Department of Transportation ("D.O.T.") with respect to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. In addition, the partnership must permit access to and copying of records, and make certain reports and provide information as required by the Secretary of Transportation. Comparable regulation exists in some states in which the Partnership conducts pipeline operations. In addition, the Partnership's truck and rail loading facilities are subject to D.O.T. regulations dealing with the transportation of hazardous materials for motor vehicles and rail cars.
Pipeline safety issues currently are receiving significant attention in various political and administrative forums at both the state and federal levels. Significant expenses could be incurred if additional safety requirements are imposed that exceed the current pipeline control system capabilities.
The Liquids Pipelines, the Mont Belvieu Fractionator, the Cora Terminal and the Painter Plant are subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The Partnership believes that its pipelines, the Cora Terminal and the Painter Plant (which are operated by the Partnership) have been operated in substantial compliance with OSHA requirements, including general industry standards, recordkeeping requirements and monitoring of occupational exposure to benzene and other regulated substances.
In general, the Partnership expects to increase expenditures in the future to comply with higher industry and regulatory safety standards such as those described above. Such expenditures cannot be accurately estimated at this time, although the Partnership does not expect that such expenditures will have a material adverse impact on the Partnership, except to the extent additional hydrostatic testing requirements are imposed.
Environmental Matters
General. The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. The Partnership believes that its operations and facilities are in general compliance with applicable environmental regulations. The Partnership has an ongoing environmental audit and compliance program. Risks of accidental leaks or spills are, however, associated with fractionation of NGLs, transportation of NGLs and refined petroleum products, the handling and storage of coal, the processing of gas, as well as the truck and rail loading of fractionated products. There can be no assurance that significant costs and liabilities will not be incurred, including those relating to claims for damages to property and persons resulting from operation of the Partnership's businesses. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, could result in increased costs and liabilities to the Partnership.
Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and the Partnership anticipates that there will be continuing changes. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may impact the environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for the Partnership and other similar businesses throughout the United States, and it is possible that the costs of compliance with environmental laws and regulations will continue to increase. The Partnership will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
Solid Waste. The Partnership owns several properties that have been used for NGL transportation and storage and coal storage for many years. Solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years with the passage and implementation of various environmental laws and regulations. A possibility exists that hydrocarbons and other solid wastes may have been disposed of on or under various properties owned by the Partnership during the operating history of these facilities. In such cases, hydrocarbons and other solid wastes could migrate from their original disposal areas and have an adverse effect on groundwater. The Partnership does not believe that there presently exists significant surface or subsurface contamination of its assets by hydrocarbons or other solid wastes.
The Partnership will generate both hazardous and nonhazardous solid wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. From time to time United States Environmental Protection Agency ("EPA") considers the adoption of stricter disposal standards for nonhazardous waste. Furthermore, it is possible that some wastes that are currently classified as nonhazardous, which could include wastes currently generated during pipeline operations, may in the future be designated as "hazardous wastes." Hazardous wastes are subject to more rigorous and costly disposal requirements. Such changes in the regulations may result in additional capital expenditures or operating expenses by the Partnership.
Superfund. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of its ordinary operations the Partnership will generate wastes that may fall within the definition of a "hazardous substance." The Partnership may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.
EPA Gasoline Volatility Restrictions. In order to control air pollution in the United States, the EPA has adopted regulations that require the vapor pressure of motor gasoline sold in the United States to be reduced from May through mid-September of each year. These regulations mandated vapor pressure reductions beginning in 1989, with more stringent restrictions beginning in 1992. States may impose additional volatility restrictions. The regulations have had a substantial effect on the market price and demand for normal butane, and to some extent isobutane, in the United States. Butanes are used by gasoline manufacturers in the production of motor gasolines. Since normal butane is highly volatile, it is now less desirable for use in blended gasolines sold during the summer months. Although the EPA regulations have reduced demand and may have resulted in a significant decrease in prices for normal butane, low normal butane prices have not impacted the Liquids Pipelines business in the same way they would impact a business with commodity price risk. The EPA regulations have presented the opportunity for additional transportation services on the North System. In the summer of 1991, the North System began long-haul transportation of refinery grade normal butane produced in the Chicago area to the Bushton, Kansas area for storage and subsequent transportation north from Bushton during the winter gasoline blending season. These additional transportation volumes produced at Chicago area refineries resulted from the more restrictive EPA vapor pressure limits on motor gasoline.
Clean Air Act. The operations of the Partnership are subject to the Clean Air Act and comparable state statutes. The Partnership believes that the operations of the Liquids Pipelines, the Mont Belvieu Fractionator, the Cora Terminal and the Painter Plant are in substantial compliance with such statutes.
Numerous amendments to the Clean Air Act were adopted in 1990. These amendments contain lengthy, complex provisions that may result in the imposition over the next several years of certain pollution control requirements with respect to air emissions from the operations of the Liquids Pipelines, the Mont Belvieu Fractionator and the Painter Plant. The EPA is developing, over a period of many years, regulations to implement those requirements. Depending on the nature of those regulations, and upon requirements that may be imposed by state and local regulatory authorities, the Partnership may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining
or obtaining operating permits and approvals and addressing other air emission-related issues. Due to the broad scope and complexity of the issues involved and the resultant complexity and controversial nature of the regulations, full development and implementation of many of the regulations has been delayed. Until such time as the new Clean Air Act requirements are implemented, the Partnership is unable to estimate the effect on earnings or operations or the amount and timing of such required capital expenditures. At this time, however, the Partnership does not believe it will be materially adversely affected by any such requirements.
Item 2.

Item 2. Properties
The Partnership believes that in all material respects it has satisfactory title to all of its assets. Although such properties are subject to liabilities in certain cases, such as customary interests generally contracted in connection with acquisition of real property, any environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor encumbrances, the Partnership believes that none of such burdens will materially detract from the value of such properties or from the Partnership's interest therein or will materially interfere with their use in the operation of the Partnership's business. Substantially all of the property, plant and equipment associated with the Liquids Pipelines, the Cora Terminal and the Painter Plant are subject to mortgages.
The Partnership conducts business and owns properties located in 10 states. The Liquids Pipelines are, in general, located on land owned by others and are operated under perpetual easements or rights-of-way granted by land owners. Where Partnership facilities are located on or cross public property, railways, rivers, roads or highways, or similar crossings, they are operating under permits or easements from public authorities, railways or public utilities, some of which are revocable at the election of the grantor. The Painter Plant is located on Bureau of Land Management land that is leased to the Partnership and Enron (50% each) until September of 2009. Millis is located on private lands and is under lease to the Partnership until September of 2009. The Cora Terminal is located on lands owned by the Partnership and on private lands under lease to the Partnership. The primary lease for Cora Terminal expires December 2015.
The right to construct and operate the Liquids Pipelines across certain property was obtained through the right of eminent domain by predecessors in title to the Partnership. The Partnership has been advised by counsel in Indiana, Iowa, Kansas, Louisiana, Missouri, Nebraska and Texas that the Partnership has the power of eminent domain in such states with respect to the North System and the Cypress Pipeline assuming the Partnership meets certain requirements, which differ from state to state. While there can be no assurance, the Partnership believes that it will meet such requirements in such states. The Partnership has been advised by counsel in Illinois that it does not have the power of eminent domain in such state. The Partnership does not believe that it has the power of eminent domain with respect to the Central Basin Pipeline. The inability of the Partnership to exercise the power of eminent domain could have a material adverse effect on the business of the Partnership in those instances where the Partnership does not have the right through leases, easements, rights-of-way, permits or licenses to use or occupy the property used for the operation of the Liquids Pipelines and where the Partnership is unable to obtain such rights.
Item 3.

Item 3. Legal Proceedings
The Partnership, in the ordinary course of business, is a defendant in various lawsuits relating to the Partnership's assets. The liabilities, if any, associated with any lawsuits pending at the time of the formation of the Partnership were retained by Enron and not assumed by the Partnership. Pursuant to an Omnibus Agreement with Enron (the "Omnibus Agreement"), the General Partner agreed to cause the Partnership, at the Partnership's expense, to cooperate with Enron in the defense of any such litigation by furnishing information relating to the Partnership's assets involved in the litigation, furnishing access to files and
otherwise assisting in the defense. The costs to the Partnership relating to such agreement have not been and are not expected to be significant. In addition, Enron agreed to indemnify the Partnership for any losses incurred in connection with the lawsuits pending at the time of formation of the Partnership. In connection with the sale of the Common Stock of the General Partner to KMI, Enron agreed to assume liability, and indemnify the Partnership, for certain lawsuits currently pending.
The General Partner is a defendant in a suit filed on September 12, 1995 by the State of Illinois. The suit seeks civil penalties and an injunction based on five counts of environmental violations for events relating to a fire that occurred at the Morris storage field in September, 1994. The fire occurred when a sphere containing natural gasoline overfilled and released product which ignited. There were no injuries, and no damage to property, other than Partnership property. The suit seeks civil penalties in the stated amount of up to $50,000 each for three counts of air and water pollution, plus $10,000 per day for any continuing violation. The State also seeks an injunction against future similar events. On August 29, 1996, the Illinois Attorney General's office proposed a settlement in the form of a consent decree that would require the Partnership to implement several fire protection recommendations, pay a $100,000 civil penalty, and pay a $500 per day penalty if established deadlines for implementing the recommendations are not met. The Partnership has made a settlement offer to the State and settlement negotiations are ongoing.
On December 10, 1996, the D.O.T issued to the General Partner a notice of eight probable violations of federal safety regulations in connection with the fire at the Morris storage field. The DOT proposed a civil penalty of $90,000. The General Partner is currently in the process of responding to the notice, but believes that the alleged violations and proposed fine will not have a material impact on the Partnership.
It is expected that the Partnership will reimburse the General Partner for any liability or expenses incurred by the General Partner in connection with these legal proceedings.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during the fourth quarter of 1996.
PART II
Item 5.

Item 5. Market for the Registrant's Common Units and Related Security Holder Matters
The following table sets forth, for the periods indicated, the high and low sale prices per Common Unit, as reported on the New York Stock Exchange, the principal market in which the securities are traded, and the amount of cash distributions paid per Common Unit.
Price Range Cash High Low Distributions ---- --- ------------- ---- First Quarter $26.375 $24.375 $0.63 Second 26.000 24.875 0.63 Quarter Third Quarter 28.125 25.375 0.63 Fourth 29.125 25.625 0.63 Quarter
First Quarter $26.000 $24.250 $0.63 Second Quarter 26.500 24.125 0.63 Third Quarter 26.750 25.125 0.63 Fourth Quarter 26.875 23.875 0.63
As of December 31, 1996, there were approximately 725 record holders of the Partnership's Common Units and there were an estimated 9,870 beneficial owners of the Common Units, including Common Units held in street name.
Following termination of the deferral period on September 30,1994, the Partnership began making distributions in respect of the limited partnership interests held by the General Partner on a pro rata basis with the Common Units. On February 14, 1997, these limited partnership interests were converted into Common Units. See "Certain Relationships and Related Transactions."
