SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
F O R M 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996 Commission file
number: 1-11234
KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0380342
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1301 McKinney Street, Ste. 3450, Houston, Texas 77010
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-844-9500
Securities registered pursuant to Section 12(b) of the Act:
Title of each className of each exchange on which registered
Common Units New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
Aggregate market value of the Common Units held by non-affiliates of the
registrant, based on closing prices in the daily composite list for transactions
on the New York Stock Exchange on March 12, 1997, was approximately
$254,043,000.
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page No.
P A R T I
Item 1. Business 1
Item 2. Properties 18
Item 3. Legal Proceedings 18
Item 4. Submission of Matters to a Vote of Security Holders 19
P A R T II
Item 5. Market for the Registrant's Common Units and
Related Security Holder Matters 20
Item 6. Selected Financial Data 21
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation 22
Item 8. Financial Statements and Supplementary Data 26
Item 9. Changes in and Disagreements on Accounting and
Financial Disclosure 26
P A R T III
Item 10. Directors and Executive Officers of the
Registrant 27
Item 11. Executive Compensation 28
Item 12. Security Ownership of Certain Beneficial
Owners and Management 30
Item 13. Certain Relationships and Related Transactions 31
P A R T IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 33
Financial Statements F-1
i
P A R T I
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
2
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.
3
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.
4
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.
5
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
6
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.
7
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
8
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
9
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
10
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
11
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
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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
13
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.
14
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.
15
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.
16
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
17
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. 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. 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
18
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. 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.
19
P A R T II
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
---- --- -------------
1996
----
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
1995
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."
20
Item 6. Selected Financial Data (unaudited)
(in thousands, except per unit and operating data)
Combined
Partnership Historical
------------------------------------------------------------------------------- ------------
Pro Forma Seven Months
Year Five Months Ended
Year Ended December 31, December 31, December 31, July 31,
---------------------------------------------- ------------ --------------- ----------
Income and Cash Flow Data:
Revenues $ 71,250 $ 64,304 $ 54,904 $ 51,180 $ 53,010 $ 24,146 $ 28,863
Cost of product sold 7,874 8,020 940 685 762 762 -
Operating Expense 27,263 19,862 19,125 19,807 20,672 8,977 11,797
Lease expense, net - - - - - - 3,536
Depreciation 9,908 9,548 8,539 7,167 7,050 2,938 2,431
General and administrative 9,132 8,739 8,196 7,073 6,641 2,729 4,716
----- ------- ------- ------- ------- ------- --------
Operating Income 17,073 18,135 18,104 16,448 17,885 8,740 6,383
Equity in earnings (loss)
of partnerships 5,675 5,755 5,867 1,835 1,755 826 1,244
Interest expense (12,634) (12,455) (11,989) (10,302) (9,648) (3,965) -
Other Income 3,129 1,311 509 510 497 166 93
Net Income $ 11,900 $ 11,314 $ 11,102 $ 8,574 $ 10,383 $ 5,777 $ 7,251
--------- ======== ======== ======== ======== ======== ========
Net Income per Common
Unit $ 1.79 $ 1.71 $ 1.86 $ 1.50 $ 1.82 $ 1.01 $ -
======== ======== ======== ======== ======== ======== ========
Additions to property, $ 8,575
plant and equipment(1) $ 7,826 $ 5,195 $ 4,688 $ 5,644 $ 1,507 $ 4,137
Balance Sheet Data (at end of
period):
Net property, plant and
equipment $235,994 $236,854 $238,850 $228,859 $ - $206,108 $116,066
Total assets 303,603 303,664 299,271 288,345 - 260,943 155,087
Long-term debt 160,211 156,938 150,219 138,485 - 110,000 -
Equity of parent - - - - - - 120,379
Partners' capital 118,344 123,116 128,474 132,391 - 136,851 -
Operating Data (unaudited):
Liquids pipelines
transportation volumes
(MBbls) 46,601 41,613 46,078 52,600 53,874 24,427 29,447
NGL fractionation volumes
(MBbls)(2) 59,912 59,546 57,703 53,053 47,517 19,060 28,457
Gas processing volumes
(MMcf/d)(3) 14 34 34 - - - -
NGL revenue volumes
(MBbls)(4) 1,638 477 - - - - -
CO2 transportation
volumes (Bcf) 63 44 32 33 32 14 18
Coal transport volumes
(Mtons)(5) 6,090 6,486 4,539 1,209 - - -
(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.
