UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
Form 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2002
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file 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 of (I.R.S. Employer
incorporation or organization) Identification No.)
500 Dallas, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------ -----------------------------------------
Common Units New York Stock Exchange
Securities registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X]
No [ ]
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 June 28, 2002 was approximately
$3,243,518,408. This figure assumes that only the general partner of the
registrant, Kinder Morgan, Inc., Kinder Morgan Management, LLC, their
subsidiaries and their officers and directors were affiliates. As of January 31,
2003, the registrant had 129,971,518 Common Units outstanding.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I
Items 1. Business and Properties............................ 3
and 2. General............................................ 3
Business Strategy.................................. 4
Recent Developments................................ 6
Products Pipelines................................. 8
Natural Gas Pipelines.............................. 19
CO2 Pipelines...................................... 24
Terminals.......................................... 26
Major Customers.................................... 30
Employees.......................................... 30
Regulation......................................... 30
Environmental Matters.............................. 34
Risk Factors....................................... 36
Item 3. Legal Proceedings.................................. 40
Item 4. Submission of Matters to a Vote of Security Holders 40
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters................................ 41
Item 6. Selected Financial Data............................ 42
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................ 44
Critical Accounting Policies and Estimates......... 44
Results of Operations.............................. 45
Outlook............................................ 52
Liquidity and Capital Resources.................... 54
New Accounting Pronouncements...................... 68
Information Regarding Forward-Looking Statements... 69
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk........................................ 71
Energy Financial Instruments....................... 71
Interest Rate Risk................................. 72
Item 8. Financial Statements and Supplementary Data........ 73
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................ 73
PART III
Item 10. Directors and Executive Officers of the Registrant. 74
Directors and Executive Officers of our General
Partner and the Delegate........................... 74
Section 16(a) Beneficial Ownership Reporting
Compliance......................................... 76
Item 11. Executive Compensation............................. 76
Item 12. Security Ownership of Certain Beneficial Owners
and Management and Related Stockholder Matters..... 82
Item 13. Certain Relationships and Related Transactions..... 84
Item 14. Controls and Procedures............................ 85
PART IV
Item 15. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K................................ 86
Index to Financial Statements...................... 89
Signatures..................................................... 160
Certifications................................................. 161
2
PART I
Items 1. and 2. Business and Properties.
General
Kinder Morgan Energy Partners, L.P., a Delaware limited partnership, is a
publicly traded limited partnership that was formed in August 1992. We are the
largest publicly-traded pipeline limited partnership in the United States in
terms of market capitalization and we own the largest independent refined
petroleum products pipeline system in the United States in terms of volumes
delivered. Unless the context requires otherwise, references to "we", "us",
"our", "KMP" or the "Partnership" are intended to mean Kinder Morgan Energy
Partners, L.P., our operating limited partnerships and their subsidiaries.
We make available free of charge on or through our Internet website, at
http://www.kindermorgan.com, our annual report on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed
or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as
reasonably practicable after we electronically file such material with, or
furnish it to, the Securities and Exchange Commission. In addition, you should
read the following discussion and analysis in conjunction with our Consolidated
Financial Statements included elsewhere in this report.
The address of our principal executive offices is 500 Dallas, Suite 1000,
Houston, Texas 77002, and our telephone number at this address is (713)
369-9000. Our common units trade on the New York Stock Exchange under the symbol
"KMP".
We provide services to our customers and create value for our unitholders
primarily through the following activities:
o transporting, storing and processing refined petroleum products;
o transporting, storing and selling natural gas;
o producing, transporting and selling carbon dioxide for use in, and
selling crude oil produced from, enhanced oil recovery operations; and
o transloading, storing and delivering a wide variety of bulk, petroleum and
petrochemical products at terminal facilities located across the United
States.
We focus on providing fee-based services to customers, avoiding commodity
price risks and taking advantage of the tax benefits of a limited partnership
structure. The assets we own or operate are grouped into the following business
segments:
o Products Pipelines: Delivers gasoline, diesel fuel, jet fuel and natural
gas liquids to various markets on over 10,000 miles of products pipelines
and 32 associated terminals serving customers across the United States;
o Natural Gas Pipelines: Transports, stores and sells natural gas and has
over approximately 15,000 miles of natural gas transmission pipelines, plus
natural gas gathering and storage facilities;
o CO2 Pipelines: Produces, transports through pipelines and markets carbon
dioxide, commonly called CO2, to oil fields that use CO2 to increase
production of oil, and owns interests in and/or operates five oil fields in
West Texas; and
o Terminals: Composed of approximately 50 owned or operated liquid and bulk
terminal facilities and more than 60 rail transloading facilities located
throughout the United States. Our terminals segment can handle over 60
million tons of coal, petroleum coke and other dry-bulk materials annually
and has a liquids storage capacity of approximately 35 million barrels for
refined petroleum products, chemicals and other liquid products.
3
Since February 1997, our operations have experienced significant growth,
and our net income has increased from $17.7 million, for the year ended December
31, 1997, to $608.4 million, for the year ended December 31, 2002. In February
1997, Kinder Morgan (Delaware), Inc., a Delaware corporation, acquired all of
the issued and outstanding stock of our general partner, changed the name of our
general partner to Kinder Morgan, G.P., Inc., and changed our name to Kinder
Morgan Energy Partners, L.P.
In October 1999, K N Energy, Inc., a Kansas corporation that provided
integrated energy services, acquired Kinder Morgan (Delaware), Inc. At the time
of the closing of this transaction, K N Energy, Inc. changed its name to Kinder
Morgan, Inc., referred to herein as KMI. In connection with the acquisition,
Richard D. Kinder, Chairman and Chief Executive Officer of our general partner
and its delegate (see below), became the Chairman and Chief Executive Officer of
KMI. KMI trades on the New York Stock Exchange under the symbol "KMI" and is one
of the largest energy transportation and storage companies in the United States,
operating, either for itself or on our behalf, more than 30,000 miles of natural
gas and products pipelines. KMI also has significant retail distribution assets
and interests in electric generation assets. At December 31, 2002, KMI and its
consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 19.2% interest in us.
In addition to the distributions it receives from its limited and general
partner interests, KMI also indirectly receives an incentive distribution from
us as a result of its ownership of our general partner. This incentive
distribution is calculated in increments based on the amount by which quarterly
distributions to unitholders exceed specified target levels as set forth in our
partnership agreement, reaching a maximum of 50% of distributions allocated to
the general partner for distributions above $0.23375 per limited partner unit
per quarter. Including both its general and limited partner interests in us, at
the 2002 distribution level, KMI received approximately 51% of all quarterly
distributions from us, of which approximately 40% is attributable to its general
partner interest and 11% is attributable to its limited partner interest. The
actual level of distributions KMI will receive in the future will vary with the
level of distributions to the limited partners determined in accordance with our
partnership agreement.
In February 2001, Kinder Morgan Management, LLC, a Delaware limited liability
company referred to herein as KMR, was formed. Our general partner owns all of
KMR's voting securities and, pursuant to a delegation of control agreement, our
general partner delegated to KMR, to the fullest extent permitted under Delaware
law and our partnership agreement, all of its power and authority to manage and
control our business and affairs, except that KMR cannot take certain specified
actions without the approval of our general partner. Under the delegation of
control agreement, KMR, as the delegate of our general partner, manages and
controls our business and affairs and the business and affairs of our operating
limited partnerships and their subsidiaries. Furthermore, in accordance with its
limited liability company agreement, KMR's activities are limited to being a
limited partner in, and managing and controlling the business and affairs of us,
our operating limited partnerships and their subsidiaries.
In May 2001, KMR issued 2,975,000 of its shares representing limited liability
company interests to KMI and 26,775,000 of its shares to the public in an
initial public offering. The shares trade on the New York Stock Exchange under
the symbol "KMR". KMR became a limited partner in us by using substantially all
of the net proceeds from that offering to purchase i-units from us. The i-units
are a separate class of limited partner interests in us and are issued only to
KMR. Under the terms of our partnership agreement, the i-units are entitled to
vote on all matters on which the common units are entitled to vote. In general,
the i-units, common units and Class B units (the Class B units are similar to
our common units except that they are not eligible for trading on the New York
Stock Exchange), will vote together as a single class, with each i-unit, common
unit, and Class B unit having one vote. We pay our quarterly distributions from
operations and from interim capital transactions to KMR in additional i-units
rather than in cash. At December 31, 2002, KMR, through its ownership of our
i-units, owned approximately 25.2% of all of our outstanding limited partner
units. KMR shares and all classes of our limited partner units were split
two-for-one on August 31, 2001, and all dollar and numerical references to such
shares and units in this paragraph and in this report have been adjusted to
reflect the effect of the split.
Business Strategy
Our business strategy is substantially the same today as it was when our
current management began managing our business in early 1997. The objective of
our business strategy is to grow our portfolio of businesses by:
o providing, for a fee, transportation, storage and handling services which
are core to the energy infrastructure of
4
growing markets;
o increasing utilization of our assets while controlling costs by:
o operating classic fixed-cost businesses with little variable costs;
and
o improving productivity to drop all top-line growth to the bottom
line;
o leveraging economies of scale from incremental acquisitions and
expansions principally by:
o reducing needless overhead; and
o eliminating duplicate costs in core operations; and
o maximizing the benefits of our financial structure, which allows us to:
o minimize the taxation of net income, thereby increasing
distributions from our high cash flow businesses; and
o maintain a strong balance sheet, thereby allowing flexibility when
raising capital for acquisitions and/or expansions.
We primarily transport and/or handle products for a fee and generally are not
engaged in the unmatched purchase and resale of commodity products. As a result,
we do not face significant risks relating directly to movements in commodity
prices.
Generally, as utilization of our pipelines and terminals increases, our
fee-based revenues increase. Increases in utilization are principally driven by
increases in demand for gasoline, jet fuel, natural gas and other energy
products transported and/or handled by us. Increases in demand for these
products are generally driven by demographic growth in markets we serve,
including the rapidly growing western and southeastern United States.
We regularly consider and enter into discussions regarding potential
acquisitions, including those from KMI or its affiliates, and are currently
contemplating potential acquisitions. While there are currently no unannounced
purchase agreements for the acquisition of any material business or assets, such
transactions can be effected quickly, may occur at any time and may be
significant in size relative to our existing assets or operations.
Products Pipelines. We plan to continue to expand our presence in the growing
refined petroleum products markets in the western and southeastern United States
through incremental expansions of pipelines and through pipeline and terminal
acquisitions that we believe will increase distributable cash. Because our North
System serves a relatively mature market, we intend 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.
Natural Gas Pipelines. We intend to grow our Texas intrastate natural gas
transportation and storage businesses by identifying and serving significant new
customers with demand for capacity on our pipeline systems and reducing
volatility through long-term agreements. Kinder Morgan Interstate Gas
Transmission serves a stable, mature market, and thus we are focused on reducing
costs and securing throughput for this pipeline. New measurement systems and
other improvements will aid in managing expenses. We will explore expansion and
storage opportunities to increase utilization levels throughout our natural gas
pipeline systems. Trailblazer has recently expanded its system and has supported
the expansion with long-term commitments secured in 2002. Red Cedar Gathering
Company, a partnership with the Southern Ute Indian Tribe, is pursuing
additional gathering and processing opportunities on tribal lands.
CO2 Pipelines. Our carbon dioxide business has two primary strategies: (a)
increase third party sales and transport of carbon dioxide, or service provider,
and (b) increase flooding for our own account, or production. As a service
provider, our strategy is to offer customers "one-stop shopping" for carbon
dioxide supply, transportation
5
and technical support service. In our production business, we plan to grow
production from our SACROC oil field by increasing our use of carbon dioxide in
enhanced oil recovery projects. Outside the Permian Basin, we intend to compete
aggressively for new supply and transportation projects, including the
acquisition of attractive carbon dioxide injection projects that would further
increase the demand for our carbon dioxide reserves and utilization of our
carbon dioxide pipeline assets. Our management believes these projects will
arise as other United States oil producing basins mature and make the transition
from primary production to enhanced recovery methods.
Terminals. We are dedicated to growing our terminals segment through a core
strategy which includes dedicating capital to expand existing facilities,
maintaining a strong commitment to operational safety and efficiency and growing
through strategic acquisitions. During 2002, we increased our ownership and
operation of liquids and bulk terminals by the announcement of four major
investment projects totaling approximately $172 million. The bulk terminals
industry in the United States is highly fragmented, leading to opportunities for
us to make selective, accretive acquisitions. In addition to efforts to expand
and improve our existing terminals, we plan to design, construct and operate new
facilities for current and prospective customers. Our management believes we can
use newly acquired or developed facilities to leverage our operational expertise
and customer relationships. In addition, we believe the combination of our
liquids and bulk terminals businesses into one segment gives us a competitive
advantage in pursuing acquisitions of terminals that handle both bulk and liquid
materials.
Recent Developments
During 2002, our assets increased 24% and our net income increased 38% from
2001 levels. In addition, distributions per unit increased 14% from $0.55 for
the fourth quarter of 2001 to $0.625 for the fourth quarter of 2002.
The following is a brief listing of activity since December 31, 2001.
Additional information regarding these items is contained in the rest of this
report.
o In January 2002, we paid approximately $29 million to NOVA Chemicals
Corporation for an additional 10% ownership interest in the Cochin Pipeline
System. Including this acquisition, we now own approximately 44.8% of the
Cochin Pipeline System. The acquisition was effective as of December 31,
2001. We record our proportionate share of the operations of the Cochin
Pipeline System as part of our Products Pipelines business segment;
o Effective January 31, 2002, we acquired all of the equity interests of
Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America),
Inc., for approximately $881.5 million, including the assumption of
approximately $154.4 million of liabilities. Tejas Gas, LLC owns a 3,400
mile intrastate natural gas pipeline system with 16 compressor stations,
two natural gas storage facilities with approximately 3.5 billion cubic
feet per day of working gas capacity and three natural gas processing
treating facilities. The acquired assets are referred to as Kinder Morgan
Tejas in this report, and together with our Kinder Morgan Texas Pipeline
system, form our Texas intrastate natural gas pipeline group, which is
included in our Natural Gas Pipelines business segment and referred to as
Kinder Morgan Texas in this report;
o On February 4, 2002, we announced two acquisitions and a major expansion
project, both within our Terminals business segment, totaling approximately
$43 million. The purchases included Pittsburgh, Pennsylvania-based Laser
Materials Services LLC, later renamed Kinder Morgan Materials Services LLC,
operator of more than 60 transload facilities in 20 states, and a 66 2/3%
ownership interest in International Marine Terminals Partnership, which
operates a bulk terminal site in Port Sulphur, Louisiana. The major
expansion project to our Carteret, New Jersey liquids terminal added
400,000 barrels of liquids storage capacity;
o On April 24, 2002, we announced a $160 million investment project to expand
our carbon dioxide business. The project includes the construction of a
new $40 million pipeline that will be commonly known as the Centerline
Pipeline. The pipeline will originate near Denver City, Texas and transport
carbon dioxide to the Snyder,Texas area. The pipeline will consist of 113
miles of 16-inch pipe and will primarily supply the SACROC Unit in the
Permian Basin of West Texas, but will also be available for existing and
prospective third-party carbon dioxide projects in the Horseshoe Atoll area
of the Permian Basin. Construction is expected to be completed in mid-2003.
The project also includes the spending of approximately $120 million to add
6
additional infrastructure, including wells, injection and compression
facilities, to support the expanding carbon dioxide flooding operations at
the SACROC Unit. Based on positive response, by the end of 2002, we
committed an additional $63 million to develop SACROC. These expenditures
are expected to quadruple carbon dioxide deliveries to the SACROC Unit and
triple oil production when compared to 2001 levels of 80 million cubic feet
per day of carbon dioxide and 9,000 barrels per day of crude oil;
o On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for
$68 million in cash. We now own 100% of Trailblazer Pipeline Company.
During the first quarter of 2002, we paid $12.0 million to CIG Trailblazer
Gas Company, an affiliate of El Paso Corporation, in exchange for CIG's
relinquishment of its rights to become a 7% to 8% equity owner in
Trailblazer Pipeline Company in mid-2002. KMI operates, on our behalf,
Trailblazer's 436-mile interstate natural gas pipeline that runs from
Rockport, Colorado to Beatrice, Nebraska;
o On May 7, 2002, we completed and placed into service our previously
announced $59 million expansion project on the Trailblazer pipeline. The
expansion project began in August 2001, as growth in Rocky Mountain natural
gas supplies created the need for additional pipeline transportation
infrastructure. The expansion project increased transportation capacity on
the pipeline by 60% to 846,000 dekatherms per day of natural gas, and the
increase has already been fully subscribed by customers. The project
included installing two new compressor stations and adding 10,000
additional horsepower at an existing compressor station;
o On May 23, 2002, we announced an approximately $50 million investment in
our Terminals business segment. The investment provides for storage
expansions and upgrade projects at our liquids terminals located in
Carteret, New Jersey, Pasadena, Texas and Dravosburg, Pennsylvania, as well
as the acquisition of a bulk terminal bagging operation located adjacent to
our existing Milwaukee, Wisconsin dry-bulk terminal. The bulk of this
expansion work will take place at our Carteret and Pasadena liquids
terminals, and will follow the expansions that we initiated in 2001. The
expansion project at our Carteret (New York Harbor area) facility will
supplement the expansion we announced in February 2002 and will add an
additional 400,000 barrels of petroleum storage capacity and will include
the construction of a new 16-inch pipeline that will connect our Carteret
facility to the Buckeye Pipeline system, a major refined petroleum products
pipeline serving the East Coast. The expansion work at our Carteret
terminal is expected to be completed in the third quarter of 2003. The
expansion project at our Pasadena (Houston, Texas ship channel) facility
will increase storage capacity by another 300,000 barrels of petroleum
products and is expected to be completed in the second quarter of 2003;
o On June 27, 2002, we announced a $30 million investment project that
involves the construction of pipeline, compression and storage facilities
to accommodate an additional 6 billion cubic feet of natural gas storage
capacity at Kinder Morgan Interstate Gas Transmission LLC's Cheyenne Market
Center. This additional capacity has been fully subscribed under 10-year
contracts. The Cheyenne Market Center offers firm natural gas storage
capabilities that will allow for the receipt, storage and subsequent
re-delivery of natural gas supplies at applicable points located in the
vicinity of the Cheyenne Hub in Weld County, Colorado and our Huntsman
storage facility in Cheyenne County, Nebraska. The Cheyenne Market Center
is expected to begin service during the summer of 2004;
o On July 15, 2002, we announced a $116 million project to expand the
capacity on a 190-mile segment of the Plantation Pipe Line system. The
project will entail replacing an existing eight-inch pipeline between
Bremen, Georgia and Knoxville, Tennessee with a new 20-inch pipeline. The
expansion will double capacity on this segment of the pipeline to
approximately 90,000 barrels per day of refined petroleum products.
Construction will be initiated only after additional commitments from
interested shippers are obtained;
o On August 6, 2002, KMR closed the public offering of 12,478,900 of its
shares (including over-allotment shares) at a price of $27.50 per share,
less commissions and underwriting expenses. The net proceeds from the
offering were used to buy additional i-units from us. We used the proceeds
of approximately $331.2 million from the i-unit issuance to reduce the debt
we incurred in our acquisition of Kinder Morgan Tejas. On August 23, 2002,
we also issued $500 million of 31-year debt with a coupon of 7.3% and $250
million of five-year debt with a coupon of 5.35%. The equity and debt
financing activities completed our long-term
7
financing for our Kinder Morgan Tejas gas system. We have no significant
senior note maturities due until 2005;
o On August 31, 2002, we completed construction of a $70 million, 86-mile,
30-inch natural gas pipeline in Texas. The new pipeline transports natural
gas from an interconnect with KMI's Natural Gas Pipeline Company of America
system in Lamar County, Texas to an existing 1,000-megawatt electric
generating facility in Lamar County, as well as a new 1,789-megawatt
electric generating facility currently being built in Kaufman County, Texas
by FPL Energy, LLC, a subsidiary of FPL Group, Inc. FPL Energy has entered
into a 30-year long-term, binding firm transportation contract with us for
the full 325,000 dekatherms per day of natural gas capacity.
o On September 1, 2002, we entered into long-term transportation storage and
sales contracts with BP Energy of North America. Through the agreements, BP
will have access to our Kinder Morgan Texas pipeline system with
transportation capacity of up to one billion cubic feet of natural gas per
day and storage capacity of up to 19 billion cubic feet of natural gas.
