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, 1999
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 class Name of each exchange on which registered
- ------------------- -----------------------------------------
Common Units of Kinder Morgan New York Stock Exchange
Energy Partners, L.P.
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
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 9, 2000 was approximately
$2,072,691,683. This figure assumes that only the general partner of the
registrant, Kinder Morgan, Inc. and officers and directors of the general
partner of the registrant and Kinder Morgan, Inc. were affiliates. As of March
9, 2000, the registrant had 59,712,109 Common Units outstanding.
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KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page No.
P A R T I
Items 1 and 2. Business and Properties 3
Item 3. Legal Proceedings 43
Item 4. Submission of Matters to a Vote of Security Holders 43
P A R T II
Item 5. Market for the Registrant's Units and Related
Security Holder Matters 44
Item 6. Selected Financial Data 45
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation 46
Item 7a. Quantitative and Qualitative Disclosures About
Market Risk 56
Item 8. Financial Statements and Supplementary Data 57
Item 9. Changes in and Disagreements on Accounting and
Financial Disclosure 57
P A R T III
Item 10. Directors and Executive Officers of the Registrant 58
Item 11. Executive Compensation 60
Item 12. Security Ownership of Certain Beneficial Owners and
Management 62
Item 13. Certain Relationships and Related Transactions 63
P A R T IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 65
Financial Statements F-1
Signatures S-1
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P A R T I
Items 1. and 2. Business and Properties
Kinder Morgan Energy Partners, L.P. ("Partnership"), a Delaware limited
partnership, is a publicly traded Master Limited Partnership ("MLP") formed in
August 1992. The Partnership manages a diversified portfolio of midstream energy
assets that provide fee-based services to customers. These assets include
pipelines, which transport refined petroleum products, natural gas liquids and
natural gas, and terminals, which transport both liquid and bulk products.
The address of the Partnership's principal executive offices is 1301 McKinney
Street, Suite 3450, Houston, Texas 77010 and its telephone number at this
address is (713) 844-9500. The Partnership trades under the New York Stock
Exchange symbol "KMP". The Partnership's operations are grouped into four
reportable business segments. These segments and their major assets are as
follows:
o Pacific Operations, consisting of a 3,300 mile refined petroleum products
pipeline system operating in Arizona, California, Nevada, New Mexico,
Oregon and Texas, truck-loading terminals and joint venture projects
including:
o the South Region, consisting of three pipeline segments:
o the South Line, which has two pipeline segments:
o the West Line, which transports petroleum products from the
Los Angeles Basin to Phoenix and Tucson, Arizona, including
intermediate points; and
o the East Line, which transports petroleum products from
El Paso, Texas to Tucson and Phoenix; and
o the San Diego Line, extending from Los Angeles to the
Partnership's terminals in Orange and San Diego, California;
o the North Region, consisting of two pipeline segments:
o the North Line, which has six pipeline segments originating in
Richmond, Concord and Bakersfield, California serving the
Partnership's terminals located in Brisbane, Bradshaw, Chico,
Fresno and San Jose, California and Sparks, Nevada; and
o the Oregon Line, extending from its Portland, Oregon origin
southward to the Partnership's terminal in Eugene, Oregon;
o 13 truck-loading terminals; and
o a 50% interest in the Colton Processing Facility, a petroleum
pipeline transmix processing facility located in Colton, California.
o Mid-Continent Operations, consisting of products pipelines and joint
venture projects including:
o the North System, a 1,600 mile pipeline that transports natural gas
liquids and refined petroleum products between south central Kansas
and the Chicago area and various intermediate points, including
eight terminals;
o a 51% interest in Plantation Pipe Line Company, which owns and
operates a 3,100 mile refined petroleum products pipeline system
throughout the southeastern United States;
o a 20% limited partner interest in Shell CO2 Company, which
transports, markets and produces CO2 for use in enhanced oil
recovery operations in the continental United States. On March 9,
2000, the Partnership announced it had reached a definitive
agreement to acquire the remaining 80% interest in Shell CO2
Company;
o the Cypress Pipeline, which transports natural gas liquids from
Mont Belvieu, Texas to a major petrochemical producer in Lake
Charles, Louisiana;
o transmix operations, which includes the processing and marketing
of petroleum pipeline transmix along the Atlantic Coast via two
transmix processing plants;
o a 50% interest in the Heartland Pipeline Company, which ships
refined petroleum products in the Midwest; and
o the Painter Gas Processing Plant, a natural gas processing plant,
fractionator and natural gas liquids terminal with truck and rail
loading facilities. The Painter Plant is leased to BP Amoco under a
long-term arrangement.
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o Natural Gas Operations, consisting of assets acquired in late 1999,
including:
o Kinder Morgan Interstate Gas Transmission LLC ("KMIGT"), which
owns a 6,700 mile natural gas pipeline, including the Pony
Express pipeline facilities, that extends from northwestern
Wyoming east into Nebraska and Missouri and south through
Colorado and Kansas;
o a 66 2/3% interest in the Trailblazer Pipeline Company, which
transmits natural gas from Colorado through southeastern Wyoming
to Beatrice, Nebraska; and
o a 49% interest in the Red Cedar Gathering Company, which gathers
natural gas in La Plata County, Colorado and owns and operates a
CO2 processing plant.
o Bulk Terminals, comprised of over 20 owned or operated bulk terminal
facilities, including:
o coal terminals located in Cora, Illinois; Paducah, Kentucky;
Newport News, Virginia; Mount Vernon, Indiana; and Los Angeles,
California;
o petroleum coke terminals located on the lower Mississippi River
and along the west coast of the United States; and
o other bulk terminals handling alumina, cement, salt, soda ash,
fertilizer and other dry bulk materials.
Business Strategy
Management's objective is to operate as a low-cost, growth-oriented MLP by:
o reducing operating expenses;
o better utilizing and expanding its asset base; and
o making selective, strategic acquisitions that will increase unitholder
distributions. Management has announced a target of approximately $1
billion of acquisitions annually.
The general partner's incentive distributions provide it with a strong
motivation to increase unitholder distributions through successful management
and business growth. The Partnership is the largest pipeline MLP in terms of
market capitalization and the second largest products pipeline system in the
United States in terms of volumes delivered. Generally, the Partnership
transports and/or handles products for a fee and is not engaged in the purchase
and resale of commodity products. As a result, the Partnership does not face
significant risks relating directly to shifts in commodity prices.
Pacific Operations. The Partnership plans to continue to expand its presence
in the rapidly growing refined products market in the Western United States
through incremental expansions of the Pacific Operations and acquisitions that
increase unitholder distributions. In May 1999, the Partnership completed an
expansion of its Southern California products pipeline system. The expansion
involved construction of 13 miles of 16-inch diameter pipeline from Carson,
California to Norwalk, California, and increased the capacity of the West Line
Southern California products pipeline system from 340,000 barrels per day to
520,000 barrels per day, an increase of over 50%.
Mid-Continent Operations. Because the North System serves a relatively mature
market, the Partnership intends to focus on increasing throughput within the
system by remaining a reliable, cost-effective provider of transportation
services and by continuing to increase the range of products transported and
services offered. The Partnership believes favorable demographics in the
southeastern United States will serve as a platform for increased use and
expansion of Plantation's pipeline system, which serves major metropolitan
areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North
Carolina; and the Washington, D.C. area. Within the Permian Basin, the strategy
of Shell CO2 Company is to offer customers "one-stop shopping" for CO2 supply,
transportation and technical support service. Outside the Permian Basin, Shell
CO2 Company intends to compete aggressively for new supply and transportation
projects. The Partnership believes these projects will arise as other U.S. oil
producing basins mature and make the transition from primary production to
enhanced recovery methods. The acquisition of the transmix operations, in
September 1999, strengthened the Partnership's existing transmix processing
business and added fee-based services related to its core refined products
pipeline business.
Natural Gas Operations. KMIGT also serves a stable, mature market, and thus
the Partnership is focused on reducing costs and securing throughput for this
pipeline. New measurement systems and other improvements will
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aid in managing expenses. Expansion and storage opportunities will be explored
to increase utilization levels. Shippers have expressed interest in expanding
the Trailblazer pipeline, which the Partnership will pursue if it can obtain
commitments for the additional capacity. The Red Cedar Gathering Company, a
partnership with the Southern Ute Indian Tribe, is pursuing other gathering and
processing opportunities on tribal land. The unique position of the Southern Ute
Indian Tribe in Red Cedar should continue to provide growth opportunities.
Bulk Terminals. The Partnership is dedicated to growing its bulk terminal
business and has a target of investing $100 to $200 million in the business per
year. Investments will be made to expand and improve existing facilities,
particularly those facilities that handle low-sulfur western coal. The
Partnership will also consider making selective acquisitions that are accretive
to unitholder distributions. Additionally, the Partnership plans to design,
construct and operate new facilities for current and prospective customers. The
Partnership believes it can use newly acquired or developed facilities to
leverage its operational expertise and customer relationships.
Recent Developments
On October 7, 1999, K N Energy, Inc. acquired Kinder Morgan, Inc., a Delaware
corporation ("Kinder Morgan - Delaware"). Kinder Morgan - Delaware is the sole
stockholder of Kinder Morgan G.P., which is the general partner of the
Partnership. At the time of the closing of the acquisition, K N Energy, Inc.
changed is name to Kinder Morgan, Inc. It is referred to as "KMI" in this
report. In connection with the acquisition, Richard Kinder, Chairman and Chief
Executive Officer of the general partner, became the Chairman and Chief
Executive Officer of KMI.
KMI (traded on the New York Stock Exchange under the symbol "KMI") is one of
the largest midstream energy companies in America. Its operations include
natural gas transportation and storage, retail natural gas distribution and
electric generation development. KMI, through its general partner interest,
operates the Partnership, and also holds a significant limited partner interest.
Combined, these two entities have an enterprise value of approximately $10
billion.
During 1999, the Partnership completed four major transactions that
contributed to Partnership assets increasing 50% and to Partnership net income
increasing 76% from 1998 levels. In addition, distributions per unit increased
12% from $0.65 for the fourth quarter of 1998 to $0.725 for the fourth quarter
of 1999.
The following is a brief listing of the transactions completed during 1999.
Additional information regarding these transactions and the acquired assets is
contained in the rest of this report.
o On June 16, 1999, the Partnership acquired an additional 27% of Plantation
Pipe Line Company for $124.2 million. As a result of this investment, the
Partnership now owns 51.17% of Plantation Pipe Line Company;
o On September 10, 1999, the Partnership acquired certain net assets,
including two transmix processing plants, for $18.25 million and the
issuance of 510,147 units. These assets currently comprise the
Partnership's transmix operations;
o Effective November 30, 1999, the Partnership acquired a 33 1/3% interest
in Trailblazer Pipeline Company for $37.6 million; and
o Effective December 31, 1999, KMI transferred over $700 million of assets
to the Partnership for $330 million and the issuance of 9.81 million
units. The Partnership financed a portion of the $330 million through KMI
and plans to repay that amount by the end of the first quarter of 2000.
Assets included in the transfer were KMIGT, formerly K N Interstate Gas
Transmission Co., an additional 33 1/3% interest in Trailblazer Pipeline
Company and a 49% interest in the Red Cedar Gathering Company. As a
result of this transaction, KMI owns 17.9% of the outstanding units as
of March 9, 2000.
On February 7, 2000, the Partnership announced that it had acquired all
shares of the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk
Terminal, Inc., both Wisconsin corporations. The purchase price for the shares
of these entities was approximately $24.1 million, including the issuance of
574,172 units. The effective date of the acquisitions was January 1, 2000, and
going forward from this date, the Partnership will include the activities of
these two terminals as part of the Bulk Terminals business segment.
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On March 9, 2000, the Partnership announced it had reached a definitive
agreement to increase its interest in Shell CO2 Company to 100%. The Partnership
will acquire the remaining 78% limited partner interest and the 2% general
partner interest in Shell CO2 Company from affiliates of Shell Exploration &
Production Company. The transaction price is $185.5 million, and the closing of
the transaction is expected to occur around April 1, 2000.
During the third quarter of 1999, the Partnership completed the sale of its
25% partnership interest in the Mont Belvieu fractionation facility to
Enterprise Products Partners, L.P. for approximately $41.8 million. The
Partnership recognized a gain of $14.1 million on the sale. Since the
Partnership does not actively trade NGLs and seeks to avoid commodity risk, the
Partnership determined that the sale of the passive interest in the
fractionation facility would produce proceeds that could be better utilized in
its core fee-based pipeline and terminal businesses.
Pacific Operations
The Partnership's Pacific Operations include interstate common carrier
pipelines regulated by the Federal Energy Regulatory Commission ("FERC"),
intrastate pipelines in California regulated by the California Public Utilities
Commission ("CPUC"), non rate-regulated terminal operations and a 50% interest
in the Colton Processing Facility.
The Pacific Operations are split into a South Region and a North Region.
Combined, the two regions consist of five pipeline segments that serve six
western states with approximately 3,300 miles of refined petroleum products
pipeline and related terminal facilities.
Refined petroleum products and related uses are:
Product Use
- ---------------------------------------------------------------
Gasoline Transportation
Diesel fuel Transportation (auto, rail, marine),
farm, industrial and commercial
Jet fuel Commercial and military air
transportation
- ---------------------------------------------------------------
The Pacific Operations pipelines transport over one million barrels per day
of refined petroleum products. The three main product types transported are
gasoline (62%), diesel fuel (21%) and jet fuel (17%). The Pacific Operations
also include 13 truck-loading terminals and provide pipeline service to
approximately 44 customer-owned terminals, three commercial airports and 12
military bases.
The Pacific Operations pipeline assets provide refined petroleum products to
some of the fastest growing populations in the United States. Significant
increases in population have occurred in southern California, Las Vegas, Nevada
and the Tucson-Phoenix, Arizona region. Pipeline transportation of gasoline and
jet fuel has a direct correlation with demographic patterns. The Partnership
believes that the positive demographics associated with the markets served by
the Pacific Operations will continue in the foreseeable future.
South Region.
The South Region consists of three pipeline segments: the West Line, the
East Line and the San Diego Line.
The West Line consists of approximately 570 miles of primary pipeline and
currently transports products for approximately 50 shippers from seven
refineries and three pipeline terminals in the Los Angeles Basin to Phoenix and
Tucson, Arizona and various intermediate commercial and military delivery
points. Also, a significant portion of West Line volumes are transported to
Colton, California for local distribution and for delivery to Calnev Pipeline,
an unaffiliated common carrier of refined petroleum products to Las Vegas,
Nevada and intermediate points. The West Line serves Partnership terminals
located in Colton and Imperial, California as well as in Phoenix and Tucson.
In May 1999, the Partnership completed an expansion of its West Line Southern
California products pipeline system. The expansion involved construction of 13
miles of 16-inch diameter pipeline from Carson, California to Norwalk,
California. The new pipeline connects to an existing Partnership 16-inch
diameter pipeline from Norwalk to Colton and provides additional capacity
between Carson and Colton. Prior to the expansion, the existing pipeline between
Carson and Colton had been operating at maximum capacity. The additional pipe
increases the capacity of
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this segment of the pipeline system from 340,000 barrels per day to 520,000
barrels per day, an increase of over 50%.
The East Line is comprised of two parallel lines originating in El Paso,
Texas and continuing approximately 300 miles west to the Tucson terminal and one
line continuing northwest approximately 130 miles from Tucson to Phoenix,
Arizona. All products received by the East Line at El Paso come from a refinery
in El Paso or are delivered through connections with non-affiliated pipelines
from refineries in west Texas and Artesia, New Mexico. The East Line serves
Partnership terminals located in Tucson and Phoenix, Arizona.
The San Diego Line is a 135-mile pipeline serving major population areas in
Orange County (immediately south of Los Angeles) and San Diego. The same
refineries and terminals that supply the West Line also supply the San Diego
Line. This line extends south to serve Partnership terminals in the cities of
Orange and San Diego. On February 25, 1999, the Partnership announced an
expansion of the San Diego Line. The expansion project will cost approximately
$22 million and consists of the construction of 23 miles of 16-inch diameter
pipe, and other appurtenant facilities. The new facilities will increase
capacity on the San Diego Line by approximately 25% and will increase the
Pacific Operation's capability to transport gasoline, diesel and jet fuel to
customers in the rapidly growing Orange County and San Diego, California
markets. Permitting for the project was completed in December 1999 and
construction started in January 2000.
North Region.
The North Region consists of two pipeline segments: the North Line and the
Oregon Line.
The North Line consists of approximately 1,075 miles of pipeline in six
segments originating in Richmond, Concord and Bakersfield, California. This line
serves the Partnership's terminals located in Brisbane, Bradshaw, Chico, Fresno
and San Jose, California, and Sparks, Nevada. The products delivered through the
North Line come from refineries in the San Francisco Bay and Bakersfield areas.
The North Line also receives product transported from various pipeline and
marine terminals that deliver products from foreign and domestic ports. A
refinery located in Bakersfield supplies substantially all of the products
shipped through the Bakersfield-Fresno segment of the North Line. In 1999, the
Partnership completed an expansion of the North Line segments serving the
Sacramento and Chico, California, and Reno, Nevada market areas. The expansion
included the installation of incremental horsepower at certain pumping
facilities and reconfiguration of manifold piping and related facilities. Prior
to the expansion, this segment of the pipeline was operating at its maximum
capacity and the new and modified facilities increased the capacity and
throughput on this segment by 20%.
The Oregon Line is a 114-mile pipeline serving approximately ten shippers.
The Oregon Line receives products from marine terminals in Portland, Oregon and
from Olympic Pipeline. Olympic Pipeline is a non-affiliated carrier that
transports products from the Puget Sound, Washington area to Portland. From its
origination point in Portland, the Oregon Line extends south and serves the
Partnership's terminal located in Eugene, Oregon.
Truck Loading Terminals. The Pacific Operations include 13 truck-loading
terminals with an aggregate usable tankage capacity of approximately 8.2 million
barrels. Terminals are located at destination points on each of the lines as
well as at certain intermediate points along each line. The simultaneous truck
loading capacity of each terminal ranges from 2 to 12 trucks. The Partnership
provides the following services at these terminals:
o short-term product storage;
o truck loading;
o vapor recovery;
o deposit control additive injection;
o dye injection;
o oxygenate blending; and
o quality control.
The capacity of terminaling facilities varies throughout the Pacific
Operations and the Partnership does not own terminaling facilities at all
pipeline delivery locations. At certain locations, the Partnership makes product
deliveries to facilities owned by shippers or independent terminal operators. At
its terminals, the Partnership provides truck
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loading and other terminal services. The Partnership charges a separate fee (in
addition to pipeline tariffs) for these additional non rate-regulated services.
Colton Processing Facility
The Colton Processing Facility, a transmix processing facility located
adjacent to the Partnership's products terminal in Colton, California, was
completed in the spring of 1998. The Partnership and Northridge Petroleum
Marketing U. S., Inc. each own 50% of the facility. Northridge is a wholly owned
subsidiary of TransCanada Energy USA Inc. The facility is designed to process
petroleum transmix, a byproduct of transporting petroleum by pipeline. The
Partnership is responsible for the operation and maintenance of the facility
while Northridge is responsible for securing transmix for processing and selling
the refined products. The Colton Processing Facility also processes proprietary
transmix on a fee basis for ARCO and Chevron USA. The facility processed
approximately 4,000 barrels per day during 1999, which was near the capacity of
the facility. Duke Energy is expected to acquire Northridge from TransCanada
during the first quarter of 2000. This change of ownership is not expected to
have a significant impact on the facility's operations.
Markets. Currently the Pacific Operations serve in excess of 100 shippers
in the refined products market, with the largest customers consisting of:
o major petroleum companies;
o independent refineries;
o the United States military; and
o independent marketers and distributors of products.
A substantial portion of the product volume transported is gasoline. Demand
for gasoline depends on such factors as prevailing economic conditions and
demographic changes in the markets served. The Partnership expects the majority
of the Pacific Operations' markets to maintain growth rates that exceed the
national average for the foreseeable future.
Currently, the California gasoline market is 945,000 barrels per day. The
Arizona gasoline market is served primarily by the Partnership at a market
demand of 135,000 barrels per day. Nevada's gasoline market is approximately
55,000 barrels per day and Oregon's is approximately 95,000 barrels per day. The
distillate (diesel and jet fuel) market is approximately 490,000 barrels per day
in California, 75,000 barrels per day in Arizona, 50,000 barrels per day in
Nevada and 62,000 barrels per day in Oregon. The Partnership transports over 1
million barrels of petroleum products per day in these states.
The volume of products transported is directly affected by the level of
end-user demand for such products in the geographic regions served. Certain
product volumes can experience seasonal variations and, consequently, overall
volumes may be lower during the first and fourth quarters of each year.
The Colton Processing Facility produces refined petroleum products, which are
injected into the segment's pipeline for delivery to markets in Southern
California and Arizona.
Supply. The majority of refined products supplied to the Pacific Operations
come from the major refining centers around Los Angeles, San Francisco and Puget
Sound, as well as waterborne terminals located near these refining centers.
Transmix is primarily supplied by petroleum pipeline and terminal operations,
including the segment's own pipelines in California and other western states.
Competition. The most significant competitors of the Pacific Operations
pipeline system are proprietary pipelines owned and operated by major oil
companies in the area where the pipeline system delivers products as well as
refineries with related trucking arrangements within the Partnership's market
areas. The Partnership believes that high capital costs, tariff regulation and
environmental permitting considerations make it unlikely that a competing
pipeline system comparable in size and scope will be built in the foreseeable
future. However, the possibility of pipelines being constructed to serve
specific markets is a continuing competitive factor. Trucks may competitively
deliver products in certain markets, particularly to shorter-haul destinations
in the Los Angeles and San Francisco Bay areas.
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Longhorn Partners Pipeline is a proposed joint venture project that would
begin transporting refined products from refineries on the Gulf Coast to El Paso
and other destinations in Texas. Increased product supply in the El Paso area
could result in some shift of volumes transported into Arizona from the West
Line to the East Line. While increased movements into the Arizona market from El
Paso would displace higher tariff volumes supplied from Los Angeles on the West
Line, such shift of supply sourcing has not had, and is not expected to have, a
material effect on operating results.
The Colton Processing Facility competes with major oil company refineries and
other transmix processing facilities in California and Arizona.
Mid-Continent Operations
The Mid-Continent Operations include:
o the North System;
o 51% of Plantation Pipe Line Company;
o 20% of Shell CO2 Company;
o the Cypress Pipeline;
o transmix operations;
o 50% of Heartland Pipeline Company; and
o a gas processing plant.
North System
The North System is an approximately 1,600-mile interstate common carrier
pipeline for natural gas liquids ("NGLs") and refined petroleum products.
NGLs are typically extracted from natural gas in liquid form under low
temperature and high pressure conditions. NGL products and related uses are as
follows:
Product Use
- ---------------------------------------------------------------
Propane Residential heating, industrial and
agricultural uses, petrochemical
feedstock
Isobutane Further processing
Natural gasoline Further processing or gasoline blending
into gasoline motor fuel
Ethane Feedstock for petrochemical plants
Normal butane Feedstock for petrochemical plants
- ---------------------------------------------------------------
The North System extends from south central Kansas to the Chicago area. South
central Kansas is a major hub for producing, gathering, storing, fractionating
and transporting NGLs. The North System's primary pipeline is comprised of
approximately 1,400 miles of 8-inch and 10-inch pipelines and includes:
o two parallel pipelines (except for a 50-mile segment in Nebraska), which
originate at Bushton, Kansas and continue to a major storage and terminal
area in Des Moines, Iowa;
o a third pipeline, which extends from Bushton to the Kansas City,
Missouri area; and
o a fourth pipeline that transports product to the Chicago area from Des
Moines.
Through interconnections with other major liquids pipelines, the pipeline
system connects Mid-Continent producing areas to markets in the Midwest and
eastern United States. The Partnership also has defined sole carrier rights to
utilize capacity on an extensive pipeline system owned by The Williams Company
that interconnects with the North System. This capacity lease agreement is in
place until February 2013 and contains a five-year renewal option. In 1999, the
Partnership entered into a long-term agreement with Aux Sable Liquid Products to
transport a significant volume of NGLs in and around the Chicago area for Aux
Sable. The Partnership will make modifications to its pipeline system and its
Morris and Lemont, Illinois facilities in order to accommodate the
transportation of NGLs for Aux Sable. The shipments are expected to begin in the
fourth quarter of 2000.
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The following table sets forth volumes, in thousands of barrels ("MBbls"), of
NGLs transported on the North System (excluding Heartland Pipeline Company) for
delivery to the various markets for the periods indicated:
Year Ended December 31,
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
Petrochemicals 1,059 1,040 1,200 684 1,125
Refineries and
line reversal 10,517 10,489 10,600 9,536 9,765
Fuels 6,172 6,150 7,976 10,500 7,763
Other (1) 8,379 5,532 7,399 8,126 7,114
------ ------ ------ ------ ------
Total 26,127 23,211 27,175 28,846 25,767
====== ====== ====== ====== ======
(1) NGL gathering systems and Chicago originations other than long-haul volumes
of refinery butanes.
The North System has approximately 7.3 million barrels of storage capacity,
which includes caverns, steel tanks, pipeline line-fill and leased storage
capacity. This storage capacity provides operating efficiencies and flexibility
in meeting seasonal demand of shippers as well as propane storage for the truck
loading terminals.
Truck Loading Terminals. The North System has seven propane truck loading
terminals and one multi-product complex at Morris, Illinois, in the Chicago
area. Propane, normal butane, isobutane and natural gasoline can be loaded at
the Morris terminal.
Markets. 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 NGL products may be applied. Demand for transportation services is
influenced not only by demand for NGLs but also by the available supply of NGLs.
Supply. NGLs extracted or fractionated at the Bushton gas processing plant
operated by KMI have historically accounted for a significant portion
(approximately 40-50%) of the NGLs transported through the North System. Other
sources of NGLs transported in the North System include large oil companies,
marketers, end-users and natural gas processors that use interconnecting
pipelines to transport hydrocarbons. KMI has signed a definitive agreement with
ONEOK, Inc. to transfer to ONEOK the Bushton plant along with other assets
previously owned by KMI. ONEOK has assumed contracts with the Partnership to
continue shipping NGLs through the North System in volumes substantially equal
to those shipped through the North System when KMI owned the Bushton plant.
Competition. The North System competes with other liquids pipelines and to a
lesser extent with rail carriers. In most cases, established pipelines are the
lowest cost alternative for the transportation of NGLs and refined petroleum
products. Consequently, pipelines owned and operated by others represent the
Partnership's primary competition. 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 indirectly with pipelines that deliver product to markets that the
North System does not serve, such as the Gulf Coast market area.
Plantation Pipe Line Company
The Partnership owns 51% of Plantation Pipe Line Company, which owns and
operates a 3,100 mile pipeline system throughout the southeastern Unites States.
Plantation serves as a common carrier of refined petroleum products to various
metropolitan areas, including Birmingham, Alabama; Atlanta, Georgia; Charlotte,
North Carolina; and the Washington, D.C. area. The Partnership believes
favorable demographics in the southeastern United States will serve as a
platform for increased utilization and expansion of Plantation's pipeline
system.
Markets. Plantation ships products for approximately 50 companies to
terminals throughout the southeastern United States. Plantation's principal
customers are Gulf Coast refining and marketing companies, fuel wholesalers and
the United States Department of Defense. In addition, Plantation services the
Atlanta, Georgia; Charlotte, North Carolina; and Washington, D.C. airports
(Ronald Reagan/National and Dulles), at which it delivers jet fuel to major
airlines.
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Supply. Products shipped on Plantation originate at various Gulf Coast
refineries from which major integrated oil companies and independent refineries
and wholesalers ship refined petroleum products. Plantation can transport over
600,000 barrels of refined petroleum products per day. In December 1999,
Plantation announced an expansion of its mainline system. The $40 million
development will increase the system's capacity by 70,000 barrels per day. The
first phase of the expansion is scheduled to be complete by October 2000.
Competition. Plantation competes primarily with the Colonial Pipeline, which
also runs from Gulf Coast refineries throughout the southeastern United States,
extending into the northeastern states.
Shell CO2 Company
On March 5, 1998, the Partnership and affiliates of Shell Oil Company
("Shell") agreed to combine their CO2 activities and assets into a partnership
(Shell CO2 Company) to be operated by Shell. The Partnership acquired, through a
newly created limited liability company, a 20% interest in Shell CO2 Company in
exchange for contributing the Central Basin Pipeline and approximately $25
million in cash. Shell contributed the following assets in exchange for an 80%
interest in Shell CO2 Company:
o an approximate 45% interest in the McElmo Dome CO2 reserves;
o an 11% interest in the Bravo Dome CO2 reserves;
o an indirect 50% interest in the Cortez pipeline;
o a 13% interest in the Bravo pipeline; and
o certain other related assets.
These assets facilitate the marketing of CO2 by bringing a complete package
of CO2 supply, transportation and technical expertise to the customer. CO2 is
used in enhanced oil recovery projects as a flooding medium for recovering crude
oil from mature oil fields. Altura Energy Ltd., which Occidental Petroleum Corp.
has agreed to acquire, is a major user of CO2 in its West Texas fields.
On March 9, 2000, the Partnership announced it had reached a definitive
agreement to increase its interest in Shell CO2 Company to 100%. The Partnership
will acquire the remaining 78% limited partner interest and the 2% general
partner interest in Shell CO2 Company from affiliates of Shell Exploration &
Production Company. The transaction price is $185.5 million, and the closing of
the transaction is expected to occur around April 1, 2000. After the closing,
the Partnership will rename Shell CO2 Company "Kinder Morgan CO2 Company." The
Partnership will own a 98.9899% limited partner ownership interest in Kinder
Morgan CO2 Company and the general partner will own a direct 1.0101% general
partner ownership interest.
Under the terms of the Shell CO2 Company partnership agreement, the
Partnership has been receiving a priority distribution of $14.5 million per year
during 1998 and 1999. To the extent the amount paid to the Partnership over this
period is in excess of the Partnership's percentage share (currently 20%) of
Shell CO2 Company's distributable cash flow for such period (discounted at 10%),
the partnership agreement provides for Shell to receive a priority distribution
in equal amounts of such overpayment. After the closing, Kinder Morgan will
amend this partnership agreement, among other things, to eliminate the priority
distribution and other provisions rendered irrelevant by the Partnership's sole
ownership.
McElmo and Bravo Domes. Shell CO2 Company operates, and owns approximately
45% of McElmo Dome, which contains more than 11 trillion cubic feet ("TCF") of
nearly pure CO2. Delivery capacity exceeds one billion cubic feet per day
("Bcf/d") to the Permian Basin and 60 million cubic feet per day ("MMcf/d") to
Utah. Additional expansions are under consideration.
The Bravo Dome, of which Shell CO2 Company owns approximately 11%, holds
reserves of approximately two TCF and covers an area of more than 1,400 square
miles. The Bravo Dome produces more than 400 MMcf/d; such production coming from
more than 350 wells in the Tubb Sandstone at 2,300 feet.
CO2 Pipelines. Shell CO2 Company owns a 50% interest in the 502-mile, 30-inch
Cortez Pipeline operated by a Shell affiliate. This pipeline carries CO2 from
the McElmo Dome source reservoir to the Denver City, Texas hub.
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The Cortez line currently transports in excess of 700 MMcf/d, including
approximately 90% of the CO2 transported on the Central Basin Pipeline (see
below).
In addition, Shell CO2 Company owns 13% of the 218 mile 20-inch Bravo
pipeline, which delivers to the Denver City hub and has a capacity of more than
350 MMcf/d. Major delivery points along the line include the Slaughter Field in
Cochran and Hockley counties, Texas, and the Wasson field in Yoakum County,
Texas. Tariffs on the Cortez and Bravo pipelines are not regulated.
Placed in service in 1985, the Central Basin Pipeline consists of
approximately 143 miles of 16-inch to 20-inch main pipeline and 157 miles of
4-inch to 12-inch lateral supply lines located in the Permian Basin between
Denver City, Texas and McCamey, Texas with a throughput capacity of 600 MMcf/d.
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
Shell, BP Amoco, and ARCO, respectively). The mainline terminates near McCamey
where it interconnects with the Canyon Reef Carriers, Inc. pipeline.
Competition. Shell CO2 Company's primary competitors for the sale of CO2
include suppliers that have an ownership interest in McElmo Dome, Bravo Dome and
Sheep Mountain Dome CO2 reserves. Shell CO2 Company's ownership interests in the
Cortez and Bravo pipelines are in direct competition with Sheep Mountain
pipeline, as well as competing with other interests in McElmo Dome and Cortez
Pipeline, for transportation of CO2 to the Denver City, Texas market area. There
is no assurance that new CO2 source fields will not be discovered which could
compete with Shell CO2 Company or that new methodologies for enhanced oil
recovery could replace CO2 flooding.
Cypress Pipeline
The Cypress Pipeline is an interstate common carrier pipeline system
originating at storage facilities in Mont Belvieu, Texas and extending 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.
Markets. The pipeline was built to service a major petrochemical producer in
the Lake Charles, Louisiana area under a 20-year ship-or-pay agreement that
expires in 2011. The contract requires a minimum volume of 30,000 barrels per
day and in 1997, the producer agreed to ship at least an additional 13,700
barrels per day for five years. Also in 1997, the Partnership expanded the
Cypress Pipeline's capacity by 25,000 barrels per day to 57,000 barrels per day.
Management continues to pursue projects that could increase throughput on the
Cypress Pipeline.
Supply. The Cypress Pipeline originates in Mont Belvieu where it is able to
receive ethane and ethane/propane mix from local storage facilities. Mont
Belvieu has facilities to fractionate NGLs received from several pipelines into
ethane and other components. Additionally, pipeline systems that transport
specification NGLs from major producing areas in Texas, New Mexico, Louisiana,
Oklahoma and the Mid-Continent Region supply ethane and ethane/propane mix to
Mont Belvieu.
Transmix Operations
The Partnership's transmix operations within the Mid-Continent business
segment consist of the transmix assets and operations acquired by the
Partnership in September 1999 from Primary Corporation. Transmix occurs when
dissimilar products are co-mingled in the pipeline transportation process.
Different products are pushed through the pipelines abutting each other, and the
area where different products mix is called transmix. Employing atmospheric
distillation units, the Partnership processes pipeline transmix generated in the
eastern United States to produce pipeline quality gasoline and light distillate
products. The processing is provided on a "for fee" basis or on a "purchase,
process and sell" basis. The processed material is returned to the generator or
is sold into the local market depending on the type of agreement in place with
the generator of the transmix. Processing facilities are located in Richmond,
Virginia and in Dorsey Junction, Maryland at the Colonial Pipeline Dorsey
Junction terminal.
The Richmond operating facility resides on an 11-acre site located near
Interstate 95 and adjacent to Virginia's James River. The facility is comprised
of a dock/pipeline, a 170,000-barrel tank farm, a processing plant, lab and
truck rack. The processing plant is composed of four distillation units that
operate 24 hours a day, 7 days a week
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providing a production capacity of approximately 8,000 barrels per day. The
facility is able to segregate feedstock for specialty fuel production. The
processing facility employs state-of-the-art PC based process control equipment
and is supported by comprehensive in-house quality control laboratory
capabilities. The facility is served by both Colonial and Plantation pipelines,
by deep-water barge (25 feet draft) and by transport truck and rail. The
Partnership also owns an additional 3.6-acre bulk oil terminal with a capacity
of 55,000 barrels located nearby in Richmond.
The Dorsey Junction operating facility is located within the Colonial
Pipeline Dorsey Junction terminal facility. The 5,000-plus barrel-per-day
processing unit became operational in February 1998. It operates 24 hours a day,
7 days a week providing dedicated transmix separation service for Colonial on a
"for fee" basis.
Markets. The Gulf and East Coast petroleum distribution system, particularly
the Mid-Atlantic region, provides the target market for the existing transmix
processing operations. An expansion effort is underway to expand operations into
the Mid-Continent area through acquisitions and/or new construction.
Additionally, existing West Coast transmix processing operations are being
integrated into the Partnership's transmix operations.