(1) Excluding the effect of construction costs related to the Cypress Pipeline, additions to property, plant and equipment would have been $3,837 for the seven-month period ended July 31, 1992. Additions to property, plant and equipment for 1993 and 1994 exclude the $25,291 and the $12,825 of assets acquired in the September 1993 Cora Terminal and June 1994 Painter Gas Processing Plant (Painter Plant) acquisitions, respectively. (2) Represents total volumes for the Mont Belvieu Fractionator and the Painter Plant (beginning in 1994). (3) Represents the volumes of the gas processing portion of the Painter Plant, which has been operationally idle since June 1996. (4) Represents the volumes of the Bushton facility (beginning in October, 1995). (5) Represents the volumes of the Cora Terminal, excluding ship or pay volumes of 252 Mtons for 1996.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations of the Partnership
Year Ended December 31, 1996 Compared With Year Ended December 31, 1995
Net income of the Partnership increased to $11.9 million in 1996 from $11.3 million in 1995. The 5.3% increase is primarily due to increased operating earnings from the Central Basin Pipeline and a $2.5 million buyout payment received from Chevron for early termination of a gas processing contract at the Painter Plant, which were partially offset by lower operating earnings from the Painter Plant, the North System and Cora Terminal.
Revenues of the Partnership increased 10.9% to $71.3 million in 1996 compared to $64.3 million in 1995. The increase in revenues was due primarily to a 42.4% increase in transport volumes on the Central Basin Pipeline combined with a full year of revenues earned at the Bushton Facility in connection with the Mobil Agreement, which was assigned to the Partnership as of October 1, 1995 (see Note 10 in the Notes to Consolidated Financial Statements). Additionally, revenues on the North System increased due to a 12.2% increase in transport volumes resulting from a favorable crop drying season and colder weather. These increases were offset by lower revenues at the Painter Plant due to the Chevron gas processing contract termination and unscheduled downtime due to an equipment malfunction.
Cost of products sold decreased $.1 million (1.8%) in 1996 as compared to 1995 primarily due to reduced product sales on the North System.
Operating expense, which includes operations and maintenance expense, fuel and power costs and taxes other than income taxes, increased 37.2% to $27.3 million in 1996 compared to $19.9 million in 1995 due to expenses incurred in connection with the Mobil Agreement. Additionally, operating expense increased $.9 million as a result of a new storage agreement with a Partnership affiliate on the North System that went into effect on January 1, 1996. The new storage agreement increases the North System's storage capacity at Bushton, Kansas from 1.5 MMBbls to 5.0 MMBbls.
Depreciation expense increased $.4 million (3.8%) during 1996 as compared to 1995 primarily as a result of 1996 property additions.
General and administrative expenses increased $0.4 million (4.5%) in 1996 as compared to 1995 primarily due to a 6% annual increase in reimbursements to Enron for services provided to the partnership by Enron and its affiliates in accordance with the Omnibus Agreement.
Interest expense increased $0.2 million (1.4%) in 1996 as compared to 1995 primarily as a result of increased borrowings under OLP-A's working capital facility due to borrowings for expansion capital expenditures.
Other income increased 127.9% to $3.3 million in 1996 as compared to $1.4 million in 1995 primarily due to the $2.5 million buyout payment received from Chevron in 1996. (See Note 3 in the Notes to Consolidated Financial Statements). In addition, other income for 1995 included a $0.5 million business interruption insurance settlement related to a previous year event on the North System.
Year Ended December 31, 1995 Compared With Year Ended December 31, 1994
Net income of the Partnership increased 1.8% to $11.3 million in 1995 from $11.1 million in 1994. The increase reflects a full year of earnings from the Painter Plant acquisition (see Note 3 in the Notes to Consolidated Financial Statements) and higher earnings on the Central Basin Pipeline and Cora Terminal, partially offset by lower
earnings on the North System and the Cypress Pipeline and lower equity earnings from the Mont Belvieu Associates partnership.
Revenues of the Partnership increased $9.4 million (17.1%) for the year ended December 31, 1995, as compared to 1994. The increase in revenue was due primarily to increased product sales on the North System and the Central Basin Pipeline, the inclusion of a full year of operations at the Painter Plant, acquired June 1994, and an increase in coal volumes handled at the Cora Terminal. Additionally, revenues increased approximately $1.4 million due to three months of revenue from the Mobil Agreement. These increases were offset by a decrease in volumes transported to refineries on the North System due to temporary downtime at two major customers' facilities combined with the effect of Gulf Coast product prices being more favorable than prices in the Midwest, which caused product to move into the Chicago area on pipelines from the Gulf Coast. In July 1995, a customer of a major North System shipper closed its synthetic natural gas facility in the Chicago area. The Partnership had been delivering approximately 2 MMBbls of ethane to the facility annually. Loss of these volumes resulted in an approximate $1.2 million loss of revenues in the last half of 1995 compared to the same period in 1994.
Cost of products sold increased significantly on both the North System and the Central Basin Pipeline primarily because of selling arrangements which allow for increased throughput, but nominal gross margin.
Operating expense increased $0.7 million (3.9%) in 1995 as compared to 1994 primarily because of the inclusion of a full year of operations at the Painter Plant and because of $1.2 million of operating expenses incurred during 1995 related to the Mobil Agreement. These increases were offset by lower operating expenses incurred on the North System as a result of lower transport volumes.
Depreciation expense increased $1.0 million (11.8%) during 1995 as compared to 1994 primarily as a result of the inclusion of a full year of operation at the Painter Plant.
General and administrative expenses increased $0.5 million (6.6%) in 1995 as compared to 1994 primarily due to a 6% annual increase in reimbursements to Enron for services provided to the Partnership by Enron and its affiliates in accordance with the Omnibus Agreement as well as the inclusion of the Painter Plant operations.
Interest expense increased $0.5 million (3.9%) in 1995 as compared to 1994 primarily as a result of the addition of debt related to the acquisition of the Painter Plant.
Other income increased $0.8 million (129.3%) in 1995 as compared to 1994 primarily because of a $0.5 million business interruption insurance settlement received in 1995 related to a previous year event on the North System.
Outlook
Under the new management, the Partnership intends to actively pursue a strategy to increase the Partnership's operating income. A three-pronged strategy will be utilized to accomplish this goal.
o Cost Reductions. The Partnership has substantially reduced its general and administrative expenses and will continue to seek further reductions where appropriate.
o Internal Growth. The Partnership intends to expand the operations of its current facilities. The Partnership has taken a number of steps that management believes will increase revenues from existing operations, including the following:
An agreement has been reached with the principal shipper on the Cypress Pipeline to expand the capacity of the pipeline effective in the fourth quarter of 1997.
The Cora Terminal is expected to handle approximately 10 million tons during 1997 as a result of an anticipated agreement with a major southeastern utility and other new business.
The volume handled by the Central Basin Pipeline is expected to increase in 1997 as a result of several new agreements.
The Painter Fractionator and Millis Terminal have been leased to Amoco on a long-term basis effective in the first quarter of 1997.
See "Item 1. Business" for a more detailed discussion regarding these and other developments.
o Strategic Acquisitions. The Partnership intends to seek opportunities to make strategic acquisitions to expand existing businesses or to enter into related businesses. The Partnership has identified several potential acquisitions, although no assurance can be given that the Partnership will be able to consummate such acquisitions. Management anticipates that acquisitions will be financed temporarily by bank bridge loans and permanently by a combination of debt and equity funding from the issuance of new Common Units.
Management intends to increase the quarterly distribution from $.63 per Unit to $.80 per Unit in the second quarter of 1997, which distribution would be payable in August 1997.
The Partnership intends to seek to refinance or restructure the $110 million First Mortgage Notes ("First Mortgage Notes") and its bank credit facilities during 1997. However, there can be no assurances that the Partnership will be able to refinance or restructure such indebtedness on terms favorable to the Partnership.
Financial Condition
General
The Partnership's primary cash requirements, in addition to normal operating expenses, are debt service, sustaining capital expenditures, discretionary capital expenditures and quarterly distributions to partners. In addition to utilizing cash generated from operations, the Partnership could meet its cash requirements through the utilization of credit facilities or by issuing additional limited partner interests in the Partnership.
Enron has the support obligation to contribute cash, if necessary, to the Partnership through September 30, 1997 in exchange for additional partnership interests (API's) to support the Partnership's ability to distribute the Minimum Quarterly Distribution (the "Minimum Quarterly Distribution") of $.55 per Unit as required by the Omnibus Agreement among the Partnership, the General Partner and Enron. KMI has obtained a $10.9 million letter of credit from First Union National Bank of North Carolina ("First Union") to support Enron's remaining obligations with respect to the Minimum Quarterly Distribution payable to the holders of the Partnership's Common Units.
In connection with KMI's acquisition of the General Partner, OLP-B entered into a credit agreement with First Union which provided for a $15.9 million revolving credit facility. The obligations of OLP-B under the credit agreement are guaranteed by the Partnership. Borrowings under the credit facility are due February 14, 1999 and bear interest, at OLP-B's option, at either First Union's Base Rate plus .5% per annum or London Interbank Offered Rate ("LIBOR") plus 2.25% per annum (in each case increasing by .25% as of the end of each calendar quarter commencing June 30, 1997). The new credit facility (i) refinanced approximately $4.4 million owed by OLP-B to Enron and (ii) replaced OLP-B's existing credit facility with First Union, which had approximately $9.6 million outstanding as of February 14, 1997. As of March 1, 1997, the Partnership's outstanding borrowings under the Credit Facility were $14.6 million. The Partnership's ability to borrow additional funds under the credit facility is subject to compliance with certain financial covenants and ratios. The new credit facility also provides for an approximate $24.1 million letter of credit that has been issued by First Union to replace a letter of credit previously
issued by Wachovia Bank of Georgia, N.A. and which was guaranteed by Enron supporting the Cora Terminal revenue bonds. The letter of credit fee has increased from .25% per annum to 1.50% per annum.
OLP-A has established a $15 million revolving credit agreement facility with a bank to meet its working capital requirements. As of March 1, 1997, the outstanding borrowings under the credit facility were $13 million. The Partnership also has the ability to borrow up to an additional $25.0 million in accordance with the provisions of the First Mortgage Notes.
In order to finance the acquisition of the General Partner, KMI borrowed $15 million from First Union. The loan is due August 31, 1999 and bears interest, at the option of KMI, at either First Union's Base Rate plus .5% per annum or LIBOR plus 2.5% per annum. The borrowings by KMI from First Union are secured by a pledge of all of the stock of the General Partner. In addition, the General Partner pledged all of the Common Units owned by it as additional collateral for the loans. The Credit Agreement requires First Union's consent for, among other things, (i) the merger or consolidation of the Partnership with any other person, (ii) the sale, lease or other disposition of all or substantially all of the Partnership's property or assets to any other person or (iii) the issuance of any additional Common Units.
Cash Provided by Operating Activities
Cash flow from operations totaled $22.8 million for the year ended December 31, 1996 compared to $22.6 million in 1995. The increase is primarily due to higher earnings and increased distribution from investments in partnerships, partially offset by increased working capital requirements.