These long-term BP contracts reserve a large portion of the 5 billion cubic
feet per day of natural gas peak capacity on Kinder Morgan Texas and are
expected to add significantly to operating results once the full contract
quantities are transported in the spring of 2003;
o On October 10, 2002, we announced an approximately $36 million investment
in our Terminals business segment. The investment includes the acquisition
of two terminal facilities and a storage expansion project at our liquids
terminal located in Perth Amboy, New Jersey. Effective September 1, 2002,
we acquired a bulk terminal facility along the Ohio River near Owensboro,
Kentucky, and a liquids terminal facility along the Mississippi River near
St. Gabriel, Louisiana. The bulk terminal is one of the nation's largest
storage and handling points for bulk aluminum and the liquids terminal
features 400,000 barrels of storage capacity and a related pipeline network
that serves the southern Louisiana area. The expansion at our Perth Amboy
terminal includes the construction of an additional 300,000 barrels of
storage capacity and increases the petroleum capacity at the facility by
more than 20%. The expansion was undertaken as a result of a long-term
storage agreement that we entered into with a petroleum customer;
o On November 11, 2002, we began construction on the new $87 million,
95-mile, 30-inch Mier-Monterrey natural gas pipeline that stretches from
South Texas to Monterrey, Mexico, one of Mexico's fastest growing
industrial areas. The new pipeline will interconnect with the southern end
of our Kinder Morgan Texas pipeline system in Starr County, Texas, and is
designed to initially transport up to 375,000 dekatherms per day of natural
gas. We have entered into a 15-year contract with Pemex Gas Y Petroquimica
Basica, which has subscribed for all of the capacity on the pipeline. The
pipeline will connect to a 1,000-megawatt power plant complex and to the
Pemex natural gas transportation system. Construction of the pipeline is
expected to be completed during the second quarter of 2003; and
o On January 7, 2003, we announced a $43 million investment to enlarge and
improve our bulk terminals businesses. The investment included the
acquisition of long-term lease contracts to operate four bulk terminal
facilities at major ports along the East Coast and in the southeastern
United States, and certain assets that provide stevedoring services at
these locations. In addition, we purchased four floating cranes at our bulk
terminal facility in Port Sulphur, Louisiana. The loading equipment
previously had been leased from a third party under an operating lease.
Our operations are grouped into four reportable business segments. For more
information on our reportable business segments, see Note 15 to our Consolidated
Financial Statements. These segments and their major assets are as follows:
Products Pipelines
Our Products Pipelines segment consists of refined petroleum products and
natural gas liquids pipelines, related terminals and transmix processing
facilities, including:
o our Pacific operations, which include interstate common carrier pipelines
regulated by the Federal Energy Regulatory Commission, intrastate pipelines
in California regulated by the California Public Utilities
8
Commission and certain non rate-regulated operations and terminal
facilities. Specifically, our Pacific operations include:
o our SFPP, L.P. operations, comprised of approximately 3,300 miles of
pipelines that transport refined petroleum products to some of the
faster growing population centers in the United States, including Los
Angeles, San Diego, and Orange County, California; the San Francisco
Bay Area; Las Vegas, Nevada (through our CALNEV pipeline) and Phoenix
and Tucson, Arizona, and 13 truck-loading terminals with an aggregate
usable tankage capacity of approximately 8.2 million barrels;
o our CALNEV pipeline operations, comprised of a 550-mile pipeline that
transports refined petroleum products from Colton, California to the
growing Las Vegas, Nevada market, and two refined petroleum products
terminals located in Barstow, California and Las Vegas, Nevada; and
o our West Coast terminals operations, which are comprised of seven
terminal facilities on the West Coast that transload and store
refined petroleum products;
o our Central Florida Pipeline, a 195-mile pipeline that transports refined
petroleum products from Tampa to the Orlando, Florida market and two
refined petroleum products terminals at Tampa and Orlando, Florida;
o our 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, and our
50% interest in the Heartland Pipeline Company, which ships refined
petroleum products in the Midwest;
o our 51% interest in Plantation Pipe Line Company, which owns and operates a
3,100-mile pipeline system that transports refined petroleum products
throughout the southeastern United States, serving major metropolitan areas
including Birmingham, Alabama; Atlanta, Georgia; Charlotte, North Carolina;
and the Washington, D.C. area;
o our 44.8% interest in the Cochin Pipeline System, a 1,900-mile pipeline
transporting natural gas liquids and traversing Canada and the United
States from Fort Saskatchewan, Alberta to Sarnia, Ontario, including four
terminals;
o our Cypress Pipeline, a 104-mile pipeline transporting natural gas liquids
from Mont Belvieu, Texas to a major petrochemical producer in Lake Charles,
Louisiana; and
o our transmix operations, which include the processing of petroleum pipeline
transmix through transmix processing plants in Colton, California;
Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; and
Wood River, Illinois.
Pacific Operations
Our Pacific operations' pipelines are split into a South Region and a North
Region. Combined, the two regions consist of seven pipeline segments that serve
six western states with approximately 3,900 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
Our Pacific operations transport over 1.1 million barrels per day of refined
petroleum products, providing pipeline service to approximately 44
customer-owned terminals, four commercial airports and 13 military bases. For
2002, the three main product types transported were gasoline (63%), diesel fuel
(21%) and jet fuel (16%). Our
9
Pacific operations also include 15 truck-loading terminals (13 on SFPP,
L.P. and two on CALNEV).
Our Pacific operations provide refined petroleum products to some of the
fastest growing population centers in the United States, including southern
California; Las Vegas and Reno, Nevada; and the Phoenix, Arizona region.
Pipeline transportation of gasoline and jet fuel generally has a direct
correlation with demographic patterns. We believe that the population growth
associated with the markets served by our Pacific operations will continue in
the foreseeable future.
South Region. Our Pacific operations' South Region consists of four pipeline
segments:
o West Line;
o East Line;
o San Diego Line; and
o CALNEV Line.
The West Line consists of approximately 630 miles of primary pipeline and
currently transports products for 45 shippers from six refineries and three
pipeline terminals in the Los Angeles Basin to Phoenix and Tucson, Arizona and
various intermediate commercial and military delivery points. Product for the
West Line can also come from foreign sources through the Los Angeles and Long
Beach port complexes and the three pipeline terminals. A significant portion of
West Line volumes is transported to Colton, California for local distribution
and for delivery to our CALNEV Pipeline. The West Line serves our terminals
located in Colton and Imperial, California as well as in Phoenix and Tucson,
Arizona.
The East Line is comprised of two parallel 8-inch and 12-inch pipelines
originating in El Paso, Texas and continuing approximately 300 miles west to our
Tucson terminal and one line continuing northwest approximately 130 miles from
Tucson to Phoenix. 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 Texas and New Mexico. The East Line serves our
terminals located in Phoenix and Tucson as well as various intermediate
commercial and military delivery points.
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. The San Diego Line serves our terminals at Orange and Mission Valley as
well as shipper terminals in San Diego and San Diego Airport through a
non-affiliated connecting pipeline.
The CALNEV Pipeline consists of two parallel 248-mile, 14-inch and 8-inch
pipelines from our facilities at Colton, California to Las Vegas, Nevada. It
also includes approximately 55 miles of pipeline serving Edwards Air Force Base.
This pipeline originates at Colton, California and serves two CALNEV terminals
at Barstow, California and Las Vegas, Nevada. The CALNEV Pipeline also serves
the military at Edwards Air Force Base and Nellis Air Force Base, as well as
certain smaller delivery points, including the Burlington Northern Santa Fe and
Union Pacific railroad yards.
North Region. Our Pacific operations' North Region consists of three pipeline
segments:
o the North Line;
o the Bakersfield Line; and
o the Oregon Line.
The North Line consists of approximately 1,075 miles of pipeline in five
segments originating in Richmond and Concord, California. This line serves our
terminals located in Brisbane, Sacramento, Chico, Fresno and San Jose,
California, and Reno, Nevada. The products delivered through the North Line come
from refineries in the San
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Francisco Bay Area. The North Line also receives product transported from
various pipeline and marine terminals that deliver products from foreign and
domestic ports.
The Bakersfield Line is a 100-mile, 8-inch pipeline serving Fresno,
California. A refinery located in Bakersfield, California supplies substantially
all of the products shipped through the Bakersfield Line.
The Oregon Line is a 114-mile pipeline serving 16 shippers. Our Oregon Line
receives products from marine terminals in Portland, Oregon and from Olympic
Pipeline. Olympic Pipeline is a non-affiliated pipeline that transports products
from the Puget Sound, Washington area to Portland. From its origination point in
Portland, the Oregon Line extends south and serves our terminal located in
Eugene, Oregon.
West Coast Terminals. These terminals are operated as part of our Pacific
operations.
The terminals include:
o the Carson Terminal;
o the Los Angeles Harbor Terminal;
o the Gaffey Street Terminal;
o the Richmond Terminal;
o the Linnton and Willbridge Terminals; and
o the Harbor Island Terminal.
The West Coast Terminals are fee-based terminals. They are located in several
strategic locations along the west coast of the United States and have a
combined total capacity of nearly eight million barrels of storage for both
petroleum products and chemicals.
The Carson Terminal and the connecting Los Angeles Harbor Terminal are
strategically located near the many refineries in the Los Angeles Basin. The
combined Carson/LA Harbor system is connected to numerous other pipelines and
facilities throughout the Los Angeles area, which gives the system significant
flexibility and allows customers to quickly respond to market conditions.
Storage at the Carson facility is primarily arranged via term contracts with
customers, ranging from one to five years. Term contracts represent 56% of total
revenues at the facility.
The Gaffey Street Terminal in San Pedro, California, is adjacent to the Port
of Los Angeles. This facility serves as a marine fuel storage and blending
facility for the marketing of local or imported bunker fuels for Los Angeles
ship traffic.
The Richmond Terminal is located in the San Francisco Bay Area. The facility
serves as a storage and distribution center for chemicals, lubricants and
paraffin waxes. It is also the principal location in northern California through
which tropical oils are imported for further processing, and from which United
States' produced vegetable oils are exported to consumers in the Far East.
The Linnton and Willbridge Terminals are located in Portland, Oregon. These
facilities handle petroleum products for distribution to both local and regional
markets. Refined products are received by pipeline, marine vessel, barge, and
rail car for distribution to local markets by truck; to southern Oregon via our
Oregon Line; to Portland International Airport via a non-affiliated pipeline;
and to eastern Washington and Oregon by barge.
The Harbor Island Terminal is located in Seattle, Washington. The facility is
supplied via pipeline and barge from northern Washington-state refineries,
allowing customers to distribute fuels economically to the greater Seattle-area
market by truck. The terminal also has the largest capacity of marine fuel oil
tanks in Puget Sound, along with a multi-component, in-line blending system for
providing customized bunker fuels to the marine
11
industry.
Truck-Loading Terminals. Our Pacific operations include 15 truck-loading
terminals (13 on SFPP, L.P. and two on CALNEV) with an aggregate usable tankage
capacity of approximately nine million barrels. The truck terminals are located
at destination points on each of our Pacific operations' pipelines as well as at
certain intermediate points along each pipeline. The simultaneous truck-loading
capacity of each terminal ranges from 2 to 12 trucks. We provide 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 our Pacific
operations, and we do not own terminaling facilities at all pipeline delivery
locations. We charge a separate fee (in addition to pipeline tariffs) for these
additional terminaling services. These fees are not regulated except for the
fees at the CALNEV terminals. At certain locations, we make product deliveries
to facilities owned by shippers or independent terminal operators.
Markets. Currently our Pacific operations' pipeline system serves
approximately 76 shippers in the refined products market, with the largest
customers consisting of:
o major petroleum companies;
o independent refiners;
o the United States military; and
o independent marketers and distributors of refined petroleum products.
A substantial portion of the product volume transported is gasoline. Demand
for gasoline depends on such factors as prevailing economic conditions,
vehicular use patterns and demographic changes in the markets served. We expect
the majority of our Pacific operations' markets to maintain growth rates that
exceed the national average for the foreseeable future.
Currently, the California gasoline market is approximately 940,000 barrels
per day. The Arizona gasoline market is served primarily by us at a market
demand of approximately 155,000 barrels per day. Nevada's gasoline market is
approximately 60,000 barrels per day and Oregon's is approximately 100,000
barrels per day. The diesel and jet fuel market is approximately 510,000 barrels
per day in California, 80,000 barrels per day in Arizona, 50,000 barrels per day
in Nevada and 60,000 barrels per day in Oregon. We transport over 1.1 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.
California has mandated the elimination of MTBE (methyl tertiary-butyl ether)
from gasoline by January 1, 2004. MTBE-blended gasoline will be replaced by an
ethanol blend. Since ethanol is not shipped in our pipelines,
12
this will result in a small reduction in California gasoline volumes. Some
suppliers/marketers are switching to ethanol before the required date, thus some
reduction in gasoline volumes will begin in January 2003. We believe the fees we
will earn for new ethanol-related services at our terminals will more than
offset the expected reduction in pipeline transportation fees.
Supply. The majority of refined products supplied to our Pacific operations'
pipeline system come from the major refining centers around Los Angeles, San
Francisco and Puget Sound, as well as waterborne terminals located near these
refining centers.
Competition. The most significant competitors of our Pacific operations'
pipeline system are proprietary pipelines owned and operated by major oil
companies in the area where our pipeline system delivers products as well as
refineries with related trucking arrangements within our market areas. We
believe 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. The use by major oil companies of trucks in certain markets
has resulted in minor but notable reductions in product volumes delivered to
certain shorter-haul destinations in the Los Angeles and San Francisco Bay
areas. We cannot predict with certainty whether the use of short-haul trucking
will continue or increase in the future.
Longhorn Partners Pipeline is a joint venture pipeline project that is
expected to begin transporting refined products from refineries on the Gulf
Coast to El Paso and other destinations in Texas in 2003. Increased product
supply in the El Paso area could result in some shift of volumes transported
into Arizona from our West Line to our East Line. While increased movements into
the Arizona market from El Paso would displace higher tariff volumes supplied
from Los Angeles on our West Line, our East Line is currently running at full
capacity and such shift of supply sourcing has not had, and is not expected to
have, a material effect on operating results.
Competitors of the Carson Terminal in the refined products market include
Shell Oil Products U.S. and BP (formerly Arco Terminal Services Company). In the
crude/black oil market, competitors include Edison Pipeline & Terminal Company,
Wilmington Liquid Bulk Terminals (Vopak) and BP. Competitors to Gaffey Street
include ST Services, Chemoil and Wilmington Liquid Bulk Terminals (Vopak).
Competition to the Richmond Terminal's chemical business comes primarily from
IMTT. Competitors to our Linnton and Willbridge Terminals include ST Services,
ChevronTexaco and Shell Oil Products U.S. Our Harbor Island Terminal competes
primarily with nearby terminals owned by Shell Oil Products U.S. and
ConocoPhillips.
Central Florida Pipeline
We own and operate a liquids terminal in Tampa, Florida, a liquids terminal
in Taft, Florida (near Orlando, Florida) and an intrastate common carrier
pipeline system that serves customers' product storage and transportation needs
in Central Florida. The Tampa Terminal contains 31 above-ground storage tanks
consisting of approximately 1.4 million barrels of storage capacity and is
connected to two ship dock facilities in the Port of Tampa that unload refined
products from barges and ocean-going vessels into the terminal. The Tampa
Terminal provides storage for gasoline, diesel fuel and jet fuel for further
movement into either trucks through five truck-loading racks or into the Central
Florida Pipeline system. The Tampa Terminal also provides storage for chemicals,
predominantly used to treat citrus crops, delivered to the terminal by vessel or
rail car and loaded onto trucks through five truck-loading racks. The Taft
Terminal contains 22 above-ground storage tanks consisting of approximately
670,000 barrels of storage capacity, providing storage for gasoline and diesel
fuel for further movement into trucks through 11 truck-loading racks.
The Central Florida Pipeline system consists of a 110-mile, 16-inch pipeline
that transports gasoline and an 85-mile, 10-inch pipeline that transports diesel
fuel and jet fuel from Tampa to Orlando, with an intermediate delivery point on
the 10-inch pipeline at Intercession City, Florida. The Central Florida Pipeline
is the only major refined products pipeline in the State of Florida. In addition
to being connected to our Tampa Terminal, the pipeline system is connected to
terminals owned and operated by TransMontaigne, Citgo, BP, and Marathon Ashland
Petroleum. The 10-inch pipeline is connected to our Taft Terminal and is also
the sole pipeline supplying jet fuel to the Orlando International Airport in
Orlando, Florida. In 2002, the pipeline transported approximately 94,000 barrels
per day of refined products, with the product mix being approximately 68%
gasoline, 14% diesel fuel, and 18% jet fuel.
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Markets. The estimated total refined petroleum product demand in the State of
Florida is approximately 785,000 barrels per day. Gasoline is, by far, the
largest component of that demand at approximately 500,000 barrels per day. The
total refined petroleum products demand for the Central Florida region of the
state, which includes the Tampa and Orlando markets, is estimated to be 335,000
barrels per day, or approximately 43% of the consumption of refined products in
the state. Our market share is approximately 120,000 barrels per day, or
approximately 36% of the Central Florida market. Most of the jet fuel used at
Orlando International Airport is moved through our Tampa Terminal and the
Central Florida Pipeline system. The market in Central Florida is seasonal, with
demand peaks in March and April during spring break and again in the summer
vacation season, and is also heavily influenced by tourism, with Disney World
and other amusement parks located in Orlando.
Supply. The vast majority of refined petroleum products consumed in Florida
is supplied from major refining centers in the gulf coast of Louisiana and
Mississippi and refineries in the Caribbean basin. A lesser amount of refined
products is being supplied by refineries in Alabama and by Texas Gulf Coast
refineries via marine vessels and through pipeline networks that extend to
Bainbridge, Georgia. The supply into Florida is generally transported by
ocean-going vessels to the larger metropolitan ports, such as Tampa, Port
Everglades near Miami, and Jacksonville. Individual markets are then supplied
from terminals at these ports and other smaller ports, predominately by trucks,
except the Central Florida region, which is served by a combination of trucks
and pipelines.
Competition. With respect to the terminal operations at Tampa, the most
significant competitors are proprietary terminals owned and operated by major
oil companies, such as Marathon Ashland Petroleum, BP and Citgo, located along
the Port of Tampa, and the ChevronTexaco and Motiva terminals in Port Tampa.
These terminals generally support the storage requirements of their parent or
affiliated companies' refining and marketing operations and provide a mechanism
for an oil company to enter into exchange contracts with third parties to serve
its storage needs in markets where the oil company may not have terminal assets.
Due to the high capital costs of tank construction in Tampa and state
environmental regulation of terminal operations, we believe it is unlikely that
new competing terminals will be constructed in the foreseeable future.
With respect to the Central Florida Pipeline system, the most significant
competitors are trucking firms and marine transportation firms. Trucking
transportation is more competitive in serving markets west of Orlando that are a
relatively short haul from Tampa, and with respect to markets east of Orlando,
our competition is trucks and product movements from marine terminals on the
east coast of Florida. We are utilizing tariff incentives to attract volumes to
the pipeline that might otherwise enter the Orlando market area by truck from
Tampa or by marine vessel into Cape Canaveral.