Supply. Transmix generated by Colonial and Plantation pipelines provides the
vast majority of the feedstock supply. These suppliers are committed by
long-term contracts. Individual shippers on Plantation spur lines and terminal
operators provide additional supply. The New York harbor also supplies transmix
type material to the Richmond facility via barge.
Competition. The transmix operations compete mainly with Buckeye Refining in
the northeast and with Placid Refining in the Gulf coast area. Tosco Refining is
a major competitor in the New York harbor area. There are various processors in
the Mid-Continent area, mainly Buckeye, Phillips and Williams Brothers, who will
compete with the Partnership's expansion efforts into that market. A number of
smaller organizations operate in the West and Southwest. These operations
compete for supply, which the Partnership envisions as the basis for growth in
the West and Southwest.
Heartland Pipeline Company
The Heartland pipeline was completed in the fall of 1990 and is owned by
Heartland Pipeline Company ("Heartland"). The Partnership and Conoco each own
50% of Heartland. The Partnership operates the pipeline and Conoco operates
Heartland's Des Moines terminal and serves as the managing partner of Heartland.
In 1999, Heartland completed an expansion into Council Bluffs, Iowa. Conoco
leased throughput capacity in the BP Amoco terminal in Council Bluffs, and
Heartland constructed a 13-mile 8-inch pipeline to allow deliveries into the
terminal. This expansion is expected to increase throughput on the Heartland
system by approximately 6,000 barrels per day by the third year of operations.
Markets. Heartland provides transportation of refined petroleum products from
refineries in the Kansas and Oklahoma area to a BP Amoco terminal in Council
Bluffs, Iowa, a Conoco terminal in Lincoln, Nebraska and Heartland's Des Moines
terminal. The demand for, and supply of, refined petroleum products in the
geographic regions served directly affect the volume of refined petroleum
products transported by Heartland.
Supply. Refined petroleum products transported by Heartland on the North
System are supplied primarily from the National Cooperative Refinery Association
crude oil refinery in McPherson, Kansas and the Conoco crude oil refinery in
Ponca City, Oklahoma.
Competition. Heartland competes with other refined product carriers in the
geographic market served. Heartland's principal competitor is Williams
Pipeline Company.
Painter Gas Processing Plant
The Painter Plant is located near Evanston, Wyoming and consists of:
o a natural gas processing plant;
o a nitrogen rejection unit;
o a fractionator;
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o an NGL terminal; and
o interconnecting pipelines with truck and rail loading facilities.
The fractionation facility has a capacity of approximately 6,000 barrels per
day, depending on the feedstock composition. The Painter Plant is leased to
Amoco Oil Company, a unit of BP Amoco, which operates the Painter Plant
fractionator and the associated Millis terminal and storage facilities for its
own account. BP Amoco also owns and operates the nearby BP Amoco Painter Complex
gas plant.
Natural Gas Operations
The Natural Gas Operations include:
o Kinder Morgan Interstate Gas Transmission LLC;
o 66 2/3% of Trailblazer Pipeline Company; and
o 49% of Red Cedar Gathering Company.
The Partnership's Natural Gas Operations consists of natural gas gathering,
transportation and storage transactions for interstate pipelines. Within this
segment, the Partnership operates over 7,100 miles of interstate natural gas
pipelines and associated storage and supply lines that are strategically located
at the center of the North American pipeline grid. The Partnership's
transportation network provides access to the major gas supply areas in the
western United States and the Midwest, as well as major consumer markets.
Kinder Morgan Interstate Gas Transmission LLC
Through Kinder Morgan Interstate Gas Transmission LLC ("KMIGT"), the
Partnership owns and operates approximately 6,700 miles of transmission lines in
Wyoming, Colorado, Kansas, Missouri and Nebraska. KMIGT provides transportation
and storage services to KMI affiliates, third-party natural gas distribution
utilities and other shippers. Pursuant to transportation agreements and FERC
tariff provisions, KMIGT offers its customers firm and interruptible
transportation and storage, including no-notice services. Under KMIGT's tariffs,
firm transportation and storage customers pay reservation charges each month
plus a commodity charge based on actual volumes transported or stored.
Interruptible transportation and storage customers pay a commodity charge based
upon actual volumes transported or stored. Reservation and commodity charges are
both based upon geographical location (KMIGT does not have seasonal rates) and
distance of the transportation service provided. Under no-notice service,
customers pay a fee for the right to use a combination of firm storage and firm
transportation to make deliveries of natural gas up to a specified volume.
No-notice customers are able to meet their peak day requirements without making
specific nominations.
The system is powered by 48 compressor stations in mainline and storage
service having an aggregate of approximately 172,590 horsepower. The pipeline
system provides storage services to its customers from its Huntsman Storage
Field in Cheyenne County, Nebraska. The facility has 39.4 billion cubic feet
("Bcf") of total storage capacity, 7.9 Bcf of working gas capacity and up to 101
MMcf/d of peak withdrawal capacity.
Markets. Markets served by KMIGT consist of a stable customer base with
expansion opportunities due to the system's access to the growing Rocky Mountain
supply sources. Markets served by KMIGT are comprised mainly of local
distribution companies and interconnecting interstate pipelines in the
mid-continent area. Markets for the local distribution companies can include
residential, commercial, industrial and agricultural customers. KMIGT also
delivers into interconnecting interstate pipelines in the mid-continent area,
which can in turn deliver gas into multiple markets throughout the United
States. Due to the demand for natural gas to run irrigation systems in the
summer, summer loads often equal the levels for the winter heating season.
Contracts. Approximately 32% of KMIGT's firm contracts expire within one
year, 28% expire within one to five years and 40% expire in more than five
years. Only 26% of firm contract maximum daily quantities will expire within one
year of December 31, 1999, and 79% of those volumes are with KMI and affiliated
entities. Based on total firm maximum daily quantities, 43% are with KMI and
affiliated entities. Over 90% of the system's firm transport capacity is
currently subscribed, with firm transport demand revenues accounting for more
than 90% of the revenues on the system.
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Competition. KMIGT competes with other interstate and intrastate gas
pipelines transporting gas from the supply sources in the Rocky Mountain and
Hugoton Basins to market centers.
Trailblazer Pipeline Company
The Partnership owns 66 2/3% of Trailblazer Pipeline Company ("Trailblazer"),
a general partnership under Illinois law. Enron Trailblazer Pipeline Company, a
subsidiary of Enron Corporation owns the remaining 33 1/3%. A committee
consisting of management representatives for each of the partners manages
Trailblazer. Natural Gas Pipeline Company of America ("NGPL"), a subsidiary of
KMI manages, maintains and operates Trailblazer and provides the personnel to
operate Trailblazer for which NGPL is reimbursed at cost. Trailblazer is a
"natural gas company" within the meaning of the Natural Gas Act. Trailblazer's
principal business is to transport and redeliver natural gas to others in
interstate commerce, and it does business in the states of Wyoming, Colorado,
Nebraska and Illinois. Trailblazer has been a fully "open access" pipeline under
Order Nos. 436/500 since June 1, 1991. Trailblazer owns and operates a 436 mile
36-inch diameter pipeline system which originates at an interconnection with
Wyoming Interstate Company Ltd.'s ("WIC") pipeline system near Rockport, Weld
County, Colorado and runs through southeastern Wyoming to a terminus near
Beatrice, Gage County, Nebraska where Trailblazer's pipeline system
interconnects with NGPL's and Northern Natural Gas Company's pipeline systems.
Trailblazer is the fourth segment of a 791 mile pipeline system known as the
Trailblazer Pipeline System, which originates in Uinta County, Wyoming with
Canyon Creek Compression Company ("Canyon"), a 22,000 brake horsepower
compressor station located at the tailgate of BP Amoco Production Company's
processing plant in the Whitney Canyon Area in Uinta County, Wyoming (Canyon's
facilities are the first segment). Canyon receives gas from the BP Amoco
processing plant and provides transportation and compression of gas for delivery
to Overthrust Pipeline Company's ("Overthrust") 88 mile 36-inch diameter
pipeline system at an interconnection in Uinta County, Wyoming (Overthrust's
system is the second segment). Overthrust delivers gas to WIC's 269 mile 36-inch
diameter pipeline system at an inter-connection (Kanda) in Sweetwater County,
Wyoming (WIC's system is the third segment). WIC delivers gas to Trailblazer at
an interconnection near Rockport in Weld County, Colorado.
On July 16, 1997, Trailblazer placed in service a new 5,200 horsepower
compressor unit in Lincoln County, Nebraska, which increased Trailblazer's firm
design capacity by 104,528 thousand cubic feet per day ("Mcf/d") to 492,000
Mcf/d. Prior to this, Trailblazer had been a free flowing system with no
compression.
Competition. While there are competing pipelines which move gas east out of
the Rocky Mountains, the main competition that Trailblazer faces is that the gas
supply in the Rocky Mountain area either stays in the area or is moved west and
therefore not transported on the Trailblazer pipeline.
Red Cedar Gathering Company
The Partnership owns a 49% equity interest in the Red Cedar Gathering Company
("Red Cedar"), a joint venture organized in August 1994. The Southern Ute Indian
Tribe owns the remaining 51%. Red Cedar owns and operates natural gas gathering
and treating facilities in La Plata County, Colorado, in the Ignacio Blanco
Field of the San Juan Basin. The Ignacio Blanco Field is that portion of the San
Juan Basin located in Colorado, most of which is located within the exterior
boundaries of the Southern Ute Indian Reservation. Red Cedar gathers coal seam
and conventional natural gas at wellheads and at several central delivery
points, and treats gas for delivery to three major interstate gas pipeline
systems and to an intrastate pipeline.
The Red Cedar gas gathering system currently consists of over 450 miles of
gathering pipeline connecting more than 600 producing wells, 17 field compressor
stations and a CO2 processing plant. A majority of the gas on the system moves
through 8-inch to 20-inch diameter pipe. The capacity and throughput of the Red
Cedar system as currently configured is approximately 600 MMcf/d of natural gas.
Bulk Terminals
The Bulk Terminals segment consists of over 20 bulk terminals, which handle
approximately 40 million tons of dry and liquid bulk products annually. The
Bulk Terminals segment includes:
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o Coal Terminals;
o Petroleum Coke Terminals; and
o Other Bulk Terminals.
Coal Terminals
The Cora Terminal is a high-speed, rail-to-barge coal transfer and storage
facility. Built in 1980, the terminal is located on approximately 480 acres of
land along the upper Mississippi River near Cora, Illinois, about 80 miles south
of St. Louis, Missouri. The terminal has a throughput capacity of about 15
million tons per year that can be expanded to 20 million tons with certain
capital additions. The terminal currently is equipped to store up to one million
tons of coal. This storage capacity provides customers the flexibility to
coordinate their supplies of coal with the demand at power plants. Storage
capacity at the Cora Terminal can be doubled with additional capital investment.
The Grand Rivers Terminal is operated on land under easements with an initial
expiration of July 2014. Grand Rivers is a coal transloading and storage
facility located along the Tennessee River just above the Kentucky Dam. The
terminal has current annual throughput capacity of approximately 12-15 million
tons with a storage capacity of approximately two million tons. With capital
improvements, the terminal could handle 25 million tons annually.
The Pier IX Terminal is located in Newport News, Virginia. The terminal
originally opened on 1983 and has the capacity to transload approximately 12
million tons of coal annually. It can store 1.3 million tons of coal on its
30-acre storage site and can custom-load multiple coals to meet an individual
customer's requirements. In addition, the Pier IX Terminal operates a cement
facility, which has the capacity to transload over 400,000 tons of cement
annually.
In addition, the Partnership operates the LAXT Coal Terminal in Los
Angeles, California and a smaller coal terminal in Mt. Vernon, Indiana.
Markets. Coal continues to dominate as the fuel for electric generation,
accounting for more than 55% of United States electric generation feedstock.
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 several hundred years. Most coal transloaded through the Partnership's
coal terminals is destined for use in coal-fired electric generation.
The Partnership believes that obligations to comply with the Clean Air Act
Amendments of 1990 will cause shippers to increase the use of low-sulfur coal
from the western United States. Approximately 80% of the coal loaded through the
Cora and Grand Rivers terminals is low sulfur coal originating from mines
located in the western United States, including the Hanna and Powder River
basins in Wyoming, western Colorado and Utah. In 1999, four major customers
accounted for approximately 90% of all the coal loaded through the Cora and
Grand Rivers Terminals.
Both Pier IX and LAXT export coal to foreign markets. Substantial portions of
the coal transloaded at these facilities are covered by long term contracts. In
addition, Pier IX serves power plants on the eastern seaboard of the United
States and imports cement pursuant to a long term contract.
Supply. Historically, the Cora and Grand Rivers Terminals have moved coal
that originated in the mines of southern Illinois and western Kentucky. Many
shippers, however, particularly in the East, are now using western coal loaded
at the terminals or a mixture of western coal and other coals as a means of
meeting environmental restrictions. The Partnership believes that Illinois and
Kentucky coal producers and shippers will continue to be important customers,
but anticipates that growth in volume through the terminals will be primarily
due to western low sulfur coal originating in Wyoming, Colorado and Utah.
The Cora Terminal sits on the mainline of the Union Pacific Railroad and is
strategically well positioned to receive coal shipments from the West. Grand
Rivers provides easy access to the Ohio-Mississippi River network and the
Tennessee-Tombigbee System. The Paducah & Louisville Railroad, a short line
railroad, serves Grand Rivers with connections to seven Class I rail lines
including the Union Pacific, CSX, Illinois Central and Burlington Northern. The
Pier IX Terminal is served by the CSX Railroad, which transports coal from
central Appalachian and
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other eastern coal basins. Cement imported at the Pier
IX Terminal primarily originates in Europe. LAXT is served by the Union Pacific
Railroad.
Competition. The Cora Terminal and Grand Rivers Terminal compete with several
coal terminals located in the general geographic area. No significant new coal
terminals have been constructed near the Cora Terminal or the Grand Rivers
Terminal in the last ten years. 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 believes the Cora Terminal and the Grand Rivers Terminal can compete
successfully with other terminals because of their favorable location,
independent ownership, available capacity, modern equipment and large storage
areas. The Pier IX Terminal competes primarily with two modern coal terminals
located in the same Virginian port complex as the Pier IX Terminal.
Petroleum Coke and Other Bulk Terminals
The Partnership owns or operates 8 petroleum coke terminals in the United
States. Petroleum coke is a by-product of the refining process and has
characteristics similar to coal. Petroleum coke supply in the United States has
increased in the last several years due to the increased use of coking units by
domestic refineries. Petroleum coke is used in domestic utility and industrial
steam generation facilities and is exported to foreign markets. Most of the
Partnership's customers are large integrated oil companies that choose to
outsource the storage and loading of petroleum coke for a fee.
The Partnership owns or operates an additional 12 bulk terminals located
primarily on the southern edge of the lower Mississippi River, the Gulf Coast
and the West Coast. The other bulk terminals serve customers in the alumina,
cement, salt, soda ash, ilminite, fertilizer, ore and other industries seeking
specialists who can build, own and operate bulk terminals.
Competition. The Partnership's petroleum coke and other bulk terminals
compete with numerous independent terminal operators, with other terminals owned
by oil companies and other industrials opting not to outsource terminal
services. Many of the other bulk terminals were constructed pursuant to
long-term contracts for specific customers. As a result, the Partnership
believes other terminal operators would face a significant disadvantage in
competing for its business.
Major Customers of the Partnership
The Partnership's total operating revenues are derived from a wide customer
base. During 1999, no revenues from transactions with a single external customer
amounted to 10% or more of the Partnership's consolidated revenues. For the year
ended December 31, 1998, the following customers accounted for more than 10% of
the Partnership's consolidated revenues:
o Equilon Enterprises(1) 13.2%
o Tosco Group 12.3%
o Chevron 11.0%
o ARCO 10.9%
(1) Equilon is the name of the joint venture, formed in January 1998, that
combined major elements of Texaco's and Shell's mid-western and western U.S.
refining and marketing businesses and nationwide trading, transportation and
lubricants businesses.
For the year ended December 31, 1997, BP Amoco Corporation, including its
subsidiaries, accounted for more than 11.9% of the Partnership's consolidated
revenues. For a more complete discussion of customers, see Note 15 of the Notes
to the Consolidated Financial Statements.
Employees
The Partnership does not have any employees. The general partner and/or the
subsidiary entities of the Partnership employ all persons necessary for the
operation of the Partnership's business. The Partnership reimburses the general
partner for the services of its employees. As of March 1, 2000, the general
partner and the
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subsidiary entities had approximately 1,200 employees. Approximately 150 hourly
personnel at certain terminals are represented by four labor unions. No other
employees of the general partner are members of a union or have a collective
bargaining agreement. The general partner considers its relations with its
employees to be good.
Regulation
Interstate Common Carrier Regulation
Some of the Partnership's pipelines are interstate common carrier pipelines,
subject to regulation by the FERC under the Interstate Commerce Act ("ICA"). 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. Petroleum pipelines are able to change
their rates within prescribed ceiling levels that are tied to an inflation
index. Shippers may protest rate increases made within the ceiling levels, 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, uses cost-of-service ratemaking,
market-based rates and settlement as alternatives to the indexing approach in
certain specified circumstances. In 1999, 1998, and 1997, application of the
indexing methodology did not significantly affect the Partnership's rates.
The ICA requires, among other things, that such rates be "just and
reasonable" and nondiscriminatory. The ICA permits interested persons to
challenge proposed new or changed rates and authorizes the FERC to suspend the
effectiveness of such rates for a period of up to seven months and to
investigate such rates. If, upon completion of an investigation, the FERC finds
that the new or changed rate is unlawful, it is authorized to require the
carrier to refund the revenues in excess of the prior tariff collected during
the pendency of the investigation. The FERC may also investigate, upon complaint
or on its own motion, rates that are already in effect and may order a carrier
to change its rates prospectively. Upon an appropriate showing, a shipper may
obtain reparations for damages sustained during the 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-day period established by the
Energy Policy Act. For this reason, the Partnership believes these rates should
be grandfathered under the Energy Policy Act. Certain rates on the Pacific
Operations' pipeline system were subject to protest during the 365-day period
established by the Energy Policy Act. Accordingly, certain of the Pacific
Operations' rates have been, and continue to be, subject to complaints with the
FERC, as is more fully described in Item 3. Legal Proceedings.
Both the performance of interstate transportation and storage services by
natural gas companies, including interstate pipeline companies, and the rates
charged for such services, are regulated by the FERC under the Natural Gas Act
and, to a lesser extent, the Natural Gas Policy Act. Legislative and regulatory
changes began in 1978 with the passage of the Natural Gas Policy Act, pursuant
to which the process of deregulation of gas sold at the wellhead was commenced.
The restructuring of the natural gas industry continued with the adoption of:
o Order 380 in 1984, which eliminated purchasers' minimum bill obligations
to the pipelines, thus making gas purchased from third parties,
particularly on the spot market, more economically attractive relative
to gas purchased from pipelines; and
o Order 436 in 1985, which provided that interstate transportation of gas
under blanket or self-implementing authority must be provided on an
open-access, non-discriminatory basis.
After Order 436 was partially overturned in federal court, the FERC issued
Order 500 in August 1987 as an interim rule intended to readopt the basic thrust
of the regulations promulgated by Order 436. Order 500 was amended by Orders 500
A through L. The FERC's stated purpose in issuing Orders 436 and 500, as
amended, was to create a more competitive environment in the natural gas
marketplace. This purpose continued with Order 497,
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issued in June 1988, which set forth new standards and guidelines imposing
certain constraints on the interaction of interstate pipelines and their
marketing affiliates and imposing certain disclosure requirements regarding that
interaction. Order 636, issued in April 1992, as amended, was a continuation of
the FERC's efforts to improve the competitive structure of the pipeline industry
and maximize the consumer benefits of a competitive structure of the pipeline
industry and a competitive wellhead gas market. In Order 636, the FERC required
interstate pipelines that perform open access transportation under blanket
certificates to "unbundle" or separate their traditional merchant sales services
from their transportation and storage services and to provide comparable
transportation and storage services with respect to all gas supplies whether
purchased from the pipeline or from other merchants such as marketers or
producers. The pipelines must now separately state the applicable rates for each
unbundled service (i.e., for the gas commodity, transportation and storage).
Specifically, Order 636 contains the following procedures to increase
competition in the industry:
o requiring the unbundling of sales services from other services, meaning
that only a separately identified merchant affiliate of the pipeline
could sell gas at points of entry into the pipeline system;
o permitting holders of firm capacity to release all or a part of their
capacity for resale by the pipeline either to the highest bidder or,
under short-term or maximum rate releases, to shippers in a prepackaged
release, with revenues in both instances credited to the releasing
shipper;
o allowing shippers to use as secondary points other receipt points and
delivery points on the system, subject to the rights of other shippers
to use those points as their primary receipt and delivery points;
o the issuance of blanket sales certificates to interstate pipelines for
unbundled services;
o the continuation of pre-granted abandonment of previously committed
pipeline sales and transportation services, subject to certain rights of
first refusal, which should make unused pipeline capacity available to
other shippers and clear the way for excess transportation services to
be reallocated to the marketplace;
o requiring that firm and interruptible transportation services be
provided by the pipelines to all parties on a comparable basis; and
o generally requiring that pipelines derive transportation rates using a
straight-fixed-variable rate method which places all fixed costs in a
fixed reservation fee that is payable without regard to usage, as
opposed to the previously used modified fixed-variable method that
allocated a part of the pipelines' fixed costs to the usage fee. The
FERC's stated position is that the straight-fixed-variable method
promotes the goal of a competitive national gas market by increasing
the cost of unnecessarily holding firm capacity rather than releasing
it, and is consistent with its directive to unbundle the pipelines'
traditional merchant sales services.
Order 636 has been affirmed in all material respects upon judicial review and
the Partnership's own FERC orders approving its unbundling plans are final and
not subject to any pending judicial review.
The acquisition of the KMIGT interstate natural gas pipeline system has
resulted in a significant increase in the percentage of the Partnership's assets
subject to regulation by the FERC. The Partnership is also subject to the
requirements of FERC Order Nos. 497, et. seq., and 566, et. seq., the Marketing
Affiliate Rules, which prohibit preferential treatment by an interstate pipeline
of its marketing affiliates and govern in particular the provision of
information by an interstate pipeline to its marketing affiliates.
Intrastate common carrier operations of the Pacific Operations in California
are subject to regulation by the CPUC under a "depreciated book plant"
methodology, which is based on an original cost measure of investment.
Intrastate tariffs filed by the Partnership with the CPUC have been established
on the basis of revenues, expenses and investments allocated as applicable to
the intrastate portion of the Partnership's business. Tariff rates with respect
to intrastate pipeline service in California are subject to challenge by
complaint by interested parties or by independent action of the CPUC. A variety
of factors can affect the rates of return permitted by the CPUC and certain
other issues similar to those which have arisen with respect to the
Partnership's FERC regulated rates could also arise with respect to the
Partnership's intrastate rates.
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:
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o marketing;
o production;
o pricing;
o pollution;
o protection of the environment; and
o safety.
Safety Regulation
The Partnership's pipelines are subject to regulation by the United States
Department of Transportation ("D.O.T.") with respect to their design,
installation, testing, construction, operation, replacement and management. 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 bulk terminal loading facilities are subject to D.O.T. regulations dealing
with the transportation of hazardous materials for motor vehicles and rail cars.
The Partnership believes that it is in substantial compliance with D.O.T. and
comparable state regulations.
The Partnership is also subject to the requirements of the Federal
Occupational Safety and Health Act ("OSHA") and comparable state statutes. The
Partnership believes that it is in substantial compliance with OSHA
requirements, including general industry standards, recordkeeping requirements
and monitoring of occupational exposure to hazardous substances.
In general, the Partnership expects to increase expenditures in the future to
comply with higher industry and regulatory safety standards. 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
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 substantial compliance with
applicable environmental regulations. The Partnership has an ongoing
environmental compliance program. However, risks of accidental leaks or spills
are associated with the transportation of NGLs, refined petroleum products and
natural gas, the handling and storage of bulk materials and the other activities
conducted by the Partnership. 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, such as emissions of pollutants,
generation and disposal of wastes and use and handling of chemical substances,
that may impact the environment and/or endangered species. Increasingly strict
environmental restrictions and limitations have resulted in increased operating
costs for the Partnership and other similar businesses throughout the United
States. 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 many years
for the transportation and storage of refined petroleum products and NGLs and
the handling and storage of coal and other bulk materials. Solid waste disposal
practices within the petroleum industry have improved over the years with the
passage and implementation of various environmental laws and regulations.
Hydrocarbons and other solid wastes may have been disposed of in, 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
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effect on soils and groundwater. The Partnership does not believe that there
currently exists significant surface or subsurface contamination of its assets
by hydrocarbons or other solid wastes not already identified and addressed. The
Partnership has maintained a reserve to account for the costs of cleanup at
these sites.
The Partnership generates 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, the
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 or bulk terminal 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
"potentially responsible persons" for releases of "hazardous substances" into
the environment. These persons include the owner or operator of a site and
companies that disposed of or arranged for the disposal of the hazardous
substances found at the site. CERCLA 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 "hazardous
substance." By operation of law, if the Partnership is determined to be a
potentially responsible person, 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. Gasoline manufacturers use butanes 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
Partnership's pipeline 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.
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 its
pipelines, storage facilities and bulk terminals 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 pipelines, storage
facilities and bulk terminals. The EPA is developing, over a period of many
years, regulations to implement those requirements. Depending on the nature of
those regulations, and upon requirements that may be imposed by state and local
regulatory authorities, the Partnership may be required to incur certain capital
expenditures over the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals and
addressing other air emission-related issues.
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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 have 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.
Risk Factors
Pending FERC and CPUC Proceedings Seek Substantial Refunds and Reductions
in Tariff Rates.
Some shippers have filed complaints with the FERC and the CPUC that seek
substantial refunds and reductions in the Pacific Operations' tariff rates.
Adverse decisions could negatively impact revenues, results of operations,
financial condition, liquidity and funds available for distribution to
unitholders. Additional challenges to tariff rates could be filed with the FERC
or CPUC in the future.
The complaints filed before the FERC allege that pipeline tariff rates (a)
for the West Line, serving Southern California and Arizona, are not entitled to
"grandfathered" status under the Energy Policy Act because "changed
circumstances" may have occurred under the Energy Policy Act, and (b) for the
East Line, serving New Mexico and Arizona, are unjust and unreasonable. An
initial decision by the FERC administrative law judge was issued on September
25, 1997. The initial decision determined that the Pacific Operations' West Line
rates were grandfathered under the Energy Policy Act. The initial decision also
included rulings that were generally adverse to the Pacific Operations regarding
certain cost of service issues for the East Line. On January 13, 1999, the FERC
issued an opinion that affirmed, in major respects, the initial decision, but
also modified certain parts of the decision that were adverse to the
Partnership. The Partnership believes the effect of the opinion will be less
than the amount that has been accrued as a reserve. Certain of the complainants
have appealed the FERC's decision to the United States Court of Appeals for the
District of Columbia Circuit.
During the pendency of the above-referenced complaint proceeding, some
shippers filed complaints that generally attack the pipeline tariff rates of the
Pacific Operations, contending that the rates are not just and reasonable under
the Interstate Commerce Act and should not be entitled to "grandfathered" status
under the Energy Policy Act. These complaints cover rates for service on the
pipeline systems serving southern California and Arizona, northern California
and Nevada, and Oregon. The complaints seek substantial reparations for alleged
overcharges during the years in question and request prospective rate reduction
on each of the challenged facilities. These complaints were suspended pending
final disposition of the FERC's January 13, 1999 decision, but are expected to
proceed to hearing at some point in the future. In January 2000, several of the
shippers amended and restated their complaints challenging the tariff rates of
the Pacific Operations. The Partnership is vigorously defending the amended and
restated complaints as it has defended the previous round of complaints.
The complaints filed before the CPUC generally challenge the rates charged
for intrastate transportation of refined petroleum through the Pacific
Operations' pipeline system in California. On August 6, 1998, the CPUC issued
its decision dismissing the complainants' challenge to SFPP's intrastate rates.
On June 24, 1999, the CPUC granted limited rehearing of its August 1998 decision
for the purpose of addressing the proper ratemaking treatment for partnership
tax expenses, the calculation of environmental costs and the public utility
status of SFPP's Sepulveda Line and its Watson Station gathering enhancement
facilities. In pursuing these rehearing issues, complainants seek prospective
rate reductions aggregating approximately $10 million per year.
For additional information about these proceedings, see Item. 3 Legal
Proceedings.
Rapid Growth May Cause Difficulties Integrating New Operations
Part of the Partnership's business strategy includes acquiring additional
businesses that will allow it to increase distributions to unitholders. During
the two-year period from December 31, 1997 to December 31, 1999, the Partnership
made several acquisitions that helped increase its asset base and its net income
over ten times. The Partnership believes that it can profitably combine the
operations of acquired businesses with its existing operations. However,
unexpected costs or challenges may arise whenever businesses with different
operations and management are combined. Successful business combinations require
management and other personnel to devote significant
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amounts of time to integrating the acquired business with existing operations.
These efforts may temporarily distract management's attention from day-to-day
business, the development or acquisition of new properties and other business
opportunities. In addition, the management of the acquired business will often
not join the Partnership's management team. The change in management may make it
more difficult to integrate an acquired business with existing operations.
Possible Increased Costs for Pipeline Easements
The Partnership generally does not own the land on which its pipelines are
constructed. Instead, the Partnership obtains the right to construct and operate
the pipelines on other people's land for a period of time. If the Partnership
were to lose these rights, its business could be negatively affected.
Southern Pacific Transportation Company has allowed the Partnership to
construct and operate a significant portion of its Pacific Operations' pipeline
under their railroad tracks. Southern Pacific Transportation Company and its
predecessors were given the right to construct their railroad tracks under
federal statutes enacted in 1871 and 1875. The 1871 statute was thought to be an
outright grant of ownership that would continue until the land ceased to be used
for railroad purposes. Two United States Circuit Courts, however, ruled in 1979
and 1980 that railroad rights-of-way granted under laws similar to the 1871
statute provide only the right to use the surface of the land for railroad
purposes without any right to the underground portion. If a court were to rule
that the 1871 statute does not permit the use of the underground portion for the
operation of a pipeline, the Partnership may be required to obtain permission
from the land owners in order to continue to maintain the pipelines. Although no
assurance can be given, the Partnership believes it could obtain such permission
over time at a cost that would not have a material negative effect on its
financial position or results of operations.
Whether the Partnership has the power of eminent domain for its pipelines
varies from state to state depending upon the type of pipeline--petroleum
liquids, natural gas or CO2--and the laws of the particular state. The
Partnership's inability to exercise the power of eminent domain could have a
material negative effect on its business if it were to lose the right to use or
occupy the property on which its pipelines are located.
Environmental Regulation Significantly Affects Partnership Business
The business operations of the Partnership are subject to federal, state and
local laws and regulations relating to environmental practices. If an accidental
leak or spill of liquid petroleum products occurs in a pipeline or at a storage
facility, the Partnership may have to pay a significant amount to clean up the
leak or spill. The resulting costs and liabilities could negatively affect the
level of cash available for distributions to unitholders. Although the
Partnership cannot predict the impact of Environmental Protection Agency
standards or future environmental measures, such costs could increase
significantly if environmental laws and regulations become stricter. Since the
costs of environmental regulation are already significant, additional regulation
could negatively affect the level of cash available for distributions to
unitholders. See "-Regulation".
Competition
Competition could ultimately lead to lower levels of profits and lower cash
distributions to unitholders. Propane competes with electricity, fuel, oil and
natural gas in the residential and commercial heating market. In the engine fuel
market, propane competes with gasoline and diesel fuel. Butanes and natural
gasoline used in motor gasoline blending and isobutane used in premium fuel
production compete with alternative products. Natural gas liquids used as feed
stocks for refineries and petrochemical plants compete with alternative feed
stocks. The availability and prices of alternative energy sources and feed
stocks significantly affect demand for natural gas liquids.
Pipelines are generally the lowest cost method for intermediate and long-haul
overland product movement. Accordingly, the most significant competitors for the
Partnership's pipelines are:
o proprietary pipelines owned and operated by major oil companies in the
areas where the Partnership's pipelines deliver products;
o refineries within the market areas served by the Partnership's
pipelines; and
o trucks.
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Additional pipelines may be constructed in the future to serve specific
markets now served by the Partnership's pipelines. Trucks competitively deliver
products in certain markets. Recently, major oil companies have increasingly
used trucking, resulting in minor but notable reductions in product volumes
delivered to certain shorter-haul destinations, primarily Orange and Colton,
California served by the South and West lines of the Pacific Operations.
The Partnership cannot predict with certainty whether this trend towards
increased short-haul trucking will continue in the future. Demand for
terminaling services varies widely throughout the pipeline system. Certain major
petroleum companies and independent terminal operators directly compete with the
Partnership at several terminal locations. At those locations, pricing, service
capabilities and available tank capacity control market share.
The Partnership's ability to compete also depends upon general market
conditions, which may change. The Partnership conducts its operations without
the benefit of exclusive franchises from government entities. The Partnership
provides common carrier transportation services through its pipelines at posted
tariffs and almost always without long-term contracts for transportation service
with customers. Demand for transportation services for refined petroleum
products is primarily a function of:
o total and per capita fuel consumption;
o prevailing economic and demographic conditions;
o alternate modes of transportation;
o alternate product sources; and
o price.
Risks Associated with Leverage
Debt Instruments May Limit Financial Flexibility. The instruments governing
the Partnership's debt contain restrictive covenants that may prevent it from
engaging in certain beneficial transactions. Such provisions may also limit or
prohibit distributions to unitholders under certain circumstances. The
agreements governing the Partnership's debt generally require it to comply with
various affirmative and negative covenants including the maintenance of certain
financial ratios and restrictions on:
o incurring additional debt;
o entering into mergers, consolidations and sales of assets; and
o granting liens.
Additionally, the agreements governing the Partnership's debt generally
prohibit the Partnership from:
o distributing amounts in excess of 100% of available cash for the
immediately preceding calendar quarter; and
o making any distribution to unitholders if an event of default exists or
would exist when such distribution is made.
The instruments governing any additional debt incurred to refinance the debt
may also contain similar or additional restrictions.
Restrictions on the Ability to Prepay SFPP's Debt May Limit Financial
Flexibility. SFPP is subject to certain restrictions with respect to its debt
that may limit the Partnership's flexibility in structuring or refinancing
existing or future debt. These restrictions include the following:
o Before December 15, 2002, the Partnership may prepay the SFPP First
Mortgage Notes (the "Series F notes") with a make-whole prepayment
premium; and
o The Partnership agreed as part of the acquisition of the Pacific
Operations to not take certain actions with respect to $190 million of the
SFPP Series F notes that would cause adverse tax consequences for the
prior general partner of SFPP.
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Unitholders May Have Negative Tax Consequences if a Default on Debt or Sale
of Assets Occurs. If the Partnership defaults on any of its debt, the lenders
will have the right to sue for non-payment. Such an action could cause an
investment loss and cause negative tax consequences for unitholders through the
realization of taxable income by unitholders without a corresponding cash
distribution. Likewise, if the Partnership were to dispose of assets and realize
a taxable gain while there is substantial debt outstanding and proceeds of the
sale were applied to the debt, unitholders could have increased taxable income
without a corresponding cash distribution.
Debt Securities are Subordinated to SFPP Debt. Since SFPP, L.P. will not
guarantee any debt securities issued by the Partnership, such debt securities
will be effectively subordinated to all debt of SFPP. If SFPP defaults on its
debt, the holders of any of the Partnership's senior debt securities would not
receive any money from SFPP until SFPP repaid its debt in full.
Limitations in the Partnership Agreements and State Partnership Law
Limited Voting Rights and Control of Management. Unitholders have only
limited voting rights on matters affecting the Partnership. The general partner
manages Partnership activities. Unitholders have no right to elect the general
partner on an annual or other ongoing basis. If the general partner withdraws,
however, the holders of a majority of the outstanding units (excluding units
owned by the departing general partner and its affiliates) may elect its
successor.