Cash Used in Investing Activities
Cash used in investing activities increased 5.8% to $9.1 million during 1996 as compared to $8.6 million during 1995. Additions to property, plant and equipment totaled $8.6 million and $7.8 million for 1996 and 1995, respectively. Property additions in 1996 increased primarily due to a new propane terminal on the North System and pipeline laterals on the Central Basin Pipeline.
Cash Used in Financing Activities
Cash used in financing activities increased 25.9% to $13.6 million for the year ended December 31, 1996 as compared to $10.8 million during 1995. Cash used during 1996 and 1995 primarily reflected distributions to Unitholders partially offset by a net increase in long-term debt in the amount of $3.3 million and $6.7 million, respectively, to finance capital expansion projects on the Central Basin Pipeline and the North System.
Information Regarding Forward Looking Statements
This filing includes forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Partnership believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Price trends and overall demand for NGLs, CO2 and coal in the United States and the condition of the capital markets and equity markets could cause actual results to differ from those in the forward looking statements herein.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page.
Item 9. Changes in and Disagreements on Accounting and Financial Disclosure
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
Directors and Executive Officers of the General Partner
As is commonly the case with publicly-traded limited partnerships, the Partnership does not employ any of the persons responsible for managing or operating the Partnership, but instead reimburses the General Partner for their services. Set forth below is certain information concerning the directors and executive officers of the General Partner. All directors of the General Partner are elected annually by, and may be removed by, KMI as the sole shareholder of the General Partner. All officers serve at the discretion of the directors of the Board of Directors of the General Partner.
Name Age Position with the General Partner Richard D. Kinder 52 Director, Chairman and CEO William V. Morgan 53 Director and Vice Chairman Alan L. Atterbury 54 Director Edward O. Gaylord 65 Director Thomas B. King 35 Director and President Thomas P. Tosoni 46 Chief Financial Officer and Assistant Secretary Michael C. Morgan 28 Vice President, Corporate Development David G. Dehaemers, Jr. 36 Secretary and Treasurer Roger C. Mosby 49 Vice President
Richard D. Kinder was elected Director, Chairman and CEO of the General Partner in February 1997. From 1992 to 1994, Mr. Kinder served as Chairman of the General Partner. From October 1990 until December 1996, Mr. Kinder was President of Enron Corp. Mr. Kinder was employed by Enron and its affiliates and predecessors for over 16 years.
William V. Morgan was elected as a director of the General Partner in June 1994 and Vice Chairman of the General Partner in February 1997. Mr. Morgan has been the President of Morgan Associates, Inc., an investment and pipeline management company, since February 1987, and Cortez Holdings Corporation, a related pipeline investment company, since October 1992. He has held legal and management positions in the energy industry since 1975, including the presidencies of three major interstate natural gas companies which are now a part of Enron: Florida Gas Transmission Company, Transwestern Pipeline Company and Northern Natural Gas Company. Prior to joining Florida Gas in 1975, Mr. Morgan was engaged in the private practice of law in Washington, D.C.
Alan L. Atterbury was elected as a director of the General Partner in February 1997. Mr. Atterbury is a co-founder of Midland Loan Services, L.P., a real estate financial services company, and has served as its Chief Executive Officer and President since its inception in 1992. Mr. Atterbury has also been the President and a Director of Midland Data Systems, the general partner of Midland Loan Services, since its inception in 1990 and the President of Midland Properties, a property management and real estate development company, since 1980.
Edward O. Gaylord was elected as a director of the General Partner in February 1997. Mr. Gaylord is the President of Gaylord & Company, a venture capital company located in Houston, Texas. Mr. Gaylord also serves as Chairman of the Board for EOTT Energy Corporation, an oil trading and transportation company also located in Houston, Texas. He is also President of Jacintoport Terminal Company.
Thomas P. Tosoni has served as Vice President, Finance and Assistant Secretary for the General Partner since July 1, 1995. He was elected Vice President, Finance & Administration and Assistant Secretary of the General Partner on September 15, 1993. Prior to that he held the position of Vice President, Controller and Assistant
Secretary of the General Partner from December 17, 1992 until September 15, 1993. From 1990 until December 1992, he served as Controller and Assistant Secretary for the General Partner. He previously served as Controller for Enron Gas Processing Company from 1986 to 1989. He served as Assistant Controller for the Production and Transportation Division of the Enron Liquid Fuels Group from 1984 to 1986.
Michael C. Morgan was elected Vice President, Corporate Development of the General Partner in February 1997. From August 1995 until February 1997, Mr. Morgan was an associate with McKinsey & Company, an international management consulting firm. In 1995, Mr. Morgan received a Masters in Business Administration from the Harvard Business School. From March 1991 to June 1993, Mr. Morgan held various positions at PSI Energy, Inc., an electric utility, including Assistant to the Chairman. Mr. Morgan received a Bachelor of Arts in Economics and a Masters of Arts in Sociology from Stanford University in 1990. Mr. Morgan is the son of William V. Morgan.
David G. Dehaemers, Jr. was elected Secretary and Treasurer of the General Partner in February 1997. Mr. Dehaemers has been self-employed as a tax and accounting consultant since 1988. Mr. Dehaemers has also been the President of TNT Wash Systems, Inc. since January 1992.
Roger C. Mosby was elected Vice President of the General Partner in February 1997. Prior to that, Mr. Mosby was Vice President for Enron Liquid Services Corp. from July 1994 until February 1997. He was Vice President of Enron Gas Processing Company from January 1990 until March 1994.
Thomas B. King was elected President of the General Partner in February, 1997. Prior to that, he held the position of Vice-President, Midwest Region for the General Partner from July 1995 until February 1997. Mr. King has held several positions since he joined Enron in 1989, including Vice President, Gathering Services of Transwestern Pipeline Company and Northern Natural Gas Company and as Regional Vice President, Marketing of Northern Natural Gas Company. From December 1989 to August 1993, he served as Director, Business Development for Northern Border Pipeline Company in Omaha, Nebraska.
Section 16(a) of the Securities Exchange Act of 1934 requires the officers and directors of the General Partner, and persons who own more than 10% of a registered class of the equity securities of the Partnership, to file reports of ownership and changes in ownership with the SEC and the New York Stock Exchange. Based solely on its review of the copies of such reports received by it, or written representations from certain reporting persons that no Forms 5 were required for those persons, the General Partner believes that during 1996, its officers and directors and 10% holders of the Partnership complied with all applicable filing requirements; except as follows:
On January 14, 1997, the General Partner and Enron filed Form 3s reporting the direct ownership by the General Partner, and the indirect ownership by Enron, of 860,000 Deferred Participation Units on September 30, 1994, the date on which the Deferral Period ended with respect to the Deferred Participation Units.
Item 11. Executive Compensation
The compensation paid by the General Partner for services rendered during 1996, 1995 and 1994 respectively, to the General Partner's Chief Executive Officer ("CEO") are as follows (no other executive officer's salaries allocated to the Partnership exceeded $100,000): Mr. Raymond R. Kaskel, who held the office of President of the General Partner from July 1, 1995 until June 30, 1996 was paid $36,500 and $22,917 for 1996 and 1995, respectively. Mr. William V. Allison, who was elected President of the General Partner as of July 1, 1996 was paid $79,375 by the General Partner during 1996. Because prior to the acquisition of the General Partner by KMI, the executive officers of the General Partner were employees of other Enron subsidiaries, and provided services to these subsidiaries, the Partnership only reimbursed the General Partner for a portion of their salaries. As a result of this allocation, the portion of the other executive officers' salaries reimbursed by the Partnership did not exceed $100,000.
In addition to the above cash compensation, for which the General Partner is reimbursed by the Partnership, the above named individuals received compensation from the General Partner or from Enron under various employee benefit plans. Under the terms of the Partnership Agreement and Omnibus Agreement among the Partnership, the General Partner and Enron, reimbursement for certain expenses, including employee benefits, was subject to certain limits. As a result of KMI's acquisition of the General Partner, Enron and its affiliates are no longer required to provide corporate staff and support services under the terms of the Omnibus Agreement, and the limitations on reimbursement for corporate staff and support services incurred by the General Partner on behalf of the Partnership are no longer applicable. During 1996, neither the General Partner nor Enron was reimbursed by the Partnership for such other compensation paid to the named executive officers because the limits were exceeded. See Note 8 of the Notes to Consolidated Financial Statements of the Partnership included elsewhere in this report.
*Less than 1% (1)All Common Units involve sole voting power and sole investment power. (2)As of March 1, 1997 the Partnership had 6,510,000 Common Units issued and outstanding. (3)As of March 1, 1997, KMI had a total of 5,293 shares of issued and outstanding voting stock and a total of 5,295 shares of issued and outstanding non voting stock. (4) Represents Units held by Kinder Morgan G.P., Inc., which is wholly owned by Kinder Morgan, Inc. (5)These shares are held by Morgan Associates, Inc., a Kansas corporation, wholly owned by Mr. Morgan.
KMI pledged all of the stock of the General Partner to First Union in connection with its acquisition of the General Partner.
Mr. Kinder has the right to acquire control of KMI, through the purchase of certain shares of stock from MAI or conversion of non-voting KMI stock to voting stock, at such time as KMI and William Morgan agree upon a long term employment contract for Mr. Morgan. In addition, commencing on February 15, 1999, Mr. Kinder and Mr. Morgan have an option to purchase certain KMI stock owned by First Union Corporation, and commencing on August 15, 2000, KMI has an option to purchase and First Union Corporation has the right to require KMI to
purchase, all of the KMI stock owned by First Union Corporation. As a result of the foregoing arrangements, Mr. Kinder may in the future acquire control of the General Partner.
Item 13. Certain Relationships and Related Transactions
General and Administrative Expenses
Under the terms of the Omnibus Agreement that was executed among Enron, the Partnership and the General Partner at the time of formation of the Partnership, Enron agreed that it and its affiliates would provide to the General Partner certain corporate staff and support services to assist the General Partner in its management and operation of the Partnership. The amount paid by the Partnership to reimburse Enron and its affiliates for such services to the General Partner was subject to certain limitations established under the terms of the Omnibus Agreement. As a result of KMI's acquisition of the General Partner, Enron and its affiliates are no longer required to provide corporate staff and support services under the terms of the Omnibus Agreement, and the limitations on reimbursement for corporate staff and support services incurred by the General Partner on behalf of the Partnership are no longer applicable.
Partnership Distributions
The General Partner owns 431,000 Common Units, representing an approximate 6.6% of the Common Units. The Partnership Agreements provide for incentive distributions payable to the General Partner out of the Partnership's Available Cash in the event that quarterly distributions to Unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution to Unitholders exceeds a target of $0.605 per Unit, the General Partner will receive incentive distributions equal to (i) 15% of that portion of the quarterly distribution per Unit that exceeds $0.605 but is not more than $0.715, plus (ii) 25% of that portion of the quarterly distribution per Unit that exceeds the quarterly distribution amount of $0.715 but is not more than $0.935, plus (iii) 50% of that portion of the quarterly distribution per Unit that exceeds $0.935.