Federal regulation of marine vessels, including the requirement, under the
Jones Act, that United States-flagged vessels contain double-hulls, is a
significant factor in reducing the fleet of vessels available to transport
refined petroleum products. Marine vessel owners are phasing in the requirement
based on the age of the vessel and some older vessels are being redeployed into
use in other jurisdictions rather than being retrofitted with a double-hull for
use in the United States. Although we believe it is unlikely that a new pipeline
system comparable in size and scope will be constructed, due to the high cost of
pipeline construction and environmental and right-of-way permitting in Florida,
the possibility of such pipelines being built is a continuing competitive
factor.
North System
Our North System is an approximately 1,600-mile interstate common carrier
pipeline for natural gas liquids and refined petroleum products. Additionally,
we include our 50% ownership interest in Heartland Pipeline Company as part of
our North System operations. ConocoPhillips owns the remaining 50% of Heartland
Pipeline Company.
Natural gas liquids are typically extracted from natural gas in liquid form
under low temperature and high pressure conditions. Natural gas liquids products
and related uses are as follows:
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Product Use
-------------- ----------------------------------------
Propane Residential heating, industrial and agricultural
uses, petrochemical feedstock
Isobutane Further processing
Natural gasoline Further processing or blending into gasoline motor
fuel
Ethane/Propane Feedstock for petrochemical plants or peak-shaving
Mix facilities
Normal butane Feedstock for petrochemical plants or blending into
gasoline motor fuel
Our 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 natural gas liquids. Our 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 single 50-mile pipeline segment in
Nebraska and Iowa), that originate at Bushton, Kansas and continue to a
major storage and terminal area in Des Moines, Iowa;
o a third pipeline, that extends from Bushton to the Kansas City, Missouri
area; and
o a fourth pipeline that extends from Des Moines to the Chicago area.
Through interconnections with other major liquids pipelines, our North
System's pipeline system connects mid-continent producing areas to markets in
the Midwest and eastern United States. We also have defined sole carrier rights
to use capacity on an extensive pipeline system owned by Williams Energy
Partners, L.P. that interconnects with our North System. This capacity lease
agreement requires us to pay $2.0 million per year, is in place until February
2013 and contains a five-year renewal option. In addition to our capacity lease
agreement with Williams, we also have a reversal agreement with Williams to help
provide for the transport of summer-time surplus butanes from Chicago area
refineries to storage facilities at Bushton. We have an annual minimum joint
tariff commitment of $0.6 million to Williams for this agreement.
Our North System has approximately 8.3 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 demands of shippers and provides propane storage for our
truck-loading terminals.
The Heartland pipeline system, which was completed in 1990, comprises one of
our North System's main line sections that originate at Bushton, Kansas and
terminates at a storage and terminal area in Des Moines, Iowa. We operate the
Heartland pipeline, and Conoco Pipe Line operates Heartland's Des Moines, Iowa
terminal and serves as the managing partner of Heartland. In 2000, Heartland
leased to ConocoPhillips Inc. 100% of the Heartland terminal capacity at Des
Moines, Iowa for $1.0 million per year on a year-to-year basis. The Heartland
pipeline lease fee, payable to us for reserved pipeline capacity, is paid
monthly, with an annual adjustment. The 2003 lease fee will be approximately
$1.07 million.
In addition, our North System has seven propane truck-loading terminals and
one multi-product complex at Morris, Illinois, in the Chicago area. Propane,
normal butane and natural gasoline can be loaded at our Morris terminal.
Markets. Our North System currently serves approximately 50 shippers in the
upper Midwest market, including both users and wholesale marketers of natural
gas liquids. These shippers include all three major refineries in the Chicago
area. Wholesale marketers of natural gas liquids primarily make direct large
volume sales to major end-users, such as propane marketers, refineries,
petrochemical plants and industrial concerns. Market demand for natural gas
liquids varies in respect to the different end uses to which natural gas liquids
products may be applied. Demand for transportation services is influenced not
only by demand for natural gas liquids but also by the available supply of
natural gas liquids. Heartland provides transportation of refined petroleum
products from refineries in the Kansas and Oklahoma areas to a BP Amoco terminal
in Council Bluffs, Iowa, a ConocoPhillips terminal in Lincoln, Nebraska and
Heartland's Des Moines terminal. The demand for, and supply of, refined
petroleum products in the geographic regions served by the Heartland pipeline
system directly affect the volume of refined petroleum products transported by
Heartland.
15
Supply. Natural gas liquids extracted or fractionated at the Bushton gas
processing plant have historically accounted for a significant portion
(approximately 40-50%) of the natural gas liquids transported through our North
System. Other sources of natural gas liquids transported in our North System
include large oil companies, marketers, end-users and natural gas processors
that use interconnecting pipelines to transport hydrocarbons. In 2000, KMI sold
to ONEOK, Inc. the Bushton plant along with other assets previously owned by
KMI. Refined petroleum products transported by Heartland on our North System are
supplied primarily from the National Cooperative Refinery Association crude oil
refinery in McPherson, Kansas and the ConocoPhillips crude oil refinery in Ponca
City, Oklahoma.
Competition. Our North System competes with other natural gas liquids
pipelines and to a lesser extent with rail carriers. In most cases, established
pipelines are the lowest cost alternative for the transportation of natural gas
liquids and refined petroleum products. Consequently, pipelines owned and
operated by others represent our primary competition. With respect to the
Chicago market, our North System competes with other natural gas liquids
pipelines that deliver into the area and with rail car deliveries primarily from
Canada. Other Midwest pipelines and area refineries compete with our North
System for propane terminal deliveries. Our North System also competes
indirectly with pipelines that deliver product to markets that our North System
does not serve, such as the Gulf Coast market area. Heartland competes with
other refined petroleum product carriers in the geographic market served.
Heartland's principal competitor is Williams Energy Partners, L.P.
Plantation Pipe Line Company
We own approximately 51% of Plantation Pipe Line Company, a 3,100-mile
pipeline system serving the southeastern United States. ExxonMobil owns the
remaining 49% interest and represents the single largest shipper on the
Plantation system. On December 21, 2000, we assumed day-to-day operations of
Plantation pursuant to agreements with Plantation Services LLC and Plantation
Pipe Line Company. 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. We believe
favorable demographics in the southeastern United States will serve as a
platform for increased utilization and expansion of Plantation's pipeline
system. For the year 2002, Plantation delivered 637,061 barrels per day, a 3%
improvement over 2001 and an all-time record high volume. These delivered
volumes are comprised of gasoline (68%), diesel/heating oil (20%) and jet fuel
(12%).
Markets. Plantation ships products for approximately 40 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. Plantation's top six shippers represent
slightly over 80% of total system volumes.
The seven states in which Plantation operates represent a collective pipeline
demand of approximately 2.0 million barrels per day of refined products.
Plantation currently has direct access to about 1.5 million barrels per day of
this overall market. The remaining 0.5 million barrels per day of demand lies in
markets (e.g. Nashville, Tennessee; North Augusta, South Carolina; Bainbridge,
Georgia; and Selma, North Carolina) currently served by Colonial Pipeline
Company. These markets represent potential growth opportunities for the
Plantation system.
In addition, Plantation delivers jet fuel to the Atlanta, Georgia; Charlotte,
North Carolina; and Washington, D.C. airports (Ronald Reagan National and
Dulles). While jet fuel shipments on Plantation have improved from the post
September 11, 2001 lows, combined deliveries to the four major airports served
by Plantation continue to be approximately 5% below historical levels. A
significant portion of this deficit is tied to Ronald Reagan National Airport
where demand is down 27% from pre-September 11 levels. We expect to see
continuing growth in jet fuel demand as we recover to pre-September 11 levels.
Plantation continues to develop its project to more than double its capacity
into the Knoxville, Tennessee market. The project scope involves the replacement
of the existing 8-inch diameter pipeline with a larger diameter pipeline.
Plantation is currently working to secure additional shipper volume commitments
to support the investment for this expansion.
16
Plantation is also developing a project to connect to the Colonial Pipeline
system at Greensboro, North Carolina. When this connection becomes operational,
Plantation shippers will have the option of carrying volumes to Greensboro and
then continuing to move to northeast markets via Colonial. This connection will
improve the liquidity of the Plantation system and will create additional
opportunities to attract incremental volumes.
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 is directly
connected to and supplied by a total of nine major refineries representing over
two million barrels per day of refining capacity.
Competition. Plantation competes primarily with Colonial Pipeline Company,
which also runs from Gulf Coast refineries throughout the southeastern United
States and extends into the northeastern states.
Cochin Pipeline System
We own 44.8% of the Cochin Pipeline System, a 1,938-mile, 12-inch
multi-product pipeline operating between Fort Saskatchewan, Alberta and Sarnia,
Ontario.
The Cochin Pipeline System and related storage and processing facilities
consist of Canadian operations and United States operations:
o the Canadian facilities are operated under the name of Cochin Pipe
Lines, Ltd.; and
o the United States facilities are operated under the name of Dome
Pipeline Corporation.
The pipeline operates on a batched basis and has an estimated system capacity
of approximately 112,000 barrels per day. Its peak capacity is approximately
124,000 barrels per day. It includes 31 pump stations spaced at 60 mile
intervals and five United States propane terminals. Associated underground
storage is available at Fort Saskatchewan, Alberta and Windsor, Ontario.
Markets. Formed in the late 1970's as a joint venture, the pipeline traverses
three provinces in Canada and seven states in the United States transporting
high vapor pressure ethane, ethylene, propane, butane and natural gas liquids to
the Midwestern United States and eastern Canadian petrochemical and fuel
markets. The system operates as a National Energy Board (Canada) and Federal
Energy Regulatory Commission (United States) regulated common carrier, shipping
products on behalf of its owners as well as other third parties.
Supply. The system is connected to the Enterprise pipeline system in
Minnesota and in Iowa, and connects with our North System at Clinton, Iowa. The
Cochin Pipeline System has the ability to access the Canadian Eastern Delivery
System via the Windsor Storage Facility Joint Venture at Windsor, Ontario.
Injection into the system can occur from:
o BP Amoco, ChevronTexaco or Dow fractionation facilities at Fort
Saskatchewan, Alberta;
o TransCanada Midstream storage at five points within the provinces of
Canada; or
o the Enterprise West Junction, in Minnesota.
Competition. The pipeline competes with Enbridge Energy Partners for natural
gas liquids longhaul business from Fort Saskatchewan, Alberta and Windsor,
Ontario. The pipeline's primary competition in the Chicago natural gas liquids
market comes from the combination of the Alliance pipeline system, which brings
unprocessed gas into the United States from Canada, and from Aux Sable, which
processes and markets the natural gas liquids in the Chicago market.
Cypress Pipeline
Our Cypress Pipeline is an interstate common carrier pipeline system
originating at storage facilities in Mont
17
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 natural gas liquids gathering, transportation, fractionation and
storage in the United States.
Markets. The pipeline was built to service Westlake Petrochemicals
Corporation 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, Westlake agreed to ship at least an additional
13,700 barrels per day through late 2002, which was later extended through May
2003. Also in 1997, we expanded the Cypress Pipeline's capacity by 25,000
barrels per day to 57,000 barrels per day.
Supply. Our 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 natural gas liquids received from several
pipelines into ethane and other components. Additionally, pipeline systems that
transport specification natural gas liquids from major producing areas in Texas,
New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and
ethane/propane mix to Mont Belvieu.
Competition. The pipeline's primary competition into the Lake Charles market
comes from Louisiana offshore gas.
Transmix Operations
Our transmix operations consist of transmix processing facilities located in
Richmond, Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood
River, Illinois; and Colton, California.
Transmix occurs when dissimilar refined petroleum 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. At our transmix processing facilities, we process and separate
pipeline transmix generated in the United States into pipeline-quality gasoline
and light distillate products. Transmix processing is performed for Duke Energy
Merchants on a "for fee" basis pursuant to a long-term contract expiring in
2010, and for Colonial Pipeline Company at Dorsey Junction, Maryland.
Our Richmond processing facility is comprised of a dock/pipeline, a
170,000-barrel tank farm, a processing plant, lab and truck rack. The facility
is composed of four distillation units that operate 24 hours a day, 7 days a
week providing a processing capacity of approximately 8,000 barrels per day.
Both the Colonial and Plantation pipelines supply the facility, as well as
deep-water barge (25 feet draft), transport truck and rail. We also own an
additional 3.6-acre bulk products terminal with a capacity of 55,000 barrels
located nearby in Richmond.
Our Dorsey Junction processing facility is located within the Colonial
Pipeline Dorsey Junction terminal facility. The 5,000-plus barrel per day
processing unit began operations in February 1998. It operates 24 hours a day, 7
days a week providing dedicated transmix separation service for Colonial.
Our Indianola processing facility is located near Pittsburgh, Pennsylvania
and is accessible by truck, barge and pipeline, primarily processing transmix
from Buckeye, Colonial, Sun and Teppco pipelines. It has capacity to process
12,000 barrels of transmix per day and operates 24 hours per day, 7 days a week.
The facility is comprised of a 500,000-barrel tank farm, a quality control
laboratory, a truck-loading rack and a processing unit. The facility can ship
output via the Buckeye pipeline as well as by truck.
Our Wood River processing facility was constructed in 1993 on property owned
by ConocoPhillips and is accessible by truck, barge and pipeline, primarily
processing transmix from both Explorer and ConocoPhillips pipelines. It has
capacity to process 5,000 barrels of transmix per day. Located on approximately
three acres leased from ConocoPhillips, the facility consists of one processing
unit. Supporting terminal capability is provided through leased tanks in
adjacent terminals.
Our Colton processing facility, completed in the spring of 1998, and located
adjacent to our products terminal in Colton, California, produces refined
petroleum products that are delivered into our Pacific operations' pipelines for
shipment to markets in Southern California and Arizona. The facility can process
over 5,000 barrels per day.
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Markets. The Gulf and East Coast refined petroleum products distribution
system, particularly the Mid-Atlantic region, provides the target market for our
East Coast transmix processing operations. The Mid-Continent area and the New
York Harbor are the target markets for our Pennsylvania and Illinois assets. Our
West Coast transmix processing operations support the markets served by our
Pacific operations. We are working to expand our Mid-Continent and West Coast
markets.
Supply. Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer and
our Pacific operations provide the vast majority of our supply. These suppliers
are committed to our transmix facilities by long-term contracts. Individual
shippers and terminal operators provide additional supply. Duke Energy Merchants
is responsible for transmix supply acquisition other than at the Dorsey Junction
facility, which is supplied by Colonial Pipeline Company.
Competition. Placid Refining is our main competitor in the Gulf coast area
and Tosco Refining is a major competitor in the New York harbor area. There are
various processors in the Mid-Continent area, primarily Phillips and Williams
Energy Services, who compete with our expansion efforts in that market. Shell
Oil US and a number of smaller organizations operate transmix processing
facilities in the West and Southwest. These operations compete for supply that
we envision as the basis for growth in the West and Southwest. Our Colton
processing facility also competes with major oil company refineries in
California.
Natural Gas Pipelines
Our Natural Gas Pipelines segment consists of natural gas transportation,
storage, gathering and matched purchases/sales for both interstate and
intrastate pipelines. Within this segment, we own over 13,400 miles of natural
gas pipelines and associated storage and supply lines that are strategically
located at the center of the North American pipeline grid. Our transportation
network provides access to the major gas supply areas in the western United
States, Texas and the Midwest, as well as major consumer markets. Our Natural
Gas Pipeline assets, consisting of assets primarily acquired since late 1999,
include:
o our Texas intrastate natural gas pipeline group, which includes Kinder
Morgan Texas Pipeline and Kinder Morgan Tejas, a combined 5,800-mile
intrastate natural gas pipeline system along the Texas Gulf Coast;
o Kinder Morgan Interstate Gas Transmission LLC, which owns a 6,100-mile
natural gas pipeline, including the Pony Express pipeline system, that
extends from northwestern Wyoming east into Nebraska and Missouri and south
through Colorado and Kansas;
o Trailblazer Pipeline Company, which transmits natural gas from Colorado
through southeastern Wyoming to Beatrice, Nebraska;
o our Casper and Douglas natural gas gathering systems, which are comprised
of approximately 1,560 miles of natural gas gathering pipelines and two
facilities in Wyoming capable of processing 210 million cubic feet of
natural gas per day;
o our 49% interest in the Red Cedar Gathering Company, which gathers natural
gas in La Plata County, Colorado and owns and operates a carbon dioxide
processing plant;
o our 50% interest in Coyote Gas Treating, LLC, which owns a 250 million
cubic feet per day natural gas treating facility in La Plata County,
Colorado; and
o our 25% interest in Thunder Creek Gas Services, LLC, which gathers,
transports and processes methane gas from coal beds in the Powder River
Basin of Wyoming.
Texas Intrastate Pipeline Group
Our Texas intrastate natural gas pipeline group consists of two primary
systems, Kinder Morgan Texas Pipeline and Kinder Morgan Tejas Pipeline. The
Tejas system was acquired on January 31, 2002 from Intergen, a joint
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venture owned by affiliates of the Royal Dutch Shell Group of Companies, and
Bechtel Enterprises Holding, Inc. The group is referred to herein as Kinder
Morgan Texas. These pipelines are increasingly interconnected and operate as a
single pipeline system, which provides its customers and suppliers with improved
flexibility and reliability. The combined assets include over 5,800 miles of
pipeline with a peak capacity of approximately 5 billion cubic feet per day of
natural gas and control of over 30 billion cubic feet of natural gas storage
capacity. In addition, Kinder Morgan Texas has the capability to process over 1
billion cubic feet per day of natural gas for liquids extraction and treat
approximately 250 million cubic feet per day of natural gas for carbon dioxide
removal.
Kinder Morgan Texas serves the Texas Gulf Coast, transporting, processing and
treating gas from multiple onshore and offshore supply sources to serve the
Houston/Beaumont/Port Arthur, Texas industrial markets, as well as local gas
distribution utilities, electric utilities and merchant power generation
markets.
Kinder Morgan Texas serves as a buyer and seller of natural gas, as well as a
transporter of natural gas. Its business is increasingly structured as a fee for
service business. Fee for service businesses include transportation, storage,
processing and treating. Kinder Morgan Texas' purchases and sales of natural gas
are primarily priced with reference to market prices in the consuming region of
its system. The difference between the purchase and sale prices is the rough
equivalent of a transportation fee.
Markets. Kinder Morgan Texas' market area consumes over 8 billion cubic feet
per day of natural gas. Of this amount, we estimate that 75% is industrial
demand (including on-site, cogeneration facilities), about 15% is merchant
generation demand and the remainder is split between local natural gas
distribution utility and power utility demand. The industrial demand is
primarily year-round load. Local natural gas distribution load peaks in the
winter months and is complemented by power demand (both merchant and utility
generation) which peaks in the summer months. As new merchant gas fired
generation has come online and displaced traditional utility generation, Kinder
Morgan Texas has successfully attached these new generation facilities to its
pipeline system in order to maintain its share of natural gas supply for power
generation.
Mexico is an increasingly important market for Kinder Morgan Texas. It serves
this market through interconnection with the facilities of Pemex at the United
States-Mexico border near Arguellas, Mexico and, starting in the second quarter
of 2003, through interconnection with our Monterrey, Mexico natural gas pipeline
project. Current deliveries through the existing interconnection near Arguellas
are approximately 250,000 dekatherms per day of natural gas and deliveries to
Monterrey are expected to be 375,000 dekatherms per day of natural gas. Kinder
Morgan Texas primarily provides transport service to these markets on a fee for
service basis, including a significant demand component, which is paid
regardless of actual throughput. Revenues earned from our activities in Mexico
are paid in U.S. dollar equivalent.
Supply. Kinder Morgan Texas purchases its gas directly from producers
attached to its system in South Texas, East Texas and along the Texas Gulf
Coast. It also purchases gas at interconnects with interstate and intrastate
pipelines. While Kinder Morgan Texas does not produce gas, it maintains an
active well connection program to offset natural declines in production along
its system, and to secure supplies for additional demand in its market area.
Kinder Morgan Texas has access to both onshore and offshore sources of supply,
and is well positioned to interconnect with liquefied natural gas projects under
development by others along the Texas Gulf Coast.