The limited partners may remove the general partner only if:
o the holders of 66 2/3% of the units vote to remove the general partner.
Units owned by the general partner and its affiliates are not counted;
o the same percentage of units approves a successor general partner;
o the Partnership continues to be taxed as a partnership for federal
income tax purposes; and
o the limited partners maintain their limited liability.
Persons Owning 20% or More of the Units Cannot Vote. Any units held by a
person that owns 20% or more of the units cannot be voted. This limitation does
not apply to the general partner and its affiliates. This provision may:
o discourage a person or group from attempting to remove the general
partner or otherwise change management; and
o reduce the price at which the units will trade under certain
circumstances. For example, a third party will probably not attempt to
remove the general partner and take over the Partnership's management by
making a tender offer for the units at a price above their trading market
price without removing the general partner and substituting an affiliate.
The General Partner's Liability to the Partnership and Unitholders May Be
Limited. The partnership agreement contains language limiting the liability of
the general partner to the Partnership or the unitholders. For example, the
partnership agreement provides that:
o the general partner does not breach any duty to the Partnership or the
unitholders by borrowing funds or approving any borrowing. The general
partner is protected even if the effect of the borrowing is to increase
incentive distributions to the general partner;
o the general partner does not breach any duty to the Partnership or the
unitholders by taking any actions consistent with the standards of
reasonable discretion outlined in the definitions of available cash and
cash from operations contained in the partnership agreement; and
o the general partner does not breach any standard of care or duty by
resolving conflicts of interest unless the general partner acts in bad
faith.
The Partnership Agreement Modifies the Fiduciary Duties of the General
Partner Under Delaware Law. Such modifications of state law standards of
fiduciary duty may significantly limit the ability of unitholders to
successfully challenge the actions of the general partner as being a breach of
what would otherwise have been a fiduciary duty. These standards include the
highest duties of good faith, fairness and loyalty to the limited partners.
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Such a duty of loyalty would generally prohibit a general partner of a Delaware
limited partnership from taking any action or engaging in any transaction for
which it has a conflict of interest. Under the partnership agreement, the
general partner may exercise its broad discretion and authority in the
management of the Partnership and the conduct of its operations as long as the
general partner's actions are in the best interest of the Partnership.
Unitholders May Have Liability To Repay Distributions. Unitholders will not
be liable for assessments in addition to their initial capital investment in the
units. Under certain circumstances, however, unitholders may have to repay the
Partnership amounts wrongfully returned or distributed to them. Under Delaware
law, the Partnership may not make a distribution to unitholders if the
distribution causes all liabilities of the Partnership to exceed the fair value
of the Partnership's assets. Liabilities to partners on account of their
partnership interests and non-recourse liabilities are not counted for purposes
of determining whether a distribution is permitted. Delaware law provides that a
limited partner who receives such a distribution and knew at the time of the
distribution that the distribution violated Delaware law will be liable to the
limited partnership for the distribution amount for three years from the
distribution date. Under Delaware law, an assignee that becomes a substituted
limited partner of a limited partnership is liable for the obligations of the
assignor to make contributions to the Partnership. However, such an assignee is
not obligated for liabilities unknown to him at the time he or she became a
limited partner if the liabilities could not be determined from the partnership
agreement.
Unitholders May be Liable if the Partnership does Not Comply With State
Partnership Law. The Partnership conducts its business in a number of states. In
some of those states, the limitations on the liability of limited partners for
the obligations of a limited partnership have not been clearly established. The
unitholders might be held liable for the Partnership's obligations as if they
were a general partner if:
o a court or government agency determined that the Partnership was
conducting business in the state but had not complied with the state's
partnership statute; or
o unitholders' rights to act together to remove or replace the general
partner or take other actions under the partnership agreement constitute
"control" of the Partnership's business.
The General Partner May Buy Out Minority Unitholders if it Owns 80% of the
Units. If at any time the general partner and its affiliates own 80% or more of
the issued and outstanding units, the general partner will have the right to
purchase all of the remaining units. Because of this right, a unitholder may
have to sell his interest against his will or for a less than desirable price.
The general partner may only purchase all of the units. The purchase price for
such a purchase will be the greater of:
o the most recent 20-day average trading price; or
o the highest purchase price paid by the general partner or its affiliates
to acquire units during the prior 90 days.
The general partner can assign this right to its affiliates or to the
Partnership.
The Partnership May Sell Additional Limited Partner Interests, Diluting
Existing Interests of Unitholders. The partnership agreement allows the general
partner to cause the Partnership to issue additional units and other equity
securities. When the Partnership issues additional equity securities, the
existing unitholders' proportionate partnership interest will decrease. Such an
issuance could negatively affect the amount of cash distributed to unitholders
and the market price of units. Issuance of additional units will also diminish
the relative voting strength of the previously outstanding units. There is no
limit on the total number of units the Partnership may issue.
General Partner Can Protect Itself Against Dilution. Whenever the Partnership
issues equity securities to any person other than the general partner and its
affiliates, the general partner has the right to purchase additional limited
partnership interests on the same terms. This allows the general partner to
maintain its partnership interest in the Partnership. No other unitholder has a
similar right. Therefore, only the general partner may protect itself against
dilution caused by issuance of additional equity securities.
Potential Conflicts of Interest Related to the Operation of the Partnership
Certain conflicts of interest could arise among the general partner, KMI and
the Partnership. Such conflicts may include, among others, the following
situations:
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The fiduciary duties of KMI's officers and directors may conflict with those
of the Partnership. Some of the directors and officers of KMI are also directors
and officers of the general partner. Conflicts of interest may result due to the
fiduciary duties such directors and officers may have to manage the business of
KMI in a manner beneficial to KMI and its shareholders. The resolution of these
conflicts may not always be in the best interests of the Partnership's
unitholders.
The similarity of KMI's acquisition strategy and that of the Partnership may
create conflicts of interest. Since KMI and the Partnership each plan to grow
their businesses through acquisitions, conflicts may arise because:
o individuals who serve on the general partner's board of directors also
serve on the board of directors of KMI, and this requires the disclosure
of information to the board of KMI of any transaction that could be of
interest to that board on behalf of KMI or its subsidiaries;
o acquisition opportunities may be presented to the interlocking directors
or those officers common to KMI and the general partner that could be in
the best interests of both KMI and the Partnership; and
o the Partnership and KMI both have an acquisition strategy to acquire
assets used in the transportation, storage and processing of energy
products that generate long-term, steady cash flows and that can be
acquired at a price that may increase their earnings and cash flow.
There is no legal limitation on either KMI's or the Partnership's
business that requires them not to enter into or acquire other
businesses, and each of their acquisition interests could conflict with
those of the other.
Any transaction that KMI effects could have been an opportunity of the
Partnership and vice-versa. The resolution of these conflicts by KMI's board of
directors and the board of directors of the general partner may not always be
the most beneficial resolution to the Partnership's unitholders.
The General Partner may not be fully reimbursed for the use of its officers
and employees by the general partner. KMI shares administrative personnel with
the general partner to operate both KMI's business and the business of the
Partnership. As a result, the officers of the general partner, who in some cases
may also be officers of KMI, must allocate, in their reasonable and sole
discretion, the time the general partner's employees spend on behalf of the
Partnership and on behalf of KMI. These allocations are not the result of
arms-length negotiations between the general partner and KMI. Although the
general partner intends to be reimbursed for its employees' activities, due to
the nature of the allocations, this reimbursement may not exactly match the
actual time and overhead spent. Since the Partnership reimburses the general
partner for its general and administrative expenses, the under allocation of the
time and overhead spent on KMI's activities would negatively affect the amount
of cash available for distribution to the Partnership's unitholders. See Item
13. "Certain Relationships and Related Transactions--General and Administrative
Expenses" in this Report.
The general partner's decisions may affect cash distributions to unitholders.
The general partner determines the amount and timing of asset purchases and
sales, capital expenditures, borrowings and reserves. All of these decisions can
impact the amount of cash distributed by the Partnership to its unitholders,
which, in turn, affects the amount of the cash incentive distribution to the
general partner.
The general partner tries to avoid being personally liable for Partnership
obligations. The general partner is permitted to protect its assets in this
manner by the partnership agreement. Under the partnership agreement, the
general partner does not breach its fiduciary duty even if the Partnership could
have obtained more favorable terms without limitations on the general partner's
liability.
The general partner's decision to exercise or assign its call right to
purchase limited partnership interests may conflict with the interests of the
unitholders. If the general partner exercises this right, a unitholder may have
to sell his interest against his will or for a less than desirable price.
Tax Treatment of Publicly Traded Partnerships Under the Internal Revenue
Code
The Internal Revenue Code of 1986, as amended (the "Code"), imposes certain
limitations on the current deductibility of losses attributable to investments
in publicly traded partnerships and treats certain publicly traded partnerships
as corporations for federal income tax purposes. The following discussion
briefly describes certain aspects of the Code that apply to individuals who are
citizens or residents of the United States without commenting
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on all of the federal income tax matters affecting the Partnership or the
unitholders, and is qualified in its entirety by reference to the Code.
Unitholders are urged to consult their own tax advisor about the federal, state,
local and foreign tax consequences to them of an investment in the Partnership.
Tax Characterization of the Partnership
The availability of the federal income tax benefits of an investment in the
Partnership to a holder of units depends, in large part, on the classification
of the Partnership as a partnership for federal income tax purposes. The Code
generally treats a publicly traded partnership formed after 1987 as a
corporation unless, for each taxable year of its existence, 90% or more of its
gross income consists of qualifying income.
If the Partnership were to fail to meet the 90% "qualified income" test (the
"Natural Resources Exception") for any year prior to or subsequent to the
acquisition of the Pacific Operations, the Partnership would be treated as a
corporation unless it met the inadvertent failure exception. Qualifying income
includes interest, dividends, real property rents, gains from the sale or
disposition of real property, income and gains derived from the exploration,
development, mining or production, processing, refining, transportation
(including pipelines transporting gas, oil or products thereof), or the
marketing of any mineral or natural resource (including fertilizer, geothermal
energy and timber), and gain from the sale or disposition of capital assets that
produced such income. The general partner believes that more than 90% of the
Partnership's gross income is, and has been, qualifying income, because the
Partnership is engaged primarily in the transportation of NGLs, refined
petroleum products and natural gas through pipelines and the handling and
storage of coal.
If the Partnership were classified as an association taxable as a corporation
for federal income tax purposes, the Partnership would be required to pay tax on
its income at corporate rates, distributions would generally be taxed to the
holders of units as corporate distributions, and no income, gain, loss,
deduction or credit would flow through to the holders of units. Because tax
would be imposed upon the Partnership as an entity, the cash available for
distribution to the holders of units would be substantially reduced. Treatment
of the Partnership as an association taxable as a corporation or otherwise as a
taxable entity would result in a material reduction in the anticipated cash flow
and after-tax return to the holders of units.
There can be no assurance that the law will not be changed so as to cause the
Partnership to be treated as an association taxable as a corporation for federal
income tax purposes or otherwise to be subject to entity-level taxation. The
partnership agreement provides that, if a law is enacted that subjects the
Partnership to taxation as a corporation or otherwise subjects the Partnership
to entity-level taxation for federal income tax purposes, certain provisions of
the partnership agreement relating to the general partner's incentive
distributions will be subject to change, including a decrease in the amount of
the Target Distribution levels to reflect the impact of entity level taxation on
the Partnership.
Passive Activity Loss Limitations
Under the passive loss limitations, losses generated by the Partnership, if
any, will only be available to offset future income generated by the Partnership
and cannot be used to offset income which an individual, estate, trust or
personal service corporation realizes from other activities, including passive
activities or investments. Income, which may not be offset by passive activity
"losses", includes not only salary and active business income, but also
portfolio income such as interest, dividends or royalties or gain from the sale
of property that produces portfolio income. Credits from passive activities are
also limited to the tax attributable to any income from passive activities. The
passive activity loss rules are applied after other applicable limitations on
deductions, such as the at-risk rules and the basis limitation. Certain closely
held corporations are subject to slightly different rules, which can also limit
their ability to offset passive losses against certain types of income. A
unitholder's proportionate share of unused losses may be deducted when the
holder of units disposes of all of such holder's units in a fully taxable
transaction with an unrelated party. Net passive income from the Partnership may
be offset by a unitholder's unused Partnership losses carried over from prior
years, but not by losses from other passive activities, including losses from
other publicly traded partnerships. In addition, a unitholder's proportionate
share of the Partnership's portfolio income, including portfolio income arising
from the investment of the Partnership's working capital, is not treated as
income from a passive activity and may not be offset by such unitholder's share
of net losses of the Partnership.
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Section 754 Election
Each of the Partnership and its operating partnerships has made, will make,
as necessary, and maintain the election provided for by Section 754 of the Code,
which will generally permit a holder of units to calculate cost recovery and
depreciation deductions by reference to the portion of the unitholder's purchase
price attributable to each asset of the Partnership. A constructive termination
of the Partnership could result in penalties and a loss of basis adjustments
under Section 754, if the Partnership were unable to determine that a
termination had occurred and, therefore, did not make a Section 754 election for
the new Partnership.
No Amortization of Book-Up Attributable to Intangibles
The acquisition of the Pacific Operations resulted in a restatement of the
capital accounts of both the former Santa Fe common unitholders and the
Partnership's pre-acquisition unitholders to fair market value ("Book-Up"). An
allocation of such increased capital account value among the Partnership's
assets was based on the values indicated by an independent appraisal obtained by
the general partner. The independent appraisal indicated that all of such value
was attributable to tangible assets. However, if such valuations are challenged
by the IRS and such challenge is successful, a portion of this Book-Up would be
allocated to intangible assets that would not be amortizable either for tax or
capital account purposes, and therefore, would not support a curative allocation
of income. This could result in a disproportionate allocation of taxable income
to either a pre-acquisition unitholder or a former Santa Fe common unitholder.
Deductibility of Interest Expense
The Code generally provides that investment interest expense is deductible
only to the extent of a non-corporate taxpayer's net investment income. In
general, net investment income for purposes of this limitation includes gross
income from property held for investment (except for net capital gains taxed at
the long-term capital gains rate) and portfolio income (determined pursuant to
the passive loss rules) reduced by certain expense (other than interest) which
are directly connected with the production of such income. Property subject to
the passive loss rules is not treated as property held for investment. However,
the IRS has issued a notice which provides that net income from a publicly
traded partnership (not otherwise treated as a corporation) may be included in
net investment income for the purposes of the limitation on the deductibility of
investment interest. A unitholder's investment income attributable to its
interest in the Partnership will include both its allocable share of the
Partnership's portfolio income and trade or business income. A unitholder's
investment interest expense will include its allocable share of the
Partnership's interest expense attributable to portfolio investments.
Tax Liability Exceeding Cash Distributions or Proceeds from Dispositions of
Units
A holder of units will be required to pay federal income tax and, in certain
cases, state and local income taxes on such holder's allocable share of the
Partnership's income, whether or not such holder receives cash distributions
from the Partnership. No assurance is given that holders of units will receive
cash distributions equal to their allocable share of taxable income from the
Partnership. Further, a holder of units may incur tax liability in excess of the
amount of cash received.
Tax Shelter Registration; Potential IRS Audit
The Partnership is registered with the IRS as a "tax shelter." No assurance
can be given that the IRS will not audit the Partnership or that tax adjustments
will not be made. The rights of a unitholder owning less than a 1% profits
interest in the Partnership to participate in the income tax audit process have
been substantially reduced. Further, any adjustments in the Partnership's
returns will lead to adjustments in the returns of holders of units and may lead
to audits of unitholders' returns and adjustments of items unrelated to the
Partnership's. Each holder of units would bear the cost of any expenses incurred
in connection with an examination of the personal tax return of such holder.
Unrelated Business Taxable Income
Certain entities otherwise exempt from federal income taxes (such as
individual retirement accounts, pension plans and charitable organizations) are
nevertheless subject to federal income tax on net unrelated business taxable
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income and each such entity must file a tax return for each year in which it has
more than $1,000 of gross income from unrelated business activities. The general
partner believes that substantially all of the Partnership's gross income will
be treated as derived from an unrelated trade or business and taxable to such
entities. The tax-exempt entity's share of the Partnership's deductions directly
connected with carrying on such unrelated trade or business are allowed in
computing the entity's taxable unrelated business income. Accordingly,
investment in the Partnership by tax-exempt entities such as individual
retirement accounts, pension plans and charitable trusts may not be advisable.
State and Local Tax Treatment
Each holder of units may be subject to income, estate or inheritance taxes in
states and localities in which the Partnership owns property or does business,
as well as in such holder's own state or locality. For purposes of state and
local tax reporting, as of December 31, 1999, the Partnership conducted business
in 20 states: Arizona, California, Colorado, Illinois, Indiana, Iowa, Kansas,
Kentucky, Louisiana, Maryland, Missouri, Nebraska, Nevada, New Mexico, Oklahoma,
Oregon, South Carolina, Texas, Virginia and Wyoming. A unitholder will likely be
required to file state income tax returns and to pay applicable state income
taxes in many of these states and may be subject to penalties for failure to
comply with such requirements. Some of the states have proposed that the
Partnership withhold a percentage of income attributable to Partnership
operations within the state for unitholders who are non-residents of the state.
In the event that amounts are required to be withheld (which may be greater or
less than a particular unitholder's income tax liability to the state), such
withholding would generally not relieve the non-resident unitholder from the
obligation to file a state income tax return.
Description of the Partnership Agreement
The following paragraphs are a summary of certain provisions of the
partnership agreement. A copy of the partnership agreement is filed as an
exhibit to this report. Unless otherwise specifically described, references
herein to the term "partnership agreement" constitute references to the
partnership agreements of the Partnership and its operating partnerships
collectively. The following discussion is qualified in its entirety by reference
to the partnership agreements for the Partnership and its operating
partnerships. With regard to allocations of taxable income and taxable loss, See
"Tax Treatment of Publicly Traded Partnerships Under the Internal Revenue Code."
Organization and Duration
The Partnership and each of the operating partnerships are Delaware limited
partnerships. Unless liquidated or dissolved at an earlier time, under the terms
of the partnership agreement, the Partnership and each of the operating
partnerships will dissolve on December 31, 2082.
Purpose
The purpose of the Partnership under the partnership agreement is to serve as
the limited partner in the operating partnerships and to conduct any other
business that may be lawfully conducted by a Delaware limited partnership.
Power of Attorney
Each limited partner, and each person who acquires a unit from a prior holder
and executes and delivers a transfer application with respect to such unit,
grants to the general partner and, if a liquidator has been appointed, the
liquidator, a power of attorney to, among other things:
o execute and file certain documents required in connection with the
qualification, continuance or dissolution of the Partnership or the
amendment of the partnership agreement in accordance with the terms of
the partnership agreement; and
o make consents and waivers contained in the partnership agreement.
Restrictions on Authority of the General Partner
The authority of the general partner is limited in certain respects under the
partnership agreement. The general partner is prohibited, without the prior
approval of holders of record of a majority of the outstanding units from,
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among other things, selling or exchanging all or substantially all of the
Partnership's assets in a single transaction or a series of related transactions
(including by way of merger, consolidation or other combination) or approving on
behalf of the Partnership the sale, exchange or other disposition of all or
substantially all of the assets of the Partnership, provided that the
Partnership may mortgage, pledge, hypothecate or grant a security interest in
all or substantially all of the Partnership's assets without such approval. The
Partnership may sell all or substantially all of its assets pursuant to a
foreclosure or other realization upon the foregoing encumbrances without such
approval. Except as provided in the partnership agreement and generally
described under "--Amendment of Partnership Agreement and Other Agreements," any
amendment to a provision of the partnership agreement generally will require the
approval of the holders of at least 66 2/3% of the units. The general partner's
ability to sell or otherwise dispose of a significant portion of the
Partnership's assets is restricted by the terms of the Partnership's credit
facilities.
In general, the general partner may not take any action, or refuse to take
any reasonable action, without the consent of the holders of at least a majority
of the outstanding units of the Partnership, (other than units owned by the
general partner and its affiliates), the effect of which would be to cause the
Partnership to be treated as an association taxable as a corporation or
otherwise taxed as an entity for federal income tax purposes.
Withdrawal or Removal of the General Partner
The general partner has agreed not to voluntarily withdraw as general partner
of the Partnership prior to January 1, 2003 (with limited exceptions described
below) without the approval of at least a majority of the outstanding units
(excluding for purposes of such determination units held by the general partner
and its affiliates) and furnishing an opinion of counsel that such withdrawal
will not cause the Partnership to be treated as an association taxable as a
corporation or otherwise taxed as an entity for federal income tax purposes or
result in the loss of the limited liability of any limited partner. On or after
January 1, 2003, the general partner may withdraw as general partner by giving
90 days' written notice (without first obtaining approval from the holders of
units), and such withdrawal will not constitute a breach of the partnership
agreement. If an opinion of counsel cannot be obtained to the effect that
(following the selection of a successor) the general partner's withdrawal would
not result in the loss of limited liability of the holders of units or cause the
Partnership to be treated as an association taxable as a corporation or
otherwise taxed as an entity for federal income tax purposes, the Partnership
will be dissolved after such withdrawal. Notwithstanding the foregoing, the
general partner may withdraw without approval of the holders of units upon 90
days' notice to the limited partners if more than 50% of the outstanding units
(other than those held by the withdrawing general partner and its affiliates)
are held or controlled by one person and its affiliates. In addition, the
partnership agreement does not restrict Kinder Morgan, Inc.'s ability to sell
directly or indirectly, all or any portion of the capital stock of the general
partner to a third party without the approval of the holders of units.
The general partner may not be removed unless such removal is approved by the
vote of the holders of not less than 66 2/3% of the outstanding units (excluding
units held by the general partner and its affiliates) provided that certain
other conditions are satisfied. Any such removal is subject to the approval of
the successor general partner by the same vote and receipt of an opinion of
counsel that such removal and the approval of a successor will not result in the
loss of limited liability of any limited partner or cause the Partnership to be
treated as an association taxable as a corporation or otherwise taxed as an
entity for federal income tax purposes.
In the event of withdrawal of the general partner where such withdrawal
violates the partnership agreement or removal of the general partner by the
limited partners under circumstances where cause exists, a successor general
partner will have the option to acquire the general partner interest of the
departing general partner (the "Departing Partner") in the Partnership for a
cash payment equal to the fair market value of such interest. Under all other
circumstances where the general partner withdraws or is removed by the limited
partners, the Departing Partner will have the option to require the successor
general partner to acquire such general partner interest of the Departing
Partner for such amount. In each case such fair market value will be determined
by agreement between the Departing Partner and the successor general partner, or
if no agreement is reached, by an independent investment banking firm or other
independent expert selected by the Departing Partner and the successor general
partner (or if no expert can be agreed upon, by the expert chosen by agreement
of the expert selected by each of them). In addition, the Partnership would also
be required to reimburse the Departing Partner for all amounts due the Departing
Partner, including without limitation all employee related liabilities,
including severance liabilities, incurred in connection with the termination of
the employees employed by the Departing Partner for the benefit of the
Partnership.
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If the above-described option is not exercised by either the Departing
Partner or the successor general partner, as applicable, the Departing Partner's
general partner interest in the Partnership will be converted into units equal
to the fair market value of such interest as determined by an investment banking
firm or other independent expert selected in the manner described in the
preceding paragraph.
The general partner may transfer all, but not less than all, of its general
partner interest in the Partnership without the approval of the limited partners
to one of its affiliates or upon its merger or consolidation into another entity
or the transfer of all or substantially all of its assets to another entity,
provided in either case that such entity assumes the rights and duties of the
general partner, agrees to be bound by the provisions of the partnership
agreement and furnishes an opinion of counsel that such transfer would not
result in the loss of the limited liability of any limited partner or cause the
Partnership to be treated as an association taxable as a corporation or
otherwise cause the Partnership to be subject to entity level taxation for
federal income tax purposes. In the case of any other transfer of the general
partner interest in the Partnership, in addition to the foregoing requirements,
the approval of at least a majority of the units is required, excluding for such
purposes those interests held by the general partner and its affiliates.
Upon the withdrawal or removal of the general partner, the Partnership will
be dissolved, wound up and liquidated, unless such withdrawal or removal takes
place following the approval of a successor general partner or unless within 180
days after such withdrawal or removal a majority of the holders of units agree
in writing to continue the business of the Partnership and to the appointment of
a successor general partner. See "-Termination and Dissolution."
Anti-takeover and Restricted Voting Right Provisions
The partnership agreement contains certain provisions that are intended to
discourage a person or group from attempting to remove the general partner or
otherwise change the management of the Partnership. If any person or group other
than the general partner and its affiliates acquires beneficial ownership of 20%
or more of the units, such person or group loses any and all voting rights with
respect to all of the units beneficially owned or held by such person.
Transfer of Units; Status as Limited Partner or Assignee
Until a unit has been transferred on the books of the Partnership, the
Partnership and the transfer agent, notwithstanding any notice to the contrary,
may treat the record holder thereof as the absolute owner for all purposes,
except as otherwise required by law or stock exchange regulation. Any transfers
of a unit will not be recorded by the transfer agent or recognized by the
Partnership unless the transferee executes and delivers a Transfer Application
(set forth on the reverse side of the certificate representing units). By
executing and delivering the Transfer Application, the transferee of units:
o becomes the record holder of such units and shall constitute an assignee
until admitted to the Partnership as a substitute limited partner;
o automatically requests admission as a substituted limited partner in the
Partnership;
o agrees to be bound by the terms and conditions of and is deemed to have
executed the partnership agreement;
o represents that such transferee has capacity, power and authority to
enter into the partnership agreement;
o grants powers of attorney to the general partner and any liquidator of
the Partnership as specified in the partnership agreement; and
o makes the consents and waivers contained in the partnership agreement.
An assignee, pending its admission as a substituted limited partner in the
Partnership, is entitled to an interest in the Partnership equivalent to that of
a limited partner with respect to the right to share in allocations and
distributions from the Partnership, including liquidating distributions. The
general partner will vote, and exercise other powers attributable to, units
owned by an assignee that has not become a substituted limited partner at the
written direction of such Assignee. See "-Meetings; Voting."
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An assignee will become a substituted limited partner of the Partnership in
respect of the transferred units upon the consent of the general partner and the
recordation of the name of the assignee on the books and records of the
Partnership. Such consent may be withheld in the sole discretion of the general
partner. Units are securities and are transferable according to the laws
governing transfers of securities. In addition to other rights acquired upon
transfer, the transferor gives the transferee the right to request admission as
a substituted limited partner in the Partnership in respect of the transferred
units. A purchaser or transferee of a unit who does not execute and deliver a
Transfer Application obtains only:
o the right to transfer the units to a purchaser or other transferee; and
o the right to transfer the right to seek admission as a substituted
limited partner in the Partnership with respect to the transferred units.
Thus, a purchaser or transferee of units who does not execute and deliver a
Transfer Application will not receive cash distributions unless the units are
held in a nominee or street name account and the nominee or broker has executed
and delivered a Transfer Application with respect to such units and may not
receive certain federal income tax information or reports furnished to record
holders of units. The transferor of units will have a duty to provide such
transferee with all information that may be necessary to obtain registration of
the transfer of the units, but the transferee agrees, by acceptance of the
certificate representing units, that the transferor will not have a duty to see
to the execution of the Transfer Application by the transferee and will have no
liability or responsibility if such transferee neglects or chooses not to
execute and forward the Transfer Application.
Holders of units may hold their units in nominee accounts, provided that the
broker (or other nominee) executes and delivers a Transfer Application. The
Partnership will be entitled to treat the nominee holder of a unit as the
absolute owner thereof, and the beneficial owner's rights will be limited solely
to those that it has against the nominee holder as a result of or by reason of
any understanding or agreement between such beneficial owner and nominee holder.
Non-citizen Assignees; Redemption
If the Partnership is or becomes subject to federal, state or local laws or
regulations that, in the reasonable determination of the general partner,
provides for the cancellation or forfeiture of any property in which the
Partnership has an interest because of the nationality, citizenship or other
related status of any limited partner or assignee, the Partnership may redeem
the units held by such limited partner or assignee at their Average Fair Market
Price. In order to avoid any such cancellation or forfeiture, the general
partner may require each record holder or assignee to furnish information about
the holder's nationality, citizenship, residency or related status. If the
record holder fails to furnish such information within 30 days after a request
for such information, or if the general partner determines on the basis of the
information furnished by such holder in response to the request that the
cancellation or forfeiture of any property in which the Partnership has an
interest may occur, the general partner may be substituted as the limited
partner for such record holder, who will then be treated as a non-citizen
assignee ("Non-citizen Assignee"), and the general partner will have the right
to redeem the units held by such record holder as described above. The
partnership agreement sets forth the rights of such record holder or assignee
upon redemption. Pending such redemption or in lieu thereof, the general partner
may change the status of any such limited partner or assignee to that of a
Non-citizen Assignee. Further, a Non-citizen Assignee (unlike an assignee who is
not a substitute limited partner) does not have the right to direct the vote
regarding such Non-citizen Assignee's units and may not receive distributions in
kind upon liquidation of the Partnership. See "-Transfer of Units; Status as
Limited Partner or Assignee."
As used in this Report:
o "Average Fair Market Price" of a limited partner interest as of any date
means the average of the daily End of Day Price (as hereinafter defined)
for the 20 consecutive Unit Transaction Days (as hereinafter defined)
immediately prior to such date;
o "End of Day Price" for any day means the last sale price on such day,
regular way, or in case no such sale takes place on such day, the
average of the closing bid and asked prices on such day, regular way, in
either case as reported in the principal consolidated transaction
reporting system with respect to securities listed or
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admitted to trading on the principal national securities exchange on
which the limited partner interests of such class are listed or
admitted to trading or, if the limited partner interests of such class
are not listed or admitted to trading on any national securities
exchange, the last quoted sale price on such day, or, if not so
quoted, the average of the high bid and low asked prices on such day
in the over-the-counter market, as reported by the NASDAQ or such
other system then in use, or if on any such day the limited partner
interests of such class are not quoted by any such organization, the
average of the closing bid and asked prices on such day as furnished
by a professional market maker making a market in the limited partner
interests of such class selected by the board of directors of the
general partner, or if on any such day no market maker is making a
market in such limited partner interests, the fair value of such
limited partner interests on such day as determined reasonably and in
good faith by the board of directors of the general partner; and
o "Unit Transaction Day" means a day on which the principal national
securities exchange on which such limited partner interests are listed
or admitted to trading is open for the transaction of business or, if
the limited partner interests of such class are not listed or admitted
to trading on any national securities exchange, a day on which banking
institutions in New York City generally are open.
Issuance of Additional Securities
The Partnership's Issuance of Securities. The partnership agreement does not
restrict the ability of the general partner to issue additional limited or
general partner interests and authorizes the general partner to cause the
Partnership to issue additional securities of the Partnership for such
consideration and on such terms and conditions as shall be established by the
general partner in its sole discretion without the approval of any limited
partners. In accordance with Delaware law and the provisions of the partnership
agreement, the general partner may issue additional partnership interests,
which, in its sole discretion, may have special voting rights to which the units
are not entitled.
Limited Pre-emptive Right of General Partner. The general partner has the
right, which it may from time to time assign in whole or in part to any of its
affiliates, to purchase units or other equity securities of the Partnership from
the Partnership whenever, and on the same terms that, the Partnership issues
such securities to persons other than the general partner and its affiliates, to
the extent necessary to maintain the percentage interest of the general partner
and its affiliates in the Partnership to that which existed immediately prior to
each such issuance.
Limited Call Right
If at any time 80% or more of the units are held by the general partner and
its affiliates, the general partner will have the right, which it may assign and
transfer to any of its affiliates or to the Partnership, to purchase all of the
remaining units as of a record date to be selected by the general partner, on at
least 10 but not more than 60 days' notice. The purchase price in the event of
such purchase shall be the greater of:
o the Average Fair Market Price of limited partner interests of such class
as of the date five days prior to the mailing of written notice of its
election to purchase limited partner interests of such class; and
o the highest cash price paid by the general partner or any of its
affiliates for any units purchased within the 90 days preceding the date
the general partner mails notice of its election to purchase such units.
Amendment of Partnership Agreement and Other Agreements
Amendments to the partnership agreement may be proposed only by or with the
consent of the general partner. In order to adopt a proposed amendment, the
general partner is required to seek written approval of the holders of the
number of units required to approve such amendment or call a meeting of the
limited partners to consider and vote upon the proposed amendment, except as
described below. Proposed amendments (other than those described below) must be
approved by holders of at least 66 2/3% of the outstanding units, except that no
amendment may be made which would:
o enlarge the obligations of any limited partner, without its consent;
o enlarge the obligations of the general partner, without its consent,
which may be given or withheld in its sole discretion;
o restrict in any way any action by or rights of the general partner as
set forth in the partnership agreement;
o modify the amounts distributable, reimbursable or otherwise payable by
the Partnership to the general partner;
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o change the term of the Partnership; or
o give any person the right to dissolve the Partnership other than the
general partner's right to dissolve the Partnership with the approval of a
majority of the outstanding units or change such right of the general
partner in any way.
The general partner may make amendments to the partnership agreement without
the approval of any limited partner or assignee of the Partnership to reflect:
o a change in the name of the Partnership, the location of the principal
place of business of the Partnership, the registered agent or the
registered office of the Partnership;
o admission, substitution, withdrawal or removal of partners in accordance
with the partnership agreement;
o a change that, in the sole discretion of the general partner, is
reasonable and necessary or appropriate to qualify or continue the
qualification of the Partnership as a partnership in which the limited
partners have limited liability or that is necessary or advisable in the
opinion of the general partner to ensure that the Partnership will not be
treated as an association taxable as a corporation or otherwise subject to
taxation as an entity for federal income tax purposes;
o an amendment that is necessary, in the opinion of counsel to the
Partnership, to prevent the Partnership or the general partner or their
respective directors or officers from in any manner being subjected to
the provisions of the Investment Company Act of 1940, as amended, the
Investment Advisors Act of 1940, as amended, or "plan asset" regulations
adopted under the Employee Retirement Income Security Act of 1974, as
amended, whether or not substantially similar to plan asset regulations
currently applied or proposed by the United States Department of Labor;
o an amendment that in the sole discretion of the general partner is
necessary or desirable in connection with the authorization of additional
limited or general partner interests;
o any amendment expressly permitted in the partnership agreement to be
made by the general partner acting alone;
o an amendment effected, necessitated or contemplated by a merger agreement
that has been approved pursuant to the terms of the partnership agreement;
and
o any other amendments substantially similar to the foregoing.
In addition, the general partner may make amendments to the partnership
agreement without such consent if such amendments:
o do not adversely affect the limited partners in any material respect;
o are necessary or desirable to satisfy any requirements, conditions or
guidelines contained in any opinion, directive, ruling or regulation of
any federal or state agency or judicial authority or contained in any
federal or state statute;
o are necessary or desirable to facilitate the trading of the units or to
comply with any rule, regulation, guideline or requirement of any
securities exchange on which the units are or will be listed for trading,
compliance with any of which the general partner deems to be in the best
interests of the Partnership and the holders of units; or
o are required to effect the intent of, or as contemplated by, the
partnership agreement.
The general partner will not be required to obtain an opinion of counsel as
to the tax consequences or the possible effect on limited liability of
amendments described in the two immediately preceding paragraphs. No other
amendments to the partnership agreement will become effective without the
approval of at least 95% of the units unless the Partnership obtains an opinion
of counsel to the effect that such amendment:
o will not cause the Partnership to be treated as an association taxable as
a corporation or otherwise cause the Partnership to be subject to entity
level taxation for federal income tax purposes; and
o will not affect the limited liability of any limited partner in the
Partnership or the limited partner of the operating partnerships.
Any amendment that materially and adversely affects the rights or preferences
of any type or class of limited partner interests in relation to other types or
classes of limited partner interests or the general partner interests will
require the approval of at least 66 2/3% of the type or class of limited partner
interests so affected.