To support the Partnership's ability to distribute the Minimum Quarterly Distribution on all outstanding Common Units through the period ending September 30, 1997, Enron agreed that, if necessary, it would contribute cash to the Partnership in exchange for APIs in the Partnership. The APIs are not entitled to cash distributions, allocations of taxable income or loss (except under limited circumstances) or voting rights, but the Partnership is required to redeem them if and to the extent that Available Cash reaches certain levels. No APIs have been purchased by Enron since the inception of the Partnership, and management does not expect that APIs will be required to be purchased to support the payment of distributions in 1997. KMI has obtained a $10.9 million letter of credit from First Union National Bank of North Carolina to support Enron's remaining obligations with respect to the Minimum Quarterly Distribution payable to the holders of the Partnership's Common Units.
South Cowden Lateral
During 1996, a lateral was constructed that connects the South Cowden Unit flood project to the Central Basin Pipeline. The lateral is owned by MAI, which is owned by William V. Morgan, and was constructed for MAI by the Partnership under the terms of a Construction Agreement at a cost of $1.35 million, which amount has been paid by MAI. In addition, MAI and the Partnership entered into an Operating & Maintenance Agreement which provides for operation and maintenance of the lateral by the Partnership, and a Transportation Agreement which allows the Partnership to ship specified quantities of CO2 on the lateral and requires the Partnership to ship certain minimum quantities of CO2 on the lateral. The agreements are coterminus and expire in 2016. During 1996, the Partnership charged MAI $31,250 under the Operating and Maintenance Agreement and MAI charged the Partnership $194,648 under the Transportation Agreement. The terms of such agreements are comparable to those which the Partnership would make available to unaffiliated third parties.
Revenues and Expenses
Revenues for the years ended December 31, 1996, 1995 and 1994 include transportation charges and product sales to an Enron subsidiary, Enron Gas Liquids, Inc., of $7.7 million, $5.9 million and $4.7 million, respectively. Another Enron subsidiary, Enron Gas Processing Company ("EGP"), provides services in connection with the Mobil Agreement (see Note 10) as well as storage and other services to the Partnership and charged $6.6 million, $2.7 million and $0.7 million for the years ended December 31, 1996, 1995 and 1994, respectively. Management believes that these charges are reasonable. As a result of KMI's acquisition of all of the common stock of the General Partner, Enron and its affiliates are no longer affiliates of the Partnership.
Other
The General Partner makes all decisions relating to the management of the Partnership. KMI owns all the common stock of the General Partner. Certain conflicts of interest could arise as a result of the relationships among the General Partner, KMI and the Partnership. The directors and officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the shareholders of KMI. In general, the General Partner has a fiduciary duty to manage the Partnership in a manner beneficial to the Unitholders. The Partnership Agreements contain provisions that allow the General Partner to take into account the interests of parties in addition to the Partnership in resolving conflicts of interest, thereby limiting its fiduciary duty to the Unitholders, as well as provisions that may restrict the remedies available to Unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty. The duty of the directors and officers of KMI to the shareholders of KMI may, therefore, come into conflict with the duties of the General Partner to the Unitholders. The Conflicts and Audit Committee of the Board of Directors of the General Partner will, at the request of the General Partner, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and the Partnership, on the other hand.
PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page.
(a)(3) Exhibits
*3.1 -Amended and Restated Partnership Agreement of Enron Liquids Pipeline, L.P. (Exhibit 3.1 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993 ("1993 10-K")) *3.2 -First Amendment to Amended and Restated Agreement of Limited Partnership of Enron Liquids Pipeline, L.P. effective as of August 6, 1992 (Exhibit 3.2 to the Partnership's Annual Report on Form 10-K for the year ended December 31, 1992 ("1992 10-K")) *3.3 -Second Amendment to Amended and Restated Agreement of Limited Partnership of Enron Liquids Pipeline, L.P. effective as of September 30, 1993 (Exhibit 3.3 to 1993 10-K) *3.4 -Third Amendment to Amended and Restated Agreement of Limited Partnership dated as of February 14, 1997 (Exhibit 4.0 to the Partnership's Form 8-K Report dated February 14, 1997) *4.1 -Specimen Certificate representing Common Units (Exhibit 4.1 to 1993 10-K) *10.1 -Omnibus Agreement among Enron Corp., Enron Liquids Pipeline Company, Enron Liquids Pipeline, L.P. and Enron Liquids Pipeline Operating Limited Partnership (Exhibit 10.1 to 1993 10-K) *10.1.-First Amendment to Omnibus Agreement, dated as of September 30, 1993 (Exhibit 10.1.1 to 1993 10-K) *10.1.-Second Amendment to Omnibus Agreement, dated as of September 7, 1994 (Exhibit 10.1.2 to 1994 10-K) *10.2 -Amended and Restated Agreement of Limited Partnership of Enron Liquids Pipeline Operating Limited Partnership effective as of August 6, 1992 (Exhibit 10.2 to 1993 10-K) *10.2.-First Amendment to Amended and Restated Agreement of Limited Partnership of Enron Liquids Pipeline Operating Limited Partnership effective as of August 6, 1992 (Exhibit 10.2.1 to 1992 10-K) *10.2.-Second Amendment to Amended and Restated Agreement of Limited Partnership of Enron Liquids Pipeline Operating Limited Partnership dated as of March 22, 1993 but effective as of August 6, 1992 (Exhibit 10.2.2 to 1992 10-K) 10.2.-Third Amendment to Amended and Restated Agreement of Limited Partnership of Enron Liquids Pipeline Operating Limited Partnership dated as of February 14, 1997 *10.3 -Conveyance, Contribution and Assumption Agreement among certain Enron Corp. subsidiaries and the Operating Partnership (Exhibit 10.3 to 1993 10-K) *10.3.-First Amendment to Conveyance, Contribution and Assumption Agreement effective as of August 6, 1992 (Exhibit 10.3.1 to 1992 10-K) *10.4 -Form of Fractionation Agreement between Enron Natural Gas Liquids Corporation ("ENGL") and Enron Gas Liquids, Inc. for fractionation services at the Mont Belvieu Fractionator (Exhibit 10.4 to Amendment No. 2 to the Partnership's Form S-1 Registration Statement, Registration No. 33-48142, filed on July 30, 1992 ("Form S-1")) *10.5 -Storage Agreement between Enron Gas Processing Company and the General Partner dated February 18, 1987 relating to the Bushton storage field, Amendment No. 1 dated October 19, 1988, Amendment No. 2 dated May 22, 1992, and Amendment No. 3 dated May 29, 1992 (Exhibit 10.5 to Form S-1) *10.5- Amendment No. 4 to Storage Agreement dated August 25, 1994 (Exhibit 10.5.1 to Form S-1) *10.6- Transportation Agreement between Enron Liquids Pipeline Company and Enron Gas Liquids Inc. dated August 1, 1989 relating to the Peoples Gas Light & Coke Company and the form of Amendment No. 1 thereto (Exhibit 10.6 to Form S-1)
*10.7 -Facilities Service Agreement between Enron Liquids Pipeline Company and Enron Gas Processing Company dated February 18, 1987, relating to facilities at Bushton, Kansas, Amendment No. 1 dated January 10, 1989, and Amendment No. 2 dated May 30, 1992 (Exhibit 10.7 to Form S-1) *10.8- Fractionation Agreement between Enron Liquids Pipeline Company and Enron Liquids Marketing Company (now Enron Gas Liquids, Inc.) for fractionation services at Bushton, Kansas, dated September 24, 1987, (first) Amendment effective as of January 1, 1988 and dated May 25, 1988, (second) Amendment dated August 1, 1989, (third) Amendment dated March 7, 1991, and Amendment No. 4 dated as of August 1, 1992 (Exhibit 10.8 to Form S-1) *10.9- Unstenched Loading Letter Agreement between Enron Liquids Pipeline Company and Enron Gas Liquids, Inc. dated November 12, 1991 (Exhibit 10.9 to Form S-1) *10.1- Note Agreement relating to the First Mortgage Notes (Exhibit 10.10 to 1993 10-K) *10.1- Trust Agreement relating to the First Mortgage Notes (Exhibit 10.11 to 1993 10-K) *10.1- Pledge and Security Agreement relating to the First Mortgage Notes (Exhibit 10.13 to 1993 10-K) *10.1- Mortgage, Security Agreement and Fixture Filing relating to the First Mortgage Notes (Exhibit 10.12 to 1993 10-K) *10.14 Amended and Restated Agreement of Limited Partnership of Enron Transportation Services, L.P. dated as of September 30, 1993 (Exhibit 10.14 to 1993 10-K) 10.1- First Amendment to Amended and Restated Agreement of Limited Partnership of Enron Transportation Services, L.P. dated as of February 14, 1997 *10.1- Asset Purchase Agreement, dated as of September 30, 1993, by and among Cora Dock Corporation, as Seller, and Enron Transportation Services, L.P., as Purchaser, and Houston Pipe Line Company, as guarantor of certain obligations of Seller (Exhibit 10.15 to 1993 10-K) *10.1- Loan Agreement, dated April 1, 1994 between Jackson-Union Counties Regional Port District and Enron Transportation Services, L.P. (Exhibit 10.18 to 1995 10-K) *10.1- Guaranty and Indemnity, dated September 30, 1993, issued by Enron Liquids Pipeline, L.P. in favor of Enron Corp. and Houston Pipe Line Company (Exhibit 10.19 to 1993 10-K) *10.1- Purchase and Sale Agreement, dated June 30, 1994, by and between Enron Gas Processing and Enron Transportation Services, L.P. (Exhibit 10 to Current Report on Form 8-K dated July 15, 1994) *10.19 Operation and Maintenance Agreement between Enron Gas Processing Company and Northern Natural Gas Company dated August 1, 1987, assigned to Enron Transportation Services, L.P. effective July 1, 1994 (Exhibit 10.24 to 1994 10-K) *10.20 Loan Agreement between Enron Liquids Pipeline Operating Limited Partnership and Bank One, Texas, N.A., dated effective May 24, 1995 (Exhibit 10.28 to 1995 10-K) *10.20.First Amendment to Loan Agreement, dated effective May 24, 1995, between Enron Liquids Pipeline Operating Limited Partnership and Bank One, Texas, N.A., dated effective September 30, 1995 (Exhibit 10.28.1 to 1995 10-K) *10.21 Letter Agreement regarding SWAP transaction to Enron Transportation Services, L.P. from First Union National Bank of North Carolina, dated February 13, 1996 (Exhibit 10.29 to 1995 10-K) *10.22 Gas Sales Agreement between Enron Liquids Pipeline Operating Limited Partnership and Enron Gas Processing Company, dated effective October 1, 1995 (Exhibit 10.30 to 1995 10-K) *10.23 Bushton Hydrocarbon Plant Sublease Agreement between Enron Liquids Pipeline Operating Limited Partnership and Enron Gas Processing Company, dated effective October 1, 1995 (Exhibit 10.31 to 1995 10-K) *10.24 Assignment and Assumption Of Contract from Enron Gas Processing Company to Enron Liquids Pipeline Operating Limited Partnership, dated October 1, 1995 (Exhibit 10.32 to 1995 10-K) *10.25 Agency Agreement between Enron Liquids Pipeline Company and Enron Liquid Fuel Company, dated July 19, 1995 (Exhibit 10.33 to 1995 10-K) *10.26 Agreement between Enron Transportation Services, L.P. and International Union of Operating Engineers, AFL-CIO, dated March 19, 1995 (Exhibit 10.34 to 1995 10-K)