Gathering, Processing and Treating. Kinder Morgan Texas owns and operates
various gathering systems in South and East Texas. These systems aggregate
pipeline quality natural gas supplies into Kinder Morgan Texas' main
transmission pipelines, and in certain cases, aggregate natural gas that must be
processed or treated into its own facilities or the facilities of others. Kinder
Morgan Texas owns two processing plants, its Texas City Plant in Galveston
County, Texas and its Galveston Bay plant in Chambers County, Texas, which
combined can process 150 million cubic feet per day of natural gas for liquids
extraction. In addition, Kinder Morgan Texas has contractual rights to process
approximately 1 billion cubic feet per day of natural gas at various third party
owned facilities. Kinder Morgan Texas also owns and operates three natural gas
treating plants that offer carbon dioxide and/or hydrogen sulfide removal.
Kinder Morgan Texas can treat for carbon dioxide removal up to 150 million cubic
feet per day of natural gas at its Fandango Complex in Zapata County, Texas, and
approximately 40 million cubic feet per day of natural gas at its Thompsonville
Facility in Jim Hogg County, Texas. In addition, Kinder Morgan Texas owns and
operates the Indian Rock Plant located in Upshur County, Texas that is capable
of treating 45 million
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cubic feet per day of natural gas for carbon dioxide and/or hydrogen sulfide
removal. These facilities are operated, or shut in, in accordance with the
prevailing economic conditions for processing and treating services and the
availability of gas requiring such services.
Storage. Kinder Morgan Texas owns the West Clear Lake natural gas storage
facility located in Harris County, Texas. Under a long term contract, Coral
Energy Resources, L.P. operates the facility and controls the 96 billion cubic
feet of natural gas working capacity, and Kinder Morgan Texas provides
transportation services into and out of the facility. Kinder Morgan Texas has
also developed a salt dome storage facility located near Markham, Texas with a
subsidiary of NISOURCE Industries, Inc. The facility consists of two salt dome
caverns with approximately 7.5 billion cubic feet of total natural gas storage
capacity, over 5.4 billion cubic feet of working natural gas capacity and up to
500 million cubic feet per day of peak deliverability. The storage facility is
leased by a partnership in which Kinder Morgan Texas and a subsidiary of NIPSCO
are partners. Kinder Morgan Texas has executed a 20-year sublease with the
partnership under which it has rights to 50% of the facility's working natural
gas capacity, 85% of its withdrawal capacity and approximately 70% of its
injection capacity. Kinder Morgan Texas also leases salt dome caverns from Dow
Hydrocarbon & Resources, Inc. and BP America Production Company in Brazoria
County, Texas. The salt dome caverns are referred to as the Stratton Ridge
Facilities and have a combined capacity of 11.8 billion cubic feet of natural
gas, working natural gas capacity of 6.6 billion cubic feet and a peak day
deliverability of up to 450 million cubic feet per day of natural gas. In
addition, Kinder Morgan Texas controls through contractual arrangements another
19.3 billion cubic feet of third party natural gas storage capacity in the
Houston, Texas area and 4 billion cubic feet of natural gas storage capacity in
the East Texas area.
Competition. The Texas intrastate natural gas market is highly competitive,
with many markets connected to multiple pipeline companies. Kinder Morgan Texas
competes with interstate and intrastate pipelines, and their shippers, to attach
new markets and supplies and for transportation, processing and treating
services.
Kinder Morgan Interstate Gas Transmission LLC
Through Kinder Morgan Interstate Gas Transmission LLC, referred to herein as
KMIGT, we own approximately 5,000 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 services, including no-notice transportation and park
and loan services. Under KMIGT's tariffs, firm transportation and storage
customers pay reservation fees each month plus a commodity charge based on the
actual transported or stored volumes. In contrast, interruptible transportation
and storage customers pay a commodity charge based upon actual transported
and/or stored volumes. Reservation fees are based upon geographical location
(KMIGT does not have seasonal rates) and the distance of the transportation
service provided. Under the no-notice service, customers pay a fee for the right
to use a combination of firm storage and firm transportation to effect
deliveries of natural gas up to a specified volume without making specific
nominations.
The system is powered by 28 transmission and storage compressor stations with
approximately 149,000 horsepower. The pipeline system provides storage services
to its customers from its Huntsman Storage Field in Cheyenne County, Nebraska.
The facility has approximately 39.5 billion cubic feet of total storage
capacity, 12.5 billion cubic feet of working gas capacity and can withdraw up to
101 million cubic feet of natural gas per day.
Markets. Markets served by KMIGT provide a stable customer base with
expansion opportunities due to the system's access to growing Rocky Mountain
supply sources. Markets served by KMIGT are comprised mainly of local natural
gas distribution companies and interconnecting interstate pipelines in the
mid-continent area. End-users for the local natural gas distribution companies
typically include residential, commercial, industrial and agricultural
customers. The pipelines interconnecting with KMIGT in turn deliver gas into
multiple markets including some of the largest population centers in the
Midwest. Natural gas demand for crop irrigation during the summer from
time-to-time exceeds heating season demand and provides KMIGT consistent volumes
throughout the year without a significant impact from seasonality.
Supply. Approximately 18%, by volume, of KMIGT's firm contracts expire within
one year and 26% expire within one to five years. Affiliated entities are
responsible for approximately 22% of the total firm transportation
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and storage capacity under contract on KMIGT's system. Over 98% of the
system's firm transport capacity is currently subscribed.
Competition. KMIGT competes with other interstate and intrastate gas
pipelines transporting gas from the supply sources in the Rocky Mountain and
Hugoton Basins to mid-continent pipelines and market centers.
Trailblazer Pipeline Company
On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in the
Trailblazer Pipeline Company that we did not already own. Trailblazer Pipeline
Company, referred to herein as Trailblazer, is an Illinois partnership and its
principal business is to transport and redeliver natural gas to others in
interstate commerce. It does business in the states of Wyoming, Colorado,
Nebraska and Illinois. Natural Gas Pipeline Company of America, a subsidiary of
KMI, manages, maintains and operates Trailblazer, for which it is reimbursed at
cost. Trailblazer's 436-mile natural gas pipeline system originates at an
interconnection with Wyoming Interstate Company Ltd.'s pipeline system near
Rockport, Colorado and runs through southeastern Wyoming to a terminus near
Beatrice, Nebraska where Trailblazer's pipeline system interconnects with
Natural Gas Pipeline Company of America's and Northern Natural Gas Company's
pipeline systems.
Trailblazer's pipeline is the fourth and last segment of a 791-mile pipeline
system known as the Trailblazer Pipeline System, which originates in Uinta
County, Wyoming with Canyon Creek Compression Company, a 22,000 horsepower
compressor station located at the tailgate of BP Amoco Production Company's
processing plant in the Whitney Canyon Area in Wyoming (Canyon Creek's
facilities are the first segment). Canyon Creek receives gas from the BP Amoco
processing plant and provides transportation and compression of gas for delivery
to Overthrust Pipeline Company's 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 Wyoming Interstate's 269-mile, 36-inch
diameter pipeline system at an inter-connection (Kanda) in Sweetwater County,
Wyoming (Wyoming Interstate's system is the third segment). Wyoming Interstate's
pipeline delivers gas to Trailblazer's pipeline at an interconnection near
Rockport in Weld County, Colorado.
Markets. Significant growth in Rocky Mountain natural gas supplies has
prompted a need for additional pipeline transportation service. In August 2000,
Trailblazer announced an approximate $58.7 million expansion to its system,
which would provide an additional capacity of approximately 324,000 dekatherms
of natural gas per day. On January 10, 2001, Trailblazer filed an application
with FERC requesting authorization to construct and operate the facilities that
would expand its capacity by 324,000 dekatherms of natural gas per day to
provide new firm long-term transportation service. On May 18, 2001, the FERC
issued an "Order Issuing Certificate" approving Trailblazer's application.
Trailblazer now has a certificated capacity of 846 million cubic feet per day of
natural gas. The FERC also granted Trailblazer's request to assess incremental
rates and fuel for shippers taking capacity related to the expansion facilities.
The expansion project started in Rockport, Colorado, where Trailblazer's
pipeline interconnects with pipelines owned by Colorado Interstate Gas Co.,
Wyoming Interstate Company, West Gas and KMIGT, and terminated in Gage County,
Nebraska. With this project, Trailblazer installed two new compressor stations
and added additional horsepower at an existing compressor station. On May 7,
2002, the expansion facilities were placed into service.
Supply. Less than 1%, by volume, of Trailblazer's firm contracts expire
before one year and 39% expire within one to five years. Affiliated entities
hold less than 1% of the total firm transportation capacity. All of the system's
firm transport capacity is currently subscribed.
Competition. While competing pipelines have been announced which would move
gas east out of the Rocky Mountains, the main competition that Trailblazer
currently faces is that the gas supply in the Rocky Mountain area either stays
in the area or is moved west and therefore is not transported on Trailblazer's
pipeline.
Casper and Douglas Natural Gas Gathering and Processing Systems
We own and operate our Casper and Douglas natural gas gathering and
processing facilities.
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The Douglas gathering system is comprised of approximately 1,500 miles of
4-inch to 16-inch diameter pipe that gathers approximately 50 million cubic feet
per day of natural gas from 650 active receipt points. Douglas Gathering has an
aggregate 24,495 horsepower of compression situated at 17 field compressor
stations. Gathered volumes are processed at our Douglas plant, located in
Douglas, Wyoming. Residue gas is delivered into KMIGT and recovered liquids are
injected in ConocoPhillips Petroleum's natural gas liquids pipeline for
transport to Borger, Texas.
The Casper gathering system is comprised of approximately 60 miles of 4-inch
to 8-inch diameter pipeline gathering approximately 20 million cubic feet per
day of natural gas from eight active receipt points. Gathered volumes are
delivered directly into KMIGT. Current gathering capacity is contingent upon
available capacity on KMIGT and the Casper Plant's 50 to 80 million cubic feet
per day processing capacity.
We believe that Casper-Douglas' unique combination of
percentage-of-proceeds, sliding scale percent-of-proceeds and keep whole plus
fee processing agreements helps to reduce our exposure to commodity price
volatility.
Markets. Casper and Douglas are processing plants servicing gas streams
flowing into KMIGT.
Competition. There are three other natural gas gathering and processing
alternatives available to conventional natural gas producers in the Greater
Powder River Basin. However, Casper and Douglas are the only two plants in the
region that provide straddle processing of natural gas streams flowing into
KMIGT upsteam of our two plant facilities. The other regional facilities include
the Hilight (80 million cubic feet per day) and Kitty (17 million cubic feet per
day) plants owned and operated by Western Gas Resources, and the Sage Creek
Processors (50 million cubic feet per day) plant owned and operated by Devon
Energy.
Red Cedar Gathering Company
We own a 49% equity interest in the Red Cedar Gathering Company, a joint
venture organized in August 1994, referred to in this document as Red Cedar. The
Southern Ute Indian Tribe owns the remaining 51%. Red Cedar owns and operates
natural gas gathering, compression and treating facilities in the Ignacio Blanco
Field in La Plata County, Colorado. The Ignacio Blanco Field lies within the
Colorado portion of the San Juan Basin, most of which is located within the
exterior boundaries of the Southern Ute Indian Tribe Reservation. Red Cedar
gathers coal seam and conventional natural gas at wellheads and at several
central delivery points, for treating, compression and delivery into any one of
four major interstate natural gas pipeline systems and an intrastate pipeline.
Red Cedar's gas gathering system currently consists of over 800 miles of
gathering pipeline connecting more than 700 producing wells, 65,000 horsepower
of compression at 17 field compressor stations and two carbon dioxide treating
plants. A majority of the natural 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 700 million cubic feet per day of natural
gas.
Coyote Gas Treating, LLC
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to herein
as Coyote Gulch. Coyote Gulch is a joint venture that was organized in December
1996. El Paso Field Services Company owns the remaining 50% equity interest. The
sole asset owned by the joint venture is a 250 million cubic feet per day
natural gas treating facility located in La Plata County, Colorado. We are the
managing partner of Coyote Gas Treating, LLC.
The inlet gas stream treated by Coyote Gulch contains an average carbon
dioxide content of between 12% and 13%. The plant treats the gas down to a
carbon dioxide concentration of 2% in order to meet interstate natural gas
pipeline quality specifications, and then compresses the natural gas into the
TransColorado Gas Transmission pipeline for transport to the Blanco, New Mexico
San Juan Basin Hub.
Effective January 1, 2002, Coyote Gulch entered into a five-year operating
lease agreement with Red Cedar. Under the terms of the lease, Red Cedar operates
the facility and is responsible for all operating and maintenance expense and
capital costs. In place of the treating fees that were previously received by
Coyote Gulch from Red Cedar, Red Cedar is required to make monthly lease
payments.
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Thunder Creek Gas Services, LLC
We own a 25% equity interest in Thunder Creek Gas Services, LLC, referred to
herein as Thunder Creek. Thunder Creek is a joint venture that was organized in
September 1998. Devon Energy owns the remaining 75% equity interest. Thunder
Creek provides gathering, compression and treating services to a number of coal
seam gas producers in the Powder River Basin. Throughput volumes include both
coal seam and conventional plant residue gas. Thunder Creek is independently
operated from offices located in Denver, Colorado with field offices in Glenrock
and Gillette, Wyoming.
Thunder Creek's operations are a combination of mainline and low pressure
gathering assets. The mainline assets include 235 miles of 4-inch to 24-inch
diameter pipeline, 19,360 horsepower of mainline compression and carbon dioxide
removal facilities consisting of a 240 million cubic feet per day carbon dioxide
treating plant complete with dehydration. The mainline assets receive gas from
26 receipt points and can deliver treated gas to three delivery points including
Colorado Interstate Gas, Wyoming Interstate Gas Company and KMIGT. The low
pressure gathering assets include 161 miles of 4-inch to 14-inch gathering
pipeline and 50,488 horsepower of field compression. Gas is gathered from 43
receipt points and delivered to the mainline at four primary locations.
CO2 Pipelines
Our CO2 Pipelines segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates, referred to herein as KMCO2. Together, they transport,
market and produce carbon dioxide for use in enhanced oil recovery operations
and own interests in other related assets in the continental United States,
through the following:
o our carbon dioxide pipelines, including:
o our Central Basin Pipeline, a 320-mile carbon dioxide pipeline
located in the Permian Basin of West Texas between Denver City, Texas
and McCamey, Texas;
o our Centerline Pipeline, a 120-mile carbon dioxide pipeline,
currently under construction with an estimated completion date of
mid-2003, located in the Permian Basin of West Texas between Denver
City, Texas and Snyder, Texas; and
o our interests in carbon dioxide pipelines, including an approximate
89% interest in the Canyon Reef Carriers Pipeline, a 50% interest in
the Cortez Pipeline and a 13% undivided interest in the Bravo
Pipeline System;
o our interests in carbon dioxide reserves, including an approximate 45%
interest in the McElmo Dome and an approximate 11% interest in the Bravo
Dome;
o our interests in oil-producing fields, including an approximate 84% working
interest in the SACROC Unit and minority interests in the Sharon Ridge
Unit, the Reinecke Unit, the MidCross Unit and the Yates Field Unit, all of
which are located in the Permian Basin of West Texas; and
o our interests in gasoline plants, including an approximate 22% ownership
interest in the Snyder Gasoline Plant, a 51% ownership interest in the
Diamond M Gas Plant and a 100% ownership interest in the North Snyder
Plant, all of which are located in the Permian Basin of West Texas (we also
own 50% net profits interests in 52.9% ownership of the Snyder Gasoline
Plant).
Our CO2 pipelines and related assets allow us to market a complete package of
carbon dioxide supply, transportation and technical expertise to the customer.
Carbon dioxide is used in enhanced oil recovery projects as a flooding medium
for recovering crude oil from mature oil fields.
On March 5, 1998, we and affiliates of Shell Exploration & Production Company
combined our carbon dioxide activities and assets into a partnership named Shell
CO2 Company, Ltd. Shell CO2 Company, Ltd. was established to transport, market
and produce carbon dioxide for use in enhanced oil recovery operations in the
continental
24
United States. Initially, we had a 20% interest in Shell CO2 Company,
Ltd. and Shell had the remaining 80% interest.
On April 1, 2000, we acquired Shell's 80% interest in Shell CO2 Company, Ltd.
for $212.1 million. After the closing, we renamed Shell CO2 Company, Ltd.,
Kinder Morgan CO2 Company, L.P. As is the case with our four other operating
partnerships, we own a 98.9899% limited partner interest in KMCO2, and our
general partner owns a direct 1.0101% general partner interest. Kinder Morgan
SACROC L.P., a limited partnership formed in December 2002 and owned by two
wholly-owned subsidiaries of KMCO2, primarily owns our interests in the SACROC
Unit.
On January 1, 2001, KMCO2 formed a joint venture, named MKM Partners, L.P.,
with Marathon Oil Company in the southern Permian Basin of West Texas. The joint
venture consists of a nearly 13% interest in the SACROC unit and a 49.9%
interest in the Yates Field unit. It is owned 85% by Marathon Oil Company and
15% by KMCO2.
Carbon Dioxide Pipelines
Placed in service in 1985, our Central Basin Pipeline consists of
approximately 143 miles of 16-inch to 20-inch main pipeline and 178 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 650 million
cubic feet per day. At its origination point in Denver City, our Central Basin
Pipeline interconnects with all three major carbon dioxide supply pipelines from
Colorado and New Mexico, namely the Cortez Pipeline (operated by KMCO2) and the
Bravo and Sheep Mountain Pipelines (operated by Occidental and BP Amoco,
respectively). Central Basin Pipeline's mainline terminates near McCamey where
it interconnects with the Canyon Reef Carriers Pipeline. The tariffs charged by
the Central Basin Pipeline are not regulated.
Currently under construction, our Centerline Pipeline consists of
approximately 113 miles of 16-inch pipe located in the Permian Basin between
Denver City, Texas and Snyder, Texas. Centerline Pipeline, when completed in
mid-2003, will have a capacity of 250 million cubic feet per day.
We operate and own a 50% ownership interest in the 502-mile, 30-inch Cortez
Pipeline. This pipeline carries carbon dioxide from the McElmo Dome source
reservoir to the Denver City, Texas hub. The Cortez Pipeline currently
transports in excess of 700 million cubic feet per day, including approximately
90% of the carbon dioxide transported on our Central Basin Pipeline.
In addition, we own a 13% undivided interest in the 218-mile, 20-inch Bravo
Pipeline, which delivers to the Denver City hub and has a capacity of more than
350 million cubic feet per day. 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.
In addition, we own 89% of the Canyon Reef Carriers Pipeline. The Canyon Reef
Carriers Pipeline extends 138 miles from McCamey, Texas, to our SACROC field.
This pipeline is 16 inches in diameter and has a capacity of approximately 290
million cubic feet per day and makes deliveries to the SACROC, Sharon Ridge,
Cogdell, Amaker Tipett and Reinecke units.
Markets. Our principal market for carbon dioxide is for injection into mature
oil fields in the Permian Basin, where industry demand is expected to be
comparable to historical demand for the next several years. We are exploring
additional potential markets, including enhanced oil recovery targets in the
North Sea and California, and coal bed methane production in the San Juan Basin
of New Mexico.
Competition. Our primary competitors for the sale of carbon dioxide include
suppliers that have an ownership interest in McElmo Dome, Bravo Dome and Sheep
Mountain Dome carbon dioxide reserves, and Petro Source, which gathers waste
carbon dioxide from natural gas production in the Val Verde Basin of West Texas.
Our ownership interests in the Cortez and Bravo pipelines are in direct
competition with other carbon dioxide pipelines. We also compete with other
interests in McElmo Dome and Cortez Pipeline, for transportation of carbon
dioxide to the Denver City, Texas market area. There is no assurance that new
carbon dioxide source fields will not be discovered which could compete with us
or that new methodologies for enhanced oil recovery could replace carbon dioxide
flooding.