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Management
The general partner will manage and operate the activities of the
Partnership, and the general partner's activities will be limited to such
management and operation. Holders of units will not direct or participate in the
management or operations of the Partnership or any of the operating
partnerships. See "--Limited Liability." The general partner will owe a
fiduciary duty to the holders of units. Notwithstanding any limitation on
obligations or duties, the general partner will be liable, as the general
partner of the Partnership, for all the debts of the Partnership (to the extent
not paid by the Partnership), except to the extent that indebtedness incurred by
the Partnership is made specifically non-recourse to the general partner.
The Partnership does not currently have any directors, officers or employees.
As is commonly the case with publicly traded limited partnerships, the
Partnership does not currently contemplate that it will directly employ any of
the persons responsible for managing or operating the Partnership's business or
for providing it with services, but will instead reimburse the general partner
or its affiliates for the services of such persons. See "-Reimbursement of
Expenses."
Reimbursement of Expenses. The general partner will receive no management fee
or similar compensation in conjunction with its management of the Partnership
(other than cash distributions). See "--Cash Distribution Policy." However, the
general partner is entitled pursuant to the partnership agreement to
reimbursement on a monthly basis, or such other basis as the general partner may
determine in its sole discretion, for all direct and indirect expenses it incurs
or payments it makes on behalf of the Partnership and all other necessary or
appropriate expenses allocable to the Partnership or otherwise reasonably
incurred by the general partner in connection with operating the Partnership's
business. The partnership agreement provides that the general partner shall
determine the fees and expenses that are allocable to the Partnership in any
reasonable manner determined by the general partner in its sole discretion. The
reimbursement for such costs and expenses will be in addition to any
reimbursement to the general partner and its affiliates as a result of the
indemnification provisions of the partnership agreement. See "-Indemnification."
Indemnification. The partnership agreement provides that the Partnership will
indemnify the general partner, any Departing Partner and any person who is or
was an officer or director of the general partner or any Departing Partner, to
the fullest extent permitted by law, and may indemnify, to the extent deemed
advisable by the general partner, to the fullest extent permitted by law, any
person who is or was an affiliate of the general partner or any Departing
Partner, any person who is or was an officer, director, employee, partner, agent
or trustee of the general partner, any Departing Partner or any such affiliate,
or any person who is or was serving at the request of the general partner or any
affiliate of the general partner or any Departing Partner as an officer,
director, employee, partner, agent, or trustee of another person ("Indemnities")
from and against any and all losses, claims, damages, liabilities (joint or
several), expenses (including, without limitation, legal fees and expenses),
judgments, fines, penalties, interest, settlement and other amounts arising from
any and all claims, demands, actions, suits or proceedings, whether civil,
criminal, administrative or investigative, in which any Indemnitee may be
involved, or is threatened to be involved, as a party or otherwise, by reason of
its status as:
o the general partner, a Departing Partner or affiliate of either;
o an officer, director, employee, partner, agent or trustee of the general
partner, any Departing Partner or affiliate of either; or
o a person serving at the request of the Partnership in another entity in
a similar capacity.
In each case the Indemnitee must have acted in good faith and in a manner
which the Indemnitee believed to be in or not opposed to the best interests of
the Partnership and, with respect to any criminal proceeding, had no reasonable
cause to believe its conduct was unlawful. Any indemnification under the
partnership agreement will only be paid out of the assets of the Partnership,
and the general partner will not be personally liable for, or have any
obligation to contribute or loan funds or assets to the Partnership to enable it
to effectuate, such indemnification. The Partnership is authorized to purchase
(or to reimburse the general partner or its affiliates for the cost of)
insurance, purchased on behalf of the general partner and such other persons as
the general partner determines, against liabilities asserted against and
expenses incurred by such persons in connection with the Partnership's
activities, whether or not the Partnership would have the power to indemnify
such person against such liabilities under the provisions described above.
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Conflicts and Audit Committee. One or more directors who are neither officers
nor employees of the general partner or any of its affiliates will serve as a
committee of the board of directors of the general partner (the "Conflicts and
Audit Committee") and will, at the request of the general partner, review
specific matters as to which the general partner believes there may be a
conflict of interest in order to determine if the resolution of such conflict
proposed by the general partner is fair and reasonable to the Partnership. The
Conflicts and Audit Committee will only review matters at the request of the
general partner, which has sole discretion to determine which matters to submit
to such Committee. Any matters approved by the Conflicts and Audit Committee
will be conclusively deemed to be fair and reasonable to the Partnership,
approved by all partners of the Partnership and not a breach by the general
partner of the partnership agreement or any duties it may owe to the
Partnership. Additionally, it is possible that such procedure in itself may
constitute a conflict of interest.
Meetings; Voting
Holders of units or assignees who are record holders of units on the record
date set pursuant to the partnership agreement will be entitled to notice of,
and to vote at, meetings of limited partners of the Partnership and to act with
respect to matters as to which approvals may be solicited. With respect to
voting rights attributable to units that are owned by assignees who have not yet
been admitted as limited partners, the general partner will be deemed to be the
limited partner with respect thereto and will, in exercising the voting rights
in respect of such units on any matter, vote such units at the written direction
of such record holder. If a proxy is not returned on behalf of the unit record
holder, such units will not be voted (except that, in the case of units held by
the general partner on behalf of Non-citizen Assignees, the general partner will
distribute the votes in respect of such units in the same ratios as the votes of
limited partners in respect of other units are cast). When a proxy is returned
properly executed, the units represented thereby will be voted in accordance
with the indicated instructions. If no instructions have been specified on the
properly executed and returned proxy, the units represented thereby will be
voted "FOR" the approval of the matters to be presented. Units held by the
general partner on behalf of Non-citizen Assignees shall be voted by the general
partner in the same ratios as the votes of the limited partners with respect to
the matter presented to the holders of units.
Any action that is required or permitted to be taken by the limited partners
may be taken either at a meeting of the limited partners or without a meeting if
consents in writing setting forth the action so taken are signed by holders of
such number of limited partner interests as would be necessary to authorize or
take such action at a meeting of the limited partners. Meetings of the limited
partners of the Partnership may be called by the general partner or by limited
partners owning at least 20% of the outstanding units of the class for which a
meeting is proposed. Limited partners may vote either in person or by proxy at
meetings. Two-thirds (or a majority, if that is the vote required to take action
at the meeting in question) of the outstanding limited partner interests of the
class for which a meeting is to be held (excluding, if such are excluded from
such vote, limited partner interests held by the general partner and its
affiliates) represented in person or by proxy will constitute a quorum at a
meeting of limited partners of the Partnership. Except for any proposal for
removal of the general partner or certain amendments to the partnership
agreement described above, substantially all matters submitted for a vote are
determined by the affirmative vote, in person or by proxy, of holders of a
majority of the outstanding limited partner interests.
Each record holder of a unit has a vote according to such record holder's
percentage interest in the Partnership, although the general partner could issue
additional limited partner interests having special voting rights. See
"--Issuance of Additional Securities." However, units owned beneficially by any
person or group (other than the general partner and its affiliates) that own
beneficially 20% or more of all units may not be voted on any matter and will
not be considered to be outstanding when sending notices of a meeting of limited
partners, calculating required votes, determining the presence of a quorum or
for other similar partnership purposes. The partnership agreement provides that
the broker (or other nominee) will vote units held in nominee or street name
accounts pursuant to the instruction of the beneficial owner, unless the
arrangement between the beneficial owner and such holder's nominee provides
otherwise.
Any notice, demand, request, report or proxy materials required or permitted
to be given or made to record holders of units (whether or not such record
holder has been admitted as a limited partner) under the terms of the
partnership agreement will be delivered to the record holder by the Partnership
or by the transfer agent at the request of the Partnership.
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Limited Liability
Except as described below, units are fully paid, and holders of units will
not be required to make additional contributions to the Partnership.
Assuming that a limited partner does not participate in the control of the
business of the Partnership, within the meaning of the Delaware limited
partnership act, and that such partner otherwise acts in conformity with the
provisions of the partnership agreement, such partner's liability under Delaware
law will be limited, subject to certain possible exceptions, generally to the
amount of capital such partner is obligated to contribute to the Partnership in
respect of such holder's units plus such holder's share of any undistributed
profits and assets of the Partnership. However, if it were determined that the
right or exercise of the right by the limited partners as a group to remove or
replace the general partner, to approve certain amendments to the partnership
agreement or to take other action pursuant to the partnership agreement
constituted "participation in the control" of the Partnership's business for the
purposes of the Delaware limited partnership act, then the limited partners
could be held personally liable for the Partnership's obligations under the laws
of the State of Delaware to the same extent as the general partner. Under
Delaware law, a limited partnership may not make a distribution to a partner to
the extent that at the time of the distribution, after giving effect to the
distribution, all liabilities of the partnership, other than liabilities to
partners on account of their partnership interests and nonrecourse liabilities,
exceed the fair value of the assets of the limited partnership. For the purpose
of determining the fair value of the assets of a limited partnership, Delaware
law provides that the fair value of property subject to nonrecourse liability
shall be included in the assets of the limited partnership only to the extent
that the fair value of that property exceeds that nonrecourse liability.
Delaware law provides that a limited partner who receives such a distribution
and knew at the time of the distribution that the distribution was in violation
of Delaware law shall be liable to the limited partnership for the amount of the
distribution for three years from the date of the distribution. Under Delaware
law, an assignee who becomes a substituted limited partner of a limited
partnership is liable for the obligations of the assignor to make contributions
to the Partnership, except the assignee is not obligated for liabilities unknown
to such assignee at the time the assignee became a limited partner and which
could not be ascertained from the partnership agreement.
The Partnership is organized under the laws of Delaware and currently
conducts business in a number of states. Maintenance of limited liability will
require compliance with legal requirements in all of the jurisdictions in which
the Partnership conducts business, including qualifying the operating
partnerships to do business therein. Limitations on the liability of limited
partners for the obligations of a limited partnership have not been clearly
established in many jurisdictions. If it were determined that the Partnership
was, by virtue of its limited partner interest in the operating partnerships or
otherwise, conducting business in any state without compliance with the
applicable limited partnership statute, or that the right or exercise of the
right by the limited partners as a group to remove or replace the general
partner, to approve certain amendments to the partnership agreement, or to take
other action pursuant to the partnership agreement constituted "participation in
the control" of the Partnership's business for the purposes of the statues of
any relevant jurisdiction, then the limited partners could be held personally
liable for the Partnership's obligations under the law of such jurisdiction to
the same extent as the general partner. The Partnership will operate in such
manner as the general partner deems reasonable and necessary or appropriate to
preserve the limited liability of holders of units.
Books and Reports
The general partner is required to keep appropriate books of the business
at the principal offices of the Partnership. The books will be maintained
for both tax and financial reporting purposes on an accrual basis. The
fiscal year of the Partnership is the calendar year.
As soon as practicable, but in no event later than 120 days after the close
of each fiscal year, the general partner will furnish each record holder of a
unit (as of a record date selected by the general partner) with an annual report
containing audited financial statements of the Partnership for the past fiscal
year, prepared in accordance with generally accepted accounting principles. As
soon as practicable, but in no event later than 90 days after the close of each
calendar quarter (except the fourth quarter), the general partner will furnish
each record holder of units upon request a report containing unaudited financial
statements of the Partnership and such other information as may be required by
law.
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The general partner will use all reasonable efforts to furnish each record
holder of a unit information reasonably required for tax reporting purposes
within 90 days after the close of each taxable year. Such information is
expected to be furnished in a summary form so that certain complex calculations
normally required of partners can be avoided. The general partner's ability to
furnish such summary information to holders of units will depend on the
cooperation of such holders of units in supplying certain information to the
general partner. Every holder of a unit (without regard to whether such holder
supplies such information to the general partner) will receive information to
assist in determining such holder's federal and state tax liability and filing
such holder's federal and state income tax returns.
Right to Inspect Partnership Books and Records
The partnership agreement provides that a limited partner can, for a purpose
reasonably related to such limited partner's interest as a limited partner, upon
reasonable demand and at such partner's own expense, have furnished to him:
o a current list of the name and last known address of each partner;
o a copy of the Partnership's tax returns;
o information as to the amount of cash, and a description and statement of
the agreed value of any other property or services contributed or to be
contributed by each partner and the date on which each became a partner;
o copies of the partnership agreement, the certificate of limited
partnership of the Partnership, amendments thereto and powers of attorney
pursuant to which the same have been executed;
o information regarding the status of the Partnership's business and
financial condition; and
o such other information regarding the affairs of the Partnership as is
just and reasonable.
The general partner may, and intends to, keep confidential from the limited
partners trade secrets or other information the disclosure of which the general
partner believes in good faith is not in the best interests of the Partnership
or which the Partnership is required by law or by agreements with third parties
to keep confidential.
Termination and Dissolution
The Partnership will continue until December 31, 2082, unless sooner
terminated pursuant to the partnership agreement. The Partnership will be
dissolved upon:
1. the election of the general partner to dissolve the Partnership, if
approved by a majority of the units;
2. the sale of all or substantially all of the assets and properties of the
Partnership and its operating partnerships;
3. the bankruptcy or dissolution of the general partner; or
4. the withdrawal or removal of the general partner or any other event that
results in its ceasing to be the general partner (other than by reason of
a transfer in accordance with the partnership agreement or withdrawal or
removal following approval of a successor).
However, the Partnership will not be dissolved upon an event described in
clause 4 if within 90 days after such event the partners agree in writing to
continue the business of the Partnership and to the appointment, effective as of
the date of such event, of a successor general partner. Upon a dissolution
pursuant to clause 3 or 4, at least a majority of the units may also elect,
within certain time limitations, to reconstitute the Partnership and continue
its business on the same terms and conditions set forth in the partnership
agreement by forming a new limited partnership on terms identical to those set
forth in the partnership agreement and having as a general partner an entity
approved by at least a majority of the units, subject to receipt by the
Partnership of an opinion of counsel that the exercise of such right will not
result in the loss of the limited liability of holders of units or cause the
Partnership or the reconstituted limited partnership to be treated as an
association taxable as a corporation or otherwise subject to taxation as an
entity for federal income tax purposes.
Registration Rights
Pursuant to the terms of the partnership agreement and subject to certain
limitations described therein, the Partnership has agreed to register for resale
under the Securities Act of 1933 and applicable state securities laws any
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units(or other securities of the Partnership) proposed to be sold by the general
partner (or its affiliates) if an exemption from such registration requirements
is not otherwise available for such proposed transaction. The Partnership is
obligated to pay all expenses incidental to such registration, excluding
underwriting discounts and commissions.
Cash Distribution Policy
A principal objective of the Partnership is to generate cash from the
Partnership operations and to distribute Available Cash to its partners in the
manner described herein. "Available Cash" generally means, with respect to any
calendar quarter, all cash received by the Partnership from all sources, less
all of its cash disbursements and net additions to reserves. For purposes of
cash distributions to holders of units, the term Available Cash excludes the
amount paid in respect of the 0.5% special limited partner interest in SFPP
owned by the former general partner of SFPP, which amount will equal 0.5% of the
total cash distributions made each quarter by SFPP to its partners.
The general partner's decisions regarding amounts to be placed in or released
from reserves may have a direct impact on the amount of Available Cash. This is
because increases and decreases in reserves are taken into account in computing
Available Cash. The general partner may, in its reasonable discretion (subject
to certain limits), determine the amounts to be placed in or released from
reserves each quarter.
Cash distributions will be characterized as either distributions of Cash from
Operations or Cash from Interim Capital Transactions. This distinction affects
the amounts distributed to holders of units relative to the general partner. See
"--Quarterly Distributions of Available Cash-Distributions of Cash from
Operations" and "-Quarterly Distributions of Available Cash-Distributions of
Cash from Interim Capital Transactions."
"Cash from Operations" generally refers to the cash balance of the
Partnership on the date the Partnership commenced operations, plus all cash
generated by the operations of the Partnership's business, after deducting
related cash expenditures, reserves, debt service and certain other items.
"Cash from Interim Capital Transactions" will generally be generated only by
borrowings, sales of debt and equity securities and sales or other dispositions
of assets for cash (other than inventory, accounts receivable and other current
assets and assets disposed of in the ordinary course of business).
To avoid the difficulty of trying to determine whether Available Cash
distributed by the Partnership is Cash from Operations or Cash from Interim
Capital Transactions, all Available Cash distributed by the Partnership from any
source will be treated as Cash from Operations until the sum of all Available
Cash distributed as Cash from Operations equals the cumulative amount of Cash
from Operations actually generated from the date the Partnership commenced
operations through the end of the calendar quarter prior to such distribution.
Any excess Available Cash (irrespective of its source) will be deemed to be Cash
from Interim Capital Transactions and distributed accordingly.
If Cash from Interim Capital Transactions is distributed in respect of each
unit in an aggregate amount per unit equal to $11.00 per unit (the initial
public offering price of the units adjusted to give effect to the 2-for-1 split
of units effective October 1, 1997) (the "Initial Unit Price"), the distinction
between Cash from Operations and Cash from Interim Capital Transactions will
cease, and both types of Available Cash will be treated as Cash from Operations.
The general partner does not anticipate that there will be significant amounts
of Cash from Interim Capital Transactions distributed.
The discussion below indicates the percentages of cash distributions required
to be made to the general partner and the holders of units. In the following
general discussion of how Available Cash is distributed, references to Available
Cash, unless otherwise stated, mean Available Cash that constitutes Cash from
Operations.
Quarterly Distributions of Available Cash. The Partnership will make
distributions to its partners with respect to each calendar quarter prior to
liquidation in an amount equal to 100% of its Available Cash for such quarter.
Distributions of Cash from Operations. Distributions by the Partnership of
Available Cash constituting Cash from Operations with respect to any quarter
will be made in the following manner:
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first, 98% to the holders of units pro rata and 2% to the general partner
until the holders of units have received a total of $0.3025 per unit for
such quarter in respect of each unit (the "First Target Distribution");
and
second, 85% of any such Available Cash then remaining to the holders of units
pro rata and 15% to the general partner until the holders of units have
received a total of $0.3575 per unit for such quarter in respect of each
unit (the "Second Target Distribution");
third, 75% of any such Available Cash then remaining to all holders of units
pro rata and 25% to the general partner until the holders of units have
received a total of $0.4675 per unit for such quarter in respect of each
unit (the "Third Target Distribution"); and
fourth, 50% of any such Available Cash then remaining to all holders of units
pro rata and 50% to the general partner.
In addition, if the First, Second and Third Target Distribution levels are
reduced to zero, as described below under "--Quarterly Distributions of
Available Cash-Adjustment of Target Distribution Levels," all remaining
Available Cash will be distributed as Cash from Operations, 50% to the holders
of units pro rata and 50% to the general partner. These provisions are
inapplicable upon the dissolution and liquidation of the Partnership.
Distributions of Cash from Interim Capital Transactions. Distributions on any
date by the Partnership of Available Cash that constitutes Cash from Interim
Capital Transactions will be distributed 98% to all holders of units pro rata
and 2% to the general partner until the Partnership shall have distributed in
respect of each unit Available Cash constituting Cash from Interim Capital
Transactions in an aggregate amount per unit equal to the Initial Unit Price.
As Cash from Interim Capital Transaction is distributed, it is treated as if
it were a repayment of the initial public offering price. To reflect such
repayment, the First, Second and Third Target Distribution levels will be
adjusted downward by multiplying each amount by a fraction, the numerator of
which is the Unrecovered Initial Unit Price immediately after giving effect to
such repayment and the denominator of which is the Unrecovered Initial Unit
Price, immediately prior to giving effect to such repayment. "Unrecovered
Initial Unit Price" includes the amount by which the Initial Unit Price exceeds
the aggregate distribution of Cash from Interim Capital Transactions per unit.
When "Payback of Initial Unit Price" is achieved, i.e., when the Unrecovered
Initial Unit Price is zero, then in effect the First, Second and Third Target
Distribution levels each will have been reduced to zero. Thereafter all
distributions of Available Cash from all sources will be treated as if they were
Cash from Operations and Available Cash will be distributed 50% to all holders
of units pro rata and 50% to the general partner.
Adjustment of Target Distribution Levels. The First, Second and Third Target
Distribution levels will be proportionately adjusted upward or downward, as
appropriate, in the event of any combination or subdivision of units (whether
effected by a distribution payable in units or otherwise) but not by reason of
the issuance of additional units for cash or property. For example, in
connection with the Partnership's two-for-one split of the units on October 1,
1997, the First, Second and Third Target Distribution levels were each reduced
to 50% of its initial level. See "--Quarterly Distributions of Available
Cash-Distributions of Cash from Operations."
In addition, if a distribution is made of Available Cash constituting Cash
from Interim Capital Transactions, the First, Second and Third Target
Distribution levels will be adjusted downward proportionately, by multiplying
each such amount, as the same may have been previously adjusted, by a fraction,
the numerator of which is the Unrecovered Initial Unit Price immediately after
giving effect to such distribution and the denominator of which is the
Unrecovered Initial Unit Price immediately prior to such distribution. For
example, assuming the Unrecovered Initial Unit Price is $11.00 per unit and if
Cash from Interim Capital Transactions of $5.50 per unit is distributed to
holders of units (assuming no prior adjustments), then the amount of the First,
Second and Third Target Distribution levels would each be reduced to 50% of its
initial level. If and when the Unrecovered Initial Unit Price is zero, the
First, Second and Third Target Distribution levels each will have been reduced
to zero, and the general partner's share of distributions of Available Cash will
increase, in general, to 50% of all distributions of Available Cash.
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The First, Second and Third Target Distribution levels may also be adjusted
if legislation is enacted which causes the Partnership to become taxable as a
corporation or otherwise subjects the Partnership to taxation as an entity for
federal income tax purposes. In such event, the First, Second, and Third Target
Distribution levels for each quarter thereafter would be reduced to an amount
equal to the product of:
o each of the First, Second and Third Target Distribution levels
multiplied by;
o one minus the sum of:
o the maximum marginal federal income tax rate to which the
Partnership is subject as an entity; plus
o any increase that results from such legislation in the effective
overall state and local income tax rate to which the Partnership
is subject as an entity for the taxable year in which such quarter
occurs (after taking into account the benefit of any deduction
allowable for federal income tax purposes with respect to the
payment of state and local income taxes).
For example, assuming the Partnership was not previously subject to state and
local income tax, if the Partnership were to become taxable as an entity for
federal income tax purposes and the Partnership became subject to a maximum
marginal federal, and effective state and local, income tax rate of 38%, then
each of the Target Distribution levels, would be reduced to 62% of the amount
thereof immediately prior to such adjustment.
Liquidation and Distribution of Proceeds
Upon dissolution of the Partnership, unless the Partnership is reconstituted
and continued as a new limited partnership, the person authorized to wind up the
affairs of the Partnership (the "Liquidator") will, acting with all of the
powers of the general partner that such Liquidator deems necessary or desirable
in its good faith judgment in connection therewith, liquidate the Partnership's
assets and apply the proceeds of the liquidation as follows:
o first towards the payment of all creditors of the Partnership and the
creation of a reserve for contingent liabilities; and
o then to all partners in accordance with the positive balances in
their respective capital accounts.
Under certain circumstances and subject to certain limitations, the
Liquidator may defer liquidation or distribution of the Partnership's assets for
a reasonable period of time and/or distribute assets to partners in kind if it
determines that a sale would be impractical or would cause undue loss to the
partners.
Generally, any gain will be allocated between the holders of units and the
general partner in a manner that approximates their sharing ratios in the
various Target Distribution levels. Holders of units and the general partner
will share in the remainder of the Partnership's assets in proportion to their
respective capital account balances in the Partnership.
Any loss or unrealized loss will be allocated to the general partner and the
holders of units: first, in proportion to the positive balances in such
partners' capital accounts until all such balances are reduced to zero; and
thereafter, to the general partner.
Transfer Agent and Registrar
Duties
First Chicago Trust Company of New York is the registrar and transfer agent
for the units and receives a fee from the Partnership for serving in such
capacities. The Partnership will pay fees charged by the transfer agent for
transfers of units except:
o fees similar to those customarily paid by holders of securities for
surety bond premiums to replace lost or stolen certificates;
o taxes or other governmental charges;
o special charges for services requested by a holder of a unit; and
o other similar fees or charges.
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The Partnership will not charge holders for disbursements of cash distributions.
The Partnership will indemnify the transfer agent, its agents and each of their
respective shareholders, directors, officers and employees against all claims
and losses that may arise out of acts performed or omitted in respect of its
activities as such, except for any liability due to any negligence, gross
negligence, bad faith or intentional misconduct of the indemnified person or
entity.
Resignation or Removal
The Transfer Agent may at any time resign, by notice to the Partnership, or
be removed by the Partnership, such resignation or removal to become effective
upon the appointment by the general partner of a successor transfer agent and
registrar and its acceptance of such appointment. If no successor has been
appointed and accepted such appointment within 30 days after notice of such
resignation or removal, the general partner is authorized to act as the transfer
agent and registrar until a successor is appointed.
Item 3. Legal Proceedings
See Note 16 of the Notes to the Consolidated Financial Statements of the
Partnership included elsewhere in this report.
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 1999.
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P A R T II
Item 5. Market for the Registrant's Units and Related Security Holder Matters
The following table sets forth, for the periods indicated, the high and low
sale prices per unit, as reported on the New York Stock Exchange, the principal
market in which the units are traded, and the amount of cash distributions
declared per unit.
Price Range
----------- Cash
High Low Distributions
---- --- -------------
1999
----
First Quarter $37.9375 $33.1250 $0.7000
Second Quarter 39.0000 33.9375 0.7000
Third Quarter 45.3750 37.5000 0.7250
Fourth Quarter 43.9375 39.6250 0.7250
1998
----
First Quarter $37.8750 $30.1250 $0.5625
Second Quarter 38.1250 35.0000 0.6300
Third Quarter 37.3750 28.5625 0.6300
Fourth Quarter 36.9375 29.5625 0.6500
The Partnership pays quarterly distributions at a current rate of $.725 per
quarter. The Partnership currently expects that it will continue to pay
comparable cash distributions in the future.
As of February 29, 2000, there were approximately 35,000 beneficial owners of
the Partnership's units.
44
<PAGE>
Item 6. Selected Financial Data (unaudited)
The following table sets forth, for the periods and at the dates indicated,
selected historical financial and operating data for the Partnership.
<TABLE>
<CAPTION>
Year Ended December 31,
1999(5) 1998(6) 1997 1996 1995
------------ ------------ ------------ ------------ ------------
(In thousands, except per unit and operating data)
<S> <C> <C> <C> <C> <C>
Income and Cash Flow Data:
Revenues $ 428,749 $ 322,617 $ 73,932 $ 71,250 $ 64,304
Cost of product sold 16,241 5,860 7,154 7,874 8,020
Operating expense 111,275 77,162 17,982 22,347 15,928
Fuel and power 31,745 22,385 5,636 4,916 3,934
Depreciation and amortization 46,469 36,557 10,067 9,908 9,548
General and administrative 35,612 39,984 8,862 9,132 8,739
------------ ------------ ------------ ------------ ------------
Operating income 187,407 140,669 24,231 17,073 18,135
Earnings from equity investments 42,918 25,732 5,724 5,675 5,755
Amortization of excess cost of
equity investments (4,254) (764) - - -
Interest (expense) (54,336) (40,856) (12,605) (12,634) (12,455)
Interest income and other, net 22,988 (5,992) (353) 3,129 1,311
Income tax (provision) benefit (9,826) (1,572) 740 (1,343) (1,432)
------------ ------------ ------------ ------------ ------------
Net income before extraordinary charge 184,897 117,217 17,737 11,900 11,314
Extraordinary charge (2,595) (13,611) - - -
============ ============ ============ ============ ============
Net income $ 182,302 $ 103,606 $ 17,737 $ 11,900 $ 11,314
============ ============ ============ ============ ============
Net income per unit before
extraordinary charge(1) $ 2.63 $ 2.09 $ 1.02 $ 0.90 $ 0.85
============ ============ ============ ============ ============
Net income per unit $ 2.57 $ 1.75 $ 1.02 $ 0.90 $ 0.85
============ ============ ============ ============ ============
Per unit cash distribution paid $ 2.78 $ 2.39 $ 1.63 $ 1.26 $ 1.26
============ ============ ============ ============ ============
Additions to property, plant and equipm$nt 82,725 $ 38,407 $ 6,884 $ 8,575 $ 7,826
Balance Sheet Data (at end of period):
Net property, plant and equipment $ 2,578,313 $ 1,763,386 $ 244,967 $ 235,994 $ 236,854
Total assets $ 3,228,738 $ 2,152,272 $ 312,906 $ 303,603 $ 303,664
Long-term debt $ 989,101 $ 611,571 $ 146,824 $ 160,211 $ 156,938
Partners' capital $ 1,774,798 $ 1,360,663 $ 150,224 $ 118,344 $ 123,116
Operating Data:
Pacific Operations -
Mainline delivery volumes (MBbls)(2) 375,663 307,997 - - -
Other delivery volumes (MBbls)(2) 10,025 17,957 - - -
Mid-Continent Operations -
Delivery volumes (MBbls)(3) 50,124 44,783 46,309 46,601 41,613
Bulk Terminals -
Transport volumes (Mtons)(4) 39,190 24,016 9,087 6,090 6,486
(1) Represents net income before extraordinary charge per unit adjusted for the two-for-one split of units on October 1, 1997.
Net income before extraordinary charge per unit was computed by dividing the interest of the holders of units in net income
before extraordinary charge by the weighted average number of units outstanding during the period.
(2) The Partnership acquired the Pacific Operations on March 6, 1998.
(3) Represents total volumes for the North System and the Cypress Pipeline only.
(4) Represents the volumes of the Cora Terminal, excluding ship or pay volumes of 252 Mtons for 1996, the Grand Rivers Terminal
from September 1997, Kinder Morgan Bulk Terminals from July 1, 1998 and the Pier IX and Shipyard Terminals from
December 18, 1998.
(5) Includes results of operations for 51% interest in Plantation Pipe Line Company, Mid-Continent transmix operations and
33 1/3% interest in Trailblazer Pipeline Company since dates of acquisition.
(6) Includes results of operations for Pacific Operations, Kinder Morgan Bulk Terminals and 24% interest in Plantation Pipe Line
Company since dates of acquisition.
</TABLE>
45
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations of the Partnership
The Partnership's financial results for the past two years reflect
significant growth across all business segments. Strategic business acquisitions
and ongoing strength in the Partnership's pipeline and terminal operations
resulted in net income before extraordinary charge of $184.9 million ($2.63 per
unit) for 1999, $117.2 million ($2.09 per unit) for 1998 and $17.7 million
($1.02 per unit) for 1997. Included in the net income for 1999 and 1998 were
extraordinary charges associated with debt refinancing transactions in the
amount of $2.6 million and $13.6 million, respectively.
Total Partnership revenue in 1999 grew 33% (to $428.7 million) over 1998
revenue of $322.6 million. For 1997, the Partnership reported total revenue of
$73.9 million. The increases in revenues reflect the addition of key
acquisitions as well as continued strong demand for refined products and bulk
tonnage. The acquisitions of Kinder Morgan Bulk Terminals, Inc. (formerly
Hall-Buck Marine, Inc.) in July 1998 and the Pier IX and Shipyard River
terminals in December 1998 were the largest contributing factors for the
increase in total Partnership revenue in 1999 compared with 1998. The
acquisition of the Pacific Operations (formerly Santa Fe Pacific Pipeline
Partners, L.P.) in March 1998 was the primary contributing factor for the
increase in total Partnership revenue in 1998 compared with 1997. Total
consolidated operating income for the past three years was $187.4 million in
1999, $140.7 million in 1998 and $24.2 million in 1997. Total consolidated net
income for the three years was $182.3 million in 1999, $103.6 million in 1998
and $17.7 million in 1997.
Pacific Operations
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1999 1998 1997
------------- -------------- -------------
<S> <C> <C> <C>
Results of Operations (In Thousands)
Revenues $ 256,692 $ 221,430 $ -
Operating expenses 44,445 42,020 -
Depreciation and amortization 30,982 25,177 -
Taxes, other than income taxes 10,611 8,548 -
------------- -------------- -------------
86,038 75,745 -
Operating Income 170,654 145,685 -
Earnings from equity investments 1,531 803 -
Interest and other, net 10,517 (6,418) -
------------- -------------- -------------
12,048 (5,615) -
============= ============== =============
Net Income $ 182,702 $ 140,070 $ -
============= ============== =============
Operating Statistics
Mainline Delivery Volumes (MMBbls) 375.7 308.0 -
Other Delivery Volumes (MMBbls) 10.0 18.0 -
Average Tariff ($/Bbl) $ 0.53 $ 0.55 $ -
</TABLE>
The Pacific Operations, acquired in March 1998, reported segment earnings of
$182.7 million on operating revenue of $256.7 million for the full year 1999.
Segment earnings and operating revenue for 1998 were $140.1 million and $221.4
million, respectively. The increase in operating results was directly affected
by the Partnership's acquisition of the Pacific Operations in March 1998. The
30% increase in earnings and 16% increase in revenue in 1999 over 1998 reflect
the inclusion of a full twelve months of operations and the continued strong
demand for gasoline, diesel fuel and jet fuel in the Partnership's West Coast
markets. Total mainline throughput volumes increased 22% in 1999 versus 1998.
Slightly lower (4%) average tariff rates and lower fee, gathering and
miscellaneous terminal volumes partially offset the 1999 revenue increase.
46
<PAGE>
Segment operating expenses, which include fuel, power and operating and
maintenance expenses, were $44.4 million in 1999 and $42.0 million in 1998. The
1999 increase resulted from higher fuel and power expenses associated with
moving a full twelve-months of product volumes. Continued investments in capital
additions and pipeline expansions resulted in higher depreciation and
amortization expense as well as higher ad valorem tax expense in 1999.
Earnings from equity investments increased 91% in 1999 from 1998. The
increase was the result of higher processing volumes at the Colton transmix
processing facility. Additionally, the segment benefited from favorable changes
in non-operating income/expense in 1999 versus 1998. The favorable variance was
primarily the result of lower 1999 expense accruals made for the FERC rate case
reserve as a result of the FERC's opinion relating to an outstanding rate case
dispute, 1999 insurance recoveries and favorable adjustments to employee
post-retirement benefit liabilities.
Mid-Continent Operations
Mid-Continent Operations
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1999 1998 1997
------------- --------------- -------------
<S> <C> <C> <C>
Results of Operations (In Thousands)
Revenues $ 57,444 $ 38,271 $ 55,777
Operating expenses 32,032 14,346 21,698
Depreciation and amortization 7,946 7,510 9,009
Taxes, other than income taxes 2,016 2,019 2,681
------------- --------------- -------------
41,994 23,875 33,388
Operating Income 15,450 14,396 22,389
Earnings from equity investments 41,364 24,892 5,724
Amortization of excess cost of equity investments (4,254) (764) -
Interest and other, net 14,300 (396) (1,371)
------------- --------------- -------------
51,410 23,732 4,353
Income Before Income Taxes 66,860 38,128 26,742
Income Tax Benefit (Expense) (8,538) (972) 740
============= =============== =============
Net Income $ 58,322 $ 37,156 $ 27,482
============= =============== =============
Operating Statistics
Delivery Volumes (MMBbls) 50.1 44.8 46.3
Average Tariff ($/Bbl) $ 0.88 $ 0.93 $ 0.93
</TABLE>
Mid-Continent Operations consist of the North System, the Cypress Pipeline,
the transmix operations, the Painter gas processing plant and the Partnership's
equity investments in Shell CO2 Company, Plantation Pipe Line Company and
Heartland Pipeline Company. The segment reported earnings of $58.3 million in
1999, $37.2 million in 1998 and $27.5 million in 1997. Segment revenue was $57.4
million in 1999, $38.3 million in 1998 and $55.8 million in 1997. The 1999
revenue increase reflects the inclusion of transmix operations acquired in
September 1999 from Primary Corporation. A 9% increase in throughput volumes on
the Partnership's North System, partially offset by slightly lower (4%) average
tariff rates also contributed to the 1999 revenue increase. The decrease in
revenue in 1998 from 1997 was primarily related to the Central Basin Pipeline,
which was contributed to Shell CO2 Company in March 1998 and subsequently
accounted for as an equity investment.