*10.27 Lease between Richard Zang Hamilton, Doris Marie Hamilton, Richard David Hamilton and James Price Hamilton, as Lessors, and Zeigler Coal Company, as Lessee, dated April 21, 1976 (Exhibit 10.35 to 1995 10-K) *10.28 Storage Agreement between Enron Gas Processing Company and Enron Liquids Pipeline Company dated effective January 1, 1996 (Exhibit 10.36 to 1995 10-K) *10.29 Termination of the Bushton Storage Agreement between Enron Gas Liquids, Inc. and Enron Liquids Pipeline Operating Limited Partnership, dated effective December 3, 1995 (Exhibit 10.37 to 1995 10-K) *10.30 Transaction Agreement between Enron Liquids Pipeline Operating Limited Partnership and Enron Capital & Trade Resources Corp., dated September 27, 1995 (Exhibit 10.38 to 1995 10-K) *10.3- Credit Agreement dated as of February 14, 1997 among Kinder Morgan Operating L.P. "B" and First Union National Bank of North Carolina with form of Notes attached (Exhibit 10.1 to the Partnership's Form 8-K Report dated February 14, 1997) *10.3- Security Agreement dated as of February 14, 1997 between Kinder Morgan Energy Partners, L.P. and First Union National Bank of North Carolina (Exhibit 10.2 to the Partnership's Form 8-K Report dated February 14, 1997) *10.3- Security Agreement dated as of February 14, 1997 between Kinder Morgan Operating L.P. "B" and First Union National Bank of North Carolina (Exhibit 10.3 to the Partnership's Form 8-K Report dated February 14, 1997) *10.3- Guaranty Agreement dated as of February 14, 1997 from Kinder Morgan Energy Partners, L.P. in favor of First Union National Bank of North Carolina (Exhibit 10.4 to the Partnership's Form 8-K Report dated February 14, 1997) *10.3- Credit Agreement dated as of February 14, 1997 among Kinder Morgan, Inc. and First Union National Bank of North Carolina (Exhibit 10.5 to the Partnership's Form 8-K Report dated February 14, 1997) *10.36 Mortgage and Security Agreement with Assignment of Rents from Enron Transportation Services, L.P. to First Union National Bank of North Carolina, dated December 29, 1994 (Exhibit 10.22 to 1994 10-K) *10.37 First Amendment to Mortgage and Security Agreement with Assignment Rents (Illinois) dated as of February 14, 1997 between Kinder Morgan Operating L.P. "B" and First Union National Bank of North Carolina (Exhibit 10.6 to the Partnership's Form 8-K Report dated February 14, 1997) *10.38 Mortgage, Security Agreement, and Financing Statement (Uinta County, Wyoming), from Enron Transportation Services in favor of First Union National Bank of North Carolina, dated as of December 29, 1994 (Exhibit 10.25 to 1994 10-K) *10.3- First Amendment to Mortgage, Security Agreement and Financing Statement (Wyoming) dated as of February 14, 1997 between Kinder Morgan Operating L.P. "B" and First Union National Bank of North Carolina as Agent (Exhibit 10.7 to the Partnership's Form 8-K Report dated February 14, 1997) 10.40 Lease dated as of September 6, 1979 between Broken Circle Cattle Company and Northern Gas Products Company 10.41 Construction Agreement between Morgan Associates, Inc. and Enron Liquids Pipeline Operating Limited Partnership dated June 20, 1996 10.42 Operating & Maintenance Agreement between Morgan Associates, Inc. and Enron Liquids Pipeline Operating Limited Partnership dated June 20, 1996 10.43 Transportation Agreement between Morgan Associates, Inc. and Enron Liquids Pipeline Operating Limited Partnership dated June 20, 1996
21 - List of subsidiaries
- - - ------------------------------------- * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.
(b) Reports on Form 8-K
Form 8-K dated February 14, 1997, covering Items 1, 5 and 7.
Page
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Public Accountants
Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994
Consolidated Balance Sheets for the years ended December 31, 1996 and 1995
Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994
Consolidated Statements of Partners' Capital for the years ended December 31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements
MONT BELVIEU ASSOCIATES
Report of Independent Public Accountants
Statements of Income for the years ended December 31, 1996, 1995 and 1994
Balance Sheets for the years ended December 31, 1996 and 1995
Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994
Statements of Partners' Capital for the years ended December 31, 1996, 1995 and 1994
Notes to Financial Statements
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Kinder Morgan Energy Partners, L.P. (Formerly Enron Liquids Pipeline, L.P.):
We have audited the accompanying consolidated balance sheet of Kinder Morgan Energy Partners, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, cash flows and partners' capital for each of the three years in the period ended December 31, 1996. 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 in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kinder Morgan Energy Partners, L.P. as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas February 21, 1997
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME (In thousands, except per unit amounts)
Year Ended December 31, 1996 1995 1994 ---- ---- ---- Revenues Trade $62,561 $57,379 $48,876 Related party 8,689 6,925 6,028 ------ ------ ------ 71,250 64,304 54,904 ------ ------ ------
Costs and expenses
Cost of products sold 7,874 8,020 940 Operations and maintenance Related party 6,558 2,683 697 Other 12,322 9,956 9,576 Fuel and power 4,916 3,934 5,481 Depreciation 9,908 9,548 8,539 General and administrative Allocated from 5,835 5,495 5,123 Enron Other 3,297 3,244 3,073 Taxes, other than 3,467 3,289 3,371 ------ ------ ------ income taxes 54,177 46,169 36,800 ------ ------ ------ Operating income 17,073 18,135 18,104 Other income (expense) Equity in earnings of 5,675 5,755 5,867 partnerships Interest expense (12,634) (12,455) (11,989) Other 3,250 1,426 622 Minority interest (121) (115) (113) ------- ------- ------- Income before income taxes 13,243 12,746 12,491 Income tax expense 1,343 1,432 1,389 ------ ------ ------ Net income $11,900 $11,314 $11,102 ======= ======= ======= Net income per Unit Note 2)$ 1.79 $ 1.71 $ 1.86 ======= ======= ======= Number of Units used in 6,510 6,510 5,865 ======= ======= ======= computation (Note 2)
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (In thousands) December 31, 1996 1995 ASSETS
Current assets Cash and cash equivalents $ 14,299 $ 14,202 Accounts receivable Trade 7,970 7,913 Related parties 4,390 2,183 Inventories Products 882 832 Materials and supplies 1,827 2,075 ----- ----- 29,368 27,205
Property, plant and equipment, at cos 272,178 263,838 Less accumulated depreciation 36,184 26,984 235,994 236,854
Investments in partnerships 32,043 32,613 ------ ------
Deferred charges and other assets 6,198 6,992 ----- -----
TOTAL ASSETS $303,603 $303,664
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities Accounts payable Trade $5,512 $5,272 Related parties 4,520 2,664 Current portion of long-term debt 1,709 1,700 Accrued liabilities 811 2,808 Accrued taxes other than income 2,304 2,155 Distributions payable 4,210 4,210 ----- ----- 19,066 18,809
Long-term liabilities and deferred credits Long-term debt 160,211 156,938 Other 3,492 2,264 163,703 159,202 Commitments and contingencies (Notes 6, 9 and 10)
Minority interest 2,490 2,537 ------- ------- Partners' capital Common unitholders 101,000 105,100 Deferred participation unitholder 16,165 16,787 General partner 1,179 1,229 118,344 123,116 TOTAL LIABILITIES AND PARTNERS' CAPITAL $303,603 $303,664
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands)
Year Ended December 31, 1996 1995 1994 ------ ----- ----- Cash flows from operating activities Reconciliation of net income to net cash provided by operating activities Net income $11,900 $11,314 $11,102 Depreciation 9,908 9,548 8,539 Equity in earnings of partnerships (5,675) (5,755) (5,867) Distributions from investments in partnerships 6,791 6,061 7,336 Changes in components of working capital Accounts receivable (2,264) (2,958) (939) Inventories 198 465 (854) Accounts payable 2,096 1,581 (690) Accrued liabilities (1,997) 1,535 (289) Accrued taxes 149 (373) (80) Distribution payable - - 540 Other, net 1,670 1,148 313 ------ ------- ------ Net cash provided by operating activities 22,776 22,566 19,111 ------ ------ ------
Cash flows from investing activities Acquisition of assets - - (12,825) Additions to property, plant and equipment (8,575) (7,826) (5,195) Contributions to partnership investment (546) (772) (304) Net cash used in investing activities (9,121) (8,598) (18,324)
Cash flows from financing activities Decrease/increase in short-term debt - (650) 650 Issuance of long-term debt 5,000 8,000 49,961 Repayment of long-term debt (1,718)(1,290) (36,762) Distributions to partners Common units (14,236)(14,236)(14,236) General partner (2,436) (2,436) (232) Minority interest (168) (168) (163) ----- ----- ----- Net cash used in financing activities (13,558)(10,780) (782)
Increase in cash and cash equivalents 97 3,188 5 Cash and cash equivalents, beginning of period 14,202 11,014 11,009 Cash and cash equivalents, end of Period $14,299 $14,202 $11,014
Supplemental disclosures of cash flow information Cash paid during the year for Interest (net of capitalized interest) $12,487 $11,870 $11,676 Income Taxes $ 397 $ 425 $ 413
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
Subsequent Event--Sale of the stock of the General Partner
Kinder Morgan Energy Partners, L.P. (the "Partnership", formerly Enron Liquids Pipeline, L.P.), a Delaware limited partnership was formed in August 1992. Effective February 14, 1997, Kinder Morgan, Inc. ("KMI") acquired all of the issued and outstanding stock of Enron Liquids Pipeline Company, the general partner, from Enron Liquids Holding Corp. ("ELHC"). At the time of the acquisition, the general partner and the Partnership's subsidiaries were renamed as follows: Kinder Morgan G.P., Inc. (the "General Partner", formerly Enron Liquids Pipeline Company); Kinder Morgan Operating L.P. "A" ("OLP-A", formerly Enron Liquids Operating Limited Partnership); Kinder Morgan Operating L.P. "B" ("OLP-B", formerly Enron Transportation Services, L.P.); and Kinder Morgan Natural Gas Liquids Corporation ("KMNGL", formerly Enron Natural Gas Liquids Corporation).
General
The Partnership's assets include two interstate natural gas liquids ("NGL" or "NGLs") pipelines ("North System" and "Cypress Pipeline"), a carbon dioxide ("CO2") pipeline ("Central Basin Pipeline"), a coal transfer facility ("Cora Terminal"), a gas processing plant ("Painter Plant"), a 25% indirect interest in an NGL fractionator in Mont Belvieu, Texas by means of the ownership of the common stock of KMNGL, and a gas processing capacity sublease ("Bushton Sublease"). The North System transports, stores and delivers a full range of NGLs and refined products from South Central Kansas to markets in the Midwest and has interconnects, using third-party pipelines in the Midwest, to the eastern United States. The Cypress Pipeline transports ethane from Mont Belvieu, Texas, to the Lake Charles, Louisiana area. The Central Basin Pipeline transports CO2 in West Texas. The Cora Terminal transfers coal from rail to barge on the banks of the Mississippi River near Cora, Illinois. The Painter Plant processes natural gas and fractionates NGLs near Evanston, Wyoming. The Bushton Sublease, which expires in 2005, provides gas processing capacity at a plant in Ellsworth County, Kansas and was executed in conjunction with an assignment of a gas processing agreement with Mobil Natural Gas, Inc. (see Note 10).