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Carbon Dioxide Reserves
We operate, and own approximately 45% of, the McElmo Dome, which contains
more than 10 trillion cubic feet of nearly pure carbon dioxide. Deliverability
and compression capacity exceeds one billion cubic feet per day. McElmo Dome
produces from the Leadville formation at 8,000 feet with 44 wells that produce
at individual rates of up to 60 million cubic feet per day.
We also own approximately 11% of Bravo Dome, which holds reserves of
approximately two trillion cubic feet of carbon dioxide. Bravo Dome produces
approximately 320 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.
Oil Reserves
The SACROC unit, in which we have increased our interest to approximately
84%, is comprised of approximately 50,000 acres located in the Permian Basin in
Scurry County, Texas. SACROC was discovered in 1948 and has produced over 1.2
billion barrels of oil since inception. We have continued the development of the
carbon dioxide project initiated by the previous owners and have arrested the
decline in production through increased carbon dioxide injection. The current
purchased carbon dioxide injection rate is 140 million cubic feet per day, up
from 120 million cubic feet per day in 2001, and the oil production rate in
February 2003 was approximately 17,000 barrels of oil per day from 160 producing
wells, up from 10,000 barrels of oil per day in December 2001.
Gas Plant Interests
We own 22% of, and now operate, the Snyder Gasoline Plant, 51% of the Diamond
M Gas Plant and 100% of the North Snyder Plant. We also own 50% net profits
interests in 52.9% ownership of the Snyder Gasoline Plant. These plants process
gas produced from the SACROC unit and neighboring carbon dioxide projects,
specifically the Sharon Ridge, Reinecke and Cogdell units, all of which are
located in the Permian Basin area of West Texas.
Terminals
Our Terminals segment includes the business portfolio of approximately 50
terminals that transload and store coal, dry-bulk materials and
petrochemical-related liquids, as well as more than 60 transload operations in
20 states.
Liquids Terminals
Kinder Morgan Liquids Terminals LLC, referred to herein as KMLT, is comprised
of 12 bulk liquids terminal facilities and 59 rail transloading and materials
handling operations. Together, these facilities have a total capacity of
approximately 35 million barrels of liquid products, primarily gasoline,
distillates, petrochemicals and vegetable oil products. In 2002, our liquids
terminals handled approximately 480 million barrels of clean petroleum,
petrochemical and vegetable oil products for 240 different customers, and our
transloading operations handled approximately 59,000 rail cars. The liquids
terminals are located in Houston, New York Harbor, South Louisiana, Chicago,
Cincinnati and Pittsburgh.
Houston. KMLT's Houston terminal complex, located in Pasadena and Galena
Park, Texas along the Houston Ship Channel, has approximately 18 million barrels
of capacity. The complex is connected via pipeline to 14 refineries, four
petrochemical plants and ten major outbound pipelines. In addition, the
facilities have four ship docks and seven barge docks for inbound and outbound
movements. The terminals are served by the Union Pacific railroad.
New York Harbor. KMLT owns two facilities in the New York Harbor area, one in
Carteret, N.J. and the other in Perth Amboy, N.J. The Carteret facility has a
capacity of approximately 6.9 million barrels of petroleum and petrochemical
products. This facility has two ship docks with a 37-foot mean low water depth
and four barge docks. It is connected to the Colonial, Buckeye, Sun and Harbor
pipeline systems and CSX and Norfolk Southern railroads. The Perth Amboy
facility has a capacity of approximately 2.3 million barrels of petroleum and
petrochemical products. Tank sizes range from 2,000 gallons to 300,000 barrels.
The facility has one ship dock and one barge
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dock. This facility is connected to the Colonial and Buckeye pipeline
systems and CSX and Norfolk Southern railroads.
South Louisiana. KMLT owns two facilities in South Louisiana: one in the Port
of New Orleans located in Harvey, Louisiana and the other near a major
petrochemical complex in Geismar, Louisiana. The New Orleans facility has
approximately 3.0 million barrels of total tanks ranging in sizes from 416
barrels to 200,000 barrels. There are three ship docks and one barge dock, and
the Union Pacific railroad provides rail service. The terminal also provides
ancillary drumming, packaging and cold storage services. A second facility is
located approximately 75 miles north of the New Orleans facility on the left
descending bank of the Mississippi River near the town of St. Gabriel,
Louisiana. The facility has approximately 400,000 barrels of tank capacity and
the tanks vary in sizes ranging from 1,990 barrels to 80,000 barrels. There are
three local pipeline connections at the facility which enable the movement of
products from the facility to the petrochemical plants in Geismar, Louisiana.
Chicago. KMLT owns two facilities in the Chicago market. One facility is in
Argo, Illinois about 14 miles southwest of downtown Chicago. The facility has
approximately 2.4 million barrels of capacity in tankage ranging from 50,000
gallons to 80,000 barrels. The Argo terminal is situated along the Chicago
sanitary and ship channel and has three barge docks. The facility is connected
to TEPPCO and Westshore pipelines, as well as a new direct connection to Midway
Airport. The Canadian National railroad services this facility. The other
facility is located in the Port of Chicago along the Calumet River. The facility
has approximately 741,000 barrels of capacity in tanks ranging from 12,000
gallons to 55,000 barrels. There are two ship docks and four barge docks, and
the facility is served by the Norfolk Southern railroad.
Cincinnati. KMLT has two facilities along the Ohio River in Cincinnati, Ohio.
The total storage is approximately 850,000 barrels in tankage ranging from 120
barrels to 96,000 barrels. There are 3 barge docks, and the NNU and CSX
railroads provide rail service.
Pittsburgh. This KMLT facility is located in Dravosburg, Pennsylvania, along
the Monongahela River. There is approximately 250,000 barrels of storage in
tanks ranging from 1,200 to 38,000 barrels. There are two barge docks, and
Norfolk Southern railroad provides rail service.
Rail Transloading Operations: We acquired Laser Materials Services LLC on
January 1, 2002, and in June 2002, we changed its name to Kinder Morgan
Materials Services LLC, referred to herein as KMMS. KMMS operates more than 60
rail transloading facilities, of which 57 are located east of the Mississippi
River. The CSX railroad provides rail service for 52 facilities and the Norfolk
Southern, Union Pacific, Kansas City Southern and A&W railroads provide rail
service for the remaining seven facilities. Approximately 50% of the products
handled by KMMS are liquids and 50% are dry bulk products. KMMS also designs and
builds transloading facilities, performs inventory management services and
provides value-added services such as blending, heating and sparging.
Competition. We are one of the largest independent operators of liquids
terminals in North America. Our largest competitors are Williams, ST Services,
IMTT, Vopak, Oil Tanking and Transmontaigne.
Bulk Terminals
Our Bulk Terminals consist of 38 bulk terminals, which handle approximately
60 million tons of bulk products annually. These terminals have 2 million tons
of covered storage and 14 million tons of open storage.
Coal Terminals
We handled approximately 25 million tons of coal in 2002, which is 45% of the
total volume at our bulk terminals.
Our 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
27
with the demand at power plants. Storage capacity at the Cora Terminal could
be doubled with additional capital investment.
Our 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 to 15
million tons with a storage capacity of approximately two million tons. With
capital improvements, the terminal could handle 25 million tons annually.
Our Pier IX Terminal is located in Newport News, Virginia. The terminal
originally opened in 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. In addition, the Pier IX Terminal operates a cement
facility, which has the capacity to transload over 400,000 tons of cement
annually. In late 2002, Pier IX also began to operate a synfuel plant on site.
Volumes of synfuel produced in 2003 could be between one and two million tons.
In addition, we operate the LAXT Coal Terminal in Los Angeles, California. In
2002, LAXT ceased shipping export coal. We received notice in January 2003 that
the facility was being sold and that our contract to operate the facility would
end in the first quarter of 2003.
We also developed our Shipyard River Terminal in Charleston, South Carolina,
to be able to unload, store and reload coal imported from various foreign
countries. The imported coal is expected to be cleaner burning low sulfur and
would be used by local utilities to comply with the Clean Air Act. Shipyard
River Terminal has the capacity to handle 2.5 million tons per year.
Markets. Coal continues to dominate as the fuel of choice for electric
generation, accounting for more than 50% 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 our
coal terminals is destined for use in coal-fired electric generation.
We believe that obligations to comply with the Clean Air Act Amendments of
1990 will cause shippers to increase the use of cleaner burning low sulfur coal
from the western United States and from foreign sources. Approximately 80% of
the coal loaded through our Cora Terminal and our Grand Rivers Terminal 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 2002, four major customers accounted for approximately 90% of all the
coal loaded through our Cora Terminal.
Our Pier IX Terminal exports coal to foreign markets. 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. Our Cora and Grand Rivers terminals handle low sulfur coal
originating in Wyoming, Colorado, and Utah as well as coal that originates in
the mines of southern Illinois and western Kentucky. However, since many
shippers, particularly in the East, are using western coal or a mixture of
western coal and other coals as a means of meeting environmental restrictions,
we anticipate that growth in volume through the terminals will be primarily due
to western low sulfur coal originating in Wyoming, Colorado and Utah.
Our Cora Terminal sits on the mainline of the Union Pacific Railroad and is
strategically positioned to receive coal shipments from the West. Grand Rivers
provides easy access to the Ohio-Mississippi River network and the
Tennessee-Tombigbee River 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 Santa
Fe. The Pier IX Terminal is served by the CSX Railroad, which transports coal
from central Appalachian and other eastern coal basins. Cement imported to the
Pier IX Terminal primarily originates in Europe.
Competition. Two new coal terminals that compete with our Cora Terminal and
our Grand Rivers Terminal will be completed in 2003. While Cora and Grand Rivers
are modern high capacity terminals, some volume will be diverted to the new
terminals by the Tennessee Valley Authority to promote increased competition.
The total reduction in 2003 is expected to be approximately four million tons,
however, such amounts could be higher if the new terminals aggressively compete
for the existing customers of our Cora and Grand Rivers coal terminals. Our
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Pier IX Terminal competes primarily with two modern coal terminals located in
the same Virginian port complex as our Pier IX Terminal.
Petroleum Coke and Other Bulk Terminals
We own or operate eight 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 our customers
are large integrated oil companies that choose to outsource the storage and
loading of petroleum coke for a fee. We handled almost six million tons of
petroleum coke in 2002.
We own or operate an additional 12 bulk terminals located primarily on the
southern edge of the lower Mississippi River, the Gulf Coast and the West Coast.
These 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. Our petroleum coke and other bulk terminals compete with
numerous independent terminal operators, other terminals owned by oil companies
and other industrials opting not to outsource terminal services. Competition
against the petroleum coke terminals that we operate but do not own has
increased significantly, primarily from companies that also market and sell the
product. This increased competition will likely decrease profitability in this
portion of the segment. Many of our other bulk terminals were constructed
pursuant to long-term contracts for specific customers. As a result, we believe
other terminal operators would face a significant disadvantage in competing for
this business.
New Terminals
Effective February 1, 2002, we acquired a 66 2/3% ownership interest in
International Marine Terminals Partnership, which operates a bulk terminal site
in Port Sulphur, Louisiana, for approximately $40.5 million, including the
assumption of $40 million of long-term debt. The terminal handles approximately
eight million tons per year of iron ore, coal, petroleum coke and barite.
Effective May 1, 2002, we acquired a bulk terminal bagging operation located
adjacent to our existing Milwaukee, Wisconsin dry bulk terminal for $8.5
million. The facility bags approximately 100,000 tons of products per year, with
road salt being the primary commodity. The facility is run and managed with
existing Milwaukee personnel.
Effective September 1, 2002, we acquired a bulk terminal along the Ohio River
near Owensboro, Kentucky for approximately $7.7 million. As of December 31,
2002, we have paid approximately $7.2 million and established a $0.5 million
liability for final purchase price settlements. This bulk terminal is one of the
nation's largest storage and handling points for bulk aluminum. The facility
also handles various other bulk materials, as well as a barge scrapping
facility.
Effective December 31, 2002, we purchased four barge-mounted crane units from
Stevedoring Services of America for approximately $11.3 million. As of December
31, 2002, we have paid $9.8 million of the total purchase price of the cranes.
These cranes have been used historically at the International Marine Terminal,
66 2/3% of which we purchased in 2002. The cranes previously had been leased
from a third party under an operating lease; our ownership of these cranes will
reduce our overall operating costs and ensure crane availability.
Effective January 1, 2003, we acquired the assets of Rudolph Stevedoring for
approximately $31.3 million. As of December 31, 2002, we have paid $29.9 million
for the Rudolph acquisition. Rudolph operates terminal facilities at four major
ports along the East Coast and handles approximately four million tons of
products per year. The primary commodities include coal, petroleum coke, salt,
and other various bulk materials.
We are of the opinion that we have generally satisfactory title to the
properties we own and use in our businesses, subject to liens for current taxes,
liens incident to minor encumbrances, and easements and restrictions
29
which do not materially detract from the value of such property or the
interests therein or the use of such properties in our businesses.
Major Customers
Our total operating revenues are derived from a wide customer base. For each
of the years ended December 31, 2002 and 2001, one customer accounted for more
than 10% of our total consolidated revenues. Total transactions in 2002 with
CenterPoint Energy accounted for 15.6% of our total consolidated revenues during
2002. Total transactions in 2001 with the Reliant Energy group of companies,
including the entities which became CenterPoint Energy in October 2002,
accounted for 20.2% of our total consolidated revenues during 2001. For the year
ended December 31, 2000, no revenues from transactions with a single external
customer amounted to 10% or more of our total consolidated revenues.
Employees
We do not have any employees. KMGP Services Company, Inc. and Kinder
Morgan, Inc. employ all persons necessary for the operation of our business.
Generally we reimburse KMGP Services Company, Inc. and Kinder Morgan, Inc.
for the services of their employees. As of December 31, 2002, KMGP Services
Company, Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately
5,390 employees. Approximately 988 hourly personnel at certain terminals and
pipelines are represented by labor unions. KMGP Services Company, Inc. and
Kinder Morgan, Inc. consider relations with their employees to be good.
Please refer to Note 12 to our Consolidated Financial Statements.
Regulation
Interstate Common Carrier Regulation
Some of our pipelines are interstate common carrier pipelines, subject to
regulation by the Federal Energy Regulatory Commission under the Interstate
Commerce Act. The ICA requires that we maintain our tariffs on file with the
FERC, which tariffs set forth the rates we charge for providing transportation
services on our interstate common carrier pipelines as well as the rules and
regulations governing these services. Petroleum pipelines may 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 2002, 2001 and 2000, application of the indexing methodology
did not significantly affect our rates.
The ICA requires, among other things, that such rates be "just and
reasonable" and nondiscriminatory. The ICA permits interested persons to
challenge newly proposed 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. 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 or
"grandfathered" under the ICA. The Energy Policy Act also limited the
circumstances under which a complaint can be made against such grandfathered
rates. The rates we charge for transportation service on our 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, we believe these rates should be grandfathered under the Energy Policy
Act. Certain rates on our Pacific operations' pipeline
30
system were subject to protest during the 365-day period established by the
Energy Policy Act. Accordingly, certain of the Pacific pipelines' 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.
Beginning in the mid-1980's, FERC initiated a number of regulatory changes
intended to create a more competitive environment in the natural gas
marketplace. Among the most important of these changes were:
o Order 436 (1985) requiring open-access, nondiscriminatory transportation
of natural gas;
o Order 497 (1988) which set forth new standards and guidelines imposing
certain constraints on the interaction of interstate natural gas pipelines
and their marketing affiliates and imposing certain disclosure requirements
regarding that interaction; and
o Order 636 (1992) which 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 natural gas
supplies whether purchased from the pipeline or from other merchants such
as marketers or producers.
Natural gas pipelines must now separately state the applicable rates for each
unbundled service they provide (i.e., for the natural gas commodity,
transportation and storage). Order 636 contains a number of procedures designed
to increase competition in the industry, including:
o requiring the unbundling of sales services from other services;
o permitting holders of firm capacity to release all or a part of their
capacity for resale by the pipeline; and
o the issuance of blanket sales certificates to interstate pipelines for
unbundled services.
Order 636 has been affirmed in all material respects upon judicial review,
and our own FERC orders approving our unbundling plans are final and not subject
to any pending judicial review.
If any of our interstate natural gas pipelines ever have marketing
affiliates, we would become 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 natural gas pipeline of its marketing
affiliates and govern in particular the provision of information by an
interstate pipeline to its marketing affiliates.
FERC Order 637
Kinder Morgan Interstate Gas Transmission LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained KMIGT's
compliance plan to implement the changes required by FERC dealing with the way
business is conducted on interstate natural gas pipelines. All interstate
natural gas pipelines were required to make such compliance filings, according
to a schedule established by FERC. From October 2000 through June 2001, KMIGT
held a series of technical and phone conferences to identify issues, obtain
input, and modify its Order 637 compliance plan, based on comments received from
FERC staff and other interested parties and shippers. On June 19, 2001, KMIGT
received a letter from FERC encouraging it to file revised pro-forma tariff
sheets, which reflected the latest discussions and input from parties into its
Order 637 compliance plan. KMIGT made such a revised Order 637 compliance filing
on July 13, 2001. The July 13, 2001 filing contained little substantive change
from the original pro-forma tariff sheets that KMIGT originally proposed on June
15, 2000. On October 19, 2001, KMIGT received an order from FERC, addressing its
July 13, 2001 Order 637 compliance plan. In the Order addressing the July 13,
2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed
31
to make several changes to its tariff, and in doing so, was directed that it
could not place the revised tariff into effect until further order of the FERC.
KMIGT filed its compliance filing with the October 19, 2001 Order on November
19, 2001 and also filed a request for rehearing/clarification of the FERC's
October 19, 2001 Order on November 19, 2001. The November 19, 2001 compliance
filing has been protested by several parties. KMIGT filed responses to those
protests on December 14, 2001. At this time, it is unknown when this proceeding
will be finally resolved. The full impact of implementation of Order 637 on the
KMIGT system is under evaluation. We believe that these matters will not have a
material adverse effect on our business, financial position or results of
operations.
Separately, numerous petitioners, including KMIGT, have filed appeals of
Order 637 in the D.C. Circuit, potentially raising a wide array of issues
related to Order 637 compliance. Initial briefs were filed on April 6, 2001,
addressing issues contested by industry participants. Oral arguments on the
appeals were held before the courts in December 2001. On April 5, 2002, the D.C.
Circuit issued an order largely affirming Order Nos. 637, et seq. The D.C.
Circuit remanded the FERC's decision to impose a 5-year cap on bids that an
existing shipper would have to match in the right of first refusal process. The
D.C. Circuit also remanded the FERC's decision to allow forward-hauls and
backhauls to the same point. Finally, the D.C. Circuit held that several aspects
of the FERC's segmentation policy and its policy on discounting at alternate
points were not ripe for review. The FERC requested comments from the industry
with respect to the issues remanded by the D.C. Circuit. They were due July 30,
2002.
On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:
o eliminated the requirement of a 5-year cap on bid terms that an existing
shipper would have to match in the right of first refusal process, and
found that no term matching cap at all is necessary given existing
regulatory controls;
o affirmed FERC's policy that a segmented transaction consisting of both a
forwardhaul up to contract demand and a backhaul up to contract demand to
the same point is permissible; and
o accordingly required, under Section 5 of the Natural Gas Act, pipelines
that the FERC had previously found must permit segmentation on their
systems to file tariff revisions within 30 days to permit such segmented
forwardhaul and backhaul transactions to the same point.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer made a filing to comply with FERC's Order
Nos. 637 and 637-A. Trailblazer's compliance filing reflected changes in:
o segmentation;
o scheduling for capacity release transactions;
o receipt and delivery point rights;
o treatment of system imbalances;
o operational flow orders;
o penalty revenue crediting; and
o right of first refusal language.
On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637
compliance filing. FERC approved Trailblazer's proposed language regarding
operational flow orders and the right of first refusal, but is requiring
Trailblazer to make changes to its tariff related to the other issues listed
above. Trailblazer anticipates no adverse impact on its business as a result of
the implementation of Order No. 637.