21
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
22
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.
23
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
24
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.
25
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 F-1.
Item 9. Changes in and Disagreements on Accounting and
Financial Disclosure
None.
26
P A R T 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
27
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.
28
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.
29
Item 12. Security Ownership of Certain Beneficial Owners
and Management
Amount and Nature of Beneficial Ownership
KMI Voting Stock KMI Non Voting Stock
Common Units (1) (Class "A" Stock) (Class "B" Stock)
------------------ ------------------- ------------------
Number Percent Number Percent Number Percent
of Units of Class(2) of Shares (3) of Class of Shares(3) of Class
First Union Corporation 429,000 6.6% 105 1.98% 2,541 47.99%
One First Union Center
5th Floor
301 South College Street
Charlotte, NC 28288-0732
Kinder Morgan G.P., Inc 431,000 6.6% -- -- -- --
1301 McKinney Street
Suite 3450
Houston, Texas 77010
Kinder Morgan, Inc. (4) 431,000 6.6% -- -- -- --
1301 McKinney Street
Suite 3450
Houston, Texas 77010
Richard D. Kinder 7,500 * 2,646 49.99% 2,648 50.01%
William V. Morgan 1,000 * 2,542(5) 48.03% 106(5) 2.00%
Alan L. Atterbury 3,000 * -- -- -- --
Edward O. Gaylord -- -- -- -- -- --
Thomas B. King -- -- -- -- -- --
Directors and Officers 12,300 * 5,188 98.00% 2,754 52.01%
as a group (9 persons)
*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
30
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.
31
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.
32
P A R T 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 F-1.
(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)
33
*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)
34
*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.
35
(b) Reports on Form 8-K
Form 8-K dated February 14, 1997, covering Items 1, 5 and 7.
36
INDEX TO FINANCIAL STATEMENTS
Page
KINDER MORGAN ENERGY PARTNERS, L.P.
AND SUBSIDIARIES
Report of Independent Public Accountants F-2
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994 F-3
Consolidated Balance Sheets for the years ended December
31, 1996 and 1995 F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994 F-5
Consolidated Statements of Partners' Capital for the
years ended December 31, 1996, 1995 and 1994 F-6
Notes to Consolidated Financial Statements F-7
MONT BELVIEU ASSOCIATES
Report of Independent Public Accountants F-22
Statements of Income for the years ended December 31,
1996, 1995 and 1994 F-23
Balance Sheets for the years ended December 31, 1996 and
1995 F-24
Statements of Cash Flows for the years ended December
31, 1996, 1995 and 1994 F-25
Statements of Partners' Capital for the years ended
December 31, 1996, 1995 and 1994 F-26
Notes to Financial Statements F-27
F-1
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
F-2
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.
F-3
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.
F-4
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.
F-5
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
Deferred Total
Common Participation General Partners'
Units Units Partner Capital
------- ------------- ------- --------
Partners' capital at December 31, 1993 $113,711 $17,376 $1,304 $132,391
Net income 10,228 652 222 11,102
Distributions (14,236) (542) (241) (15,019)
--------- ----- ----- -------
Partners' capital at December 31, 1994 109,703 17,486 1,285 128,474
Net income 9,633 1,469 212 11,314
Distributions (14,236) (2,168) (268) (16,672)
-------- ------- ----- -------
Partners' capital at December 31, 1995 105,100 16,787 1,229 123,116
Net income 10,136 1,546 218 11,900
Distributions (14,236) (2,168) (268) (16,672)
-------- ------- ----- -------
Partners' capital at December 31, 1996 $101,000 $16,165 $1,179 $118,344
======== ======= ====== ========
The accompanying notes are an integral part of these consolidated
financial statements.
F-6
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").
F-7
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.
F-8
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
====== ====== ======
F-9
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
F-10
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.
F-11
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
F-12
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
F-13
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
F-14
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
F-15
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.
F-16
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
F-17
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.
F-18
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.