The Partnership operates through two operating limited partnerships, OLP-A and OLP-B (collectively, the "Operating Partnerships"). Kinder Morgan G.P., Inc. is a wholly owned subsidiary of KMI and serves as the sole general partner of the Partnership, OLP-A and OLP-B. The Partnership and the Operating Partnerships are governed by Amended and Restated Agreements of Limited Partnership and certain other agreements (collectively, the "Partnership Agreements").
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. Summary of Significant Accounting Policies
Principles of Consolidation and Use of Estimates
The consolidated financial statements include the assets, liabilities and results of operations of the Partnership and its majority-owned subsidiaries. All significant intercompany items have been eliminated in consolidation.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
Cash equivalents are defined as all highly liquid short-term investments with original maturities of three months or less.
Inventories
Inventories of products consist of NGLs which are valued at the lower of cost (weighted-average cost method) or market. Materials and supplies are stated at the lower of cost or market.
Property, Plant and Equipment
Property, plant and equipment is stated at its acquisition cost. Expenditures for maintenance and repairs are charged to operations in the period incurred. The cost of property, plant and equipment sold or retired and the related depreciation are removed from the accounts in the period of sale or disposition. The provision for depreciation is computed using the straight-line method based on estimated economic or Federal Energy Regulatory Commission ("FERC") - mandated lives. Generally, composite depreciation rates are applied to functional groups of property having similar economic characteristics and range from 2.5% to 12.5%, excluding certain short-lived assets such as vehicles. The original cost of property retired is charged to accumulated depreciation and amortization, net of salvage and cost of removal. No retirement gain or loss is included in income except in the case of extraordinary retirements or sales.
In March 1995, the Financial Accounting Standards Board issued 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," which requires, among other things, that long-lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Partnership adopted SFAS No. 121 in the first quarter of 1996. The adoption of SFAS No. 121 did not have a material impact on the Partnership's financial position or results of operations.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Property, plant and equipment consists of the following (in thousands):
December 31, 1996 1995
Liquids Pipelines $223,337 $217,105 Coal Handling 24,197 23,932 Gas Processing 13,529 13,120 Land 2,936 2,288 Other 8,179 7,393 -------- ----- Total $272,178 $263,838 ======== ========
Revenue Recognition
Revenues for the pipeline operations are generally recognized on delivery based on the actual volume transported. Coal handling and gas processing revenues are recognized based upon volumes loaded and volumes processed or fractionated, respectively.
Investments in Partnerships
The Partnership's investments in partnerships accounted for under the equity method consisted of the following (dollars in thousands):
Percent December 31, Ownership 1996 1995
Mont Belvieu Associates 50% $27,205 $27,481 Heartland Pipeline Company 50% 4,838 5,132 ---- ------- ------- Total 100% $32,043 $32,613 ==== ======= =======
The Partnership's equity in earnings of investments in partnerships is as follows (in thousands):
Year Ended December 31,
1996 1995 1994 ------ ------ -----
Mont Belvieu Associates $4,968 $5,208 $5,534 Heartland Pipeline Company 707 547 333 Total $5,675 $5,755 $5,867 ====== ====== ======
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized combined financial information of the partnerships is presented below (in thousands):
December 31, 1996 1995 Balance Sheet Current assets $ 7,729 $ 9,472 Non-current assets 54,401 44,743 Current liabilities 5,043 3,992 Non-current liabilities 15,022 1,019 Partners' equity 42,065 49,204
Year Ended December 31, 1996 1995 1994 ------ ------ -----
Income Statement Revenues $31,534 $30,032 $31,548 Expenses 19,563 18,074 18,396 ------ ------ ------ Net income $11,971 $11,958 $13,152 ======= ======= =======
The excess of the Partnership's cost over its 50% share of the underlying net assets of the partnerships is being amortized over the estimated remaining life of the property, plant and equipment of the partnerships. Such amortization is reflected as a reduction in equity earnings related to the Partnership's investments.
Minority Interest
Minority interest consists of the approximate 1% general partner interest in the Operating Partnerships as well as other contributions that have been made relative to the Mont Belvieu Fractionator.
Income Taxes
The Partnership is not a taxable entity for federal income tax purposes. As such, no federal income tax will be paid by the Partnership. Each partner will be required to report on its tax return its allocable share of the taxable income and loss of the Partnership. Such taxable income or loss may vary substantially from the net income or net loss reported in the consolidated statement of income primarily because of accelerated tax depreciation.
KMNGL, however, is subject to corporate federal and state income taxes. Accordingly, for financial reporting purposes, no recognition has been given to income taxes related to the operations of the Partnership other than those recorded by KMNGL.
KMNGL accounts for income taxes under the provisions of SFAS No. 109 - "Accounting for Income Taxes." SFAS No. 109 provides for an asset and liability approach for accounting for income taxes. Under this approach, deferred assets and liabilities are recognized based on anticipated future tax consequences
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
attributable to differences between financial statement carrying amounts of assets and liabilities of their respective tax bases.
The difference between KMNGL's effective income tax rate of approximately 37.0% and the federal statutory tax rate relates to state income taxes.
KMNGL's net deferred tax liability at December 31, 1996 and 1995 was $3.2 million and $2.2 million, respectively. At December 31, 1996, KMNGL had recorded deferred tax assets related to $1.3 million of alternative minimum tax credit carryforwards with no expiration date and tax benefits of a net operating loss ("NOL") carryforward which substantially expires in 2008. In 1996, KMNGL utilized approximately $0.5 million of its approximate $3.7 million NOL carryforward.
Net Income Per Unit
Net income per unit is computed by dividing net income, after the deduction of the General Partner's interest, including incentives, by the weighted average number of outstanding Participating Units which includes 5,650,000 Common Units ("Common Units" represent limited partnership interests in the Partnership) and, after September 30, 1994, also includes the 860,000 limited partner units held by the General Partner on December 31, 1996. On February 14, 1997, these limited partnership interests were converted to Common Units and the General Partner then sold 429,000 of the units to a third party. (See Note 5).
3. The Painter Plant
Acquisition
On June 30, 1994, the Partnership acquired, through OLP-B, the Painter Plant, a gas processing plant located in Uinta County, Wyoming, and related assets consisting of terminal facilities and construction work- in-progress associated with such facilities and certain pipelines connecting the plant with third party facilities. The assets were acquired from Enron Gas Processing Company, an indirect wholly-owned subsidiary of Enron Corp. ("Enron"). The accompanying consolidated financial statements include the results of operations for the Painter Plant beginning July 1, 1994. The cost of this acquisition was $12.8 million which OLP-B originally financed with a note from Enron. The debt was subsequently refinanced with a third party lender. (See Note 4). This acquisition was accounted for as a purchase.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Detailed below is summarized pro forma results of operations for the Partnership for 1994 as though the Painter Plant had been a part of the Partnership's operations as of January 1, 1994.
(Unaudited; in thousands, except per unit amounts) Year Ended December 31, 1994 Pro Forma
Revenues $58,275 Net income 11,921 Net income per unit 2.00
The above pro forma consolidated results do not purport to present actual operating results had the acquisition of the Painter Plant occurred on January 1, 1994.
Chevron Contract Buyout
In 1996, under a contract that was to extend through December 1998, Chevron, USA ("Chevron") was the only gas processing customer at the Painter Plant. In April 1996, the Partnership was notified by Chevron that it was exercising its right to terminate the gas processing agreement at the Painter Plant effective as of August 1, 1996. The gas processing agreement with Chevron allowed for early termination by Chevron, subject to an approximate $2.9 million one time termination payment. On June 14, 1996, a force majeure event occurred and the Painter Plant gas processing facilities were shut down. Chevron subsequently disputed its obligation to pay the early termination payment. The Partnership negotiated with Chevron to settle all claims between the two parties under the gas processing agreement. The Partnership agreed in September 1996 to accept $2.7 million as full and final settlement of all claims. This amount was reduced to $2.5 million in connection with the settlement of certain disputed receivables. Historically, approximately 56% of the revenues from the Painter Plant were generated from processing Chevron gas. Management estimates that the Chevron contract would have generated approximately $3.9 million of revenue during each of the remaining two years of the contract.
The fractionation, terminaling and storage operations conducted at the Painter Plant are continuing. The fractionation agreement with Chevron, which extends through November 1997, remains in effect, and the Partnership has fractionation agreements with other third parties.
Gas Processing and Terminal Lease to Amoco
On February 14, 1997, the Partnership executed an operating lease agreement with Amoco Oil Company ("Amoco") for Amoco's use of the fractionator and the Partnership's Millis Terminal and Storage Facility ("Millis") with the nearby Amoco Painter Complex Gas Plant. The lease will generate approximately $1.0 million of cash flow in 1997 with annual escalations thereafter. The primary term of the lease expires
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
February 14, 2007, with evergreen provisions at the end of the primary term. Amoco will take assignment of all of the commercial arrangements currently in place, including the Chevron fractionation agreement described above, and will assume all day to day operations, maintenance, repairs, replacements and all expenses (other than minor easement fees), taxes and charges associated with the fractionator and the Millis facilities. After lease year seven, Amoco may elect to purchase the fractionator and Millis facilities under certain terms. A portion of the gas processing facilities and the nitrogen rejection unit at the Painter Plant remain operationally idle. The Partnership continues to assess its alternatives for these idled facilities.
4. Long-Term Debt
OLP-A
OLP-A has outstanding $110 million of 8.79% First Mortgage Notes ("First Mortgage Notes") due 2007. Such notes are secured by substantially all of the liquids pipeline property, plant and equipment of OLP-A and the common stock of KMNGL and are with recourse to the General Partner.
As allowed by the agreement between OLP-A and the holders of the $110 million of 8.79% First Mortgage Notes, OLP-A has established a committed $15 million revolving credit facility with a bank to meet its working capital requirements.
OLP-A's credit facility with the bank has a variable rate interest equal to the London Interbank Offered Rate ("LIBOR") plus 1.75% per annum, requires quarterly interest payments on outstanding borrowings, and upon its June 1, 1998 termination, requires the repayment of the entire outstanding principal amount. At December 31, 1996, the Partnership had outstanding borrowings of $13 million under this facility. During 1996, the weighted-average interest rate was 7.22% per annum.
OLP-B
OLP-B has outstanding $23.7 million principal amount of tax exempt bonds issued by the Jackson-Union Counties Regional Port District due 2024. Such bonds bear interest at a weekly floating market rate. During 1996, the weighted-average interest rate on these bonds was 3.58% per annum. OLP-B has entered into an interest rate swap which fixes the interest rate at approximately 3.65% per annum during the period from February 13, 1996 to December 31, 1998.