32
On November 14, 2001, Trailblazer made its compliance filing pursuant to the
FERC order of October 15, 2001. That compliance filing has been protested.
Separately, also on November 14, 2001, Trailblazer filed for rehearing of that
FERC order. These pleadings are pending FERC action.
Standards of Conduct Rulemaking
On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in Docket
No. RM01-10 in which it proposed new rules governing the interaction between an
interstate natural gas pipeline and its affiliates. If adopted as proposed, the
Notice of Proposed Rulemaking could be read to limit communications between
KMIGT, Trailblazer and their respective affiliates. In addition, the Notice
could be read to require separate staffing of KMIGT and its affiliates, and
Trailblazer and its affiliates. Comments on the Notice of Proposed Rulemaking
were due December 20, 2001. Numerous parties, including KMIGT, have filed
comment on the Proposed Standards of Conduct Rulemaking. On May 21, 2002, FERC
held a technical conference dealing with the FERC's proposed changes in the
Standard of Conduct Rulemaking. On June 28, 2002, KMIGT and numerous other
parties flied additional written comments under a procedure adopted at the
technical conference. The Proposed Rulemaking is awaiting further FERC action.
We believe that these matters, as finally adopted, will not have a material
adverse effect on our business, financial position or results of operations.
The FERC also issued a Notice of Proposed Rulemaking in Docket No.
RM02-14-000 in which it proposed new regulations for cash management practices,
including establishing limits on the amount of funds that can be swept from a
regulated subsidiary to a non-regulated parent company. KMIGT filed comments on
August 28, 2002. We believe that these matters, as finally adopted, will not
have a material adverse effect on our business, financial position or results of
operations.
In addition to the matters described above, we may face additional challenges
to our rates in the future. Shippers on our pipelines do have rights to
challenge the rates we charge under certain circumstances prescribed by
applicable regulations. There can be no assurance that we will not face
challenges to the rates we receive for services on our pipeline systems in the
future. In addition, since many of our assets are subject to regulation, we are
subject to potential future changes in applicable rules and regulations that may
have an adverse effect on our business, financial position or results of
operations.
California Public Utilities Commission
The intrastate common carrier operations of our Pacific operations' pipelines
in California are subject to regulation by the California Public Utilities
Commission under a "depreciated book plant" methodology, which is based on an
original cost measure of investment. Intrastate tariffs filed by us with the
CPUC have been established on the basis of revenues, expenses and investments
allocated as applicable to the California intrastate portion of our Pacific
operation'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 our FERC regulated rates could also arise with
respect to our intrastate rates. Certain of our Pacific operations' pipeline
rates have been, and continue to be, subject to complaints with the CPUC, as is
more fully described in Item 3. Legal Proceedings.
Safety Regulation
Our interstate pipelines are subject to regulation by the United States
Department of Transportation and our intrastate pipelines are subject to
comparable state regulations with respect to their design, installation,
testing, construction, operation, replacement and management. In addition, we
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 we conduct pipeline operations. In
addition, our truck and terminal loading facilities are subject to U.S. DOT
regulations dealing with the transportation of hazardous materials by motor
vehicles and rail cars. We believe that we are in substantial compliance with
U.S. DOT and comparable state regulations.
33
For example, recent federal legislation signed into law in December 2002
includes new guidelines for the U.S. DOT and pipeline companies in the areas of
testing, education, training and communication. The Pipeline Safety Improvement
Act of 2002 provides a consistent set of guidelines for all operators to follow
and requires the riskiest 50% of products pipelines and natural gas pipelines in
the United States to be inspected within five years of the law's enactment. The
pipeline risk ratings are based on numerous factors, including the population
density in the geographic regions served by a particular pipeline, as well as
the age and condition of the pipeline and its protective coating. The remaining
50% of the natural gas pipelines must be inspected within ten years of the law's
enactment. The law requires pipelines to be re-evaluated every seven years
thereafter.
The law also requires pipeline companies to review their public education
programs for effectiveness within one year of the law's enactment and provide
information to the U.S. DOT that will be used as part of a national mapping
system. We have already supplied mapping information for our products pipelines
and are well under way in providing the same information for our natural gas and
carbon dioxide pipeline systems. In addition, within one year of the law's
enactment, pipeline companies must implement a qualification program to make
certain that employees are properly trained, using criteria the U.S. DOT is
responsible for providing. We will be integrating appropriate aspects of this
new pipeline safety law into our Operator Qualification Program, which is
already in place and functioning.
We are also subject to the requirements of the Federal Occupational Safety
and Health Act and comparable state statutes. We believe that we are in
substantial compliance with Federal OSHA requirements, including general
industry standards, recordkeeping requirements and monitoring of occupational
exposure to hazardous substances.
In general, we expect 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 we do not expect that such
expenditures will have a material adverse impact on us, except to the extent
additional hydrostatic testing requirements are imposed.
State and Local Regulation
Our activities are subject to various state and local laws and regulations,
as well as orders of regulatory bodies, governing a wide variety of matters,
including:
o marketing;
o production;
o pricing;
o pollution;
o protection of the environment; and
o safety.
Environmental Matters
Our operations are subject to federal, state and local laws and regulations
governing the release of regulated materials into the environment or otherwise
relating to environmental protection or human health or safety. We believe that
our operations and facilities are in substantial compliance with applicable
environmental laws and regulations. Any failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
penalties, imposition of remedial requirements, issuance of injunction as to
future compliance or other mandatory or consensual measures. We have an ongoing
environmental compliance program. However, risks of accidental leaks or spills
are associated with the transportation and storage of natural gas liquids,
refined petroleum products, natural gas and carbon dioxide, the handling and
storage of liquid and bulk materials and the other activities conducted by us.
There can be no assurance that we will not incur significant costs and
liabilities relating to claims for damages to property, the environment, natural
resources, or persons resulting from the
34
operation of our 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 us.
Environmental laws and regulations have changed substantially and rapidly
over the last 25 years, and we anticipate that there will be continuing changes.
One trend in environmental regulation is to increase reporting obligations and
place more restrictions and limitations on activities, such as emissions of
pollutants, generation and disposal of wastes and use, storage and handling of
chemical substances, that may impact human health, the environment and/or
endangered species. Increasingly strict environmental restrictions and
limitations have resulted in increased operating costs for us and other similar
businesses throughout the United States. It is possible that the costs of
compliance with environmental laws and regulations may continue to increase. We
will attempt to anticipate future regulatory requirements that might be imposed
and to plan accordingly, but there can be no assurance that we will identify and
properly anticipate each such charge, or that our efforts will prevent material
costs, if any, from arising.
We are currently involved in environmentally related legal proceedings and
clean up activities. Although no assurance can be given, we believe that the
ultimate resolution of all these environmental matters will not have a material
adverse effect on our business, financial position or results of operations. We
have recorded a total reserve for environmental matters in the amount of $52.7
million at December 31, 2002. For additional information, see Note 16 to our
Consolidated Financial Statements included elsewhere in this report.
Solid Waste
We own numerous properties that have been used for many years for the
production of crude oil, natural gas and carbon dioxide, the transportation and
storage of refined petroleum products and natural gas liquids and the handling
and storage of coal and other liquid and bulk materials. Solid waste disposal
practices within the petroleum industry have changed 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 us during the operating history of the facilities
located on such properties. In addition, some of these properties have been
operated by third parties whose treatment and disposal or release of
hydrocarbons or other solid wastes was not under our control. In such cases,
hydrocarbons and other solid wastes could migrate from their original disposal
areas and have an adverse effect on soils and groundwater. We maintain a reserve
to account for the costs of cleanup at sites known to have surface or subsurface
contamination requiring response action.
We generate both hazardous and nonhazardous solid wastes that are subject to
the requirements of the Federal Resource Conservation and Recovery Act and
comparable state statutes. From time to time, state regulators and the United
States Environmental Protection Agency consider 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 liquids or bulk terminal operations, may
in the future be designated as "hazardous wastes." Hazardous wastes are subject
to more rigorous and costly disposal requirements than nonhazardous wastes. Such
changes in the regulations may result in additional capital expenditures or
operating expenses for us.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as the "Superfund" law, and analogous state laws, impose 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 U.S. 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, in addition to compensation for material resource
damages, if any. Although "petroleum" is excluded from CERCLA's definition of a
"hazardous substance," in the course of our ordinary operations, we will
generate materials that may fall within the definition of "hazardous substance."
By operation of law, if we are determined to be a potentially responsible
person, we may be responsible under CERCLA for all or part of the costs required
to clean up sites at which such materials are present, in addition to
compensation for
35
material resource damages, if any.
Clean Air Act
Our operations are subject to the Clean Air Act and comparable state
statutes. We believe that the operations of our pipelines, storage facilities
and 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 our pipelines, treating
facilities, storage facilities and terminals. The U.S. 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, we may be required to incur certain
capital expenditures over the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals and addressing other air emission-related issues.
Due to the broad scope and complexity of the issues involved and the
resultant complexity and controversial nature of the regulations, full
development and implementation of many Clean Air Act regulations have been
delayed. Until such time as the new Clean Air Act requirements are implemented,
we are unable to estimate the effect on earnings or operations or the amount and
timing of such required capital expenditures. At this time, however, we do not
believe that we will be materially adversely affected by any such requirements.
Clean Water Act
Our operations can result in the discharge of pollutants. The Federal Water
Pollution control Act of 1972, as amended, also known as the Clean Water Act,
and analogous state laws impose restrictions and strict controls regarding the
discharge of pollutants into state waters or waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in accord
with the terms of a permit issued by applicable federal or state authorities.
The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean
Water Act as they pertain to prevention and response to oil spills. Spill
prevention control and countermeasure requirements of the Clean Water Act and
some state laws require diking and similar structures to help prevent
contamination of navigable waters in the event of an overflow or release. We
believe we are in substantial compliance with these laws.
EPA Gasoline Volatility Restrictions
In order to control air pollution in the United States, the U.S. 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 U.S. EPA
regulations have reduced demand and may have contributed to a significant
decrease in prices for normal butane, low normal butane prices have not impacted
our pipeline business in the same way they would impact a business with
commodity price risk. The U.S. EPA regulations have presented the opportunity
for additional transportation services on our North System. In the summer of
1991, our 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.
Risk Factors
Pending Federal Energy Regulatory Commission and California Public Utilities
Commission proceedings seek substantial refunds and reductions in tariff rates
on some of our pipelines. If the proceedings are determined adversely, they
could have a material adverse impact on us. Regulators and shippers on our
pipelines have rights to challenge the rates we charge under certain
circumstances prescribed by applicable regulations. In 1992, and from
36
1995 through 2001, some shippers on our pipelines filed complaints with the
Federal Energy Regulatory Commission and California Public Utilities Commission
that seek substantial refunds for alleged overcharges during the years in
question and prospective reductions in the tariff rates on our Pacific
operations' pipeline system.
The FERC complaints, separately docketed in two different proceedings,
predominantly attacked the interstate pipeline tariff rates of our Pacific
operations' pipeline system, contending that the rates were not just and
reasonable under the Interstate Commerce Act and should not be entitled to
"grandfathered" status under the Energy Policy Act. Complaining shippers seek
substantial reparations for alleged overcharges during the years in question and
request prospective rate reductions on each of the challenged facilities.
Hearings on the second of these two proceedings began in October 2001, and an
initial decision by the administrative law judge is expected in the first half
of 2003.
The complaints filed before the CPUC challenge the rates charged for
intrastate transportation of refined petroleum products through the Pacific
operations' pipeline system in California. After the CPUC dismissed the initial
complaint and subsequently granted a limited rehearing on April 10, 2000, the
complainants filed a new complaint with the CPUC asserting the intrastate rates
were not just and reasonable.
We currently believe the FERC complaints seek approximately $197 million in
tariff reparations and prospective annual tariff reductions, the aggregate
average annual impact of which would be approximately $45 million. We currently
believe the CPUC complaints seek approximately $15 million in tariff reparations
and prospective annual tariff reductions, the aggregate average annual impact of
which would be approximately $31 million. If any amounts are ultimately owed, it
will be impacted by the passage of time and the application of interest.
Decisions regarding these complaints could negatively impact our cash flow.
Additional challenges to tariff rates could be filed with the FERC and CPUC in
the future. For additional information regarding these complaints, please see
Note 16 of the Notes to the Consolidated Financial Statements included elsewhere
in this report.
Proposed rulemaking by the Federal Energy Regulatory Commission or other
regulatory agencies having jurisdiction could adversely impact our income and
operations. New regulations or different interpretations of existing regulations
applicable to our assets could have a negative impact on our business, financial
condition and results of operations. For example, on September 27, 2001, the
FERC issued a Notice of Proposed Rulemaking in Docket No. RM01-10. The proposed
rule would expand the FERC's current standards of conduct to include a regulated
transmission provider and all of its energy affiliates. It is not known whether
the FERC will issue a final rule in this docket and, if it does, whether as a
result we could incur increased costs and increased difficulty in our
operations.
Increased regulatory requirements relating to the integrity of our pipelines
will require us to spend additional money to comply with these requirements.
Through our regulated pipeline subsidiaries, we are subject to extensive laws
and regulations related to pipeline integrity. For example, recent federal
legislation signed into law in December 2002 includes new guidelines for the
U.S. DOT and pipeline companies in the areas of testing, education, training and
communication. Compliance with existing and recently enacted regulations
requires significant expenditures. Additional laws and regulations that may be
enacted in the future could significantly increase the amount of these
expenditures.
Our rapid growth may cause difficulties integrating new operations. As
discussed above, part of our business strategy includes acquiring additional
businesses that will allow us to increase distributions to our unitholders.
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 amounts of time to
integrating the acquired business with existing operations. These efforts may
temporarily distract their 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 often will not join our management team.
The change in management may make it more difficult to integrate an acquired
business with our existing operations.
Our acquisition strategy requires access to new capital. Tightened credit
markets or more expensive capital would impair our ability to grow. Part of our
business strategy includes acquiring additional businesses that will allow us to
increase distributions to our unitholders. During the period from December 31,
1996 to December 31, 2002, we made a significant number of acquisitions that
increased our asset base over 28 times and increased our net income over 51
times. We regularly consider and enter into discussions regarding potential
acquisitions and are
37
currently contemplating potential acquisitions. These transactions can be
effected quickly, may occur at any time and may be significant in size relative
to our existing assets and operations. We may need new capital to finance these
acquisitions. Limitations on our access to capital will impair our ability to
execute this strategy. We normally fund acquisitions with short term debt and
repay such debt through equity and debt offerings. An inability to access the
capital markets may result in a substantial increase in our leverage and have a
detrimental impact on our credit profile. One of the factors that increases our
attractiveness to investors, and as a result may make it easier for us to access
the capital markets, is the fact that distributions to our partners are not
subject to the double taxation that shareholders in corporations may experience
with respect to dividends that they receive. President Bush has proposed
eliminating the tax on corporate dividends. If the tax on corporate dividends
were eliminated or reduced, such a change could potentially make it more
difficult for us to access the capital markets and reduce the value of our
units.
Environmental regulation could result in increased operating and capital
costs for us. Our business operations are subject to federal, state and local
laws and regulations relating to environmental protection. If an accidental leak
or spill of liquid petroleum products or chemicals occurs from our pipelines or
at our storage facilities, we may have to pay a significant amount to clean up
the leak or spill or pay for government penalties, liability to government
agencies for natural resource damage, personal injury or property damage to
private parties or significant business interruption. The resulting costs and
liabilities could negatively affect our level of cash flow. In addition,
emission controls required under the Federal Clean Air Act and other similar
federal and state laws could require significant capital expenditures at our
facilities. The impact of Environmental Protection Agency standards or future
environmental measures on us could increase our costs significantly if
environmental laws and regulations become stricter. The costs of environmental
regulation are already significant, and additional regulation could increase
these costs or could otherwise negatively affect our business.
Competition could ultimately lead to lower levels of profits and lower cash
flow. We face competition from other pipelines and terminals in the same markets
as our assets, as well as from other means of transporting and storing energy
products. For a description of the competitive factors facing our business,
please see Items 1 and 2 "Business and Properties" in this report for more
information.
We do not own approximately 97.5% of the land on which our pipelines are
constructed and we are subject to the possibility of increased costs to retain
necessary land use. We obtain the right to construct and operate the pipelines
on other people's land for a period of time. If we were to lose these rights,
our business could be affected negatively.
Southern Pacific Transportation Company has allowed us to construct and
operate a significant portion of our Pacific operations' pipeline system 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, we may be required to obtain permission from the
landowners in order to continue to maintain the pipelines. Approximately 10% of
our pipeline assets are located in the ground underneath railroad rights-of-way.
Whether we have the power of eminent domain for our pipelines varies from
state to state depending upon the type of pipeline -- petroleum liquids, natural
gas or carbon dioxide -- and the laws of the particular state. Our inability to
exercise the power of eminent domain could negatively affect our business if we
were to lose the right to use or occupy the property on which our pipelines are
located.
We could be treated as a corporation for United States income tax purposes.
Our treatment as a corporation would substantially reduce the cash distributions
on the common units that we will distribute quarterly. The anticipated benefit
of an investment in our common units depends largely on the treatment of us as a
partnership for federal income tax purposes. We have not requested, and do not
plan to request, a ruling from the Internal Revenue Service on this or any other
matter affecting us. Current law requires us to derive at least 90% of our
annual gross income from specific activities to continue to be treated as a
partnership for federal income tax purposes. We may
38
not find it possible, regardless of our efforts, to meet this income
requirement or may inadvertently fail to meet this income requirement. Current
law may change so as to cause us to be treated as a corporation for federal
income tax purposes without regard to our sources of income or otherwise subject
us to entity-level taxation.
If we were to be treated as a corporation for federal income tax purposes, we
would pay federal income tax on our income at the corporate tax rate, which is
currently a maximum of 35% and would pay state income taxes at varying rates.
Under current law, distributions to unitholders would generally be taxed as a
corporate distribution. Because a tax would be imposed upon us as a corporation,
the cash available for distribution to a unitholder would be substantially
reduced. Treatment of us as a corporation would cause a substantial reduction in
the value of our units.
Our debt instruments may limit our financial flexibility and increase our
financing costs. The instruments governing our debt contain restrictive
covenants that may prevent us from engaging in certain transactions that we deem
beneficial and that may be beneficial to us. The agreements governing our debt
generally require us 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;
o granting liens; and
o entering into sale-leaseback transactions.
The instruments governing any future debt may contain similar restrictions.
If interest rates increase significantly, our earnings could be adversely
affected. At December 31, 2002, we had approximately $1.9 billion of debt,
excluding fair market of interest rate swaps, subject to variable interest
rates.
The distressed financial condition of some of our customers could have an
adverse impact on us in the event these customers are unable to pay us for the
services we provide. Some of our customers are experiencing severe financial
problems. The bankruptcy of one or more of them, or some other similar
proceeding or liquidity constraint might make it unlikely that we would be able
to collect all or a significant portion of amounts owed by the distressed entity
or entities. In addition, such events might force such customers to reduce or
curtail their future use of our products and services, which could have a
material adverse effect on our results of operations and financial condition.
The interests of KMI may differ from our interest and the interests of our
unitholders. KMI indirectly owns all of the stock of our general partner and
elects all of its directors. Our general partner owns all of KMR's voting shares
and elects all of its directors. Furthermore, some of KMR's directors and
officers are also directors and officers of KMI and our general partner and have
fiduciary duties to manage the businesses of KMI in a manner that may not be in
the best interest of our unitholders. KMI has a number of interests that differ
from the interests of our unitholders. As a result, there is a risk that
important business decisions will not be made in the best interests of our
unitholders.
Our partnership agreement restricts or eliminates a number
of the fiduciary duties that would otherwise be owed by our general partner to
our unitholders. Modifications of state law standards of fiduciary duties may
significantly limit the ability of our unitholders to successfully challenge the
actions of our general partner in the event of a breach of fiduciary duties.