F-19
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):
1996 1995 1994
---- ---- ----
Revenues
Liquids pipelines $54,064 $46,986 $44,753
Coal transfer and storage 8,059 8,398 6,670
Gas processing and fractionation 9,127 8,920 3,481
------- ------- -------
Total $71,250 $64,304 $54,904
======= ======= =======
Depreciation and Amortization
Liquids pipelines $7,558 $7,267 $7,173
Coal transfer and storage 1,366 1,332 905
Gas processing and fractionation 984 949 461
------ ------ ------
Total $9,908 $9,548 $8,539
====== ====== ======
Operating Income
Liquids pipelines $13,100 $10,346 $12,916
Coal transfer and storage 4,001 4,320 3,638
Gas processing and fractionation (28) 3,469 1,550
-------- ------- -------
Total $17,073 $18,135 $18,104
======= ======= =======
Additions to Property, Plant
and Equipment
Liquids pipelines $7,673 $7,342 $4,171
Coal transfer and storage 606 148 718
Gas processing and fractionation 296 336 306
------ ------ -----
Total $8,575 $7,826 $5,195
====== ====== ======
Total Assets
Liquids pipelines $247,266 $245,329 $243,505
Coal transfer and storage 28,738 29,673 30,527
Gas processing and fractionation 12,833 14,479 14,253
Other (a) 14,766 14,183 10,986
-------- -------- --------
Total $303,603 $303,664 $299,271
======== ======== ========
(a) Other includes cash and other miscellaneous
assets.
F-20
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
1994
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
1995
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
1996
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
F-21
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
F-22
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.
F-23
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
399
Accrued taxes other than income 536
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.
F-24
MONT BELVIEU ASSOCIATES
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 $10,607 $10,824 $12,384
Depreciation and amortization 1,424 1,297 1,229
Changes in components of working capital
Advances to fractionator (230) 92 (103)
Accounts receivable 1,804 (1,745) 853
Accounts payable due to fractionator(2,426) 1,161 (475)
Accrued taxes other than income - (1) -
Other, net 732 (1,423) 412
------- ------- ------
Net cash provided by operating activities 11,911 10,205 14,300
------- ------- ------
Cash flows from investing activities
Additions to property, plant and equipment (11,684) (2,089) (1,404)
------- ------ ------
Net cash used in investing activities (11,684) (2,089) (1,404)
------- ------ ------
Cash flows from financing activities
Contributions from partners 871 1,652 252
Issuance of long-term debt 17,000 436 1,148
Repayment of long-term debt (399) (166) -
Cash distributions (14,308) (10,036) (14,294)
Distribution of Equity Loan
to Enterprise (3,400) - -
Net cash used in financing activities (236) (8,114) (12,894)
----- ------- -------
Increase (decrease) in cash and cash equivalents(9) 2 2
Cash and cash equivalents, beginning of period 11 9 7
Cash and cash equivalents, end of period $ 2 $ 11 $ 9
======= ======== =======
Supplemental disclosures of cash flow information
Cash paid during the year for
interest (including capitalized interest) $333 $125 $17
The accompanying notes are an integral part of these financial
statements.
F-25
MONT BELVIEU ASSOCIATES
STATEMENT OF PARTNERS' CAPITAL
(In thousands)
Total
Enterprise Partners'
KMNGL Products Co. Capital
----- ------------ -------
Partners' capital at December 31, 1993 (unaudited) $ 19,174 $ 19,174 $ 38,348
Contributions 126 126 252
Net income 6,192 6,192 12,384
Distributions (7,147) (7,147) (14,294)
------- ------- -------
Partners' capital at December 31, 1994 18,345 18,345 36,690
Contributions 826 826 1,652
Net income 5,412 5,412 10,824
Distributions (5,018) (5,018) (10,036)
------- ------- -------
Partners' capital at December 31, 1995 19,565 19,565 39,130
Contributions 435 436 871
Net income 5,304 5,303 10,607
Distributions (7,154) (7,154) (14,308)
Distributions for equity loan -- (3,400) (3,400)
--------- -------- --------
Partners' capital at December 31, 1996 $ 18,150 $ 14,750 $ 32,900
========= ======== ========
The accompanying notes are an integral part of these financial
statements.
F-26
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.
F-27
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.
F-28
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)
S-1