OLP-B had outstanding at December 31, 1996 a $12.8 million note which bore interest at a rate equal to the LIBOR plus a variable rate ranging from 1.25% per annum to 1.75% per annum. During 1996, the weighted-average interest rate was 7.06% per annum. OLP-B also had outstanding at December 31, 1996, a $4.4 million, 6.96% promissory note to Enron due September 30, 2003. In addition, OLP-B had a $2.0 million, committed working capital revolving line of credit with a bank which at December 31, 1996 was unused. In connection with KMI's acquisition of the General Partner, OLP-B refinanced its existing bank indebtedness with a new $15.9 million revolving credit facility with First Union National Bank of North Carolina ("First Union"). The obligations of OLP-B under the credit facility are guaranteed by the Partnership. Borrowings under the credit facility are due February 14, 1999 and bear interest, at OLP-B's option, at either First Union's Base Rate plus .5% per annum or LIBOR plus 2.25% per annum (in each case
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
increasing by .25% as of the end of each calendar quarter commencing June 30, 1997). The Partnership's ability to borrow additional funds under the credit facility is subject to compliance with certain financial covenants and ratios.
Maturities of the Partnership's long-term debt as of December 31, 1996 were as follows (in thousands): 1997 $ 1,709 1998 25,718 1999 18,915 2000 11,946 2001 11,946 Thereafter 91,751
After giving effect to the refinancing of OLP-B's indebtedness, maturities of the Partnership's long-term debt as of March 15, 1997 were as follows (in thousands): 1997 $ 106 1998 24,115 1999 25,796 2000 11,061 2001 11,013 Thereafter 89,979
The estimated fair value of the long-term debt based upon prevailing interest rates available to the Partnership at December 31, 1996 and 1995 is disclosed below. Fair value as used in SFAS No. 107 -- "Disclosures About Fair Value of Financial Instruments" represents the amount at which the instrument could be exchanged in a current transaction between willing parties.
December 31, 1996 December 31, 1995 Carrying Estimated Carrying Estimated Value Fair Value Value Fair Value (in thousands)
Long-term debt ($161,920) ($152,631) ($158,638) ($162,029) Interest rate swap - $ 155 - -
5. Partners' Capital
At December 31, 1996, Partners' capital consisted of 5,650,000 Common Units representing an 85.1% limited partner interest in the Partnership, 860,000 units held by the General Partner representing a 12.9% limited partner interest (see below) and a 2% general partner interest which includes the General Partner's approximate 1% general partner interest in the Operating Partnerships. On February 14, 1997, the limited
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
partnership interests held by the General Partner were converted to Common Units and the General Partner then sold 429,000 of its Common Units to a third party.
Through September 30, 1997, Enron has agreed to contribute cash in exchange for additional partnership interests ("APIs") if Available Cash (as defined below) is insufficient to meet the Minimum Quarterly Distributions (the "Minimum Quarterly Distribution") on the Common Units of $0.55 per Unit . Available Cash, as defined in the Partnership Agreements, generally consists of all cash receipts of the Partnership less all of its cash disbursements and net additions to reserves. Through December 31, 1996, no such capital contributions have been required. (See Note 8).
On September 30, 1994, the Deferral Period, as defined in the Partnership Agreements, ended with respect to the 12.9% limited partner interests then held by the General Partner. As a result, these limited partner interests became eligible and began to participate in all allocations of income or losses and distributions made with respect to Common Units effective with the fourth quarter of 1994. In order for the Deferral Period to end, the Partnership was required to generate and distribute approximately $0.63 per Common Unit for four consecutive quarters after September 30, 1993. The fourth quarterly distribution of $0.63 per Unit occurred in the third quarter of 1994.
6. Litigation and Other Contingencies
General
The Partnership, in the ordinary course of business, is a defendant in various lawsuits relating to the Partnership's assets. Although no assurance can be given, the Partnership believes, based on its experience to date, that the ultimate resolution of such items will not have a material adverse impact on the Partnership's financial position or results of operations.
The liabilities, if any, associated with any lawsuits pending at the time the Partnership was formed in 1992 were retained by Enron and not assumed by the Partnership. Pursuant to the Omnibus Agreement, the General Partner agreed to cause the Partnership, at the Partnership's expense, to cooperate with Enron in the defense of any such litigation by furnishing information relating to the Partnership's assets involved in the litigation, furnishing access to files and otherwise assisting in the defense. The costs to the Partnership relating to such agreement have not been and are not expected to be significant. In addition, Enron agreed to indemnify the Partnership for any losses incurred in connection with the lawsuits pending at the time the Partnership was formed. In connection with the sale of the Common Stock of the General Partner to KMI, Enron agreed to assume liability, and indemnify the Partnership, for certain lawsuits then pending.
Morris Storage Facility
The General Partner is a defendant in a suit filed on September 12, 1995 by the State of Illinois. The suit seeks civil penalties and an injunction based on five counts of environmental violations for events relating to a fire that occurred at the Morris storage field in September, 1994. The fire occurred when a sphere containing natural gasoline overfilled and released product which ignited. There were no injuries and no damage to property, other than Partnership property. The suit seeks civil penalties in the stated amount of
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
up to $50,000 each for three counts of air and water pollution, plus $10,000 per day for any continuing violation. The State also seeks an injunction against future similar events. On August 29, 1996, the Illinois Attorney General's office proposed a settlement in the form of a consent decree that would require the Partnership to implement several fire protection recommendations, pay a $100,000 civil penalty, and pay a $500 per day penalty if established deadlines for implementing the recommendations are not met. The Partnership has made a settlement offer to the State and settlement negotiations are ongoing. If attempts at settlement are unsuccessful, the General Partner will vigorously defend itself and the Partnership against the charges. Although no assurance can be given, the Partnership believes that the ultimate resolution of this matter will not have a material adverse effect on its financial position or results of operations.
On December 10, 1996, the U.S. Department of Transportation ("D.O.T") issued to the General Partner a notice of eight probable violations of federal safety regulations in connection with the fire at the Morris storage field. The D.O.T proposed a civil penalty of $90,000. The General Partner is currently in the process of responding to the notice, but believes that the alleged violations and proposed fine will not have a material impact on the Partnership.
It is expected that the Partnership will reimburse the General Partner for any liability or expenses incurred by the General Partner in connection with these legal proceedings.
The operations of the Partnership are subject to federal, state and local laws and regulations relating to protection of the environment. The Partnership believes that its operations and facilities are in general compliance with applicable environmental regulations. The Partnership has an ongoing environmental audit and compliance program. Risks of accidental leaks or spills are, however, associated with fractionation of NGLs, transportation of NGLs and refined petroleum products, the handling and storage of coal, the processing of gas, as well as the truck and rail loading of fractionated products. There can be no assurance that significant costs and liabilities will not be incurred, including those relating to claims for damages to property and persons resulting from operation of the Partnership's businesses. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies thereunder, could result in increased costs and liabilities to the Partnership.
7. Major Customers and Concentrations of Credit Risk
A substantial portion of the Partnership's revenues is derived from transportation services to oil and gas refining and marketing companies in the Midwest. This concentration could affect the Partnership's overall exposure to credit risk inasmuch as these customers could be affected by similar economic or other conditions. However, management believes that the Partnership is exposed to minimal credit risk. The Partnership generally does not require collateral for its receivables.
In 1996, revenues from two customers represented 12.4% and 10.4% of total Partnership revenues. In 1995, revenues from two customers represented 10.2% each of total Partnership revenues. In 1994, revenues from one liquids pipelines customer represented 10.1% of total Partnership revenues.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. Related Party Transactions
Revenues and Expenses
Revenues for the years ended December 31, 1996, 1995 and 1994 include transportation charges and product sales to an Enron subsidiary, Enron Gas Liquids, Inc., of $7.7 million, $5.9 million and $4.7 million, respectively. Another Enron subsidiary, Enron Gas Processing Company ("EGP"), provides services in connection with the Mobil Agreement (see Note 10) as well as storage and other services to the Partnership and charged $6.6 million, $2.7 million and $0.7 million for the years ended December 31, 1996, 1995 and 1994, respectively. Management believes that these charges are reasonable. As a result of KMI's acquisition of all of the common stock of the General Partner, Enron and its affiliates are no longer affiliates of the Partnership.
The Partnership leases certain capacity rights of 17 MBbls/d of the North System to Heartland Pipeline Company ("Heartland") under a long-term lease agreement which will expire in 2010. Revenues earned from Heartland for the lease rights were $0.9 million for each of the years ended December 31, 1996, 1995 and 1994.
General and Administrative Expenses
The Partnership has no employees and is managed and controlled by the General Partner pursuant to the Partnership Agreements. Under the terms of the Partnership Agreements, the General Partner is reimbursed for certain expenses incurred by it on behalf of the Partnership. Additionally, prior to the sale of the General Partner, Enron and its affiliates were reimbursed for certain corporate staff and support services rendered to the General Partner in managing and operating the Partnership pursuant to the terms of the Omnibus Agreement which was executed among Enron, the Partnership and the General Partner at the time of formation of the Partnership. The amount paid by the Partnership to reimburse Enron and its affiliates for such services to the General Partner was subject to certain limitations established under the terms of the Omnibus Agreement. For the years ended December 31, 1996, 1995 and 1994 the maximum amount allowed for reimbursements of $5.8 million, $5.5 million and $5.1 million, respectively, were paid to Enron for Basic Services, as defined in the Omnibus Agreement. As a result of KMI's acquisition of the General Partner, Enron and its affiliates are no longer required to provide corporate staff and support services under the terms of the Omnibus Agreement, and the limitations on reimbursement for corporate staff and support services incurred by the General Partner on behalf of the Partnership are no longer applicable.
Partnership Distributions
The General Partner owns 431,000 Common Units, representing approximately 6.6% of the Common Units. The Partnership Agreements provide for incentive distributions payable to the General Partner out of the Partnership's Available Cash in the event that quarterly distributions to Unitholders exceed certain specified targets. In general, subject to certain limitations, if a quarterly distribution to Unitholders exceeds a target of $0.605 per Unit, the General Partner will receive incentive distributions equal to (i) 15% of that portion of the quarterly distribution per Unit that exceeds $0.605 but is not more than $0.715, plus (ii) 25% of that portion of the quarterly distribution per Unit that exceeds the quarterly distribution amount of $0.715
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
but is not more than $0.935, plus (iii) 50% of that portion of the quarterly distribution per Unit that exceeds $0.935.
To support the Partnership's ability to distribute the Minimum Quarterly Distribution on all outstanding Common Units through the period ending September 30, 1997, Enron agreed that, if necessary, it would contribute cash to the Partnership in exchange for APIs in the Partnership. The APIs are not entitled to cash distributions, allocations of taxable income or loss (except under limited circumstances) or voting rights, but the Partnership is required to redeem them if and to the extent that Available Cash reaches certain levels. No APIs have been purchased by Enron since the inception of the Partnership, and management does not expect that APIs will be required to be purchased to support the payment of distributions in 1997. KMI obtained a $10.9 million letter of credit from First Union to support Enron's remaining obligations with respect to the Minimum Quarterly Distribution payable to the holders of the Partnership's Common Units.