These state law standards include the duties of care and loyalty. The duty of
loyalty, in the absence of a provision in the limited partnership agreement
to the contrary, would generally prohibit our general partner from taking any
action or engaging in any transaction as to which
39
it has a conflict of interest. Our limited partnership agreement contains
provisions that prohibit limited partners from advancing claims that otherwise
might raise issues as to compliance with fiduciary duties or applicable law. For
example, that agreement provides that the general partner may take into account
the interests of parties other than us in resolving conflicts of interest.
Further, it provides that in the absence of bad faith by the general partner,
the resolution of a conflict by the general partner will not be a breach of any
duty. The provisions relating to the general partner apply equally to KMR as its
delegate.
Item 3. Legal Proceedings.
See Note 16 of the Notes to the Consolidated Financial Statements 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 our unitholders during the
fourth quarter of 2002.
40
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters.
The following table sets forth, for the periods indicated, the high and low
sale prices per common unit, as reported on the New York Stock Exchange, the
principal market in which our common units are traded, the amount of cash
distributions declared per common and Class B unit, and the fractional i-unit
distribution declared per i-unit. All information has been adjusted to give
effect to the two-for-one split of common units and i-units effective August 31,
2001.
Price Range
Cash i-unit
High Low Distributio Distributions
------ ------ ------------------------
2002
First Quarter $38.65 $28.60 $0.5900 0.016969
Second Quarter 36.55 30.98 0.6100 0.019596
Third Quarter 33.90 28.00 0.6100 0.020969
Fourth Quarter 35.45 30.15 0.6250 0.018815
2001
First Quarter $31.73 $26.13 $0.5250 (1)
Second Quarter 36.70 30.67 0.5250 0.014837
Third Quarter 37.08 30.75 0.5500 0.014738
Fourth Quarter 39.05 34.55 0.5500 0.014818
- ----------
(1)There was no i-unit distribution for the first quarter of 2001. We initially
issued i-units in May 2001.
All of the information is for distributions declared with respect to that
quarter. The declared distributions were paid within 45 days after the end of
the quarter. We currently expect that we will continue to pay comparable cash
and i-unit distributions in the future assuming no adverse change in our
operations, economic conditions and other factors. However, we can give no
assurance that future distributions will continue at such levels.
As of January 31, 2003, there were approximately 109,000 beneficial owners of
our common units, one holder of our Class B units and one holder of our i-units.
41
Item 6. Selected Financial Data
The following tables set forth, for the periods and at the dates indicated,
selected historical financial data for us.
Year Ended December 31,
--------------------------------------------
2002(4) 2001(5) 2000(6) 1999(7) 1998(8)
(In thousands, except per unit data)
Income and Cash Flow Data:
Revenues..................... $4,237,057 $2,946,676 $ 816,442 $428,749 $322,617
Cost of product sold ........ 2,704,295 1,657,689 124,641 16,241 5,860
Operating expense............ 431,153 400,601 185,967 107,357 74,768
Fuel and power............... 86,413 73,188 43,216 31,745 22,385
Depreciation and
amortization............... 172,041 142,077 82,630 46,469 36,557
General and administrative... 118,857 109,293 64,427 39,530 42,378
---------- ---------- ---------- -------- --------
Operating income............. 724,298 563,828 315,561 187,407 140,669
Earnings from equity
investments................ 89,258 84,834 71,603 42,918 25,732
Amortization of excess cost of
Equity investments ........ (5,575) (9,011) (8,195) (4,254) (764)
Interest expense............. (178,279) (175,930) (97,102) (54,336) (40,856)
Interest income and other,
Net........................ (6,042) (5,005) 10,415 22,988 (5,992)
Income tax provision......... (15,283) (16,373) (13,934) (9,826) (1,572)
----------- ----------- ----------- ---------- ---------
Income before extraordinary
Charge.................... 608,377 442,343 278,348 184,897 117,217
Extraordinary charge -- -- -- (2,595) (13,611)
----------- ----------- ----------- ---------- ---------
Net income.................. $ 608,377 $ 442,343 $ 278,348 $ 182,302 $ 103,606
General Partner's interest
in net income............ $ 270,816 $ 202,095 $ 109,470 $ 56,273 $ 33,447
Limited Partners' interest
in net income............... $ 337,561 $ 240,248 $ 168,878 $ 126,029 $ 70,159
Basic Limited
Partners' income
per unit before
extraordinary charge(1).... $ 1.96 $ 1.56 $ 1.34 $ 1.31 $ 1.04
Basic Limited Partners' net
income per unit............ $ 1.96 $ 1.56 $ 1.34 $ 1.29 $ 0.87
Diluted Limited Partners' net
income per unit(2)......... $ 1.96 $ 1.56 $ 1.34 $ 1.29 $ 0.87
Per unit cash distribution
Paid....................... $ 2.36 $ 2.08 $ 1.60 $ 1.39 $ 1.19
Additions to property, plant
and equipment............. $ 542,235 $ 295,088 $ 125,523 $ 82,725 $ 38,407
Balance Sheet Data (at end of period):
Net property, plant and
equipment................... $6,244,242 $5,082,612 $3,306,305 $2,578,313 $1,763,386
Total assets................ $8,353,576 $6,732,666 $4,625,210 $3,228,738 $2,152,272
Long-term debt(3)........... $3,659,533 $2,237,015 $1,255,453 $ 989,101 $ 611,571
Partners' capital........... $3,415,929 $3,159,034 $2,117,067 $1,774,798 $1,360,663
- ----------
(1)Represents income before extraordinary charge per unit adjusted for the
two-for-one split of units on August 31, 2001. Basic Limited Partners' income
per unit before extraordinary charge was computed by dividing the interest of
our unitholders in income before extraordinary charge by the weighted average
number of units outstanding during the period.
(2)Diluted Limited Partners' net income per unit reflects the potential
dilution, by application of the treasury stock method, that could occur if
options to issue units were exercised, which would result in the issuance of
additional units that would then share in our net income.
(3) Excludes market value of interest rate swaps.
(4)Includes results of operations for the additional 10% interest in the Cochin
Pipeline System, Kinder Morgan Materials Services LLC (formerly Laser
Materials Services LLC), the 66 2/3% interest in International Marine
Terminals, Tejas Gas,
42
LLC, Milwaukee Bagging Operations, the remaining 33 1/3% interest in
Trailblazer Pipeline Company, the Owensboro Gateway Terminal and IC Terminal
Holdings Company and Consolidated Subsidiaries since dates of acquisitions.
The additional interest in Cochin was acquired on December 31, 2001. Kinder
Morgan Materials Services LLC was acquired on January 1, 2002. We acquired a
33 1/3% interest in International Marine Terminals on January 1, 2002 and an
additional 33 1/3% interest on February 1, 2002. Tejas Gas, LLC was acquired
on January 31, 2002. The Milwaukee Bagging Operations were acquired on May 1,
2002. The remaining interest in Trailblazer was acquired on May 6, 2002. The
Owensboro Gateway Terminal and IC Terminal Holdings Company and Subsidiaries
were acquired on September 1, 2002.
(5)Includes results of operations for the remaining 50% interest in the Colton
Processing Facility, Kinder Morgan Texas Pipeline, Casper and Douglas gas
gathering assets, 50% interest in Coyote Gas Treating, LLC, 25% interest in
Thunder Creek Gas Services, LLC, Central Florida Pipeline LLC, Kinder Morgan
Liquids Terminals LLC, Pinney Dock & Transport LLC, CALNEV Pipe Line LLC,
34.8% interest in the Cochin Pipeline System, Vopak terminal LLCs, Boswell
terminal assets, Stolt-Nielsen terminal assets and additional gasoline and
gas plant interests since dates of acquisition. The remaining interest in the
Colton Processing Facility, Kinder Morgan Texas Pipeline, Casper and Douglas
gas gathering assets and our interests in Coyote and Thunder Creek were
acquired on December 31, 2000. Central Florida and Kinder Morgan Liquids
Terminals LLC were acquired January 1, 2001. Pinney Dock was acquired March
1, 2001. CALNEV was acquired March 30, 2001. Our second investment in Cochin,
representing a 2.3% interest, was made on June 20, 2001. Vopak terminal LLCs
were acquired July 10, 2001. Boswell terminals were acquired August 31, 2001.
Stolt-Nielsen terminals were acquired on November 8 and 29, 2001, and our
additional interests in the Snyder Gasoline Plant and the Diamond M Gas Plant
were acquired on November 14, 2001.
(6)Includes results of operations for Kinder Morgan Interstate Gas
Transmission, 66 2/3% interest in Trailblazer, 49% interest in Red Cedar,
Milwaukee Bulk Terminals, Dakota Bulk Terminal, remaining 80% interest in
Kinder Morgan CO2 Company, L.P., Devon Energy carbon dioxide properties,
Kinder Morgan Transmix Company, LLC, a 32.5% interest in Cochin Pipeline
System and Delta Terminal Services LLC since dates of acquisition. Kinder
Morgan Interstate Gas Transmission, Trailblazer assets, and our 49% interest
in Red Cedar were acquired on December 31, 1999. Milwaukee Bulk Terminals,
Inc. and Dakota Bulk Terminal, Inc. were acquired on January 1, 2000. The
remaining 80% interest in Kinder Morgan CO2 Company, L.P. was acquired April
1, 2000. The Devon Energy carbon dioxide properties were acquired June 1,
2000. Kinder Morgan Transmix Company, LLC was acquired on October 25, 2000.
Our 32.5% interest in Cochin was acquired on November 3, 2000, and Delta
Terminal Services LLC was acquired on December 1, 2000.
(7)Includes results of operations for 51% interest in Plantation Pipe Line
Company, Products Pipelines' initial transmix operations and 33 1/3% interest
in Trailblazer Pipeline Company since dates of acquisition. Our second
investment in Plantation, representing a 27% interest was made on June 16,
1999. The Products Pipelines' initial transmix operations were acquired on
September 10, 1999, and our initial 33 1/3% investment in Trailblazer was
made on November 30, 1999.
(8)Includes results of operations for Pacific operations' pipeline system,
Kinder Morgan Bulk Terminals and 24% interest in Plantation Pipe Line Company
since dates of acquisition. The Pacific operations' pipeline system was
acquired March 6, 1998. Kinder Morgan Bulk Terminals were acquired on July 1,
1998 and our 24% interest in Plantation Pipe Line Company was acquired on
September 15, 1998.
43
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Our discussion and analysis of our financial condition and results of
operations are based on our Consolidated Financial Statements, which were
prepared in accordance with accounting principles generally accepted in the
United States of America. You should read the following discussion and analysis
in conjunction with our Consolidated Financial Statements included elsewhere in
this report, specifically, in connection with Note 15 to our Consolidated
Financial Statements, entitled "Reportable Segments".
Critical Accounting Policies and Estimates
Certain amounts included in or affecting our Consolidated Financial
Statements and related disclosures must be estimated, requiring us to make
certain assumptions with respect to values or conditions that cannot be known
with certainty at the time the financial statements are prepared.
The preparation of our financial statements in conformity with generally
accepted accounting principles requires our management to make estimates and
assumptions that affect:
o the amounts we report for assets and liabilities;
o our disclosure of contingent assets and liabilities at the date of the
financial statements; and
o the amounts we report for revenues and expenses during the reporting
period.
Therefore, the reported amounts of our assets and liabilities, revenues and
expenses and associated disclosures with respect to contingent assets and
obligations are necessarily affected by these estimates. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with experts and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates. Any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others.
With respect to our environmental exposure, we utilize both internal staff
and external experts to assist us in identifying environmental issues and in
estimating the costs and timing of remediation efforts. Often, as the
remediation evaluation and effort progresses, additional information is
obtained, requiring revisions to estimated costs. These revisions are reflected
in our income in the period in which they are reasonably determinable. In
December 2002, after a thorough review of any potential environmental issues
that could impact our assets or operations and of our need to correctly record
all related environmental contingencies, we recognized a $0.3 million
non-recurring reduction in environmental expense and in our overall accrued
environmental liability, and we included this amount within Other, net in the
accompanying Consolidated Statement of Income for 2002. The $0.3 million income
item resulted from the necessity of properly adjusting and realigning our
environmental expenses and accrued liabilities between our reportable business
segments, specifically between our Products Pipelines and our Terminals business
segments. The $0.3 million reduction in environmental expense resulted in a
$15.7 million non-recurring loss to our Products Pipelines business segment and
a $16.0 million non-recurring gain to our Terminals business segment.
With respect to legal proceedings, we are subject to litigation and
regulatory proceedings as the result of our business operations and
transactions. We utilize both internal and external counsel in evaluating our
potential exposure to adverse outcomes from orders, judgments or settlements. To
the extent that actual outcomes differ from our estimates, or additional facts
and circumstances cause us to revise our estimates, our earnings will be
affected. In general, we expense legal costs as incurred. When we identify
specific litigation that is expected to continue for a
44
significant period of time and require substantial expenditures, we identify
a range of possible costs expected to be required to litigate the matter to a
conclusion or reach an acceptable settlement. If no amount within this range is
a better estimate than any other amount, we record a liability equal to the low
end of the range. Any such liability recorded is revised as better information
becomes available.
In addition, effective January 1, 2002, we adopted Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets". SFAS No.
142 eliminates the amortization of goodwill, requires annual impairment testing
of goodwill and introduces the concept of indefinite life intangible assets. The
new rules also prohibit the amortization of goodwill associated with business
combinations that close after June 30, 2001.
These new requirements will impact future period net income by an amount
equal to the discontinued goodwill amortization offset by goodwill impairment
charges, if any, and adjusted for any differences between the old and new rules
for defining intangible assets on future business combinations. An initial
impairment test was required in 2002 as of January 1, 2002. We completed this
initial transition impairment test in June 2002 and determined that our goodwill
was not impaired as of January 1, 2002.
Finally, regarding our pension disclosures, we are required to make
assumptions and estimates regarding the accuracy of our pension investment
returns. Specifically, these include:
o our investment return assumptions;
o the significant estimates on which those assumptions are based; and
o the potential impact that changes in those assumptions could have on our
reported results of operations and cash flows.
We consider our overall pension liability exposure to be minimal in relation
to the value of our total consolidated assets and net income. However, in
accordance with SFAS No. 87, "Employers' Accounting for Pensions", a component
of our net periodic pension cost includes the return on pension plan assets,
including both realized and unrealized changes in the fair market value of
pension plan assets.
A source of volatility in pension costs comes from this inclusion of
unrealized or market value gains and losses on pension assets as part of the
components recognized as pension expense. To prevent wide swings in pension
expense from occurring because of one-time changes in fund values, SFAS No. 87
allows for the use of an actuarial computed "expected value" of plan asset gains
or losses to be the actual element included in the determination of pension
expense. The actuarial derived expected return on pension assets not only
employs an expected rate of return on plan assets, but also assumes a
market-related value of plan assets, which is a calculated value that recognizes
changes in fair value in a systematic and rational manner over not more than
five years. As required, we disclose the weighted average expected long-run rate
of return on our plan assets, which is used to calculate our plan assets'
expected return. For more information on our pension disclosures, see Note 10 to
our Consolidated Financial Statements, included elsewhere in this report.
Results of Operations
In 2002, we managed to again achieve record levels of revenues, operating
income, net income and earnings per unit. The fiscal year ended December 31,
2002 marked the fifth successive year that we have improved on all four of these
operating measures since the change in control of our general partner in
February 1997. We owe our success primarily to the continuing execution of the
same strategy adopted by management in 1997:
o providing, for a fee, transportation, storage and handling services which
are core to the energy infrastructure of growing markets;
o increasing utilization of assets while containing costs;
o leveraging economies of scale from incremental acquisitions and
expansions; and
45
o maximizing the benefits of our financial structure.
In 2002, our net income was $608.4 million ($1.96 per diluted unit) on
revenues of $4,237.1 million, compared to net income of $442.3 million ($1.56
per diluted unit) on revenues of $2,946.7 million in 2001, and net income of
$278.3 million ($1.34 per diluted unit) on revenues of $816.4 million in 2000.
Our total consolidated operating income was $724.3 million in 2002, $563.8
million in 2001 and $315.6 million in 2000. Operating expenses, excluding
depreciation, depletion and amortization, general and administrative expenses
and taxes, other than income taxes, were $3,170.5 million in 2002, compared with
$2,087.5 million in 2001 and $332.2 million in 2000.
The increases in overall revenues, expenses and net income in 2002 compared
to 2001 were attributable to both solid internal growth and contributions from
acquired assets, especially from our acquisition of Kinder Morgan Tejas,
formerly Tejas Gas, LLC, on January 31, 2002. Each of our four business segments
reported increased earnings in 2002 over 2001. The increases in overall
revenues, expenses and income in 2001 compared to 2000 resulted mainly from
assets and businesses that we acquired from GATX Corporation in the first
quarter of 2001, from KMI on December 31, 2000, and from other acquisitions made
during 2001 as well as internal growth from existing assets. In addition, in
2001, just as in 2002, each business segment reported increased earnings over
the prior year.
Equity earnings, from our investments accounted for under the equity method
of accounting, were $83.7 million in 2002, $75.8 million in 2001 and $63.4
million in 2000. These amounts represent equity earnings net of expense from
allowable amortization of excess investment costs. Additionally, we declared a
record cash distribution of $0.625 per unit for the fourth quarter of 2002 (an
annualized rate of $2.50). Our distribution for the fourth quarter of 2002 was
14% higher than the $0.55 per unit distribution we made for the fourth quarter
of 2001, and 32% higher than the $0.475 per unit distribution we made for the
fourth quarter of 2000.
Products Pipelines
Our Products Pipelines segment reported earnings of $343.9 million on
revenues of $576.5 million in 2002. This compared to earnings of $312.5 million
on revenues of $605.4 million in 2001 and earnings of $222.7 million on revenues
of $420.3 million in 2000. Operating expenses, excluding depreciation and taxes,
other than income taxes, were $151.1 million, $222.5 million and $172.4 million
for each of the three years ended December 31, 2002, 2001 and 2000,
respectively. The $31.4 million (10%) overall increase in segment earnings in
2002 over 2001 includes the $15.7 million non-recurring loss from the adjustment
and realignment of our environmental liabilities referred to above in our
"Critical Accounting Policies and Estimates". Excluding the non-recurring
environmental loss, segment earnings were $359.6 million in 2002. The increase
in segment earnings in 2002 over the prior year was primarily related to the
strong year-to-year results reported from our CALNEV pipeline operations, our
44.8% ownership interest in the Cochin Pipeline system and our Pacific
operations.
The year-to-year $28.9 million (5%) decrease in segment revenues and the
$71.4 million (32%) decrease in segment expenses, include reductions of $67.8
million in transmix revenues and $68.6 million in transmix expenses, both
resulting from our long-term transmix processing agreement with Duke Energy
Merchants. During the first quarter of 2001, we entered into a 10-year agreement
with Duke Energy Merchants to process transmix on a fee basis only. Under the
agreement, Duke Energy Merchants is responsible for procurement of the transmix
and sale of the products after processing. This agreement allows us to eliminate
commodity price exposure in our transmix operations.
Partially offsetting the overall decrease in segment revenues was a $14.7
million increase in revenues earned from our CALNEV Pipeline, the result of an
almost 2% increase in average pipeline tariff rates in 2002 and the inclusion,
in 2002, of a full year of operations versus nine months in 2001. Our
proportionate share of revenues from the Cochin Pipeline system increased $12.0
million in 2002 compared to 2001, the increase resulting from higher volumes and
tariffs as well as our additional ownership interest. Our Pacific operations
reported a $10.6 million (4%) increase in revenues in 2002 compared to 2001.
Although mainline delivery volumes remained flat in 2002, compared to the prior
year, overall revenues were higher due to a 2% increase in average pipeline
tariff rates and higher non-transportation revenues.
46
For all products pipelines owned or operated at both December 31, 2002 and
2001, total throughput delivery of refined petroleum products, consisting of
gasoline, diesel fuel and jet fuel, was up 1.2% in 2002 over 2001. Gasoline
delivery volumes were up 4.5% in 2002, compared to 2.6% nationally. Although our
total jet fuel delivery volumes were down 3.8% for 2002, reflecting the effects
of the September 11, 2001 terrorist attacks, deliveries of jet fuel improved
steadily throughout the year.