Segment operating expenses increased to $32.0 million in 1999 versus $14.3
million in 1998. The increase was due to the inclusion of the transmix
operations, the higher throughput volumes on the North System and an 18%
increase in throughput volumes on the Cypress Pipeline. Segment operating
expenses for 1997 were $21.7 million. The $7.4 million decrease in expenses in
1998 from 1997 resulted from the transfer of the Central Basin Pipeline,
47
<PAGE>
the assignment of the Mobil gas processing agreement at the Bushton Plant in
April 1997 and lower purchase/sale contracts reported by the North System.
Depreciation and amortization expenses totaled $7.9 million in 1999, which are
consistent with 1998 depreciation and amortization expenses of $7.5 million. The
1998 depreciation and amortization expenses decreased $1.5 million from the $9.0
million reported in 1997 as a result of the transfer of the Central Basin
Pipeline.
Earnings from equity investments increased $16.5 million (66%) to $41.4
million in 1999 compared with $24.9 million in 1998. This follows an increase in
equity earnings of $19.2 million in 1998 compared with 1997. The 1999 increase
resulted from the segment's increased investment in Plantation Pipe Line
Company. The overall increase was partially offset by lower earnings from the
Partnership's investment in the Mont Belvieu fractionation facility, which was
sold to Enterprise Products Partners L.P. in September 1999. The 1998 increase
was the result of ownership interests in Plantation Pipe Line Company and Shell
CO2 Company acquired in 1998. Amortization of excess cost of equity investments
represents the amortization of the difference between the Partnership's initial
investment in Plantation Pipe Line Company and its proportionate share of the
underlying book value of Plantation on the dates of acquisition. The
period-to-period increases in amortization of such excess costs correspond with
the Partnership's 1998 and 1999 equity investments in Plantation. Allocable
interest and other non-operating income items totaled $14.3 million in 1999
versus expense of $0.4 million in 1998 and $1.4 million in 1997. The 1999 amount
includes the benefit of a $14.1 million gain on the sale of the Partnership's
interest in the Mont Belvieu fractionation facility. The $1.4 million expense
for 1997 was largely attributable to a $0.6 million contested product loss at
the Mont Belvieu fractionation facility.
Segment income tax expense increased $7.6 million in 1999 compared with 1998.
This follows a $1.7 million increase in 1998 over the previous year. The 1999
and 1998 income tax provisions include the Partnership's share of tax expense
relating to its investment in Plantation Pipe Line Company.
Bulk Terminals
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------
1999 1998 1997
------------- -------------- --------------
<S> <C> <C> <C>
Results of Operations (In Thousands)
Revenues $ 114,613 $ 62,916 $ 18,155
Operating expenses 66,630 36,901 6,131
Depreciation and amortization 7,541 3,870 1,058
Taxes, other than income taxes 3,525 1,573 257
------------- -------------- --------------
77,696 42,344 7,446
Operating Income 36,917 20,572 10,709
Earnings from equity investments 23 37 -
Interest and other, net (669) (765) (1)
------------- -------------- --------------
(646) (728) (1)
Income Before Income Taxes 36,271 19,844 10,708
Income Tax (Expense) (1,288) (600) -
============= ============== ==============
Net Income $ 34,983 $ 19,244 $ 10,708
============= ============== ==============
Operating Statistics
Transport Volumes (MM Tons) 39.2 24.0 9.1
</TABLE>
The Bulk Terminals segment reported earnings of $35.0 million in 1999, $19.2
million in 1998 and $10.7 million in 1997. Segment revenue was $114.6 million in
1999, $62.9 million in 1998 and $18.2 million in 1997. The increase in operating
results was directly affected by the Partnership's acquisitions of Kinder Morgan
Bulk Terminals, Inc. (formerly Hall-Buck Marine, Inc.) in July 1998, the Pier IX
and Shipyard River terminals in
48
<PAGE>
December 1998 and the Grand Rivers coal terminal in September 1997. The 82%
increase in segment revenues in 1999 over 1998 resulted from the inclusion of a
full year of operations for Kinder Morgan Bulk Terminals, Pier IX and Shipyard
in 1999 as well as from a 10% increase in coal transport revenue from the
segment's Cora and Grand Rivers coal terminals. The year-to-year coal transport
revenue increase was the result of an 18% increase in coal transport volumes,
partially offset by a 7% decrease in average transfer rates. Overall higher
segment revenue in 1999 over 1998 was partially offset by lower revenue from
coal marketing activities. The increase in segment revenues in 1998 over 1997
was the result of the additions of Kinder Morgan Bulk Terminals, the Grand
Rivers coal terminal and a 93% increase in marketing revenue.
Operating expenses, which include the segment's cost of sales, fuel, power
and operating and maintenance expenses, totaled $66.6 million in 1999 compared
to $36.9 million in 1998 and $6.1 million in 1997. The increases were the result
of acquisitions made during the last two years as well as yearly increases in
combined fuel, power and operating expenses associated with the transfer of
higher coal volumes. The 1999 increase in operating expenses was partly offset
by higher 1998 cost of sales expenses related to purchase/sale marketing
contracts. The 1998 cost of sales were also higher than the 1997 cost of sales,
contributing to the increase in segment operating expenses in 1998 over 1997.
Depreciation and amortization expense was $7.5 million in 1999, $3.9 million in
1998 and $1.1 million in 1997. Taxes, other than income taxes, were $3.5 million
in 1999, $1.6 million in 1998 and $0.3 million in 1997. The increases in both
depreciation and taxes, other than income taxes, were primarily due to the
addition of Kinder Morgan Bulk Terminals as well as to capital additions made at
the segment's coal terminals.
Other
Income items not attributable to any segment include general and
administrative expenses, unallocable interest income and expense and minority
interest. Total Partnership general and administrative expenses totaled $35.6
million in 1999 compared with $40.0 million in 1998 and $8.9 million in 1997.
The increase from the 1997 amount was attributable to higher administrative
expenses associated with acquisitions made by the Partnership in 1998 and 1999.
The Partnership continues to focus on productivity and expense controls. Total
Partnership interest expense, net of interest income, was $52.6 million in 1999,
$38.6 million in 1998 and $12.1 million in 1997. The increases were primarily
due to debt assumed by the Partnership as part of the acquisition of the Pacific
Operations as well as to expenses related to the financing of the Partnership's
1998 and 1999 investments. Minority interest increased to $2.9 million in 1999
compared with $1.0 million in 1998 and $0.2 million in 1997. The year-to-year
increases resulted from higher earnings attributable to SFPP (Pacific
Operations) as well as to higher overall Partnership income.
Outlook
The Partnership intends to actively pursue a strategy to increase the
Partnership's operating income. The Partnership will use a three-pronged
strategy to accomplish this goal.
o Cost Reductions. The Partnership has substantially reduced the operating
expenses of those operations of the Partnership that were owned at the
time the general partner was acquired in February 1997. In addition, the
Partnership has made substantial reductions in the operating expenses of
the businesses and assets that it has acquired since February 1997. The
Partnership intends to 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:
o completing the expansion of its West Line Southern California products
pipeline system in May 1999. The expansion increased the capacity of
that system by over 50%;
o beginning the expansion of its San Diego Line. The expansion project
will cost approximately $22 million and consists of the construction
of 23 miles of 16-inch diameter pipe, and other appurtenant
facilities. The new facilities will increase capacity on the
San Diego Line by approximately 25%;
o Entering into an agreement to provide pipeline transportation
services on the North System for Aux Sable Liquid Products, L.P. in
the Chicago area beginning around October 2000;
49
<PAGE>
o constructing a multi-million dollar cement import and distribution
facility at the Shipyard River terminal, which will be completed in
fourth quarter 2000, as part of a 30 year cement contract with Blue
Circle Cement;
o purchasing an additional loading dock at the Shipyard River terminal
from Chevron Corporation for $4 million;
o completing a $3.4 million, 13 mile expansion of the Heartland
pipeline system in August 1999 in conjunction with its partner,
Conoco Pipe Line Company;
o beginning a $13 million upgrade to the coal loading facilities at the
Cora and Grand Rivers coal terminals. The two terminals handled an
aggregate of 16.0 million tons of coal during 1999 compared with 13.5
million tons in 1998; and
o increasing earnings and cash flow, as a result of the Partnership's
March 9, 2000 announcement that it had reached an agreement to acquire
the remaining 80% of Shell CO2 Company.
o Strategic Acquisitions. Since January 1, 1999, the Partnership made the
following acquisitions:
o Plantation Pipe Line Company (27%) June 16, 1999
o Transmix Operations September 10,1999
o Trailblazer Pipeline Company (33 1/3%) November 30, 1999
o Kinder Morgan Interstate Gas Transmission LLC December 31, 1999
o Trailblazer Pipeline Company (33 1/3%) December 31, 1999
o Red Cedar Gathering Company (49%) December 31, 1999
o Milwaukee Bulk Terminals, Inc. January 1, 2000
o Dakota Bulk Terminal, Inc. January 1, 2000
The Partnership intends to seek opportunities to make additional strategic
acquisitions to expand existing businesses or to enter into related businesses.
The Partnership periodically considers potential acquisition opportunities as
such opportunities are identified. No assurance can be given that the
Partnership will be able to consummate any such acquisitions. Management
anticipates that the Partnership will finance acquisitions temporarily by
borrowings under its bank credit facilities or by issuing commercial paper, and
permanently by issuing new debt securities and/or units.
On January 20, 2000, the Partnership announced a quarterly distribution of
$0.725 per unit for the fourth quarter of 1999. The distribution for the fourth
quarter of 1998 was $0.65 per unit. Management intends to increase the
distribution to an annual level of at least $3.10 ($0.775 per quarter) per unit
beginning with the distribution for the first quarter of 2000 assuming no
adverse change in the Partnership's operations, economic conditions and other
factors.
Liquidity and Capital Resources
The Partnership's primary cash requirements, in addition to normal operating
expenses, are debt service, sustaining capital expenditures, expansion capital
expenditures and quarterly distributions to partners. In addition to utilizing
cash generated from operations, the Partnership could meet its cash requirements
through borrowings under its credit facilities or issuing short-term commercial
paper, long-term notes or additional units. The Partnership expects to fund
future cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities. Expansion capital expenditures are
expected to be funded through additional Partnership borrowings or issuance of
additional units. Interest payments are expected to be paid from cash flows from
operating activities and debt principal payments will be met by additional
borrowings as they become due or by issuance of additional units.
Operating Activities
Net cash provided by operating activities was $182.9 million for 1999. This
amount was $48.9 million higher than the $134.0 million of cash provided by
operating activities in 1998. The increase in cash flow from operations was
primarily the result of higher net earnings, increased distributions from equity
investments and higher non-cash depreciation and amortization charges. Higher
earnings, primarily due to the Partnership's acquisitions since March 1998,
accounted for $67.7 million of the increase. Distributions from equity
investments increased $14.0 million in
50
<PAGE>
1999 versus 1998. The increase resulted primarily from the Partnership's
increased investment in Plantation Pipe Line Company. The Partnership's
initial investment of 24% was made in September 1998 and an additional
investment of 27% was made in June 1999. Higher depreciation and amortization
expenses accounted for $13.4 million of the total increase in cash provided by
operations. The higher depreciation expense in 1999 was attributable to the
inclusion of a full year of expense for the Pacific Operations and Kinder
Morgan Bulk Terminals as well as to higher property balances as a result of
increased capital expenditures. Higher amortization of excess investment costs
resulted from the Partnership's increased investment in Plantation Pipe
Line Company. In addition, as part of a settlement agreement relating to
previous litigation matters with El Paso Refinery L.P. and its general partner,
SFPP made a final payment of $8 million in the second quarter of 1998.
The overall increase in cash provided by operating activities was partially
offset by higher earnings from equity investments, the gain on the sale of the
Mont Belvieu fractionation facility and lower cash inflows relative to net
changes in non-current operating assets and liabilities. The $17.2 million
increase in earnings from equity investments resulted primarily from income
generated from the Partnership's investment in Plantation Pipe Line Company. The
sale of the Mont Belvieu fractionation facility, netted with one-time special
charges, resulted in a $10.1 million gain in 1999 (see Note 4 to the
Consolidated Financial Statements). The $28.6 million year-to-year decrease in
cash provided by operating activities designated as Other, net, represents
higher cash outflows related to changes in long-term assets and liabilities as
well as to non-cash gains, losses and tax expense. The overall decrease includes
a $12.4 million decrease due to environmental reserve changes, a $8.9 million
decrease due to litigation reserve changes and a $6.0 million decrease due to
higher accrued insurance reimbursements. The changes reflect the benefits to the
Partnership, during 1999, of reductions in expense accruals made for
environmental and legal matters. The 1999 change in litigation reserves was
primarily due to accrual adjustments made for the FERC rate case reserve as a
result of the FERC's opinion relating to an outstanding rate case dispute.
Investing Activities
Net cash used in investing activities was $196.5 million in 1999 compared to
$281.7 million in 1998. The $85.2 million decrease in funds used in investing
activities was attributable to larger asset acquisitions in 1998 relative to
1999 and to higher proceeds from the sale of investments, property, plant and
equipment in 1999 versus 1998. The $5.7 million net cash inflow from the
acquisition of assets during 1999 includes $25.7 million of cash held by the
Natural Gas Operations at the time they were acquired from KMI. Partially
offsetting this amount was $15.3 million used to acquire the Mid-Continent
Operations' transmix processing facilities and $4.0 million used to acquire
additional dock facilities at the Partnership's Shipyard River terminal. In
1998, the Partnership spent $107.1 million in asset acquisitions, consisting of
$74.7 million for the purchase of the Pacific Operations and $32.4 million for
Bulk Terminal acquisitions. The $43.0 million increase in cash received from the
sale of investments, property, plant and equipment in 1999 over 1998 reflects
the $41.8 million received for the sale of the Partnership's interest in the
Mont Belvieu fractionation facility in September 1999.
The overall decrease in funds used in investing activities was partly offset
by increases in capital expenditures, primarily in the Partnership's Pacific
Operations, and by larger long-term equity investment acquisitions. Excluding
the effect of cash used for asset acquisitions, additions to property, plant and
equipment were $82.7 million in 1999 and $38.4 million in 1998. These additions
of property, plant and equipment include both expansion and sustaining projects.
The $161.8 million used in 1999 for acquisitions of equity investments included
$124.2 million for the additional investment in Plantation Pipe Line Company and
$37.6 million for the Partnership's first one-third interest in Trailblazer
Pipeline Company. In 1998, the Partnership spent $135.0 million on acquisitions
of equity investments, consisting of the Partnership's $110.0 million initial
investment in Plantation Pipe Line Company and its $25.0 million investment in
Shell CO2 Company.
Financing Activities
Net cash provided by financing activities was $22.0 million in 1999 compared
with $169.9 million in 1998. This decrease of $147.9 million from the comparable
1998 period included a $212.2 million decrease due to the sale of fewer units in
1999 versus 1998 and a $68.4 million decrease due to higher distributions to all
partners. Overall debt financing activities provided $216.3 million in cash
during 1999 versus $84.8 million during 1998. The increase in borrowings was
mainly due to 1999 acquisitions.
51
<PAGE>
Distributions to all partners increased to $190.8 million in 1999 compared to
$122.4 million in 1998. Higher distributions were the result of an increase in
the number of units, an increase in paid distributions per unit and an increase
in incentive distributions to the general partner as a result of increased
distributions to unitholders. The Partnership paid distributions of $2.775 per
unit in 1999 compared to $2.385 per unit in 1998. The increase in paid
distributions resulted from favorable operating results in 1999. The Partnership
believes that future operating results will continue to support similar levels
of quarterly cash distributions, however, no assurance can be given that future
distributions will continue at such levels.
Partnership Distributions
The partnership agreement requires the Partnership to distribute 100% of
"Available Cash" (as defined in the partnership agreement) to the Partners
within 45 days following the end of each calendar quarter in accordance with
their respective percentage interests. Available Cash consists generally of all
cash receipts of the Partnership and its operating partnerships, less cash
disbursements and net additions to reserves (including any reserves required
under debt instruments for future principal and interest payments) and amounts
payable to the former Santa Fe general partner in respect of its 0.5% interest
in SFPP.
Available Cash of the Partnership is initially distributed 98% to the limited
partners (including the approximate 2% limited partner interest of the general
partner) and 2% to the general partner. These distribution percentages are
modified to provide for incentive distributions to be paid to the general
partner in the event that quarterly distributions to unitholders exceed certain
specified targets.
Available Cash for each quarter is distributed, first, 98% to the limited
partners and 2% to the general partner until the limited partners have received
a total of $0.3025 per unit for such quarter, second, 85% to the limited
partners and 15% to the general partner until the limited partners have received
a total of $0.3575 per unit for such quarter, third, 75% to the limited partners
and 25% to the general partner until the limited partners have received a total
of $0.4675 per unit for such quarter, and fourth, thereafter 50% to the limited
partners and 50% to the general partner. Incentive distributions are generally
defined as all cash distributions paid to the general partner that are in excess
of 2% of the aggregate amount of cash being distributed. The general partner's
incentive distributions declared by the Partnership for 1999 were $55,000,963,
while the incentive distributions paid during 1999 were $51,301,689.
Credit Facilities
The Partnership has a $300 million unsecured five-year credit facility and a
$300 million unsecured 364-day credit facility with a syndicate of financial
institutions. First Union National Bank is the administrative agent under the
agreements.
Interest on borrowings is payable quarterly. Interest on the credit
facilities accrues at the Partnership's option at a floating rate equal to
either:
o First Union National Bank's base rate (but not less than the Federal
Funds Rate, plus .5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating
of the Partnership's long-term senior unsecured debt.
The LIBOR margins under the 364-day credit facility are higher than the
margins under the five-year credit facility. The five-year credit facility also
permits the Partnership to obtain bids for fixed rate loans from members of the
lending syndicate.
The credit facilities include restrictive covenants that are customary for
these types of facilities, including without limitation:
o requirements to maintain certain financial ratios;
o restrictions on the incurrence of additional indebtedness;
o restrictions on entering into mergers, consolidations and sales of
assets;
o restrictions on granting liens;
o prohibitions on making cash distributions to holders of units more
frequently than quarterly;
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<PAGE>
o prohibitions on making cash distributions in excess of 100% of
Available Cash for the immediately preceding calendar quarter; and
o prohibitions on making any distribution to holders of units if an
event of default exists or would exist upon making such distribution.
As of December 31, 1999, the Partnership had outstanding borrowings under the
credit facilities of $197.6 million including the following:
o $125 million borrowed to fund the purchase price of its interest in
Plantation Pipe Line Company acquired on June 16, 1999;
o $37.6 million borrowed to fund the purchase price of its 33 1/3%
interest in Trailblazer Pipeline Company acquired on November 30,
1999; and
o $35 million borrowed to fund general corporate purposes.
The Partnership has an outstanding letter of credit issued under the credit
facilities in the amount of $23.7 million that backs-up the OLP-B tax-exempt
bonds due 2024. The letter of credit reduces the amount available for borrowing
under the credit facilities.
In addition, as of December 31, 1999, the Partnership financed $330 million
through KMI to fund part of the acquisition of assets acquired from KMI on
December 31, 1999. Per the Closing Agreement entered into as of January 20,
2000, the Partnership must pay KMI a per diem fee of $180.56 for each $1,000,000
financed. The Partnership paid $200 million on January 21, 2000, and the
Partnership plans to refinance the remaining amount by March 31, 2000.
In December 1999, the Partnership established a commercial paper program
providing for the issuance of up to $300 million of commercial paper. Borrowings
under the commercial paper program reduce the borrowings allowed under the
five-year credit facility. As of December 31, 1999, the Partnership had not
issued any commercial paper.
As of December 31, 1999, SFPP's long term debt aggregated $355 million and
consisted of $181.0 million of Series F notes and $174.0 million borrowed under
SFPP's $175.0 million bank credit facility. The Series F notes are payable in
annual installments through December 15, 2004. The credit facility matures in
August 2000. The Partnership intends to refinance some or all of the remaining
Series F notes as they become payable. The credit facility permits SFPP to
refinance the $32.5 million of Series F notes due on or before December 15, 2000
(plus a $29.5 million prepayment allowed on such date). The SFPP credit facility
also provides for a working capital facility of up to $25 million.
In December 1999, Trailblazer entered into a 364-day revolving credit
agreement with Toronto Dominion, Inc. providing for loans up to $10 million. The
agreement expires December 26, 2000. At December 31, 1999, the outstanding
balance under Trailblazer's revolving credit agreement was $10 million. The
agreement provides for an interest rate of LIBOR plus 0.875%. At December 31,
1999, the interest rate on the credit facility debt was 7.615%. Under the terms
of the revolving credit agreement with Toronto Dominion, Inc., Trailblazer
partnership distributions are restricted by certain financial covenants.
Senior Notes
On January 29, 1999, the Partnership issued $250 million of 6.30% Senior Notes
("Notes") due 2009. Interest on the Notes is payable semi-annually on February 1
and August 1 of each year beginning on August 1, 1999. The indenture governing
the Notes contains restrictions on the ability of the Partnership to enter into
sale and leaseback transactions, grant liens on its assets and merge or
consolidate with other entities. In the offering, the Partnership received
proceeds, net of underwriting discounts and commissions, of approximately $248
million. The proceeds were used to pay the outstanding balance on the
Partnership's credit facility and for working capital and other Partnership
purposes. The Notes were initially guaranteed by certain subsidiaries of the
Partnership. In connection with the refinancing of the Partnership's credit
facility on September 29, 1999, the Partnership's subsidiaries were released
from their guarantees of the credit facility. As a result, the subsidiary
guarantees under the Notes were also automatically released in accordance with
the terms of the Notes. At December 31, 1999, the unamortized Note liability
balance was approximately $249.3 million.
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<PAGE>
The Partnership may redeem the Notes at any time, upon not less than 30 and
not more than 60 days notice, at a price equal to 100% of the principal amount
of the Notes plus accrued interest to the redemption date (subject to the right
of holders of record on the relevant record date to receive interest due on an
interest payment date that is on or prior to the redemption date) plus a
Make-Whole Premium, if any (the "Redemption Price"). The Redemption Price would
never be less than 100% of the principal amount of the senior notes plus accrued
interest to the redemption date.
The amount of the Make-Whole Premium would be equal to the excess, if any,
of:
(1) the sum of the present values, calculated as of the redemption date, of:
(a) each interest payment that, but for such redemption, would have been
payable on the senior notes being redeemed on each interest payment
date occurring after the redemption date (excluding any accrued
interest for the period prior to the redemption date); and
(b) the principal amount that would have been payable at the final
maturity of the senior notes if they had not been redeemed;
over
(2) the principal amount of the senior notes being redeemed.
The present value of interest and principal payments referred to in clause
(1) above would be calculated by discounting the amount of each payment of
interest or principal from the date that the payment would have been payable,
but for the redemption, to the redemption date at a discount rate equal to the
Treasury Yield (as defined below) plus 25 basis points.
For purposes of determining the Make-Whole Premium, "Treasury Yield" means a
rate of interest per annum equal to the weekly average yield to maturity of
United States Treasury Notes that have a constant maturity that corresponds to
the remaining term to maturity of the Notes, calculated to the nearest 1/12th of
a year.
Senior Secured Notes
On September 23, 1992, under the terms of a Note Purchase Agreement,
Trailblazer Pipeline Company issued and sold an aggregate principal amount of
$101 million of Senior Secured Notes to a syndicate of fifteen insurance
companies. Security for the notes was provided principally by an assignment of
certain Trailblazer transportation contracts. Effective April 29, 1997, an
amendment to the Note Purchase Agreement was added. This amendment allowed
Trailblazer to include several additional transportation contracts as security
for the notes, added a limitation on the amount of additional money that
Trailblazer could borrow and relieved Trailblazer from the security deposit
obligation. At December 31, 1999, the outstanding balance under the Senior
Secured Notes was $30.3 million. The Senior Secured Notes have a fixed annual
interest rate of 8.03% and will be repaid in semiannual installments of $5.05
million from March 1, 2000 through September 1, 2002, the final maturity date.
Interest is payable semiannually in March and September. Under the terms of the
Note Purchase Agreement, Trailblazer partnership distributions are restricted by
certain financial covenants.
Capital Requirements for Recent Transactions
Plantation Pipe Line Company. On June 16, 1999, the Partnership acquired
27% of Plantation Pipe Line Company for $124.2 million. The Partnership
borrowed $125 million under its credit facilities.
Transmix Operations. On September 10, 1999, the Partnership acquired transmix
processing assets from Primary Corporation for approximately $30.3 million in
aggregate consideration consisting of 510,147 units and $16.0 million, of which
$15.7 million has been paid as of December 31, 1999.
Trailblazer Pipeline Company. Effective November 30, 1999, the Partnership
acquired 33 1/3% of Trailblazer Pipeline Company for $37.6 million, which the
Partnership borrowed under its credit facilities.
54
<PAGE>
Natural Gas Operations. Effective December 31, 1999, the Partnership acquired
certain net assets of KMI for approximately $736.5 million in aggregate
consideration consisting of $330 million and 9.81 million units. The
Partnership intends to repay the outstanding portion of the $330 million under
its credit facilities by March 31, 2000.
Year 2000
There was no interruption to any business operation because of any Year 2000
glitch in programming. All operations were running smoothly on January 1, 2000.
All business operations ran smoothly on January 3, 2000, when a full staff
returned to work, and have continued running without incident throughout the
year.
Other dates of concern, such as February 29, 2000, were addressed as part of
the Year 2000 program and have been remedied. The Partnership does not expect
any disruptions due to Year 2000 problems throughout the rest of the year. There
have been no incidents of consequence reported by material suppliers, customers
or service providers, and no disruption to business through any electronic
interface with third party companies.
Expenditures to handle the Year 2000 issue were less than the moneys
allocated and were not material. No further Year 2000 expenditures are planned.
The Partnership has contingency plans and emergency response plans to address
any unexpected incidents.
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. These forward looking statements are identified as any statement that
does not relate strictly to historical or current facts. They use words such as
"anticipate," "continue," "estimate," "expect," "may," "will," or other similar
words. These statements discuss future expectations or contain projections.
Specific factors which could cause actual results to differ from those in the
forward looking statements, include:
o price trends and overall demand for natural gas liquids, refined
petroleum products, carbon dioxide, natural gas, coal and other bulk
materials in the United States. Economic activity, weather,
alternative energy sources, conservation and technological advances
may affect price trends and demand;
o changes in the Partnership's tariff rates implemented by the Federal
Energy Regulatory Commission or the California Public Utilities
Commission;
o the Partnership's ability to integrate any acquired operations into
its existing operations;
o if railroads experience difficulties or delays in delivering products
to the bulk terminals;
o the Partnership's ability to successfully identify and close strategic
acquisitions and make cost saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical plants,
utilities, military bases or other businesses that use the
Partnership's services;
o the condition of the capital markets and equity markets in the United
States; and
o the political and economic stability of the oil producing nations of
the world.
See Items 1 and 2 "Business and Properties - Risk Factors" for a more
detailed description of these and other factors that may affect the forward
looking statements. When considering forward looking statements, one should keep
in mind the risk factors described in "Risk Factors" above. The risk factors
could cause the Partnership's actual results to differ materially from those
contained in any forward looking statement. The Partnership disclaims any
obligation to update the above list or to announce publicly the result of any
revisions to any of the forward looking statements to reflect future events or
developments.
55
<PAGE>
In addition, the Partnership's classification as a partnership for federal
income tax purposes means that the Partnership does not generally pay federal
income taxes on its net income. It does, however, pay taxes on the net income of
subsidiaries that are corporations. The Partnership is relying on a legal
opinion from its counsel, and not a ruling from the Internal Revenue Service, as
to its proper classification for federal income tax purposes. See Items 1 and 2
"Business and Properties - Tax Treatment of Publicly Traded Partnerships Under
the Internal Revenue Code."
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
The market risk inherent in the Partnership's market risk sensitive
instruments and positions is the potential change arising from increases or
decreases in interest rates as discussed below. Generally, the Partnership's
market risk sensitive instruments and positions are characterized as "other than
trading." The Partnership's exposure to market risk as discussed below includes
"forward-looking statements" and represents an estimate of possible changes in
fair value or future earnings that would occur assuming hypothetical future
movements in interest rates. The Partnership's views on market risk are not
necessarily indicative of actual results that may occur and do not represent the
maximum possible gains and losses that may occur, since actual gains and losses
will differ from those estimated, based on actual fluctuations in interest rates
and the timing of transactions.
The Partnership utilizes both variable rate and fixed rate debt in its
financing strategy. See Note 9 of the Notes to the Consolidated Financial
Statements of the Partnership included elsewhere in this report for additional
information related to the Partnership's debt instruments. For fixed rate debt,
changes in interest rates generally affect the fair value of the debt
instrument, but not the Partnership's earnings or cash flows. Conversely, for
variable rate debt, changes in interest rates generally do not impact the fair
value of the debt instrument, but may affect the Partnership's future earnings
and cash flows. The Partnership does not have an obligation to prepay fixed rate
debt prior to maturity and, as a result, interest rate risk and changes in fair
value should not have a significant impact on the fixed rate debt until the
Partnership would be required to refinance such debt.
As of December 31, 1999 and 1998, the carrying values of the Partnership's
long-term fixed-rate debt, was approximately $460.6 million and $244.0 million,
respectively, compared to fair values of $471.9 million and $278.3 million,
respectively. Fair values were determined using quoted market prices, where
applicable, or future cash flow discounted at market rates for similar types of
borrowing arrangements. A hypothetical 10% change in the average interest rates
applicable to such debt for 1999 and 1998, respectively, would result in changes
of approximately $15.0 million and $6.4 million, respectively, in the fair
values of these instruments.
As of December 31, 1999, the carrying value and fair value of the
Partnership's borrowings outstanding under its revolving credit facilities,
including accrued interest, was $208.7 million. Fair value was determined using
future cash flows discounted based on market rates for similar types of
borrowing arrangements. A hypothetical 10% change in the average interest rate
applicable to this debt would result in a change of approximately $20.8 million
in the Partnership's annualized pre-tax earnings. As of December 31, 1999 and
1998, the carrying value and fair value of the Partnership's variable-rate debt
was $737.7 million and $367.6 million, respectively.
As of December 31, 1999, the Partnership was party to interest rate swap
agreements with a notional principal amount of $200 million for the purpose of
hedging the interest rate risk associated with its variable-rate debt
obligations. A hypothetical 10% change in the average interest rates related to
these swaps would not have a material effect on the Partnership's annual pre-tax
earnings.
The Partnership monitors its mix of fixed- and variable-rate debt obligations
in light of changing market conditions and from time to time may alter that mix
by, for example, refinancing balances outstanding under its variable- rate
revolving credit facilities with fixed-rate debt or by entering into interest
rate swaps or other interest rate hedging agreements.
As of December 31, 1999, the Partnership's cash and investment portfolio did
not include fixed-income securities. Due to the short-term nature of the
Partnership's investment portfolio, a hypothetical 10% increase in interest
rates would not have a material effect on the fair market value of the
Partnership's portfolio. Since the Partnership has the ability to liquidate this
portfolio, it does not expect its operating results or cash flows to be
materially affected to any significant degree by the effect of a sudden change
in market interest rates on its investment portfolio.
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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.
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PART III
Item 10. Directors and Executive Officers of the Registrant
Directors and Executive Officers of the General Partner
As is commonly the case with publicly-traded limited partnerships, the
Partnership does not employ any of the persons responsible for managing or
operating the Partnership, but instead reimburses the general partner for its
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, Kinder Morgan, Inc. as the sole
shareholder of the general partner. All officers serve at the discretion of the
board of directors of the general partner.
Name Age Position with the General Partner
---- --- ---------------------------------
Richard D. Kinder 55 Director, Chairman and CEO
William V. Morgan 56 Director, Vice Chairman and President
Edward O. Gaylord 68 Director
Gary L. Hultquist 56 Director
William V. Allison 52 President, Natural Gas Pipeline Operations
Thomas A. Bannigan 46 President, Products Pipeline Operations
Dixon B. Betz 51 Chief Executive Officer, River Consulting, Inc.,
subsidiary
David G. Dehaemers, Jr. 39 Vice President, Corporate Development
Joseph Listengart 31 Vice President, General Counsel and Secretary
Michael C. Morgan 31 Vice President, Strategy and Investor Relations
C. Park Shaper 31 Vice President, Treasurer and Chief Financial
Officer
Thomas B. Stanley 49 President, Bulk Terminals
James E. Street 43 Vice President, Human Resources and
Administration
Richard D. Kinder was elected Director, Chairman and Chief Executive Officer
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 Director of the general partner in June 1994,
Vice Chairman of the general partner in February 1997 and President of the
general partner in November 1998. 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.
Edward O. Gaylord was elected Director of the general partner in February
1997. Mr. Gaylord is the Chairman of the Board of Directors of Jacintoport
Terminal Company, a liquid bulk storage terminal on the Houston, Texas ship
channel. Mr. Gaylord also serves as Chairman of the Board for EOTT Energy
Corporation, an oil trading and transportation company also located in Houston,
Texas. Mr. Gaylord is also a Director of Seneca Foods Corporation and Imperial
Sugar Company.
Gary L. Hultquist was elected Director of the general partner in October 1999.
Mr. Hultquist is the Managing Director of Hultquist Capital, LLC, a San
Francisco-based strategic and merger advisory firm. He also serves as Chairman
and Chief Executive Officer of TitaniumX Corporation, a supplier of
high-performance storage disk substrates and magnetic media to the disk drive
industry. He is also a member of the Board of Directors of Rodel, Inc.
Previously, Mr. Hultquist practiced law in two San Francisco area firms for over
15 years, specializing in business, intellectual property, securities and
venture capital litigation.
William V. Allison was elected President, Natural Gas Pipeline Operations
of the general partner in September 1999. He served as President, Pipeline
Operations of the general partner from February 1999 to September 1999. From
April 1998 to February 1999, he served as Vice President and General Counsel of
the general partner. From
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1977 to April 1998, Mr. Allison was employed at Enron Corp. where he held
various executive positions, including President of Enron Liquid Services
Corporation, Florida Gas Transmission Company and Houston Pipeline Company and
Vice President and Associate General Counsel of Enron Corp. Prior to joining
Enron Corp., he was an attorney at the FERC.
Thomas A. Bannigan was elected President, Products Pipeline Operations of the
general partner in October 1999. Since 1980, Mr. Bannigan has held various legal
and management positions in the energy industry, including General Counsel and
Secretary of Plantation Pipe Line Company, and from May 1998 until October 1999,
President and Chief Executive Officer of Plantation Pipe Line Company.
Dixon B. Betz founded River Consulting, Inc., a subsidiary of Kinder Morgan
Bulk Terminals, Inc., in 1981 and has since served as its Chief Executive
Officer. Mr. Betz received a Bachelor of Science degree in Mathematics from
Louisiana State University in 1971.
David G. Dehaemers, Jr. was elected Vice President, Corporate Development of
the general partner in January 2000. He was Treasurer of the general partner
from February 1997 to January 2000 and Vice President and Chief Financial
Officer of the general partner from July 1997 to January 2000. He served as
Secretary of the general partner from February 1997 to August 1997. From October
1992 to January 1997, he was Chief Financial Officer of Morgan Associates, Inc.,
an energy investment and pipeline management company. Mr. Dehaemers was
previously employed by the national CPA firms of Ernst & Whinney and Arthur
Young. He is a CPA, and received his undergraduate Accounting degree from
Creighton University in Omaha, Nebraska. Mr. Dehaemers received his law degree
from the University of Missouri-Kansas City and is a member of the Missouri Bar.
Joseph Listengart was elected Vice President and General Counsel of the
general partner in October 1999. Mr. Listengart became an employee of the
general partner in March 1998 and was elected its Secretary in November 1998.
From March 1995 through February 1998, Mr. Listengart worked as an attorney for
Hutchins, Wheeler & Dittmar, a Professional Corporation. Mr. Listengart received
his Juris Doctor, magna cum laude, from Boston University in May 1994, his
Masters in Business Administration from Boston University in January 1995 and
his Bachelors of Arts degree in Economics from Stanford University in June 1990.
Michael C. Morgan was elected Vice President, Strategy and Investor
Relations of the general partner in January 2000. He was Vice President,
Corporate Development of the general partner from February 1997 to January 2000.