South Cowden Lateral
During 1996, a lateral was constructed that connects the South Cowden Unit flood project to the Central Basin Pipeline. The lateral is owned by Morgan Associates, Inc. ("MAI"), which is owned by William V. Morgan, and was constructed for MAI by the Partnership under the terms of a Construction Agreement at a cost of $1.35 million, which amount has been paid by MAI. In addition, MAI and the Partnership entered into an Operating & Maintenance Agreement which provides for operation and maintenance of the lateral by the Partnership and a Transportation Agreement which allows the Partnership to ship specified quantities of CO2 on the lateral and requires the Partnership to ship certain minimum quantities of CO2 on the lateral. The agreements are coterminus and expire in 2016. During 1996, the Partnership charged MAI $31,250 under the Operating & Maintenance Agreement and MAI charged the Partnership $194,648 under the Transportation Agreement. The terms of such agreements are comparable to those which the Partnership would make available to unaffiliated third parties.
9. Regulatory Matters
The tariffs charged for interstate common carrier pipeline transportation for the North System and the Cypress Pipeline are subject to rate regulation by the FERC under the Interstate Commerce Act ("ICA"). The ICA requires, among other things, that petroleum products (including NGLs) pipeline rates be just and reasonable and non-discriminatory. Pursuant to FERC Order No. 561, effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying Order No. 561, expands the circumstances under which petroleum pipelines may employ cost-of-service ratemaking in lieu of the indexing methodology, effective January 1, 1995. In 1995 and 1996, application of the indexing methodology did not significantly affect the Partnership's rates.
10. Commitments and Leases
The primary shipper on the Cypress Pipeline has the right until 2011 to purchase up to a 50% joint venture interest in the pipeline at a price based on, among other things, the construction cost of the Cypress Pipeline, plus adjustments for expansions. If the customer exercises its rights under the option, management anticipates that no loss will accrue to the Partnership.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under a joint tariff agreement, the Partnership's North System is obligated to pay minimum tariff revenues of approximately $2.2 million per contract year to an unaffiliated pipeline company subject to certain adjustments. This agreement expires June 30, 2001, but provides for two five-year extensions at the option of the Partnership.
On October 1, 1995, EGP assigned to the Partnership an EGP gas processing contract with Mobil Natural Gas, Inc. (the "Mobil Agreement"). Under this contract, the Partnership is obligated to process dedicated volumes of natural gas produced by Mobil. Also on October 1, 1995, the Partnership subleased from EGP a portion of the capacity at the Bushton gas processing plant located in Ellsworth County, Kansas (the "Bushton Plant"). The leased capacity at the Bushton Plant enables the Partnership to fulfill the processing obligations it assumed in the Mobil Agreement. The Mobil Agreement and the sublease agreement are coterminous with primary terms ending April 30, 2005. As a result of these transactions, the Partnership receives processing fees from Mobil and makes sublease payments to EGP.
The Partnership has entered into certain operating leases primarily in relation to the gas processing and coal terminaling operations. The leases have remaining terms ranging from eight to thirty-one years. Future commitments related to these leases, including the sublease payments to EGP, at December 31, 1996 are as follows (in thousands):
1997 $ 1,411 1998 1,305 1999 1,357 2000 1,505 2001 1,535 Thereafter 8,050 ----- Total minimum payments 15,163
Total lease expenses, including related variable charges, incurred for the years ended December 31, 1996, 1995 and 1994 were $1.5 million, $1.4 million and $0.4 million, respectively.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Business Segment Information
The Partnership's operations are classified into three business segments: Liquids pipelines (which includes transportation services and NGL and CO2 product sales to shippers), coal transfer and storage, and gas processing and fractionation. Financial information by business segment follows (in thousands):
(a) Other includes cash and other miscellaneous assets.
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. Quarterly Financial Data (Unaudited)
(In thousands, except Operating Net Income per unit amounts) Revenues Income Net Income per Unit
First Quarter $15,137 $4,900 $2,935 $0.51 Second Quarter 10,394 2,927 1,259 0.22 Third Quarter 12,192 3,580 1,906 0.33 Fourth Quarter 17,181 6,697 5,002 0.76
First Quarter $15,708 $5,846 $3,996 $0.60 Second Quarter 12,322 2,852 1,615 0.24 Third Quarter 15,215 2,830 978 0.14 Fourth Quarter 21,059 6,607 4,725 0.71
First Quarter $18,431 $5,124 $2,810 $0.42 Second Quarter 14,668 2,860 1,353 0.20 Third Quarter 14,422 1,948 2,346 0.35 Fourth Quarter 23,729 7,141 5,391 0.82
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Mont Belvieu Associates:
We have audited the accompanying balance sheet of Mont Belvieu Associates (a Texas general partnership) as of December 31, 1996 and 1995, and the related statements of income, cash flows and partners' capital for each of the three years in the period ended December 31, 1996. 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 in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Mont Belvieu Associates as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the years in the period ended December 31, 1996 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas February 21, 1997
MONT BELVIEU ASSOCIATES STATEMENT OF INCOME (In thousands)
Year Ended December 31, 1996 1995 1994
Revenues $26,954 $25,795 $27,272
Costs and expenses Operations and maintenance 14,302 13,361 13,221 Depreciation 1,424 1,293 1,222 Taxes, other than income taxes 634 517 502 Amortization of organization costs -- 4 7 ------ ------ ------ 16,360 15,175 14,952
Operating income 10,594 10,620 12,320
Other income (expense) Interest expense (92) (125) (17) Other 105 329 81 ------ ------- ------ 13 204 64 ------ ------- ------
Net income $10,607 $10,824 $12,384 ======= ======= =======
The accompanying notes are an integral part of these financial statements.
MONT BELVIEU ASSOCIATES BALANCE SHEET (In thousands)
December 31, 1996 1995 ASSETS
Current assets Cash and cash equivalents $ 2 $ 11 Accounts receivable Due from partners 1,542 3,261 Trade 3,510 3,595 Advances to fractionator 1,448 1,218 ------ ------ 6,502 8,085
Property, plant and equipment, at cost 68,609 56,926 Less accumulated depreciation 22,643 21,219 45,966 35,707
TOTAL ASSETS $52,468 $43,792 ======= =======
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities Accounts payable due to fractionator $ 282 $ 2,708 Current portion of long-term debt 2,996 Accrued taxes other than income 536 Deferred revenues 732 - ------ ------ 4,546 3,643
Long-term debt (Note 3) 15,022 1,019
Partners' capital 32,900 39,130 ------ ------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $52,468 $43,792
The accompanying notes are an integral part of these financial statements.
MONT BELVIEU ASSOCIATES STATEMENT OF CASH FLOWS (In thousands)
The accompanying notes are an integral part of these financial statements.
MONT BELVIEU ASSOCIATES STATEMENT OF PARTNERS' CAPITAL (In thousands)
The accompanying notes are an integral part of these financial statements.
MONT BELVIEU ASSOCIATES NOTES TO FINANCIAL STATEMENTS
1. Organization and Formation
Mont Belvieu Associates ("MBA"), a Texas general partnership formed on July 17, 1985, owns an undivided 50% interest in a natural gas liquids fractionation facility (the "Mont Belvieu Fractionator" or the "Fractionator") located in Chambers County, Texas. Enterprise Products Company ("Enterprise") owns a 50% interest in MBA and operates the Fractionator. Kinder Morgan Natural Gas Liquids Corporation ("KMNGL") owns the remaining 50% interest and serves as the managing general partner for MBA.
2. Summary of Significant Accounting Policies
Basis of Presentation
MBA accounts for its investment in the Fractionator using the proportionate consolidation method of accounting, whereby MBA's proportionate share of assets, liabilities, revenues and operating expenses are reflected in the accompanying financial statements.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash Equivalents
Cash equivalents are defined as all highly liquid short-term investments with original maturities of three months or less.
Property, Plant and Equipment
Property, plant and equipment is stated at cost. Depreciation is computed using the straight-line method based on the estimated economic and physical life of the assets. Effective January 1, 1994, the depreciable life was extended from 20 to 30 years to more appropriately reflect the remaining useful life of these assets. This change resulted in a $1.6 million adjustment to depreciation expense for 1994.
Revenue Recognition
Revenues are recognized based on actual barrels fractionated.
Income Taxes
MBA is not a taxable entity for federal income tax purposes. As such, no federal income tax will be paid by MBA. Each partner will be required to report on its tax return its allocable share of the taxable income or loss of MBA.
MONT BELVIEU ASSOCIATES NOTES TO FINANCIAL STATEMENTS
3. Long-Term Debt
MBA's debt at December 31, 1996 included a note payable to Enterprise for expansion projects. The original principal balance of $1.6 million is due in 48 equal monthly payments with the final payment being made in September 1999. Interest on the note is equal to the Eurodollar rate plus 1.75%. During 1995, the weighted-average interest rate on this note was 7.14%. The note is secured by MBA's partnership interest in the Fractionator.
MBA has outstanding a $17 million promissory note which bears interest equal to the London Interbank Offered Rate ("LIBOR") plus a margin of .75% per annum. The principle amount is payable in equal monthly installments, except for the final payment due December 31, 2001, based on a six year amortization schedule commencing February 14, 1997. The loan is non-recourse to the partners and is secured by the borrower's rights under the Operating Agreement between the joint owners.
Maturities of long-term debt as of December 31, 1996 were as follows (in thousands): 1997 $2,996 1998 3,233 1999 3,054 2000 2,833 2001 5,903 Thereafter -
4. Related Party Transactions and Concentration of Credit Risk
Generally, each partner of the Fractionator has the right to deliver natural gas liquids up to its proportionate share of fractionator capacity. Approximately 92% of revenues was earned from the partners of the Fractionator in 1996. All billings are passed from the Fractionator to MBA for its applicable portion. In turn, MBA bills each of its partners. All of MBA's revenues are derived from fractionation services to customers in the Gulf Coast area. This concentration could impact MBA's exposure to credit risk inasmuch as these customers could be affected by similar economic or other conditions. However, management believes that MBA is exposed to minimal credit risk. MBA generally does not require collateral for its receivables.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 21st day of March, 1997.
KINDER MORGAN ENERGY PARTNERS, L.P. (A Delaware Limited Partnership) By: KINDER MORGAN G.P., INC. as General Partner
By:/s/ Thomas B. King Thomas B. King President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.
Signature Title Date
/s/ Richard D. Kinder Director, Chairman and CEO March 21, 1997 Richard D. Kinder (Principal Executive Officer)
/s/ William V. Morgan Director and Vice Chairman March 21, 1997 William V. Morgan
/s/ Alan L. Atterbury Director March 21, 1997 Alan L. Atterbury
/s/ Edward O. Gaylord Director March 21, 1997 Edward O. Gaylord
/s/ Thomas B. King Director and President March 21, 1997 Thomas B. King
/s/ Thomas P. Tosoni Chief Financial Officer March 21, 1997 Thomas P. Tosoni (Principal Financial and Accounting Officer)
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