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.
C. Park Shaper was elected Vice President, Treasurer and Chief Financial
Officer of the general partner in January 2000. Previously, Mr. Shaper was
President and Director of Altair Corporation, an enterprise focused on the
distribution of web-based investment research for the financial services
industry. He also served as Vice President and Chief Financial Officer of First
Data Analytics, a wholly-owned subsidiary of First Data Corporation, from 1997
until June 1999. From 1995 to 1997, he was a consultant with The Boston
Consulting Group. Mr. Shaper has prior experience with TeleCheck Services, Inc.
and as a management consultant with the Strategic Services Division of Andersen
Consulting. Mr. Shaper has a Bachelor of Science degree in Industrial
Engineering and a Bachelor of Arts degree in Quantitative Economics from
Stanford University. He also received a Master of Management degree from the
J.L. Kellogg Graduate School of Management at Northwestern University.
Thomas B. Stanley was elected President, Bulk Terminals of the general
partner in August 1998. From 1993 to July 1998, he was President of Hall-Buck
Marine, Inc. (now known as Kinder Morgan Bulk Terminals, Inc.), for which he has
worked since 1980. Mr. Stanley is a CPA with ten years' experience in public
accounting, banking, and insurance accounting prior to joining Hall-Buck. He
received his bachelor's degree from Louisiana State University in 1972.
James E. Street was elected Vice President, Human Resources and
Administration of the general partner in August 1999. From October 1996 to
August 1999, Mr. Street was Senior Vice President, Human Resources and
Administration for Coral Energy. Prior to joining Coral Energy, he was Vice
President, Human Resources of Enron
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Corp. from July 1989 to August 1992. Mr. Street received a Bachelor of Science
degree from the University of Nebraska at Kearney in 1979 and a Masters of
Business Administration degree from the University of Nebraska at Omaha in 1984.
Item 11. Executive Compensation
The Partnership has no executive officers, but is obligated to reimburse
the general partner for compensation paid to the general partner's executive
officers in connection with their operation of the Partnership's business. The
following table summarizes all compensation paid to the general partner's chief
executive officer and to each of the general partner's four other most highly
compensated executive officers for services rendered to the Partnership during
1999, 1998 and 1997.
Summary Compensation Table
<TABLE>
<CAPTION>
Annual Compensation Long-Term Compensation
Awards Payouts<F5>
--------------------------------------------------------------------------
Units Underlying All Other
Name and Principal Position Year Salary Bonus<F4> Options Compensation<F6>
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Richard D. Kinder<F1> 1999 $150,003 $ - - $ - $7,554
Director, Chairman and CEO 1998 200,004 - - - 13,584
1997 175,664 - - - 12,757
William V. Allison<F2> 1999 192,497 250,000 - - 9,335
President, Natural Gas Pipeline Operations 1998 99,998 200,000 10,000 - 11,366
1997 22,917 - - - -
David G. Dehaemers, Jr. 1999 161,249 250,000 - 3,753,868 7,408
Vice President, Corporate Development 1998 141,247 200,000 - - 34,393
1997 101,910 130,000 - - 7,598
Michael C. Morgan 1999 161,249 250,000 - 3,753,868 7,408
Vice President, Strategy and Investor 1998 141,247 200,000 - - 50,421
Relations 1997 101,910 130,000 - - 7,539
Dixon B. Betz<F3> 1999 250,000 75,000 - - 16,602
CEO, River Consulting, Inc., subsidiary 1998 125,000 152,000 5,000 - 6,200
<FN>
<F1> Effective October 1, 1999, Mr. Kinder's annual salary was reduced to $1.00. Mr. Kinder is not eligible
for annual bonuses or unit option grants.
<F2> Prior to the acquisition of the general partner by Kinder Morgan, Inc., Mr. Allison served as President
of the general partner from January 1, 1997 until February 14, 1997.
<F3> River Consulting, Inc., a subsidiary of Kinder Morgan Bulk Terminals, Inc., was acquired on July 1, 1998.
<F4> Amounts earned in year shown and paid the following year.
<F5> Represents amounts paid pursuant to the Partnership's Executive Compensation Plan. See "-Executive
Compensation Plan."
<F6> Represents the general partner's contributions to the Retirement Savings Plan (a 401(k) plan), the
imputed value of general partner-paid group term life insurance exceeding $50,000, and
compensation attributable to taxable moving and parking expenses allowed.
</FN>
</TABLE>
Retirement Savings Plan. Effective July 1, 1997, the general partner
established the Kinder Morgan Retirement Savings Plan, a defined contribution
401(k) plan, that permits all full-time employees of the general partner to
contribute 1% to 15% of base compensation, on a pre-tax or after-tax basis, into
participant accounts. In addition to a mandatory contribution equal to 4% of
base compensation per year for each plan participant, the general partner may
make discretionary contributions in years when specific performance objectives
are met. Any discretionary contributions are made during the first quarter
following the performance year. In March 2000, an additional 2% discretionary
contribution was made to individual accounts based on 1999 financial targets to
unitholders. All contributions, together with earnings thereon, are immediately
vested and not subject to forfeiture. Participants may direct the investment of
their contributions into a variety of investments. Plan assets are held and
distributed
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pursuant to a trust agreement. Because levels of future compensation,
participant contributions and investment yields cannot be reliably predicted
over the span of time contemplated by a plan of this nature, it is impractical
to estimate the annual benefits payable at retirement to the individuals listed
in the Summary Compensation Table above.
Executive Compensation Plan. Pursuant to the Partnership's Executive
Compensation Plan (the "Plan"), executive officers of the general partner are
eligible for awards equal to a percentage of the "Incentive Compensation Value",
which is defined as cash distributions to the general partner during the four
calendar quarters preceding the date of redemption times eight (less a
participant adjustment factor, if any). Under the Plan, no eligible employee may
receive a grant in excess of 2% and total awards under the Plan may not exceed
10%. In general, participants may redeem vested awards in whole or in part from
time to time by written notice. The Partnership may, at its option, pay the
participant in units (provided, however, the unitholders approve the plan prior
to issuing such units) or in cash. The Partnership may not issue more than
200,000 units in the aggregate under the Plan. Units will not be issued to a
participant unless such units have been listed for trading on the principal
securities exchange on which the units are then listed. The Plan terminates
January 1, 2007 and any unredeemed awards will be automatically redeemed. The
board of directors of the general partner may, however, terminate the Plan
before such date, and upon such early termination, the Partnership will redeem
all unpaid grants of compensation at an amount equal to the highest Incentive
Compensation Value, using as the determination date any day within the previous
twelve months, multiplied by 1.5. The Plan was established in July 1997 and on
July 1, 1997, the board of directors of the general partner granted awards
totaling 2% of the Incentive Compensation Value to each of Thomas King, David
Dehaemers and Michael Morgan. Originally, 50% of such awards were to vest on
each of January 1, 2000 and January 1, 2002. No awards were granted during 1998
and 1999.
All of Mr. King's awards were forfeited when he resigned as President of the
general partner on December 1, 1998. On January 4, 1999, the awards granted to
Mr. Dehaemers and Mr. Morgan were amended to provide for the immediate vesting
and pay-out of 50% of their awards, or 1% of the Incentive Compensation Value.
The board of directors of the general partner believes that accelerating the
vesting and pay-out of the awards was in the best interest of the Partnership
because it capped the total payment the participants were entitled to receive
with respect to 50% of their awards.
Unit Option Plan. Pursuant to the Partnership's unit Option Plan (the "Option
Plan") key personnel of the Partnership and its affiliates are eligible to
receive grants of options to acquire units. The total number of units available
under the plan is 250,000. None of the options granted under the Option Plan may
be "Incentive Stock Options" under Section 422 of the Internal Revenue Code. If
an option expires without being exercised, the number of units covered by such
option will be available for a future award. The exercise price for an option
may not be less than the fair market value of a unit on the date of grant.
Either the board of directors of the general partner or a committee of the board
of directors will administer the Option Plan. The Plan terminates on March 5,
2008.
No individual employee may be granted options for more than 10,000 units in
any year. The board of directors or the committee will determine the duration
and vesting of the options to employees at the time of grant. As of December 31,
1999, options for 211,200 units were granted to 100 employees of the general
partner. Forty percent of such options will vest on the first anniversary of the
date of grant and twenty percent on each anniversary, thereafter. The options
expire seven years from the date of grant.
The Option Plan also granted to each non-employee director of the Partnership
as of April 1, 1998, an option to acquire 5,000 units at an exercise price equal
to the fair market value of the units on such date. In addition, each new
non-employee director will receive options to acquire 5,000 units on the first
day of the month following his or her election. Under this provision, as of
December 31, 1999, options for 10,000 units were granted to two individuals.
Forty percent of such options will vest on the first anniversary of the date of
grant and twenty percent on each anniversary, thereafter. The non-employee
director options will expire seven years from the date of grant.
The following tables set forth certain information at December 31, 1999 and
for the fiscal year then ended with respect to unit options granted to and
exercised by the individuals named in the Summary Compensation Table above. Mr.
Allison and Mr. Betz were the only persons named in the Summary Compensation
Table that have been granted options. No options have been granted at an option
price below fair market value on the date of grant.
61
<PAGE>
Aggregated Option Exercises in 1999,
and 1999 Year-End Option Values
<TABLE>
<CAPTION>
Number of Units
Underlying Unexercised Value of Unexercised
Options at In-the-Money Options
Units Acquired Value 1999 Year-End at 1999 Year-End<F1>
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
William V. Allison - - 4,000 6,000 $33,250 $49,875
Dixon B. Betz - - 2,000 3,000 $16,625 $24,938
<FN>
<F1>Calculated on the basis of the fair market value of the underlying units at year-end, minus the exercise price.
</FN>
</TABLE>
KMI Option Plan. Under KMI's stock option plan, key personnel of KMI and its
affiliates, including employees of the general partner and the Partnership's
subsidiaries, are eligible to receive grants of options to acquire shares of
common stock of KMI. This option plan is administered by the Board of Directors
of KMI. The primary purpose for granting stock options under this plan to
employees of the general partner and the Partnership's subsidiaries is to
provide them with an incentive to increase the value of common stock of KMI. A
secondary purpose of the grants is to provide compensation to those employees
for services rendered to the Partnership and its subsidiaries.
As of December 31, 1999, the individuals named in the Summary Compensation
Table had the following options to acquire shares of KMI common stock.
Total Number of Options Number of Vested Options
Richard D. Kinder -- --
Dixon B. Betz 50,000 --
William V. Allison 250,000 --
David G. Dehaemers, Jr. 250,000 --
Michael C. Morgan 250,000 --
None of these options were granted with an exercise price below the fair
market value of the common stock on the date of grant. The options expire 10
years after the date of grant. Twenty five percent of the options vest on each
of the first four anniversaries after the date of grant.
Directors fees. During 1999, each member of the board of directors of the
general partner who was not also an employee of the general partner was paid an
annual retainer of $20,000 in lieu of all attendance fees.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table sets forth certain information as of March 9, 2000,
regarding the beneficial ownership of (i) the units and (ii) the common stock of
Kinder Morgan, Inc., the parent company of the general partner, by all directors
of the general partner, each of the named executive officers, all directors and
executive officers as a group and all persons known by the general partner to
own beneficially more than 5% of the units.
62
<PAGE>
Amount and Nature of Beneficial Ownership
Units(1) KMI Voting Stock
--------------------- ----------------------
Number Percent Number Percent
of Units(2) of Class of Shares(3) of Class
----------- -------- ------------ --------
Richard D. Kinder(4) 137,950 * 23,989,992 21.19%
William V. Morgan(5) 2,000 * 7,035,408 6.21%
Edward O. Gaylord(6) 18,000 * - -
Gary L. Hultquist 500 * 500 -
William V. Allison(7) 4,000 * - -
Dixon B. Betz(8) 100,714 * - -
David G. Dehaemers 2,000 * - -
Michael C. Morgan 1,000 * - -
James E. Street - * 4,500 -
Directors and Executive 332,329 * 31,031,400 27.41%
Officers as a group (13 persons)(9)
*Less than 1%
(1) All units involve sole voting power and sole investment power.
(2) As of March 9, 2000, the Partnership had 59,712,109 units issued and
outstanding.
(3) As of March 9, 2000, Kinder Morgan, Inc.("KMI") had a total of 113,207,568
shares of issued and outstanding voting stock.
(4) Includes 2,950 units owned by Mr. Kinder's spouse. Mr. Kinder disclaims
beneficial ownership of such units.
(5) The KMI shares are held by Morgan Associates, Inc., a Kansas corporation,
wholly owned by Mr. Morgan.
(6) Includes options to purchase 3,000 units exercisable within 60 days of
March 9, 2000.
(7) Includes options to purchase 4,000 units exercisable within 60 days of
March 9, 2000.
(8) Includes 26,090 units held by a trust for the benefit of Mr. Betz'
children, and also includes options to purchase 2,000 units exercisable
within 60 days of March 9, 2000.
(9) Includes options to purchase 16,000 units exercisable within 60 days
of March 9, 2000.
Item 13. Certain Relationships and Related Transactions
General and Administrative Expenses
The general partner provides the Partnership with general and administrative
services and is entitled to reimbursement of all direct and indirect costs
related to the business activities of the Partnership. The general partner
incurred general and administrative expenses of $30.7 million in 1999, $38.0
million in 1998 and $6.9 million in 1997.
The general partner shares administrative personnel with KMI to operate both
KMI's business and the business of the Partnership. As a result, the officers of
the general partner, who in some cases may also be officers of KMI, must
allocate, in their reasonable and sole discretion, the time the general
partner's employees spend on behalf of the Partnership and on behalf of KMI. For
2000, KMI will pay the general partner $1 million as reimbursement for the
services of the general partner's employees. Although management of the general
partner believes this amount to fairly reflect the value of the services to be
performed for KMI, the determination of this amount was not the result of arms
length negotiations. Due to the nature of the allocations, this reimbursement
may not exactly match the actual time and overhead spent. The general partner
and KMI will reevaluate the amount to be charged to KMI for the services
provided to KMI by the employees of the general partner.
Partnership Distributions
See Item 7. for information regarding Partnership Distributions.
63
<PAGE>
Natural Gas Operations
Effective December 31, 1999, the Partnership acquired the Natural Gas
Operations from Kinder Morgan, Inc. See Items 1. and 2. "Business
Properties--Recent Developments" and "--Natural Gas Operations" for more
information. In connection with this acquisition, as of December 31, 1999, the
Partnership had outstanding borrowings of $330 million under a note payable to
KMI. The borrowing was used to fund part of the acquisition of assets acquired
from KMI on December 31, 1999. Per the Closing Agreement entered into as of
January 20, 2000, the Partnership must pay KMI a per diem fee of $180.56 for
each $1,000,000 of unpaid principal. The Partnership paid a principal amount of
$200 million on January 21, 2000, and the Partnership plans to refinance the
remaining note principal by March 31, 2000. Included in the Partnership's
acquisition of the Natural Gas Operations was KMI's 33 1/3% interest in the
Trailblazer Pipeline Company, which KMI acquired in January 1998 for a price of
$11.3 million.
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.
64
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K
(a)(1) and (2) Financial Statements and Financial Statement
Schedules
See "Index to Financial Statements" set forth on page F-1.
(a)(3) Exhibits
*2.1 - Purchase Agreement dated October 18, 1997 between
Kinder Morgan Energy Partners, L.P., Kinder Morgan
G.P., Inc., Santa Fe Pacific Pipeline Partners, L.P.,
Santa Fe Pacific Pipelines, Inc. and SFP Pipeline
Holdings, Inc. (Exhibit 2 to the Partnership's
Registration Statement on Form S-4 (File No.
333-44519) filed February 4, 1998)
*2.2 - Master Agreement dated as of January 1, 1998 among
Shell Western E&P Inc., Shell Western Pipelines Inc.,
Shell Cortez Pipeline Company, Shell CO2 LLC, Shell
CO2 General LLC, Shell Land & Energy Company, Kinder
Morgan Operating L.P. "A" and Kinder Morgan CO2 LLC
(Exhibit 2.2 to the Partnership's Current Report on
Form 8-K filed March 18, 1998 (the "March 18, 1998
Form 8-K"))
*2.3 - First Amended and Restated Agreement of Limited Partnership dated
as of March 5, 1998, by and between Shell CO2 General LLC, Kinder
Morgan CO2, LLC and Shell CO2 LLC (Exhibit 2.3 to the March 18, 1998
Form
8-K)
2.4 - Amendment to the Limited Partnership Agreement of
Shell CO2 Company, Ltd. dated as of September 30, 1998
(filed as Exhibit 2.4 to the Partnership's 1998 Form
10-K)
*2.5 - Assumption and Indemnification Agreement dated as of
January 1, 1998 among Shell CO2 General LLC, Shell CO2
LLC, Shell Western E&P Inc., Shell Western Pipelines
Inc., Shell Cortez Pipeline Company, Shell Land &
Energy Company, Kinder Morgan CO2 LLC, Kinder Morgan
Operating L.P. "A" and Shell CO2 Company, Ltd.
(Exhibit 2.4 to the March 18, 1998 Form 8-K)
*2.6 - Guaranty and Indemnification Agreement dated as of
January 1, 1998 between Shell Western E&P Inc. and
Kinder Morgan Energy Partners, L.P. (Exhibit 2.5 to
the March 5, 1998 Form 8-K)
*2.7 - Contribution Agreement dated as of December 30, 1999, by and among
Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc.,
Kinder Morgan, Inc., Natural Gas Pipeline Company of America and KN
Gas Gathering, Inc. (filed as Exhibit 99.1 to the Partnership's
Current Report on Form 8-K filed January 14, 2000)
*3.1 - Second Amended and Restated Agreement of Limited
Partnership of Kinder Morgan Energy Partners, L.P.
effective as of February 14, 1997 (filed as Exhibit
3.1 to Amendment No. 1 to Kinder Morgan Energy
Partners, L.P. Registration Statement on Form S-4,
file No. 333-46709, filed on April 14, 1998)
*3.2 - Amendment No. 1 to Second Amended and Restated
Agreement of Limited Partnership of Kinder Morgan
Energy Partners, L.P. dated as of January 20, 2000
(filed as Exhibit 4.1 to the Partnership's Current
Report on Form 8-K filed January 20, 2000)
*4.1 - Specimen Certificate evidencing Common Units
representing Limited Partner Interests (filed as
Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy
Partners, L.P. Registration Statement on Form S-4,
file No. 333-44519, filed on February 4, 1998)
*4.2 - Indenture dated as of January 29, 1999 among Kinder
Morgan Energy Partners, L.P., the guarantors listed on
the signature page thereto and U.S. Trust Company of
Texas, N.A., as trustee, relating to Senior Debt
Securities (filed as Exhibit 4.1 to the Partnership's
Current Report on Form 8-K filed February 16, 1999
(the "February 16, 1999 Form 8-K"))
*4.3 - First Supplemental Indenture dated as of January 29,
1999 among Kinder Morgan Energy Partners, L.P., the
subsidiary guarantors listed on the signature page
thereto and U.S. Trust Company of Texas, N.A., as
trustee, relating to $250,000,000 of 6.30% Senior
Notes due February 1, 2009 (filed as Exhibit 4.2 to
the February 16, 1999 Form 8-K)
*4.4 - Second Supplemental Indenture dated as of September
30, 1999 among Kinder Morgan Energy Partners, L.P. and
U.S. Trust Company of Texas, N.A., as trustee,
relating to release of subsidiary guarantors under the
$250,000,000 of 6.30% Senior Notes due February 1,
2009
65
<PAGE>
(filed as Exhibit 4.4 to the Partnership's Form
10-Q for the quarter ended September 30, 1999 (the
"1999 Third Quarter Form 10-Q"))
4.5 - Certain instruments with respect to long-term debt of
the Partnership and its consolidated subsidiaries
which relate to debt that does not exceed 10% of the
total assets of the Partnership and its consolidated
subsidiaries are omitted pursuant to Item 601(b) (4)
(iii) (A) of Regulation S-K, 17 C.F.R. ss.229.601. The
Partnership hereby agrees to furnish supplementally to
the Securities and Exchange Commission a copy of each
such instrument upon request.
*10.1 - Kinder Morgan Energy Partners, L.P. Common Unit Option
Plan (filed as Exhibit 10.6 to the Partnership's 1997
Form 10-K)
*10.2 - Employment Agreement with William V. Morgan (filed as
Exhibit 10.1 to the Partnership's Form 10-Q for the
quarter ended March 31, 1997)
*10.3 - Kinder Morgan Energy Partners L.P. Executive
Compensation Plan (filed as Exhibit 10 to the
Partnership's Form 10-Q for the quarter ended June 30,
1997)
21.1 - List of Subsidiaries
23.1 - Consent of PricewaterhouseCoopers LLP
27.1 - Financial Data Schedule for Kinder Morgan Energy
Partners, L.P.
- ---------------------
* Asterisk indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith.
(b) Reports on Form 8-K
Report dated October 7, 1999, on Form 8-K was filed on October 22, 1999,
pursuant to Items 5 and 7 of that form. Pursuant to the Agreement and Plan of
Merger, the acquisition of Kinder Morgan, Inc., a Delaware corporation and sole
stockholder of Kinder Morgan G.P., Inc., by Kinder Morgan, Inc., a Kansas
corporation formerly known as K N Energy, Inc., was disclosed according to Item
5. Kinder Morgan G.P., Inc. is the general partner of the Partnership. An
exhibit of the associated press release was filed pursuant to Item 7.
66
<PAGE>
INDEX TO FINANCIAL STATEMENTS
Page
----
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Accountants F-2
Consolidated Statements of Income for the years ended
December 31, 1999, 1998, and 1997 F-3
Consolidated Balance Sheets for the years ended December 31, 1999
and 1998 F-4
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998, and 1997 F-5
Consolidated Statements of Partners' Capital for the years
ended December 31, 1999, 1998, and 1997 F-6
Notes to Consolidated Financial Statements F-7
Certain supplementary financial statement schedules have been omitted because
the information required to be set forth therein is either not applicable or is
shown in the financial statements or notes thereto.
F-1
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of
Kinder Morgan Energy Partners, L.P.
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of cash flows and of partners' capital
present fairly, in all material respects, the financial position of Kinder
Morgan Energy Partners, L.P. (a Delaware Limited Partnership) and subsidiaries
(the Partnership) at December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999 in conformity with accounting principles generally accepted in
the United States. These financial statements are the responsibility of the
Partnership's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States, which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas
March 10, 2000
F-2
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands Except Per Unit Amounts)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
------------- -------------- -------------
1999 1998 1997
------------- -------------- -------------
<S> <C> <C> <C>
Revenues $ 428,749 $ 322,617 $ 73,932
Costs and Expenses
Cost of products sold 16,241 5,860 7,154
Operations and maintenance 95,121 65,022 15,039
Fuel and power 31,745 22,385 5,636
Depreciation and amortization 46,469 36,557 10,067
General and administrative 35,612 39,984 8,862
Taxes, other than income taxes 16,154 12,140 2,943
------------- -------------- -------------
241,342 181,948 49,701
------------- -------------- -------------
Operating Income 187,407 140,669 24,231
Other Income (Expense)
Earnings from equity investments 42,918 25,732 5,724
Amortization of excess cost of equity investments (4,254) (764) -
Interest, net (52,605) (38,600) (12,078)
Other, net 14,085 (7,263) (701)
Gain on sale of equity interest net of special charges 10,063 - -
Minority Interest (2,891) (985) (179)
------------- -------------- -------------
Income Before Income Taxes and Extraordinary charge 194,723 118,789 16,997
Income Tax Benefit (Expense) (9,826) (1,572) 740
------------- -------------- -------------
Income Before Extraordinary charge 184,897 117,217 17,737
Extraordinary charge on early extinguishment of debt (2,595) (13,611) -
------------- -------------- -------------
Net Income $ 182,302 $ 103,606 $ 17,737
============= ============== =============
Calculation of Limited Partners' Interest in Net Income:
Income Before Extraordinary Charge $ 184,897 $ 117,217 $ 17,737
Less: General Partner's interest in Net Income (56,273) (33,447) (4,074)
------------- -------------- -------------
Limited Partners' Net Income before extraordinary charge 128,624 83,770 13,663
Less: Extraordinary charge on early extinguishment of debt (2,595) (13,611) -
============= ============== =============
Limited Partners' Net Income $ 126,029 $ 70,159 $ 13,663
============= ============== =============
Net Income per Unit before extraordinary charge $ 2.63 $ 2.09 $ 1.02
============= ============== =============
Extraordinary charge per Unit $ 0.06 $ 0.34 $ -
============= ============== =============
Net Income per Unit $ 2.57 $ 1.75 $ 1.02
============= ============== =============
Number of Units used in Computation 48,974 40,120 13,411
============= ============== =============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-3
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands)
<TABLE>
<CAPTION>
December 31,
------------------------------------
----------------- -----------------
1999 1998
----------------- -----------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 40,052 $ 31,735
Accounts and notes receivable 71,783 44,125
Inventories
Products 8,380 2,901
Materials and supplies 4,703 2,640
Other Current Assets 7,014 -
----------------- -----------------
131,932 81,401
----------------- -----------------
Property, Plant and Equipment, at cost 2,696,122 1,836,719
Less accumulated depreciation 117,809 73,333
----------------- -----------------
2,578,313 1,763,386
----------------- -----------------
Equity Investments 418,651 238,608
----------------- -----------------
Notes receivable 10,041 172
Intangibles 56,630 58,536
Deferred charges and other assets 33,171 10,169
================= =================
TOTAL ASSETS $ 3,228,738 $ 2,152,272
================= =================
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade $ 15,692 $ 11,690
Related parties 3,569 13,952
Current portion of long-term debt 209,200 -
Accrued rate refunds 36,607 -
Accrued interest 10,014 2,536
Accrued right-of-way liabilities 7,039 5,839
Accrued taxes 8,870 4,195
Accrued other liabilities 28,170 19,270
----------------- -----------------
319,161 57,482
----------------- -----------------
Long-Term Liabilities and Deferred Credits
Long-term debt 989,101 611,571
Other 97,379 104,789
----------------- -----------------
1,086,480 716,360
----------------- -----------------
Commitments and Contingencies
Minority Interest 48,299 17,767
----------------- -----------------
Partners' Capital
Common Units 1,759,142 1,348,591
General Partner 15,656 12,072
----------------- -----------------
1,774,798 1,360,663
----------------- -----------------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $ 3,228,738 $ 2,152,272
================= =================
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-4
<PAGE>
<TABLE>
<CAPTION>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended December 31,
-----------------------------------------------------
---------------- ---------------- -------------
1999 1998 1997
---------------- ---------------- -------------
<S> <C> <C> <C>
Cash Flows From Operating Activities
Reconciliation of net income to net cash provided by operating activities
Net income $ 182,302 $ 103,606 $ 17,737
Extraordinary charge on early extinguishment of debt 2,595 13,611 -
Depreciation and amortization 46,469 36,557 10,067
Amortization of excess cost of equity investments 4,254 764 -
Earnings from equity investments (42,918) (25,732) (5,724)
Distributions from equity investments 33,686 19,670 9,588
Gain on sale of equity interest net of special charges (10,063) - -
Changes in components of working capital
Accounts receivable (12,358) 1,203 3,791
Inventories (2,817) (734) (902)
Accounts payable (9,515) 197 (5,102)
Accrued liabilities 11,106 (14,115) 2,774
Accrued taxes 497 (1,266) 557
El Paso Settlement - (8,000) -
Other, net (20,382) 8,220 (834)
---------------- ---------------- -------------
Net Cash Provided by Operating Activities 182,856 133,981 31,952
---------------- ---------------- -------------
Cash Flows From Investing Activities
Acquisitions of assets 5,678 (107,144) (20,038)
Additions to property, plant and equipment for
expansion and maintenance projects (82,725) (38,407) (6,884)
Sale of investments, property, plant and equipment 43,084 64 162
Acquisitions of equity investments (161,763) (135,000) -
Contributions to equity investments (800) (1,234) (3,532)
---------------- ---------------- -------------
Net Cash Used in Investing Activities (196,526) (281,721) (30,292)
---------------- ---------------- -------------
Cash Flows From Financing Activities
Issuance of debt 550,287 492,612 43,400
Payment of debt (333,971) (407,797) (58,496)
Long-term debt - refinancing / issue costs (3,569) (16,768) -
Proceeds from issuance of common units 68 212,303 33,678
Contributions from General Partner's Minority Interest 146 12,349 -
Distributions to partners
Common Units (135,835) (93,352) (21,768)
General Partner (52,674) (27,450) (2,280)
Minority Interest (2,316) (1,614) (245)
Other, net (149) (420) (636)
---------------- ---------------- -------------
Net Cash Provided by (Used in) Financing Activities 21,987 169,863 (6,347)
---------------- ---------------- -------------
Increase (Decrease) in Cash and Cash Equivalents 8,317 22,123 (4,687)
Cash and Cash Equivalents, Beginning of Period 31,735 9,612 14,299
================ ================ =============
Cash and Cash Equivalents, End of Period $ 40,052 $ 31,735 $ 9,612
================ ================ =============
Noncash Investing and Financing Activities
Contribution of net assets to partnership investments $ 20 $ 60,387 $ -
Assets acquired by the issuance of Common Units $ 420,850 $ 1,003,202 $ -
Assets acquired by the assumption of liabilities $ 111,509 $ 569,822 $ -
Supplemental disclosures of cash flow information
Cash paid during the year for
Interest (net of capitalized interest) $ 48,222 $ 47,616 $ 12,611
Income Taxes $ 529 $ 1,354 $ 463
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-5
<PAGE>
<TABLE>
<CAPTION>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(In Thousands)
Deferred Total
Common Participation General Partners'
Units Units Partner Capital
-------------- --------------- -------------- ---------------
<S> <C> <C> <C> <C>
Partners' capital at December 31, 1996 $ 101,000 $ 16,165 $ 1,179 $ 118,344
Net income 13,440 223 4,074 17,737
Transfer of deferred
participation units 16,388 (16,388) - -
Net proceeds from issuance
of common units 33,678 - - 33,678
Capital contributions - - 345 345
Distributions (17,666) - (2,214) (19,880)
-------------- --------------- -------------- ---------------
Partners' capital at December 31, 1997 146,840 - 3,384 150,224
Net income 70,159 - 33,447 103,606
Net proceeds from issuance
of common units 1,212,421 - - 1,212,421
Capital contributions 10,234 - 2,678 12,912
Distributions (91,063) - (27,437) (118,500)
-------------- --------------- -------------- ---------------
Partners' capital at December 31, 1998 1,348,591 - 12,072 1,360,663
Net income 126,029 - 56,273 182,302
Net proceeds from issuance
of common units 420,357 - (15) 420,342
Distributions (135,835) - (52,674) (188,509)
-------------- --------------- -------------- ---------------
Partners' capital at December 31, 1999 $ 1,759,142 $ - $ 15,656 $ 1,774,798
============== =============== ============== ===============
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
F-6
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
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. 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).
Merger of KMI
On October 7, 1999, KMI completed a merger with K N Energy, Inc., a Kansas
corporation, providing integrated energy services including the gathering,
processing, transportation and storage of natural gas, marketing of natural gas
and natural gas liquids and electric power generation and sales. The combined
entity was renamed Kinder Morgan, Inc. and trades under the New York Stock
Exchange symbol "KMI". KMI remains the sole stockholder of the general partner.
General
The Partnership is a publicly traded Master Limited Partnership that
manages a diversified portfolio of midstream energy assets. It trades under the
New York Stock Exchange symbol "KMP" and conducts business through four
operating limited partnerships, OLP-A, OLP-B, Kinder Morgan Operating L.P. "C"
("OLP-C") and Kinder Morgan Operating L.P. "D" ("OLP-D") (collectively, the
"operating partnerships"). Kinder Morgan Bulk Terminals, Inc. (formerly
Hall-Buck Marine, Inc.) and its consolidated subsidiaries are owned and
controlled by OLP-C. OLP-D owns 99.5% of and controls SFPP, L.P. ("SFPP").
Kinder Morgan G.P., Inc. is a wholly owned subsidiary of KMI and serves as the
sole general partner of the Partnership and the operating partnerships. The
Partnership and the operating partnerships are governed by Amended and Restated
Agreements of Limited Partnership and certain other agreements (collectively,
the "partnership agreements").
Prior to 1998, the Partnership reported three business segments: Liquids
Pipelines; Coal Transfer, Storage and Services; and Gas Processing and
Fractionation. Due to acquisitions made in 1998, the Partnership reevaluated and
began reporting the following three business segments: Pacific Operations;
Mid-Continent Operations; and Bulk Terminals. For the period 1997, the previous
Liquids Pipelines and Gas Processing and Fractionation segments have been
combined to present the current Mid-Continent Operations segment and the Coal
Transfer, Storage and Services segment has been reclassified as the Bulk
Terminals segment. Finally, due to the acquisition of certain assets from KMI
(see note 3), effective December 31, 1999, the Partnership now competes in a
fourth reportable business segment: Natural Gas Operations.
The "Pacific Operations" include four common carrier refined petroleum
products pipelines covering approximately 3,300 miles and transporting over one
million barrels per day of refined petroleum products such as gasoline, diesel
and jet fuel. The Pacific Operations also include 13 truck loading terminals.
These operations serve approximately 44 customer-owned terminals, three
commercial airports and 12 military bases in six western states.
The "Mid-Continent Operations" include two interstate common carrier natural
gas liquids ("NGL" or "NGLs") pipelines ("North System" and "Cypress Pipeline"),
a 51% equity interest in Plantation Pipe Line Company, a 20% equity interest in
Shell CO2 Company, transmix processing and supply operations and a gas
processing plant ("Painter Plant"). The North System includes a 1,600 mile
common carrier pipeline that transports, stores and delivers a full range of
NGLs and refined petroleum 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. Additionally, the North System has eight truck
loading terminals, which primarily deliver propane throughout the upper Midwest.
The Cypress Pipeline is a 100 mile pipeline that transports ethane from Mont
Belvieu, Texas, to the Lake Charles,
F-7
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KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Louisiana area. Plantation Pipe Line Company owns and operates a 3,100 mile
common carrier refined petroleum products pipeline serving the southeastern
United States. Shell CO2 Company produces, markets and delivers CO2 for enhanced
oil recovery operations in the continental United States. The transmix
operations include the supplying, trading and refining of petroleum pipeline
transmix. Included in these operations are two transmix processing plants, one
located in Richmond, Virginia and the other in Dorsey Junction, Maryland. BP
Amoco operates the Painter Plant assets under an operating lease agreement.
The "Natural Gas Operations" segment consists of a one-third interest in
Trailblazer Pipeline Company ("Trailblazer") purchased on November 30, 1999 and
over $700 million of assets acquired by the Partnership from KMI, effective
December 31, 1999. Included in the purchase were the Kinder Morgan Interstate
Gas Transmission LLC ("KMIGT", formerly K N Interstate Gas Transmission Co.), an
additional one-third interest in Trailblazer and a 49% equity interest in the
Red Cedar Gathering Company ("Red Cedar"). The acquired interest in Trailblazer,
when combined with the one-third interest purchased on November 30, 1999, gave
the Partnership a controlling two-thirds ownership interest. Going forward from
December 31, 1999, the three businesses will comprise the Partnership's Natural
Gas Operations.
The "Bulk Terminals" segment consists of over 20 bulk terminals that handle
approximately 40 million tons of coal, petroleum coke and other products
annually. The Partnership itself, or through Kinder Morgan Bulk Terminals, Inc.,
owns or operates these bulk terminals, which are located primarily on the
Mississippi River and the West Coast. The Pier IX Terminal, a coal and cement
handling facility located on a 30-acre site in Newport News, Virginia, has the
capacity to transload approximately 12 million tons of coal annually. The
Shipyard River Terminal, located on a 52-acre site in Charleston, South
Carolina, is an import-export dry and liquid bulk product handling facility,
which can transload coal, asphalt, fertilizer and other aggregates. The segment
also includes two modern high speed rail-to barge coal transfer, storage and
loading facilities ("Cora Terminal" and "Grand Rivers Terminal"). The Cora
Terminal is located on the banks of the Mississippi River near Cora, Illinois
and the Grand Rivers Terminal is located on the banks of the Tennessee River
near Paducah, Kentucky. River Consulting, Inc., a major engineering and
construction management company specializing in designing and construction
services for dry bulk material handling terminals is also included in the Bulk
Terminals segment.
Two-for-one Common Unit Split
On September 2, 1997, the Partnership's general partner approved a two-for-one
unit split of the Partnership's outstanding units representing limited partner
interests in the Partnership. All references to the number of units and per unit
amounts in the consolidated financial statements and related notes have been
restated to reflect the effect of the split for all periods presented.
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 and controlled
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.
F-8
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Inventories
Inventories of products consist of natural gas liquids, refined petroleum
products, natural gas and coal. These assets 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 lives. Generally, composite depreciation rates are applied
to functional groups of property having similar economic characteristics and
range from 2.0% 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.
The Partnership evaluates impairment of its property, plant and equipment in
accordance with 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." The Partnership reviews for the impairment of long-lived assets
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. An impairment loss would be recognized when
estimated future cash flows expected to result from the use of the asset and its
eventual disposition is less than its carrying amount.
Equity Method of Accounting
Investments in greater than 20% owned affiliates, which the Partnership does
not control, are accounted for by the equity method of accounting, whereby the
investment is carried at cost of acquisition, plus the Partnership's equity in
undistributed earnings or losses since acquisition.
Excess of Cost Over Fair Value
The excess of the Partnership's cost over its underlying net asset book value
in investments is being amortized using the straight-line method over the
estimated remaining life of the assets. Amortization of this excess for
undervalued depreciable assets is recorded over a period not to exceed 50 years
and for intangible assets is recorded over a period not to exceed 40 years.
Amortization of excess cost on investments in consolidated affiliates is
reflected as amortization expense; amortization of excess cost on investments
accounted for under the equity method is reflected as amortization of excess
cost of equity investments. The total unamortized excess cost over fair value of
net assets on investments in consolidated affiliates (goodwill) was
approximately $48.6 million and $50.3 million as of December 31, 1999 and 1998,
respectively, and such amounts are included within intangibles on the
accompanying balance sheet. The total unamortized excess cost over underlying
book value of net assets on investments accounted for under the equity method
was approximately $273.5 million and $112.0 million as of December 31, 1999 and
1998, respectively, and such amounts are included within equity investments on
the accompanying balance sheet.
The Partnership periodically evaluates the propriety of the carrying amount of
the excess of cost over fair value of net assets of businesses acquired, as well
as the amortization period, to determine whether current events or circumstances
warrant adjustments to the carrying value and/or revised estimates of useful
lives. At this time, the Partnership believes no such impairment has occurred
and no reduction in estimated useful lives is warranted.
Revenue Recognition
Revenues for the pipeline operations are recognized based on delivery of
actual volume transported or minimum obligations under take-or-pay contracts.
Bulk terminal transfer service revenues are recognized based on volumes loaded.
Recognition of transmix processing revenues is based on volumes processed or
sold. Revenues from energy related product sales of the Red Lightning energy
services unit are based on delivered quantities of product.
F-9
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Matters
Environmental expenditures that relate to current operations are expensed or
capitalized as appropriate. Expenditures that relate to an existing condition
caused by past operations, and which do not contribute to current or future
revenue generation, are expensed. Liabilities are not discounted to net present
value and are recorded when environmental assessments and/or remedial efforts
are probable and the costs can be reasonably estimated. Generally, the timing of
these accruals coincides with the completion of a feasibility study or the
Partnership's commitment to a formal plan of action.
Minority Interest
Minority interest consists of the approximate 1% general partner interest in
the operating partnerships, the 0.5% special limited partner interest in SFPP,
L.P., the 33 1/3% interest in Trailblazer Pipeline Company, owned 66 2/3% and
controlled by OLP-A and the 50% interest in Globalplex Partners, a Louisiana
joint venture owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.
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 or loss of the Partnership. 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.
The tax attributes of the Partnership's net assets flow directly to each
individual partner. Individual partners will have different investment bases
depending upon the timing and prices of acquisition of partnership units.
Further, each partner's tax accounting, which is partially dependent upon the
partner's individual tax position, may differ from the accounting followed in
the financial statements. Accordingly, there could be significant differences
between each individual partner's tax basis and the partner's proportionate
share of the net assets reported in the financial statements. SFAS No. 109
requires disclosure by a publicly held partnership of the aggregate difference
in the basis of its net assets for financial and tax reporting purposes.
However, the Partnership does not have access to information about each
individual partner's tax attributes in the Partnership, and the aggregate tax
bases cannot be readily determined. In any event, management does not believe
that, in the Partnership's circumstances, the aggregate difference would be
meaningful information.
Net Income Per Unit
Net Income per unit was computed by dividing limited partner's interest in net
income by the weighted average number of units outstanding during the period.
3. Acquisitions and Joint Ventures
With respect to the following acquisitions and joint ventures, the results of
operations are included in the consolidated financial statements from the
effective date of acquisition.
Santa Fe
Kinder Morgan Operating L.P. "D" ("OLP-D"), a Delaware limited partnership,
acquired on March 6, 1998, 99.5% of SFPP, L.P. ("SFPP"), the operating
partnership of Santa Fe Pacific Pipeline Partners, L.P. ("Santa Fe"). The
transaction was accounted for under the purchase method of accounting and was
valued at more than $1.4 billion inclusive of liabilities assumed. The
Partnership acquired the interest of Santa Fe's common unitholders in SFPP in
exchange for approximately 26.6 million units (1.39 units of the Partnership for
each Santa Fe common unit). The Partnership paid $84.4 million to Santa Fe
Pacific Pipelines, Inc. (the "former SF General Partner") in exchange for the
general partner interest in Santa Fe. The $84.4 million was borrowed under the
Partnership's credit facility. Also on March 6, 1998, SFPP redeemed from the
former SF General Partner a 0.5% interest in SFPP for $5.8 million. The
redemption was paid from SFPP's cash reserves. After the redemption, the former
SF General Partner continues to own a .5% special limited partner interest in
SFPP.
F-10
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Assets acquired in this transaction comprise the Partnership's Pacific
Operations, which include over 3,300 miles of pipeline and thirteen owned and
operated terminals.
Shell CO2 Company
On March 5, 1998, the Partnership and affiliates of Shell Oil Company
("Shell") agreed to combine their CO2 activities and assets into a partnership,
Shell CO2 Company, Ltd. ("Shell CO2 Company"), to be operated by a Shell
affiliate. The Partnership acquired, through a newly created limited liability
company, a 20% interest in Shell CO2 Company in exchange for contributing the
Central Basin Pipeline and approximately $25 million in cash. The $25 million
was borrowed under the Partnership's credit facility. The Partnership accounts
for its partnership interest in Shell CO2 Company under the equity method. The
investment is included as part of the Mid-Continent Operations.
Under the terms of the Shell CO2 Company partnership agreement, the
Partnership will receive a priority distribution of $14.5 million per year
during 1998 through 2001. To the extent the amount paid to the Partnership over
this period is in excess of the Partnership's percentage share (currently 20%)
of Shell CO2 Company's distributable cash flow for such period (discounted at
10%), Shell will receive a priority distribution in equal amounts of such
overpayment during 2002 and 2003.
Hall-Buck Marine, Inc.
Effective July 1, 1998, the Partnership acquired Hall-Buck Marine, Inc.
("Hall-Buck") for approximately $100 million. The transaction was accounted for
under the purchase method of accounting. Hall-Buck, headquartered in Sorrento,
Louisiana, is one of the nation's largest independent operators of dry bulk
terminals, operating over twenty terminals on the Mississippi River, the Ohio
River, and the Pacific Coast. In addition, Hall-Buck owns all of the common
stock of River Consulting Incorporated, a nationally recognized leader in the
design and construction of bulk material facilities and port related structures.
The $100 million of consideration consisted of approximately 2.1 million
units and assumed indebtedness of $23 million. After the acquisition, the
Partnership changed the name of Hall-Buck Marine, Inc. to Kinder Morgan Bulk
Terminals, Inc. and accounts for its activity as part of the Bulk Terminals
business segment.
Plantation Pipe Line Company
On September 15, 1998, OLP-A acquired a 24% interest in Plantation Pipe Line
Company for $110 million. On June 16, 1999, OLP-D acquired Chevron's approximate
27% interest in Plantation Pipe Line Company for $124.2 million. As a result of
this second investment, the Partnership now owns approximately 51% of Plantation
Pipe Line Company, and Exxon Pipeline Company, an affiliate of ExxonMobil
Corporation, owns approximately 49%. Plantation Pipe Line Company owns and
operates a 3,100 mile pipeline system throughout the southeastern United States
which serves as a common carrier of refined petroleum products to various
metropolitan areas, including Atlanta, Georgia; Charlotte, North Carolina; and
the Washington, D.C. area. The Partnership does not control Plantation Pipe Line
Company, and therefore, accounts for its investment in Plantation under the
equity method of accounting and includes its activity as part of the
Mid-Continent Operations.
Transmix Operations
On September 10, 1999, the Partnership acquired certain net assets, including
transmix processing plants in Richmond, Virginia and Dorsey Junction, Maryland,
from Primary Corporation. As consideration for the sale, the Partnership paid
Primary $18.25 million (before purchase price adjustments) and 510,147 units
valued at approximately $14.3 million. The processing plants are strategically
positioned to service transmix requirements along the Atlantic Coast from the
Gulf Coast refineries to the distribution terminals in the New York harbor. Both
the petroleum products refining and marketing activities of the transmix
operations are included as part of the Mid-Continent Operations.
Trailblazer Pipeline Company
Effective November 30, 1999, the Partnership acquired a 33 1/3% interest in
Trailblazer Pipeline Company for $37.6 million from Columbia Gulf Transmission
Company, an affiliate of Columbia Energy Group. Trailblazer
F-11
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pipeline Company is an Illinois partnership that owns and operates a 436-mile
natural gas pipeline system that traverses from Colorado through southeastern
Wyoming to Beatrice, Nebraska. Trailblazer has a certificated capacity of 492
million cubic feet per day ("MMcf/d") of natural gas. For the month of December
1999, the Partnership accounted for its 33 1/3% interest in Trailblazer Pipeline
Company under the equity method of accounting and included its activity as part
of the Mid-Continent Operations. Effective December 31, 1999, following the
Partnership's acquisition of a second 33 1/3% interest in Trailblazer,
Trailblazer's activities became part of the newly formed Natural Gas Operations
business segment.
KMI Asset Contributions
Effective December 31, 1999, the Partnership acquired over $700 million of
assets from KMI. The Partnership paid KMI $330 million and 9.81 million common
units as consideration for the assets. The Partnership purchased Kinder Morgan
Interstate Gas Transmission LLC ("KMIGT", formerly K N Interstate Gas
Transmission Co.), a 33 1/3% interest in Trailblazer Pipeline Company and a 49%
equity interest in the Red Cedar Gathering Company. The acquired interest in
Trailblazer, when combined with the interest purchased on November 30, 1999,
gave the Partnership a 66 2/3% controlling ownership interest. The transaction
was accounted for under the purchase method of accounting, and going forward
from December 31, 1999, the three businesses will comprise the Partnership's
Natural Gas Operations.
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the twelve months ended December 31, 1999 and 1998, assumes the
Partnership's acquisition of SFPP, its interest in Shell CO2 Company, Hall-Buck,
its interest in Plantation Pipe Line Company, net assets from Primary
Corporation, KMIGT, its controlling interest in Trailblazer and its interest in
Red Cedar Gathering Company, had occurred as of January 1, 1998. The unaudited
Pro Forma financial results have been prepared for comparative purposes only and
may not be indicative of the results that would have occurred if the Partnership
had acquired SFPP, its interest in Shell CO2 Company, Hall-Buck, its interest in
Plantation Pipe Line Company, net assets from Primary Corporation, KMIGT, its
controlling interest in Trailblazer and its interest in Red Cedar Gathering
Company on the dates indicated or which will be attained in the future.
Amounts presented below are in thousands, except for per unit amounts:
Pro Forma
Twelve Months Ended
December 31,
Income Statement 1999 1998
---------------- -------------------
(Unaudited)
Revenues $597,921 $590,055
Operating Income 250,404 241,787
Net Income before extraordinary
charge 233,384 202,157
Net Income 230,789 188,450
Net Income per unit before
extraordinary charge $2.61 $2.63
Net Income per unit $2.56 $2.39
Other Acquisitions
Cardlock Fuels System, Inc.
On August 26, 1998, the Partnership signed a series of definitive agreements
to form a joint venture with Cardlock Fuels System, Inc ("CFS"), an affiliate of
Southern Counties Oil Co., for the purpose of constructing unattended, automated
fueling stations adjacent to the Partnership's terminal facilities within its
Pacific Operations. The Partnership agreed to provide the terminal sites, and
CFS agreed to contribute its unattended, automated fueling station expertise
including marketing and electronic transaction processing services. At February
29, 2000, the joint venture had completed site construction and commenced
operations at the Pacific Operations' Reno, Fresno and Phoenix terminals. Three
additional sites at the Bradshaw, Colton and San Jose terminals have scheduled
completion dates by the end of the second quarter of 2000.
F-12
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Acquisitions Subsequent to December 31, 1999
On February 7, 2000, the Partnership announced that it had acquired all shares
of the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal,
Inc., both Wisconsin corporations. The effective date of the acquisitions was
January 1, 2000. The Partnership paid an aggregate consideration of
approximately $24.1 million, including 574,172 units. The acquisition of the two
entities was accounted for under the purchase method of accounting and the
Partnership will include their activities as part of the Bulk Terminals business
segment.
On March 9, 2000, the Partnership announced it had reached a definitive
agreement to increase its interest in Shell CO2 Company to 100%. The Partnership
will acquire the remaining 78% limited partner interest and the 2% general
partner interest in Shell CO2 Company from affiliates of Shell Exploration &
Production Company. The transaction price is $185.5 million, and the closing of
the transaction is expected to occur around April 1, 2000. After the closing,
the Partnership will rename Shell CO2 Company "Kinder Morgan CO2 Company."
4. Gain on Sale of Equity Interest net of Special Charges
During the third quarter of 1999, the Partnership completed its previously
announced sale of its partnership interest in the Mont Belvieu fractionation
facility for approximately $41.8 million. The Partnership recognized a gain of
$14.1 million on the sale. Offsetting the gain amount were charges of
approximately $3.6 million relating to the write-off of abandoned project costs,
primarily within the Pacific Operations, and a charge of $0.4 million relating
to prior years' over-billed storage tank lease fees within the Partnership's
Mid-Continent Operations.
5. Income Taxes
Certain operations of the Partnership are conducted through wholly-owned
corporate subsidiaries that are subject to income tax. Income/(loss) before
income tax expense attributable to corporate operations was $(1.9) million,
$(1.3) million and $2.5 million for the years ended December 31, 1999, 1998, and
1997, respectively. For the periods ended December 31, 1999, 1998, and 1997,
respectively, the provision for income taxes consists of deferred income tax of
$0.6 million, $0.0 million, and $(1.1) million, respectively, and current income
tax of $9.2 million, $1.6 million and $0.3 million, respectively. The 1999 and
1998 income tax provisions include $8.5 million and $1.7 million, respectively,
attributable to the Partnership's share of Plantation Pipe Line Company's income
taxes. The net deferred tax liability of $1.5 million and $0.5 million at
December 31, 1999 and 1998, respectively, consists of deferred tax liabilities
of $4.0 million and $1.3 million, respectively, and deferred tax assets of $2.5
million and $0.8 million, respectively.
Reconciling items between income tax expense computed at the statutory rate
and actual income tax expense primarily include for the year ended: December 31,
1999, intercompany income and expense items eliminated in the consolidation of
the Partnership, amortization of certain intangibles and inclusion of the
Partnership's share of income tax expense from Plantation Pipe Line Company;
December 31, 1998, intercompany income and expense items eliminated in the
consolidation of the Partnership, amortization of certain intangibles, a change
in estimate of prior years' provision, former Hall-Buck Marine, Inc. employees'
exercise of stock options prior to acquisition by the Partnership and inclusion
of the Partnership's share of income tax expense from Plantation Pipe Line
Company; and December 31, 1997, the effect of a change in estimate of prior
years' provision, a partial liquidating distribution and state income taxes.
6. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
December 31,
------------------------
1999 1998
---------- -----------
Gas and liquid pipelines $1,729,034 $ 941,313
Liquids pipeline station equipment 550,044 537,913
Coal and bulk tonnage transfer,
storage and services 107,052 94,686
Gas and transmix processing 45,232 13,984
Land 72,259 72,259
Land right-of-way 93,909 93,898
F-13
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Construction work in process 38,653 27,405
Other 59,939 55,261
Total Cost 2,696,122 1,836,719
Accumulated Depreciation and
Amortization (117,809) (73,333)
----------- ------------
$2,578,313 $ 1,763,386
=========== ============
7. Equity Investments
The Partnership's significant equity investments at December 31, 1999
consisted of Plantation Pipe Line Company (51%), Red Cedar Gathering Company
(49%), Shell CO2 Company (20%), Colton Transmix Processing Facility (50%) and
Heartland Pipeline Company (50%). The Partnership had an equity investment in
Trailblazer Pipeline Company (33 1/3%) for one month of 1999 (see note 3). The
Partnership sold its interest in Mont Belvieu Associates during the third
quarter of 1999 (see note 4). Total equity investments consisted of the
following (in thousands):
December 31,
------------------------
1999 1998
---------- -----------
Plantation Pipe Line Company $229,349 $109,401
Red Cedar Gathering Company 88,249 -
Shell CO2 Company 86,675 86,688
Colton Transmix Processing Facility 5,263 5,187
Heartland Pipeline Company 4,818 4,348
Mont Belvieu Associates - 27,568
All Others 4,297 5,416
-------- --------
Total $418,651 $238,608
======== ========
The Partnership's earnings from equity investments was as follows (in
thousands):
1999 1998 1997
----- ---- ----
Plantation Pipe Line Company $22,510 $ 4,421 $ -
Shell CO2 Company 14,500 14,500 -
Mont Belvieu Associates 2,500 4,577 5,009
Heartland Pipeline Company 1,571 1,394 715
Colton Transmix Processing
Facility 1,531 803 -
Trailblazer Pipeline Company 284 - -
All Others 22 37 -
------- ------- ------
Total $42,918 $25,732 $5,724
======= ======= ======
Amortization of excess cost $(4,254) $ (764) -
======= ======= ======
Summarized combined unaudited financial information for the Partnership's
significant equity investments is reported below (in thousands):
Income Statement 1999 1998 1997
---------------- ----- ---- ----
Revenues $344,017 $287,158 $198,960
Costs and expenses 244,515 188,555 147,777
Earnings before extraordinary
items 99,502 98,603 51,183
Net income 99,502 96,609 51,183
December 31,
------------------------
Balance Sheet 1999 1998
------------- ---------- -----------
Current assets $137,828 $132,855
Non-current Assets 450,791 442,954
Current liabilities 64,333 61,160
Non-current liabilities 289,671 264,974
Partners'/Owners' equity 234,615 249,675
F-14
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. Gas Processing and Fractionation Transactions
Gas Processing and Terminal Lease to BP Amoco
On February 14, 1997, the Partnership executed an operating lease agreement
with Amoco Oil Company ("Amoco", a unit of BP Amoco) for Amoco's use of the
Painter Plant fractionator and the Partnership's Millis Terminal and Storage
Facility with the nearby BP Amoco Painter Complex Gas Plant. The lease generated
$1.0 million of cash flow in each of the years 1999, 1998 and 1997.
9. Debt
The Partnership's debt facilities consist of:
o a $300 million unsecured five-year credit facility;
o a $300 million unsecured 364-day credit facility;
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $181 million of Series F First Mortgage Notes (a subsidiary,
SFPP, L.P., is the obligor on the notes);
o a $175 million secured credit facility of SFPP, L.P.;
o $30.3 million of Senior Secured Notes (a subsidiary,
Trailblazer Pipeline Company, is the obligor on the notes)
o a $10 million unsecured 364-day credit facility of
Trailblazer Pipeline Company;
o $23.7 million of tax-exempt bonds due 2024 (a subsidiary, Kinder
Morgan Operating L.P. "B" ("OLP-B"), is the obligor on these bonds).
In February 1998, the Partnership refinanced the first mortgage notes and
existing bank credit facilities of OLP-A with a $325 million secured revolving
credit facility expiring in February 2005. On December 1, 1998, the credit
facility was amended to release the collateral and the credit facility became
unsecured. The credit facility had an outstanding balance of $230 million at
December 31, 1998. Borrowings under the credit facility were primarily used to
fund the Partnership's investment in Plantation Pipe Line Company in June 1999.
On September 29, 1999, the $325 million credit facility was replaced with a $300
million unsecured five-year credit facility expiring in September 2004 and a
$300 million unsecured 364-day credit facility. In September 1999, the
Partnership recorded an extraordinary charge of $2.6 million related to the
retirement of the $325 million credit facility.
The outstanding balance under the five-year credit facility was $197.6 million
at December 31, 1999. No borrowings were outstanding under the 364-day credit
facility at December 31, 1999. Borrowings under the five-year credit facility
were primarily used to fund the Partnership's $37.6 million investment in
Trailblazer on November 30, 1999 and the acquisition of assets from KMI on
December 31, 1999. During the period from September 29, 1999 to December 31,
1999, the weighted average interest rate on the five-year credit facility was
approximately 6.17% per annum.
The Partnership has an outstanding letter of credit issued under the credit
facilities in the amount of $23.7 million that backs-up the OLP-B tax-exempt
bonds due 2024. The letter of credit reduces the amount available for borrowing
under the credit facilities.
In addition, as of December 31, 1999, the Partnership financed $330 million
through KMI to fund part of the acquisition of assets acquired from KMI on
December 31, 1999. Per the Closing Agreement entered into as of January 20,
2000, the Partnership must pay KMI a per diem fee of $180.56 for each $1,000,000
financed. The Partnership paid $200 million on January 21, 2000, and the
Partnership plans to refinance the remaining amount by March 31, 2000.
On November 6, 1998, the Partnership filed with the SEC a shelf registration
statement with respect to the sale from time to time of up to $600 million in
debt and/or equity securities. On January 29, 1999, the Partnership closed a
public offering of $250 million in principal amount of 6.30% Senior Notes due
February 1, 2009 ("Notes") at a price to the public of 99.67% per Note. In the
offering, the Partnership received proceeds, net of underwriting discounts and
commissions, of approximately $248 million. The proceeds were used to pay the
outstanding balance on the credit facility and for working capital and other
Partnership purposes. In connection with the refinancing of the Partnership's
credit facility on September 29, 1999, the Partnership's subsidiaries were
released from their guarantees of the credit facility. As a result, the
subsidiary guarantees under the Notes were also automatically
F-15
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
released in accordance with the terms of the Notes. At December 31, 1999, the
unamortized Note liability balance was $249.3 million.
At December 31, 1999, the outstanding balance under SFPP's Series F notes was
$181.0 million. The annual interest rate on the Series F notes is 10.70%, the
maturity is December 2004, and interest is payable semiannually in June and
December. The Series F notes are payable in annual installments of $32.5 million
in 2000, $39.5 million in 2001, $42.5 million in 2002 and $37.0 million in 2003.
The Series F notes may also be prepaid in full or in part at a price equal to
par plus, in certain circumstances, a premium. The Series F notes are secured by
mortgages on substantially all of the properties of SFPP (the "Mortgaged
Property"). The Series F notes contain certain covenants limiting the amount of
additional debt or equity that may be issued and limiting the amount of cash
distributions, investments, and property dispositions.
At December 31, 1999, the outstanding balance under SFPP's bank facility was
$174.0 million. The bank credit facility provides for borrowings of up to $175
million due in August 2000 and interest, at a short-term Eurodollar rate,
payable quarterly. This bank credit facility is used primarily to fund the
Series F payments when due. Borrowings under this facility are also secured by
the Mortgaged Property and are generally subject to the same terms and
conditions as the Series F notes. At December 31, 1999, the interest rate on the
credit facility debt was 6.295%.
On September 23, 1992, under the terms of a Note Purchase Agreement,
Trailblazer Pipeline Company issued and sold an aggregate principal amount of
$101 million of Senior Secured Notes to a syndicate of fifteen insurance
companies. Security for the notes was provided principally by an assignment of
certain Trailblazer transportation contracts. Effective April 29, 1997, an
amendment to the Note Purchase Agreement was added. This amendment allowed
Trailblazer to include several additional transportation contracts as security
for the notes, added a limitation on the amount of additional money that
Trailblazer could borrow and relieved Trailblazer from the security deposit
obligation. At December 31, 1999, the outstanding balance under the Senior
Secured Notes was $30.3 million. The Senior Secured Notes have a fixed annual
interest rate of 8.03% and will be repaid in semiannual installments of $5.05
million from March 1, 2000 through September 1, 2002, the final maturity date.
Interest is payable semiannually in March and September.
In December 1999, Trailblazer entered into a 364-day revolving credit
agreement with Toronto Dominion, Inc. providing for loans up to $10 million. The
agreement expires December 26, 2000. At December 31, 1999, the outstanding
balance under Trailblazer's revolving credit agreement was $10 million. The
agreement provides for an interest rate of LIBOR plus 0.875%. At December 31,
1999, the interest rate on the credit facility debt was 7.615%. Under the terms
of the Note Purchase Agreement, as amended, and the revolving credit agreement
with Toronto Dominion, Inc., Trailblazer partnership distributions are
restricted by certain financial covenants.
OLP-B's $23.7 million principal amount of tax-exempt bonds due 2024 were
issued by the Jackson-Union Counties Regional Port District. Such bonds bear
interest at a weekly floating market rate. During 1999, the weighted-average
interest rate on these bonds was 3.40% per annum.
In December 1999, the Partnership established a commercial paper program
providing for the issuance of up to $300 million of commercial paper. Borrowings
under the commercial paper program reduce the borrowings allowed under the
five-year credit facility. As of December 31, 1999, the Partnership had not
issued any commercial paper.
Maturities of Debt
The scheduled maturities of debt outstanding at December 31, 1999, are
summarized as follows (in thousands):
2000 $ 556,584
2001 49,615
2002 53,116
2003 37,017
2004 227,147
Thereafter 274,822
---------
Total $ 1,198,301
===========
F-16
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Of the $556,584 scheduled to mature in 2000, the Partnership intends to
refinance $347,384 on a long-term basis under its existing credit facilities.
Fair Value of Financial Instruments
The estimated fair value of the long-term debt based upon prevailing interest
rates available to the Partnership at December 31, 1999 and December 31, 1998 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, 1999 December 31, 1998
------------------------------- --------------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
------------ ------------ ---------- ------------
(in thousands)
Long-term debt $ 1,198,301 $ 1,209,625 $ 611,571 $ 645,873
10. Pensions and Other Postretirement Benefits
In connection with the acquisition of SFPP and Hall-Buck in 1998, the
Partnership acquired certain liabilities for pension and postretirement
benefits. The Partnership has a noncontributory defined benefit pension plan
covering the former employees of Hall-Buck. The benefits under this plan were
based primarily upon years of service and final average pensionable earnings.
The Partnership also provides medical and life insurance benefits to current
employees, their covered dependents and beneficiaries of SFPP and Kinder Morgan
Bulk Terminals, Inc. The Partnership also provides the same benefits to former
salaried employees of SFPP.
The SFPP postretirement benefit plan is frozen as no additional participants
may join the Plan. The Partnership will continue to fund the cost associated
with those employees currently in the Plan for medical benefits and life
insurance coverage during retirement.
Net periodic benefit costs for these plans include the following components
(in thousands):
<TABLE>
<CAPTION>
1999 1998
-------------------------------- -------------------------------
Other Post- Other Post-
retirement retirement
Pension Benefits Benefits Pension Benefits Benefits
---------------- ------------ ---------------- -----------
<S> <C> <C> <C> <C>
Net periodic benefit cost
Service cost $ - $ 80 $ 98 $ 636
Interest cost 141 696 76 983
Expected return on plan assets (150) - (70) -
Amortization of prior service cost - (493) - (493)
Actuarial loss (gain) - (340) - (208)
---------------- ------------ ---------------- -----------
Net periodic benefit cost $ (9) $ (57) $ 104 $ 918
---------------- ------------ ---------------- -----------
---------------- ------------ ---------------- -----------
Additional amounts recognized
Curtailment (gain) loss $ - $ (3,859) $ (425) $ -
</TABLE>
Information concerning benefit obligations, plan assets, funded status
and recorded values for these plans follows (in thousands):
F-17
<PAGE>
<TABLE>
<CAPTION>
1999 1998
-------------------------------- -------------------------------
Other Post- Other Post-
retirement retirement
Pension Benefits Benefits Pension Benefits Benefits
---------------- ------------ ---------------- -----------
<S> <C> <C> <C> <C>
Change in benefit obligation
Benefit obligation at Jan. 1 $ 1,862 $ 14,734 $ - $ -
Service cost - 80 98 636
Interest cost 141 696 76 983
Plan participants' contributions - - - 117
Administrative Expenses (12) - - -
Actuarial loss 86 (1,521) - 529
Acquisitions - - 2,201 13,039
Curtailment (gain) - (3,859) (425) -
Benefit paid from plan assets (340) (566) (88) (570)
---------------- ------------ ---------------- -----------
Benefit obligation at Dec. 31 $ 1,737 $ 9,564 $ 1,862 $ 14,734
================ ============ ================ ===========
Change in Plan Assets
Fair value of plan assets at Jan. 1 $ 1,833 $ - $ - $ -
Actual return on plan assets 300 - 136 -
Acquisitions - - 1,628 -
Employer contributions 279 566 157 453
Plan participants' contributions - - - 117
Administrative Expenses (12) - - -
Benefits paid from plan assets (340) (566) (88) (570)
---------------- ------------ ---------------- -----------
Fair value of plan assets
at Dec. 31 $ 2,060 $ - $ 1,833 $ -
================ ============ ================ ===========
</TABLE>
<TABLE>
<CAPTION>
1999 1998
-------------------------------- -------------------------------
Other Post- Other Post-
retirement retirement
Pension Benefits Benefits Pension Benefits Benefits
---------------- ------------ ---------------- -----------
<S> <C> <C> <C> <C>
Funded status $ 323 $ (9,564) $ (29) $ (14,734)
Unrecognized net transition oblig. 2 (3,012) 3 -
Unrecognized net actuarial (gain) (250) - (187) (1,831)
Unrecognized prior service (benefit) - (1,777) - (2,270)
---------------- ------------ ---------------- -----------
(Accrued) benefit cost $ 75 $ (14,353) $ (213) $ (18,835)
================ ============ ================ ===========
Weighted-Average Assumptions at
December 31
Discount rate 7.0% 7.0% 7.0% 7.0%
Expected return on plan assets 8.5% - 8.5% -
Rate of compensation increase - - 4.0% 4.0%
</TABLE>
The unrecognized prior service credit will be amortized straight-line over the
remaining expected service to retirement (4.6 years). For 1999 and 1998, the
assumed health care cost trend rate for medical costs was 8.5% and 9%,
respectively, and is assumed to decrease gradually to 5% by 2005 and remain
constant thereafter.
F-18
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A one-percentage change in assumed health care cost trend rates would have the
following effects (in thousands):
1999 1998
-------------------- --------------------
Other Postretirement Other Postretirement
Benefits Benefits
-------------------- --------------------
Effect on total of service
and interest cost components
1-Percentage point increase $ 53 $ 103
1-Percentage point decrease $ (45) $ (93)
Effect on postretirement
benefit obligation
1-Percentage point increase $ 658 $ 1,655
1-Percentage point decrease $ (565) $ (1,490)
Multiemployer Plans and Other Benefits. With the acquisition of Hall-Buck,
effective July 1, 1998, the Partnership participates in multi-employer pension
plans for the benefit of its employees who are union members. Partnership
contributions to these plans were $0.6 million from the period of acquisition
through December 31, 1998, and $0.6 million for the twelve-month period ended
December 31, 1999. These plans are not administered by the Partnership and
contributions are determined in accordance with the provisions of negotiated
labor contracts. Other benefits include a self-insured health and welfare
insurance plan and an employee health plan where employees may contribute for
their dependents' health care costs. Amounts charged to expense for these plans
were $0.5 million from the period of acquisition through December 31, 1998, and
$0.5 million for the twelve-month period ended December 31, 1999.
The Partnership terminated the Employee Stock ownership Plan (the "ESOP") held
by Hall-Buck for the benefit of its employees on August 13, 1998. All
participants became fully vested retroactive to July 1, 1998, the effective date
of the acquisition. The assets remaining in the plan were distributed during
1999.
The Partnership assumed River Consulting, Inc.'s (a consolidated affiliate of
Hall-Buck Marine, Inc.), savings plan under Section 401(k) of the Internal
Revenue Code. This savings plan allowed eligible employees to contribute up to
10 percent of their compensation on a pre-tax basis, with the Partnership
matching 2.5 percent of the first 5 percent of the employees' wage. Matching
contributions are vested at the time of eligibility, which is one year after
employment. Effective January 1, 1999, this savings plan was merged into the
retirement savings plan of the general partner.
11. Partners' Capital
At December 31, 1999, Partners' capital consisted of 48,465,137 units held by
third parties, 9,810,000 units held by KMI and 862,000 units held by the general
partner. Together, these 59,137,137 units represent the limited partners'
interest and an effective 98% interest in the Partnership, excluding the general
partner's incentive distribution. At December 31, 1998 and 1997 there were
48,821,690 and 14,111,200 units outstanding, respectively. The general partner
interest represents an effective 2% interest in the Partnership, excluding the
general partner's incentive distribution.
On February 14, 1997, the 1,720,000 deferred participation units held by the
general partner were converted to common units and 858,000 of these units were
sold to a third party. Since the deferred participation units owned by the
general partner are now common units, they are no longer separately disclosed.
In 1998, the Partnership issued 26,548,879 and 2,121,033 units, respectively,
for the acquisition of SFPP and Hall-Buck. Additionally, 6,070,578 units were
issued in a primary public offering in June 1998 and 30,000 units were
repurchased by the Partnership in December 1998.
During 1999, the Partnership issued 510,147 units in September 1999 for the
acquisition of assets from Primary Corporation and 9,810,000 units on December
31, 1999 related to the acquisition of assets from KMI (see note 3).
Additionally, 2,000 units were issued during 1999 in accordance with unit option
exercises, and the Partnership repurchased 6,000 units in January 1999 and 700
units in December 1999.
F-19
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For purposes of maintaining partner capital accounts, the partnership
agreement specifies that items of income and loss shall be allocated among the
partners in accordance with their respective percentage interests. Normal
allocations according to percentage interests are done only, however, after
giving effect to any priority income allocations in an amount equal to incentive
distributions allocated 100% to the general partner.
Incentive distributions allocated to the general partner are determined by the
amount quarterly distributions to unitholders exceed certain specified target
levels. For the years ended December 31, 1999, 1998 and 1997, the Partnership
distributed $2.85, $2.4725 and $1.8775 respectively, per unit. The distributions
for 1999, 1998 and 1997 required incentive distributions to the general partner
in the amount of $55,000,963, $32,737,571 and $3,935,852, respectively. The
increased incentive distributions paid for 1999 over 1998 and 1998 over 1997
reflect the increase in amounts distributed per unit as well as the issuance of
additional units.
On January 20, 2000, the Partnership declared a cash distribution for the
quarterly period ended December 31, 1999, of $0.725 per unit. The distribution
was paid on February 14, 2000, to unitholders of record as of January 31, 2000,
and required an incentive distribution to the general partner of $14,416,737.
Since this distribution was declared after the end of the quarter, no amount is
shown in the December 31, 1999 balance sheet as a Distribution Payable.
12. Concentrations of Credit Risk
For the year ended December 31, 1999, no single external customer of the
Partnership accounted for more than 10% of consolidated revenue. Four customers
of the Partnership each accounted for over 10% of consolidated revenues for
1998. In 1997, only one customer accounted for more than 10% of consolidated
revenues. See note 15 for more information on major customers. Additionally, a
portion of the Partnership's revenues is derived from transportation services to
oil and gas refining and marketing companies in the Midwest. Although 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, management believes that the Partnership is exposed to minimal
credit risk. The Partnership generally does not require collateral for its
receivables.
13. Related Party Transactions
Revenues and Expenses
The Partnership leases approximately 30 MBbls/d of North System capacity to
Heartland Pipeline Company ("Heartland") under a lease agreement. The primary
term of the lease agreement expires in 2010, but provides for four five-year
renewal options subject to each party's approval. Revenues earned from Heartland
for the lease rights were approximately $1.0 million in 1999 and approximately
$0.9 million for each of the years ended December 31, 1998 and 1997.
General and Administrative Expenses
Since the sale of the general partner in February 1997, the general partner
provides the Partnership with general and administrative services and is
entitled to reimbursement of all direct and indirect costs related to the
business activities of the Partnership. The general partner incurred general and
administrative expenses of $30.7 million in 1999, $38.0 million in 1998 and $6.9
million in 1997.
The general partner shares administrative personnel with KMI to operate both
KMI's business and the business of the Partnership. As a result, the officers of
the general partner, who in some cases may also be officers of KMI, must
allocate, in their reasonable and sole discretion, the time the general
partner's employees spend on behalf of the Partnership and on behalf of KMI. For
2000, KMI will pay the general partner $1 million as reimbursement for the
services of the general partner's employees. Although management of the general
partner believes this amount to fairly reflect the value of the services to be
performed for KMI, the determination of this amount was not the result of arms
length negotiations. No such amounts were paid by KMI to the Partnership during
1999. Due to the nature of the allocations, this reimbursement may not exactly
match the actual time and overhead spent. The general partner and KMI will
reevaluate the amount to be charged to KMI for the services provided to KMI by
the employees of the general partner.
F-20
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Partnership Distributions
Kinder Morgan G.P., Inc.
Kinder Morgan G.P., Inc. (the "general partner") serves as the sole general
partner of the four operating partnerships as well as the sole general partner
of the Partnership. Pursuant to the partnership agreements, the general partner
interests represent a 1% ownership interest in the Partnership, and a direct
1.0101% ownership interest in the operating partnerships. Together then, the
general partner owns an effective 2% interest in the operating partnerships,
excluding incentive distributions; the 1.0101% direct general partner ownership
interest (accounted for as minority interest in the consolidated financial
statements of the Partnership) and the 0.9899% ownership interest indirectly
owned via its 1% ownership interest in the Partnership.
At December 31, 1999, the general partner owned 862,000 units, representing
approximately 1.5% of the outstanding units. The partnership agreements
governing the operation of the Partnership and the operating partnerships
require the partnerships to distribute 100% of the "Available Cash" (as defined
in the partnership agreements) to the partners within 45 days following the end
of each calendar quarter in accordance with their respective percentage
interests. Available Cash consists generally of all cash receipts of the
partnerships, less all of their cash disbursements, net additions to reserves,
and amounts payable to the former Santa Fe General Partner in respect of its
0.5% interest in SFPP, L.P.
In general, Available Cash for each quarter is distributed, first, 98% to the
limited partners and 2% to the general partner until the limited partners have
received a total of $0.3025 per unit for such quarter, second, 85% to the
limited partners and 15% to the general partner until the limited partners have
received a total of $0.3575 per unit for such quarter, third, 75% to the limited
partners and 25% to the general partner until the limited partners have received
a total of $0.4675 per unit for such quarter, and fourth, thereafter 50% to the
limited partners and 50% to the general partner. Incentive distributions are
generally defined as all cash distributions paid or payable to the general
partner that are in excess of 2% of the aggregate amount of cash being
distributed. The general partner's declared incentive distributions for the
years ended December 31, 1999, 1998, and 1997 were $55,000,963, $32,737,571 and
$3,935,852, respectively.
Kinder Morgan, Inc.
Kinder Morgan, Inc. ("KMI") serves as the sole stockholder of the general
partner. At December 31, 1999, KMI owned 9,810,000 units, representing
approximately 16.6% of the outstanding units. Since KMI acquired these units on
December 31, 1999 (see note 3), no distributions were paid to KMI with respect
to these units during 1999.
14. Leases and Commitments
The Partnership has entered into certain operating leases. Including probable
elections to exercise renewal options, the leases have remaining terms ranging
from one to forty-four years. Future commitments related to these leases at
December 31, 1999 are as follows (in thousands):
2000 $ 8,176
2001 7,290
2002 7,399
2003 6,745
2004 4,571
Thereafter 28,804
---------
Total minimum payments $ 62,985
=========
Total minimum payments have not been reduced for future minimum sublease
rentals aggregating approximately $2.8 million. Total lease and rental expenses,
including related variable charges, incurred for the years ended December 31,
1999, 1998, and 1997 were $8.8 million, $7.3 million and $3.4 million,
respectively.
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
F-21
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
adjustments for expansions. If the customer exercises its rights under the
option, management anticipates that no loss will accrue to the Partnership.
Under a joint tariff agreement, the Partnership's North System is obligated to
pay minimum tariff revenues of approximately $2.0 million per contract year to
an unaffiliated pipeline company subject to certain adjustments. This agreement
expires March 1, 2013, but provides for a five-year extension at the option of
the Partnership.
During 1998, the Partnership established a unit option plan, which provides
that key personnel are eligible to receive grants of options to acquire units.
The number of units available under the option plan is 250,000. The option plan
terminates in March 2008. As of December 31, 1999, options for 211,200 units
were granted to certain personnel with a term of seven years at exercise prices
equal to the market price of the units at the grant date. In addition, as of
December 31, 1999, options for 10,000 units were granted to two non-employee
directors of the Partnership. The options granted generally vest forty percent
in the first year and twenty percent each year thereafter.
The Partnership applies Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees," and related interpretations in
accounting for unit options granted under the Partnership's option plan. Pro
forma information regarding changes in net income and per unit data if the
accounting prescribed by Statement of Financial Accounting Standards No.123
"Accounting for Stock Based Compensation," had been applied is not material. No
compensation expense has been recorded since the options were granted at
exercise prices equal to the market prices at the date of grant.
During 1997, the Partnership established an Executive Compensation Plan for
certain executive officers of the general partner. The Partnership may, at its
option and with the approval of the unitholders, pay the participants in units
instead of cash. Eligible awards are equal to a formula based upon the cash
distributions paid to the general partner during the four calendar quarters
preceding the date of redemption multiplied by eight (the "Calculated Amount").
Calculated amounts are accrued as compensation expense and adjusted quarterly.
Under the plan, no eligible employee may receive a grant in excess of 2% and
total awards under the Plan may not exceed 10% of the Calculated Amount. The
plan terminates January 1, 2007, and any unredeemed awards will be automatically
redeemed.
At December 31, 1998, certain executive officers of the general partner had
outstanding awards totaling 2% of the Calculated Amount eligible to be granted
under the Plan. On January 4, 1999, 50% of the awards granted to these executive
officers were vested and paid out. At December 31, 1999, each participant
continues to have a grant of 1% under the plan.
15. Reportable Segments
The Partnership has adopted SFAS No. 131 -- "Disclosures About Segments of an
Enterprise and Related Information". The Partnership competes in four reportable
business segments: Pacific Operations, Mid-Continent Operations, Natural Gas
Operations and Bulk Terminals (see note 1). The accounting policies of the
segments are the same as those described in the summary of significant
accounting policies (see note 2). The Partnership evaluates performance based on
each segments' earnings, which excludes general and administrative expenses,
third-party debt costs, unallocable non-affiliated interest income and expense,
and minority interest. The Partnership's reportable segments are strategic
business units that offer different products and services. They are managed
separately because each segment involves different products and marketing
strategies.
Financial information by segment follows (in thousands):
F-22
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1999 1998 1997
----------- ----------- -----------
Revenues
Pacific Operations $ 256,692 $ 221,430 $ -
Mid-Continent Operations 57,444 38,271 55,777
Bulk Terminals 114,613 62,916 18,155
----------- ----------- -----------
Total Segments $ 428,749 $ 322,617 $ 73,932
=========== =========== ===========
Operating Income
Pacific Operations $ 170,654 $ 145,685 $ -
Mid-Continent Operations 15,450 14,396 22,389
Bulk Terminals 36,917 20,572 10,709
----------- ----------- -----------
Total Segments $ 223,021 $ 180,653 $ 33,098
=========== =========== ===========
Earnings from equity investments
Pacific Operations $ 1,531 $ 803 $ -
Mid-Continent Operations 41,364 24,892 5,724
Bulk Terminals 23 37 -
----------- ----------- -----------
Total Segments $ 42,918 $ 25,732 $ 5,724
=========== =========== ===========
Interest revenue
Pacific Operations $ - $ - $ -
Mid-Continent Operations - 22 (159)
Bulk Terminals - - -
----------- ----------- -----------
Total Segments $ - $ 22 $ (159)
=========== =========== ===========
Interest (expense)
Pacific Operations $ - $ - $ -
Mid-Continent Operations - (338) (505)
Bulk Terminals - - -
----------- ----------- -----------
Total Segments $ - $ (338) $ (505)
=========== =========== ===========
Other, net (including amortization of excess cost of equity investments)
Pacific Operations $ 10,517 $ (6,418) $ -
Mid-Continent Operations 10,046 (844) (707)
Bulk Terminals (669) (765) (1)
----------- ----------- -----------
Total Segments $ 19,894 $ (8,027) $ (708)
=========== =========== ===========
F-23
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1999 1998 1997
----------- ----------- -----------
Income tax benefit (expense)
Pacific Operations $ - $ - $ -
Mid-Continent Operations (8,538) (972) 740
Bulk Terminals (1,288) (600) -
----------- ----------- -----------
Total Segments $ (9,826) $ (1,572) $ 740
=========== =========== ===========
Segment earnings
Pacific Operations $ 182,702 $ 140,070 $ -
Mid-Continent Operations 58,322 37,156 27,482
Bulk Terminals 34,983 19,244 10,708
----------- ----------- -----------
Total Segments (1) $ 276,007 $ 196,470 $ 38,190
=========== =========== ===========
Assets at December 31
Pacific Operations $1,592,111 $1,549,523 $ -
Mid-Continent Operations 510,568 381,881 254,084
Natural Gas Operations 879,076 - -
Bulk Terminals 203,601 186,298 54,710
----------- ----------- -----------
Total Segments (2) $3,185,356 $2,117,702 $ 308,794
=========== =========== ===========
Depreciation and amortization
Pacific Operations $ 30,982 $ 25,177 $ -
Mid-Continent Operations 7,946 7,510 9,009
Bulk Terminals 7,541 3,870 1,058
----------- ----------- -----------
Total Segments $ 46,469 $ 36,557 $ 10,067
=========== =========== ===========
Equity Investments at December 31
Pacific Operations $ 9,501 $ 10,534 $ -
Mid-Continent Operations 320,842 228,005 31,711
Natural Gas Operations 88,249 - -
Bulk Terminals 59 69 -
----------- ----------- -----------
Total Segments $ 418,651 $ 238,608 $ 31,711
=========== =========== ===========
Capital expenditures
Pacific Operations $ 64,177 $ 23,925 $ -
Mid-Continent Operations 4,497 4,531 4,310
Bulk Terminals 14,051 9,951 2,574
----------- ----------- -----------
Total Segments $ 82,725 $ 38,407 $ 6,884
=========== =========== ===========
(1) The following reconciles segment earnings to net income.
1999 1998 1997
----------- ----------- -----------
Segment earnings $ 276,007 $ 196,470 $ 38,190
Interest and corporate
administrative expenses (a) (93,705) (92,864) (20,453)
----------- ----------- -----------
Net Income $ 182,302 $ 103,606 $ 17,737
=========== =========== ===========
(a) Includes interest and debt expense, general and administrative expenses,
minority interest expense, extraordinary charges and other insignificant items.
(2) The following reconciles segment assets to consolidated assets.
1999 1998 1997
----------- ----------- -----------
Segment assets $3,185,356 $2,117,702 $ 308,794
Corporate assets (a) 43,382 34,570 4,112
----------- ----------- -----------
Total assets $3,228,738 $2,152,272 $ 312,906
=========== =========== ===========
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
F-24
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Partnership's total operating revenues are derived from a wide customer
base. During 1999, no revenues from transactions with a single external customer
amounted to 10% or more of the Partnership's consolidated revenues. In 1998,
revenues from one customer of the Partnership's Pacific Operations and Bulk
Terminals segments represented approximately $42.5 million (13.2%) of the
Partnership's consolidated revenues. Additionally, in 1998, three other
customers of the Pacific Operations accounted for more than 10% of the
Partnership's consolidated revenues. These customers had revenues of
approximately $39.7 million (12.3%), $35.29 million (11.0%) and $35.28 million
(10.9%), respectively, of consolidated revenues. For the year ended December 31,
1997, revenues from one customer of the Mid-Continent Operations segment
represented approximately $8.8 million (11.9%) of the Partnership's consolidated
revenues.
16. Litigation and Other Contingencies
The tariffs charged for interstate common carrier pipeline transportation for
the Partnership's pipelines are subject to rate regulation by the Federal Energy
Regulatory Commission ("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. For
each of the years ended December 31, 1999, 1998 and 1997, the application of the
indexing methodology did not significantly affect the Partnership's rates.
FERC Proceedings
SFPP
Tariffs charged by SFPP are subject to certain proceedings involving shippers'
protests regarding the interstate rates, as well as practices and the
jurisdictional nature of certain facilities and services on the Pacific
Operations' pipeline systems. In September 1992, El Paso Refinery, L.P. ("El
Paso") filed a protest/complaint with the FERC challenging SFPP's East Line
rates from El Paso, Texas to Tucson and Phoenix, Arizona, challenging SFPP's
proration policy and seeking to block the reversal of the direction of flow of
SFPP's six inch pipeline between Phoenix and Tucson. At various dates following
El Paso's September 1992 filing, other shippers on SFPP's South System,
including Chevron U.S.A. Products Company ("Chevron"), Navajo, ARCO Products
Company ("ARCO"), Texaco Refining and Marketing Inc. ("Texaco"), Refinery
Holding Company, L.P. (a partnership formed by El Paso's long-term secured
creditors that purchased El Paso's refinery in May 1993), Mobil Oil Corporation
and Tosco Corporation, filed separate complaints, and/or motions to intervene in
the FERC proceeding, challenging SFPP's rates on its East and West Lines.
Certain of these parties also claimed that a gathering enhancement charge at
SFPP's Watson origin pump station in Carson, California was charged in violation
of the ICA. In subsequent procedural rulings, the FERC consolidated these
challenges (Docket Nos. OR92-8-000, et al.) and ruled that they must proceed as
a complaint proceeding, with the burden of proof being placed on the complaining
parties. Such parties must show that SFPP's rates and practices at issue violate
the requirements of the ICA.
Hearings in the FERC proceeding commenced on April 9, 1996 and concluded on
July 19, 1996. The parties completed the filing of their post-hearing briefs on
December 9, 1996. An initial decision by the FERC administrative law judge was
issued on September 25, 1997 (the "Initial Decision").
The Initial Decision upheld SFPP's position that "changed circumstances" were
not shown to exist on the West Line, thereby retaining the just and reasonable
status of all West Line rates that were "grandfathered" under the Energy Policy
Act of 1992 ("EPACT"). Accordingly, such rates are not subject to challenge,
either for the past or prospectively, in that proceeding. The administrative law
judge's decision specifically excepted from that ruling SFPP's Tariff No. 18 for
movement of jet fuel from Los Angeles to Tucson, which was initiated subsequent
to the enactment of EPACT.
The Initial Decision also included rulings that were generally adverse to SFPP
on such cost of service issues as the capital structure to be used in computing
SFPP's 1985 starting rate base under FERC Opinion 154-B, the level of income tax
allowance, and the recoverability of civil and regulatory litigation expense and
certain pipeline reconditioning costs. The administrative law judge also ruled
that a gathering enhancement service at SFPP's
F-25
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Watson origin pump station in Carson, California was subject to FERC
jurisdiction and ordered that a tariff for that service and supporting cost of
service documentation be filed no later than 60 days after a final FERC order on
this matter.
On January 13, 1999, the FERC issued its Opinion No. 435, which affirmed in
part and modified in part the Initial Decision. In Opinion No. 435, the FERC
ruled that all but one of the West Line rates are "grandfathered" as just and
reasonable and that "changed circumstances" had not been shown to satisfy the
complainants' threshold burden necessary to challenge those rates. The FERC
further held that the one "non-grandfathered" West Line tariff did not require
rate reduction. Accordingly, all complaints against the West Line rates were
dismissed without any requirement that SFPP reduce, or pay any reparations for,
any West Line rate.
With respect to the East Line rates, Opinion No. 435 reversed in part and
affirmed in part the Initial Decision's ruling regarding the methodology of
calculating the rate base for the East Line. Among other things, Opinion No. 435
modified the Initial Decision concerning the date on which the starting rate
base should be calculated and the income tax allowance and allowable cost of
equity used to calculate the rate base. In addition, Opinion No. 435 ruled that
no reparations would be owed to any complainant for any period prior to the date
on which that complainant's complaint was filed, thus reducing the potential
reparations period for most complainants by two years. On January 19, 1999, ARCO
Products Company filed a petition with the United States Court of Appeals for
the District of Columbia Circuit for review of Opinion No. 435. SFPP and a
number of the complainants have each sought rehearing by FERC of elements of
Opinion No. 435. In compliance with Opinion No. 435, on March 15, 1999, SFPP
submitted a compliance filing implementing the rulings made by FERC,
establishing the level of rates to be charged by SFPP in the future, and setting
forth the amount of reparations owed by SFPP to the complainants under the
order. SFPP's compliance filing was contested by the complainants. SFPP's
compliance filing and the rehearing petitions of SFPP and others are pending
before the FERC. The Partnership believes Opinion No. 435 substantially reduces
the negative impact of the Initial Decision.
In December 1995, Texaco filed an additional FERC complaint, which involves
the question of whether a tariff filing was required for movements on certain of
SFPP's lines upstream of its Watson, California station origin point (the
"Sepulveda Lines") and, if so, whether those rates may be set in that proceeding
and what those rates should be. Texaco's initial complaint was followed by
several other West Line shippers filing similar complaints and/or motions to
intervene, all of which have been consolidated into Docket Nos. OR96-2-000 et
al. Hearings before an administrative law judge were held in December 1996 and
the parties completed the filing of final post-hearing briefs on January 31,
1997.
On March 28, 1997, the administrative law judge issued an initial decision
holding that the movements on SFPP's Sepulveda Lines are not subject to FERC
jurisdiction. On August 5, 1997, the FERC reversed that decision and found the
Sepulveda Lines to be subject to the jurisdiction of the FERC. SFPP was ordered
to make a tariff filing within 60 days to establish an initial rate for these
facilities. The FERC reserved decision on reparations until it ruled on the
newly-filed rates. On October 6, 1997, SFPP filed a tariff establishing the
initial interstate rate for movements on the Sepulveda Lines from Sepulveda
Junction to Watson Station at the preexisting rate of five cents per barrel,
along with supporting cost of service documentation. Subsequently, several
shippers filed protests and motions to intervene at the FERC challenging that
rate. On October 27, 1997, SFPP made a responsive filing at the FERC, requesting
that these protests be held in abeyance until the FERC ruled on SFPP's request
for rehearing of the August 5, 1997 order, and also indicating that SFPP
intended to defend the new tariff both on the basis of its cost of service and
as a market-based rate. On November 5, 1997, the FERC issued an order accepting
the new rate effective November 6, 1997, subject to refund, and referred the
proceeding to a settlement judge. On December 10, 1997, following a settlement
conference held at the direction of the FERC, the settlement judge recommended
that the settlement procedures be terminated. On December 24, 1997, FERC denied
SFPP's request for rehearing of the August 5, 1997 decision. On December 31,
1997, SFPP filed an application for market power determination, which, if
granted, will enable it to charge market-based rates for this service. Several
parties protested SFPP's application. On September 30, 1998, the FERC issued an
order finding that, based on SFPP's application, SFPP lacks market power in the
Watson Station destination market served by the Sepulveda Lines. The FERC found
that SFPP appeared to lack market power in the origin market served by the
Sepulveda Lines as well, but established a hearing to permit the protesting
parties to substantiate allegations that SFPP possessed market power in the
origin market. Hearing before a FERC administrative law judge on this limited
issue commenced on February 7, 2000 and concluded on February 17, 2000. The
matter will be briefed to the administrative law judge in March and April 2000.
F-26
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On October 22, 1997, ARCO Products Company, Mobil Oil Corporation and Texaco
Refining and Marketing, Inc. filed another complaint at the FERC (Docket No.
OR98-1-000) challenging the justness and reasonableness of all of SFPP's
interstate rates. The complaint again challenges SFPP's East and West Line rates
and raises many of the same issues, including a renewed challenge to the
grandfathered status of West Line rates, that have been at issue in Docket Nos.
OR92-8-000, et al. The complaint includes an assertion that the acquisition of
SFPP and the cost savings anticipated to result from the acquisition constitute
"changed circumstances" that provide a basis for terminating the "grandfathered"
status of SFPP's otherwise protected rates. The complaint also seeks to
establish that SFPP's grandfathered interstate rates from the San Francisco Bay
area to Reno, Nevada and from Portland to Eugene, Oregon are also subject to
"changed circumstances" and, therefore, can be challenged as unjust and
unreasonable. On November 26, 1997, Ultramar Diamond Shamrock Corporation filed
a similar complaint at the FERC (Docket No. OR98-2-000). Both reparations and
prospective rate deductions are sought for movements on all of the lines.
SFPP filed answers to both complaints with the FERC on November 21, 1997 and
December 22, 1997, respectively, and intends to vigorously defend all of the
challenged rates. On January 20, 1998, the FERC issued an order accepting the
complaints and consolidating both complaints into one proceeding, but holding
them in abeyance pending a Commission decision on review of the Initial Decision
in Docket Nos. OR92-8-000 et al. In July 1998, some complainants amended their
complaints to incorporate updated financial and operational data on SFPP. SFPP
answered the amended complaints. In a companion order to Opinion No. 435, the
FERC directed the complainants to amend their complaints, as may be appropriate,
consistent with the terms and conditions of its orders, including Opinion No.
435. On January 10th and 11th, 2000, the complainants again amended their
complaints to incorporate further updated financial and operational data on
SFPP. SFPP filed an answer to these amended complaints on February 15th and
intends to defend vigorously all of the challenged rates.
Applicable rules and regulations in this field are vague, relevant factual
issues are complex and there is little precedent available regarding the factors
to be considered or the method of analysis to be employed in making a
determination of "changed circumstances", which is the showing necessary to make
"grandfathered" rates subject to challenge. The Partnership believes, after
consultation with FERC counsel, that the acquisition of SFPP, standing alone,
should not be found to constitute "changed circumstances", however, the
Partnership's realization of cost savings resulting from the acquisition may
increase the risk of a finding of "changed circumstances".
If "changed circumstances" are found, SFPP rates previously "grandfathered"
under EPACT may lose their "grandfathered" status and, if such rates are found
to be unjust and unreasonable, shippers may be entitled to a prospective rate
reduction together with reparations for periods from the date of the complaint
to the date of the implementation of the new rates.
The Partnership is not able to predict with certainty whether settlement
agreements will be completed with some or all of the complainants, the final
terms of any such settlement agreements that may be consummated, or the final
outcome of the FERC proceedings should they be carried through to their
conclusion, and it is possible that current or future proceedings could be
resolved in a manner adverse to the Partnership.
KMIGT
On January 23, 1998, KMIGT filed a general rate case with the FERC requesting
a $30.2 million increase in annual revenues. As a result of the FERC's action,
KMIGT was allowed to place its rates into effect on August 1, 1998, subject to
refund, and provisions for refund were recorded based on expected ultimate
resolution. On November 3, 1999, KMIGT filed a comprehensive Stipulation and
Agreement to resolve all issues in this proceeding. The FERC approved the
Stipulation and Agreement on December 22, 1999. The settlement rates have been
placed in effect, and refunds for past periods will be made in the first quarter
of 2000. As of December 31, 1999, the Partnership had accrued $36.6 million for
these rate refunds.
TRAILBLAZER
On July 1, 1997, Trailblazer filed a rate case with the FERC (Docket No.
RP97-408) which reflected a proposed annual revenue increase of $3.3 million.
The timing of the rate case filing was in accordance with the requirements of
Trailblazer's previous rate case settlement in Docket No. RP93-55. The FERC
issued an order on July 31, 1997,
F-27
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
which suspended the rates to be effective January 1, 1998. Major issues in the
rate case include throughput levels used in the design of rates, levels of
depreciation rates, return on investment and the cost of service treatment of
the Columbia settlement revenues. Trailblazer filed a proposed settlement
agreement with the administrative law judge on May 8, 1998. The presiding
administrative law judge certified the settlement to the FERC in an order dated
June 25, 1998. The FERC issued an order on October 19, 1998 remanding the
settlement, which was contested by two parties, to the presiding administrative
law judge for further action. A revised settlement was filed on November 20,
1998. The presiding administrative law judge certified the revised settlement to
the FERC on January 25, 1999.
The FERC issued orders on April 28, 1999 and August 3, 1999, approving the
revised settlement as to all parties except the two parties who contested the
settlement. Rehearing is pending. As to the two contesting parties, the FERC
established hearing procedures. On March 3, 2000, Trailblazer and the two
parties filed a joint motion indicating that a settlement in principle has been
reached. On March 6, 2000, the presiding administrative law judge issued an
order suspending the procedural schedule and hearing pending the filing of the
appropriate documents necessary to terminate the proceeding.
California Public Utilities Commission Proceeding
A complaint was filed with the California Public Utilities Commission ("CPUC")
on April 7, 1997 by ARCO Products Company, Mobil Oil Corporation and Texaco
Refining and Marketing Inc. against SFPP, L.P. The complaint challenges rates
charged by SFPP for intrastate transportation of refined petroleum products
through its pipeline system in the State of California and requests prospective
rate adjustments. On October 1, 1997, the complainants filed testimony seeking
prospective rate reductions aggregating approximately $15 million per year.
On August 6, 1998, the CPUC issued its decision dismissing the complainants'
challenge to SFPP's intrastate rates. On June 24, 1999, the CPUC granted limited
rehearing of its August 1998 decision for the purpose of addressing the proper
ratemaking treatment for partnership tax expenses, the calculation of
environmental costs and the public utility status of SFPP's Sepulveda Line and
its Watson Station gathering enhancement facilities. In pursuing these rehearing
issues, complainants seek prospective rate reductions aggregating approximately
$10 million per year.
Under the existing CPUC procedural schedule, complainants and defendant SFPP
will submit testimony in support of their respective positions in February and
March 2000. Evidentiary hearings are scheduled to commence in mid-March 2000,
with an initial decision addressing the rehearing issues expected from the CPUC
during the last quarter of 2000.
The Partnership believes it has adequate reserves recorded for any adverse
decision related to this matter.
SPTC Easements
SFPP and Southern Pacific Transportation Company ("SPTC") are engaged in a
judicial reference proceeding to determine the extent, if any, to which the rent
payable by SFPP for the use of pipeline easements on rights-of-way held by SPTC
should be adjusted pursuant to existing contractual arrangements (Southern
Pacific Transportation Company vs. Santa Fe Pacific Corporation, SFP Properties,
Inc., Santa Fe Pacific Pipelines, Inc., SFPP, L.P., et al., Superior Court of
the State of California for the County of San Francisco, filed August 31, 1994).
Although SFPP received a favorable ruling from the trial court in May 1997, in
September 1999, the California Court of Appeals remanded the case back to the
trial court for further proceeding. SFPP is accruing amounts for payment of the
rental for the subject rights-of-way consistent with the company's expectations
of the ultimate outcome of the proceeding.
Trailblazer
On March 25, 1998, CIG Trailblazer Gas Company ("CIG Trailblazer") filed a
lawsuit in the First Judicial District, State of Wyoming in Docket 149 No. 387,
subsequently amended on February 3, 1999, against the three partners of
Trailblazer. CIG Trailblazer purchased Tennessee Trailblazer Gas Company's
("Tennessee Trailblazer") interest in an agreement ("Tennessee agreement") dated
November 1, 1982 with the Trailblazer partners. The Tennessee agreement gave
Tennessee Trailblazer the right to participate as an equity owner and partner in
Trailblazer expansions beyond Trailblazer's original certificated capacity of
525 MMcf/d. The agreement also gave
F-28
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Tennessee Trailblazer the right to attend management committee meetings of
Trailblazer. CIG Trailblazer claims in the lawsuit, that as owners of the
Tennessee agreement it has a right to attend management committee meetings but
has been excluded from them by the management committee of Trailblazer. CIG
Trailblazer originally claimed that it had the right to participate in the 1997
expansion of Trailblazer, but has amended its complaint to eliminate that
contention and its claim for damages. In its amended answer, the partners in
Trailblazer contend that the Tennessee agreement is no longer valid and
enforceable. They also contend that if it is valid and enforceable, CIG
Trailblazer will have an obligation to cause Wyoming Interstate Company
("Wyoming Interstate") to be offered for sale to Trailblazer. CIG Trailblazer
also filed a separate lawsuit on February 2, 1999, in Docket 152 No. 408,
requesting a declaratory order that if they become a partner in Trailblazer
under the 1982 agreement, CIG Trailblazer will not be required to contribute or
sell Wyoming Interstate to Trailblazer. On January 31, 2000, the parties reached
a settlement of all claims and counterclaims in these two proceedings.
Accordingly, on February 29, 2000 and March 1, 2000, the Wyoming Court issued
orders dismissing the litigation in Docket 149 No. 387 and Docket 152 No. 408,
respectively.
Environmental Matters
The Partnership is subject to environmental cleanup and enforcement actions
from time to time. In particular, the federal Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA" or "Superfund" law) generally
imposes joint and several liability for cleanup and enforcement costs, without
regard to fault or the legality of the original conduct, on current or
predecessor owners and operators of a site. The operations of the Partnership
are also subject to Federal, state and local laws and regulations relating to
protection of the environment. Although the Partnership believes its operations
are in general compliance with applicable environmental regulations, risks of
additional costs and liabilities are inherent in pipeline and terminal
operations, and there can be no assurance significant costs and liabilities will
not be incurred by the Partnership. Moreover, it is possible that other
developments, such as increasingly stringent environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property or persons
resulting from the operations of the Partnership, could result in substantial
costs and liabilities to the Partnership.
The Partnership is currently involved in the following governmental
proceedings related to compliance with environmental regulations:
o SFPP, along with several other respondents, is involved in one cleanup
ordered by the United States Environmental Protection Agency related to
ground water contamination in the vicinity of SFPP's storage facilities and
truck loading terminal at Sparks, Nevada.
o SFPP is currently involved in several ground water hydrocarbon remediation
efforts under administrative orders issued by the California Regional Water
Quality Control Board and two other state agencies.
o The Partnership and the San Bernardino County District Attorney have reached
an agreement in principle to settle allegations by the district attorney that
in May 1999, SFPP discharged, in violation of applicable environmental laws,
a quantity of hydrotest water contaminated with jet fuel into the San
Bernardino County Flood Control District Channel. The amounts to be paid by
the Partnership under the proposed settlement are not material.
In addition, the Partnership from time to time is involved in civil
proceedings relating to damages alleged to have occurred as a result of
accidental leaks or spills of refined petroleum products or natural gas liquids.
Among these matters is a lawsuit originally filed in February 1998 against SFPP
in the Superior Court of the State of California in and for the County of Solano
by 283 individual plaintiffs alleging personal injury and property damage
arising from a release in 1996 of petroleum products from SFPP's pipeline
running through Elmira, California. An amended complaint was filed on May 22,
1998. No trial date has been set. The Partnership continues to aggressively
defend the action, and has settled the personal injury claims of approximately
80 plaintiffs.
Although no assurance can be given, the Partnership believes that the ultimate
resolution of all these matters will not have a material adverse effect on its
financial position or results of operations. The Partnership has recorded a
reserve for environmental claims in the amount of $21.1 million at December 31,
1999.
F-29
<PAGE>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other
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.
17. Quarterly Financial Data (unaudited)
Operating Operating Net Income
Revenues Income Net Income per Unit
(In thousands, except per unit amounts)
- --------------------------------------------------------------------------------
1999
First Quarter $100,049 $47,645 $41,069 $0.57
Second Quarter 102,933 47,340 43,113 0.61
Third Quarter (1) 104,388 48,830 52,553 0.77
Fourth Quarter 121,379 43,592 45,567 0.62
- --------------------------------------------------------------------------------
1998
First Quarter (2) $36,741 $15,091 $353 $(0.12)
Second Quarter 82,044 39,371 30,313 0.50
Third Quarter 101,900 41,732 35,116 0.52
Fourth Quarter 101,932 44,475 37,824 0.55
- --------------------------------------------------------------------------------
(1) 1999 third quarter includes an extraordinary charge of $2,595 due to an
early extinguishment of debt. Net income before extraordinary charge was
$55,148 and net income per unit before extraordinary charge was $0.82.
(2) 1998 first quarter includes an extraordinary charge of $13,611 due to an
early extinguishment of debt. Net income before extraordinary charge was
$13,964 and net income per unit before extraordinary charge was $0.52.
F-30
<PAGE>
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 10th day of
March 2000.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware Limited Partnership)
By: KINDER MORGAN G.P., INC.
as General Partner
By:/s/ William V. Morgan
-------------------------------
William V. Morgan,
Vice Chairman and 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.
Name Title Date
---- ----- ----
/s/ Richard D. Kinder Chairman of the Board and Chief March 10, 2000
- ----------------------- Executive Officer of Kinder Morgan G.P., Inc.
Richard D. Kinde
/s/ William V. Morgan Director, Vice Chairman and President March 10, 2000
- ----------------------- President of Kinder Morgan G.P., Inc.
William V. Morgan
/s/ Edward O. Gaylord Director of Kinder Morgan G.P., Inc. March 10, 2000
- -----------------------
Edward O. Gaylord
/s/ Gary L. Hultquist Director of Kinder Morgan G.P., Inc. March 10, 2000
- -----------------------
Gary L. Hultquist
/s/ C. Park Shaper Vice President, Treasurer and March 10, 2000
- ----------------------- Chief Financial Officer of Kinder
C. Park Shaper Morgan G.P., Inc. (principal
financial officer and principal
accounting officer)
S-1
SUBSIDIARIES OF KINDER MORGAN ENERGY PARTNERS, L.P.
Kinder Morgan Operating L.P. "A", a Delaware limited partnership.
Kinder Morgan Operating L.P. "B", a Delaware limited partnership.
Kinder Morgan Operating L.P. "C", a Delaware limited partnership.
Kinder Morgan Operating L.P. "D", a Delaware limited partnership.
Kinder Morgan Interstate Gas Transmission LLC, a Delaware limited liability
company.
Plantation Pipe Line Company, a Delaware corporation. Although Kinder Morgan
Energy Partners, L.P. owns more that 50% of the outstanding capital stock of
Plantation Pipe Line Company, its financial results are not consolidated with
those of the partnership because the partnership does not control the
corporation.
CGT Trailblazer, LLC, a Delaware limited liability company.
NGPL Trailblazer, LLC, a Colorado limited liability company.
Trailblazer Pipeline Company, an Illinois general partnership.
Kinder Morgan CO2, LLC, a Delaware limited liability company.
Heartland Pipeline Company, a Texas general partnership.
SFPP L.P., a Delaware limited partnership.
Kinder Morgan Bulk Terminals Inc., a Louisiana corporation.
River Consulting, Inc., a Louisiana corporation.
Western Plant Services, Inc., a California corporation.
CONSENT OF INDEPENDENT ACCOUNTANTS
----------------------------------
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (Nos. 333-25995, 333-66931 and 333-62155) and the
incorporation by reference in the Registration Statement on Form S-8 (No.
333-56343) of Kinder Morgan Energy Partners, L.P. of our report dated March
10, 2000 appearing on page F-2 of this Form 10-K
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
March 13, 2000
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<PERIOD-END> DEC-31-1999
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