Excluding the $68.6 million decrease in our transmix cost of sales expense
referred to above, the segment's overall expenses remained relatively flat
during 2002. Excluding depreciation and taxes, other than income taxes, expenses
related to Cochin increased a slight $1.7 million, due to the increase in
delivery volumes and our additional ownership interest.
The $89.8 million (40%) increase in segment earnings in 2001 compared to 2000
was mainly attributable to acquisitions we made since December 2000 and to cost
savings resulting from our assumption of the operating duties of Plantation Pipe
Line Company on December 21, 2000. The $185.1 million (44%) increase in revenues
for 2001 compared to 2000 was primarily the result of an incremental $158.5
million in revenues from acquisitions made since the fourth quarter of 2000,
$39.4 million in operating reimbursements from Plantation, and a $21.0 million
(8%) improvement in our Pacific operations' revenues, primarily resulting from a
3% increase in mainline delivery volumes and an over 4% increase in average
tariff rates.
Acquisitions made since the fourth quarter of 2000, which contributed to our
segment's results in 2001 include:
o Kinder Morgan Transmix Company, LLC;
o the remaining 50% interest in the Colton Transmix Processing Facility;
o a 34.8% interest in the Cochin Pipeline system (in January 2002, we
acquired an additional 10% ownership interest, which was made effective
December 31, 2001, bringing our total interest to 44.8%); and
o assets acquired from GATX Corporation, consisting of Central Florida
Pipeline LLC, CALNEV Pipe Line LLC and petroleum product and chemical
terminals.
The segment's overall increase in revenues was partially offset by a $33.8
million decrease in transmix revenues, the result of entering into our long-term
transmix processing agreement with Duke Energy Merchants during the first
quarter of 2001, as referred to above. The $50.1 million (29%) increase in
expenses, excluding depreciation and taxes, other than income taxes, for our
Products Pipelines segment in 2001 compared to 2000, resulted primarily from our
acquisitions, costs incurred under our operations agreement with Plantation and
higher fuel and power expenses on our Pacific operations' pipelines. This
increase was partially offset by a reduction in transmix expenses due to our
agreement with Duke Energy Merchants.
Operating income for each of the three years ended December 31, 2002, 2001
and 2000 was $342.4 million, $299.0 million and $195.1 million, respectively.
Earnings from our Products Pipelines' equity investments, net of amortization of
excess costs, were $25.7 million in 2002, $22.7 million in 2001 and $29.1
million in 2000. The $3.0 million (13%) increase in net equity earnings in 2002
versus 2001 was due to a $2.3 million decrease in expenses from the amortization
of excess investment costs and a $0.7 million increase in equity earnings, both
related to our 51% ownership interest in Plantation Pipe Line Company. Effective
January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142
"Goodwill and Other Intangible Assets" and ceased amortizing the amount of our
equity investment costs that exceeded the underlying fair value of net assets.
The increase in our proportionate share of Plantation's earnings in 2002
resulted from Plantation's higher revenues and lower operating and interest
expenses. The higher revenues resulted from record delivery volumes, the lower
operating expenses resulted from lower power costs and the lower interest
expenses resulted from lower average borrowing rates. The $6.4 million (22%)
decrease in the segment's equity earnings in 2001 versus 2000 was due to lower
equity earnings from Plantation Pipe Line Company as a result of lower
throughput and to the absence of equity earnings from our Colton Transmix
Processing Facility during 2001. On December 31, 2000, we acquired the remaining
50% ownership interest in the facility and since that date, we have included
Colton's operational results in our consolidated financial statements.
47
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding CALNEV Pipe Line LLC and related terminals acquired from
GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at
the Federal Energy Regulatory Commission involving shippers' complaints
regarding the interstate rates, as well as practices and the jurisdictional
nature of certain facilities and services, on our Pacific operations' pipeline
systems. Generally, the interstate rates on our Pacific operations' pipeline
systems are "grandfathered" under the Energy Policy Act of 1992 unless
"substantially changed circumstances" are found to exist. To the extent
"substantially changed circumstances" are found to exist, our Pacific operations
may be subject to substantial exposure under these FERC complaints. We currently
believe that these FERC complaints seek approximately $197 million in tariff
reparations and prospective annual tariff reductions, the aggregate average
annual impact of which would be approximately $45 million. However, even if
"substantially changed circumstances" are found to exist, we believe that the
resolution of these FERC complaints will be for amounts substantially less than
the amounts sought.
Natural Gas Pipelines
Our Natural Gas Pipelines segment reported earnings of $276.8 million on
revenues of $3,086.2 million in 2002. In 2001, the segment reported earnings of
$193.8 million on revenues of $1,869.3 million, and in 2000, reported earnings
of $113.1 million on revenues of $174.2 million. Expenses, excluding
depreciation charges and taxes, other than income taxes, were $2,770.6 million,
$1,656.1 million and $51.3 million for each of the three years ended December
31, 2002, 2001 and 2000, respectively. The segment's significant $83.0 million
(43%) increase in year-to-year earnings and its $1,216.9 million (65%) increase
in year-to-year revenues in 2002 versus 2001 relate primarily to our January 31,
2002 acquisition of Kinder Morgan Tejas. Kinder Morgan Tejas' operations include
a 3,400-mile intrastate natural gas pipeline system that has good access to
natural gas supply basins in Texas. The acquisition and subsequent integration
of its assets with our pre-existing natural gas pipeline assets in the State of
Texas, particularly our Kinder Morgan Texas Pipeline system, has produced a
strategic and complementary intrastate pipeline business combination.
Both Kinder Morgan Tejas and KMTP, which together comprise our Texas
intrastate natural gas group, purchase and sell significant volumes of natural
gas, which is transported through their pipeline systems. Our objective is to
match every purchase and sale, thus locking-in the equivalent of a
transportation fee. The purchase and sale activity results in considerably
higher revenues and operating expenses compared to the interstate natural gas
pipeline systems of Kinder Morgan Interstate Gas Transmission and Trailblazer
Pipeline Company, which we acquired on December 31, 1999 from KMI. Both KMIGT
and Trailblazer charge a transportation fee for gas transmission service but
neither system has significant gas purchases and resales.
Together, in 2002, the combination of our two intrastate natural gas
pipeline systems earned $117.5 million, generated revenues of $2,830.0 million
and incurred $2,679.3 million in expenses, excluding depreciation and taxes,
other than income taxes. In 2001, KMTP alone had $48.0 million in earnings,
$1,599.3 million in revenues and $1,537.3 million in expenses. Year-over-year
operating results from our Trailblazer Pipeline Company also contributed to the
segment's increase in earnings and revenues in 2002. In May 2002, we completed a
$59 million expansion project that increased transportation capacity on the
pipeline by approximately 60%. As a result, Trailblazer realized a 24% increase
in natural gas transportation volumes in 2002 compared to 2001. The overall
increase in segment revenues in 2002 compared to 2001 was partially offset by a
$28.2 million decrease in revenues earned by our Casper and Douglas natural gas
gathering and processing system, and by a $16.0 million decrease in revenues
earned by KMIGT. Casper and Douglas' revenue decrease was primarily related to a
general decline in natural gas prices in and around the Rocky Mountain region
since the end of the third quarter of 2001, and KMIGT's revenue decrease was
mainly the result of lower operational gas sales and lower fuel recovery rates
in 2002.
The $1,114.5 million (67%) increase in segment expenses, excluding
depreciation and taxes, other than income taxes, in 2002 over 2001 was mainly
due to our Kinder Morgan Tejas acquisition, but the overall increase was
partially offset by a $26.8 million decrease in expenses incurred by Casper and
Douglas, related to the decrease in natural gas prices.
The segment's $80.7 million (71%) increase and $1,695.1 million increase in
year-to-year earnings and revenues in 2001 over 2000 relate primarily to the
inclusion of assets that we acquired from KMI on December 31, 2000, and
48
to a strong performance from our pre-existing assets.
Effective on December 31, 2000, we acquired from KMI:
o Kinder Morgan Texas Pipeline, L.P.;
o our Casper and Douglas natural gas gathering and processing systems;
o a 50% interest in Coyote Gas Treating, LLC; and
o a 25% interest in Thunder Creek Gas Services, LLC.
Combined, KMTP and the Casper and Douglas systems earned $64.6 million,
produced operating revenues of $1,688.6 million and incurred expenses, excluding
depreciation and taxes, other than income taxes, of $1,608.0 million in 2001.
The segment's overall increase in revenues in 2001 over 2000 also resulted from
a $9.2 million (6%) increase in revenues earned by KMIGT, mainly due to higher
fuel recovery revenues, driven by a reduction in fuel losses. The overall
increase in segment expenses was partially offset by lower expenses on the
Trailblazer Pipeline, primarily the result of favorable system imbalance
settlements.
Operating income for each of the three years ended December 31, 2002, 2001
and 2000 was $253.5 million, $171.9 million and $97.3 million, respectively. We
account for the segment's investments in Red Cedar Gas Gathering Company, Coyote
Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity method of
accounting. Earnings from these equity investments, net of amortization of
excess costs, were $23.6 million in 2002, $21.2 million in 2001 and $15.0
million in 2000. The $2.4 million (11%) increase in 2002 over 2001 resulted
primarily from a $1.1 million increase in earnings from our 49% interest in Red
Cedar, mainly due to a $0.9 million decrease in amortization of excess
investment costs related to our adoption of SFAS No. 142. The $6.2 million (41%)
increase in 2001 over 2000 resulted from the inclusion of $3.5 million of net
equity earnings from our investments in Coyote and Thunder Creek and a $2.7
million increase in earnings from our investment in Red Cedar, primarily the
result of higher revenues from custom compression projects.
CO2 Pipelines
Our CO2 Pipelines segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. In 2002, our CO2 Pipelines segment reported earnings of
$101.0 million on revenues of $146.3 million. This compared to earnings of $92.1
million on revenues of $122.1 million in 2001. Expenses, excluding depreciation,
depletion, amortization, and taxes, other than income taxes, totaled $42.7
million in 2002 versus $37.4 million in 2001. The $8.9 million (10%) increase in
year-to-year earnings was primarily attributable to the $24.2 million (20%)
increase in revenues, partially offset by higher depreciation, depletion and
operating expenses. The increase in revenues was driven by higher oil production
volumes produced at the segment's SACROC Unit, as well as higher carbon dioxide
pipeline delivery volumes. Oil production at SACROC, located in the Permian
Basin of West Texas, increased 43% in 2002 compared to 2001. Delivery volumes of
carbon dioxide, including deliveries on our Central Basin Pipeline and our
majority-owned Canyon Reef Carriers Pipeline increased 37% in 2002. Offsetting
the revenue increase was an $11.6 million (66%) increase in non-cash
depreciation and depletion charges and a $5.3 million (14%) increase in
operating and maintenance expenses, both of which related to the higher oil
production volumes. Depreciation and depletion charges were also up in 2002
compared to 2001, primarily as a result of the capital expenditures we made
since the end of 2001 and a change to a higher unit-of-production depletion rate
on January 1, 2002.
The segment reported operating income of $66.6 million in 2002 and $59.6
million in 2001. Earnings from equity investments, net of amortization of excess
costs, were $34.3 million in 2002, compared to $32.0 million in 2001. The $2.3
million (7%) increase resulted from higher earnings from the segment's 50%
ownership interest in Cortez Pipeline Company, mainly due to lower average debt
balances and lower average borrowing rates, partially offset by slightly lower
carbon dioxide delivery volumes.
Prior to April 1, 2000, we owned 20% of Kinder Morgan CO2 Company, L.P.,
formerly Shell CO2 Company, L.P., and we accounted for our investment under the
equity method of accounting. After our acquisition of the remaining 80%
ownership interest on April 1, 2000, we included the company's financial results
in our consolidated
49
financial statements. Therefore, the segment's 2000 results consist
primarily of:
o one quarter of equity earnings from our original 20% interest in Kinder
Morgan CO2 Company, L.P.;
o nine months of operations from pre-existing assets owned by the
partnership, including its 50% ownership interest in Cortez Pipeline
Company; and
o seven months of operations from significant carbon dioxide pipeline assets
and oil-producing property interests that were acquired from Devon Energy
on June 1, 2000.
For the year 2000, our CO2 Pipelines segment reported $68.1 million of
earnings, $26.8 million of expenses, excluding depreciation, depletion,
amortization and taxes, other than income taxes, and $89.2 million of revenues.
Operating income totaled $48.1 million and equity earnings, net of amortization
of excess costs, totaled $19.3 million, representing the $3.6 million from our
20% interest in Kinder Morgan CO2 Company, L.P. and $15.7 million from the
segment's interest in Cortez Pipeline Company.
Terminals
Our Terminals segment includes the business portfolio of approximately 50
terminals that transload and store coal, dry-bulk materials and
petrochemical-related liquids, as well as more than 60 transload operations in
20 states. The segment reported earnings of $191.6 million on revenues of $428.0
million in 2002. This compared to earnings of $136.2 million on revenues of
$349.9 million in 2001 and earnings of $40.2 million on revenues of $132.8
million in 2000. Expenses, excluding depreciation and taxes, other than income
taxes, for each of the three years ended December 31, 2002, 2001 and 2000, were
$206.1 million, $171.5 million and $81.7 million, respectively. Operating income
for each of the three years ended December 31, 2002, 2001 and 2000 was $180.7
million, $142.7 million and $39.5 million, respectively. The $55.4 million (41%)
increase in segment earnings in 2002 over 2001 includes the $16.0 million
non-recurring gain from the adjustment and realignment of our environmental
liabilities referred to above in our "Critical Accounting Policies and
Estimates".
Excluding the non-recurring environmental item mentioned in the immediately
preceding paragraph, segment earnings totaled $175.6 million in 2002. Most of
the growth in segment earnings and revenues in 2002 compared to 2001 was driven
by the acquisitions and asset purchases that we have made since the last half of
2001, as well as internal growth. These investments accounted for $25.1 million
of segment earnings growth in 2002. Internal growth at existing facilities,
primarily driven by expansion projects at various terminals, accounted for $14.3
million of segment earnings growth in 2002 over 2001.
Our acquisitions and additions included:
o the terminal businesses we acquired from Koninklijke Vopak N.V.,
effective July 10, 2001;
o the terminal businesses we acquired from The Boswell Oil Company,
effective August 31, 2001;
o the terminal businesses we acquired from an affiliate of Stolt-Nielsen,
Inc. in November 2001;
o Kinder Morgan Materials Services LLC, formerly Laser Materials Services
LLC, acquired effective January 1, 2002;
o a 66 2/3% interest in International Marine Terminals Partnership (a 33 1/3%
interest acquired effective January 1, 2002 and an additional 33 1/3%
interest acquired effective February 1, 2002);
o the Milwaukee Bagging Operations, acquired effective May 1, 2002;
o the Owensboro Gateway Terminal, acquired effective September 1, 2002;
o the St. Gabriel Terminal, acquired effective September 1, 2002; and
50
o the purchase of four floating cranes at our bulk terminal facility in Port
Sulphur, Louisiana in December 2002.
In 2002 compared to 2001, the acquisitions listed above accounted for
incremental amounts of $25.1 million in earnings, $88.5 million in revenues and
$56.4 million in expenses, excluding depreciation and taxes, other than income
taxes. Expansion projects undertaken during 2002 at our Carteret Terminal in New
York Harbor and at our Pasadena Terminal on the Houston, Texas Ship Channel
contributed to an almost 4% increase in the segment's leaseable capacity of
liquids products. In addition, while adding the incremental capacity during
2002, we maintained a strong liquids capacity utilization rate of 97%, the same
level reached in 2001. Declines in engineering services and in the volume of
transloaded bulk products partially offset the overall increases in segment
earnings and revenues in 2002. Including all bulk terminals owned at December
31, 2002, transloading of bulk tonnage decreased 6% in 2002 compared to 2001.
The decline was primarily due to lower terminal transfers of petroleum coke,
salt tonnage and other dry-bulk materials. Volumes of coal handled at our bulk
terminals are expected to continue to decline in 2003 due to the fact that we
will no longer operate the LAXT Coal Terminal after the first quarter of 2003
and to the opening of competing terminals during 2003 in the geographic regions
served by our Cora and Grand Rivers coal terminals. Volumes at Cora and Grand
Rivers are expected to decline by approximately 4 million tons in 2003.
Comparing 2001 to 2000, the year-to-year increases in our Terminals'
revenues, expenses and earnings were driven principally by the strategic
acquisitions we have made since the end of 2000.
In addition to the investments listed above, these acquisitions include:
o Delta Terminal Services LLC, acquired effective December 1, 2000;
o Kinder Morgan Liquids Terminals LLC, acquired from GATX Corporation
effective January 1, 2001; and
o Pinney Dock & Transport LLC, acquired effective March 1, 2001.
In 2001 compared to 2000, the acquisitions and investments we made since the
end of 2000 accounted for incremental amounts of $101.6 million in earnings,
$203.6 million in revenues and $79.4 million in expenses, excluding depreciation
and taxes, other than income taxes. On an aggregate basis, bulk tonnage transfer
volumes, including coal and all other bulk materials, increased 22% in 2001 over
2000 levels. Our transfers of liquids volumes, including refined petroleum
products, chemicals and all other liquids volumes increased 8% in 2001 compared
with 2000 when the liquids terminals were owned by other entities. The increase
in 2001 expenses over 2000 was the result of acquisitions made in 2001 and
higher maintenance and operating expenses associated with the transfer of higher
volumes.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. General and
administrative expenses totaled $118.9 million in 2002, compared to $109.3
million in 2001 and $64.4 million in 2000. The $9.6 million (9%) increase in
general and administrative expenses in 2002 compared to the prior year was
primarily due to additional employee benefit, compensation and reimbursement
charges, higher insurance related expenses and administrative expenses related
to our Kinder Morgan Tejas acquisition. The year-to-year increase in our general
and administrative expenses in 2001 compared to 2000 was mainly due to our
larger and more diverse operations. During 2001, we incorporated pipeline and
terminal businesses that we acquired from GATX Corporation, incorporated
additional natural gas pipeline assets that we acquired from KMI on December 31,
2000 and operated Plantation Pipe Line Company for a full year. We continue to
manage aggressively our infrastructure expense and to focus on our productivity
and expense controls.
Our total interest expense, net of interest income, was $176.5 million in
2002, $171.5 million in 2001 and $93.3 million in 2000. The slight $5.0 million
(3%) increase in net interest items in 2002 compared to 2001 reflects higher
average borrowings during 2002 due to our acquisition and expansion projects.
The change in net financing charges was partially offset by a decrease in
average borrowing rates that have occurred since the end of 2001. In 2002, we
issued $1.5 billion in principal amount of senior notes and we retired a
maturing amount of $200 million in principal amount of senior notes. In March
2001, we closed a public offering of $1.0 billion in principal amount of senior
51
notes. The 2001 increase was primarily due to the additional debt we issued
related to the financing of the acquisitions that we have made since the end of
2000 and to the $134.8 million in third-party debt we assumed as part of the
assets acquired from GATX Corporation.
Minority interest, which includes the 1.0101% general partner interest in our
five operating limited partnerships, totaled $9.6 million in 2002, compared to
$11.4 million in 2001 and $8.0 million in 2000. The $1.8 million (16%) decrease
in 2002 from 2001 resulted primarily from our acquisition of an additional
ownership interest in Trailblazer Pipeline Company. In May 2002, we acquired the
remaining 33 1/3% ownership interest in Trailblazer that we did not already own,
thereby eliminating the minority interest relating to Trailblazer Pipeline
Company. The $3.4 million (43%) increase in minority interest in 2001 over 2000
resulted from earnings attributable to MidTex Gas Storage Company, L.P., a
partnership controlled by Kinder Morgan Texas Pipeline L.P. as well as to our
higher overall income.
Outlook
We actively pursue a strategy to increase our operating income. We will use a
three-pronged approach to accomplish this goal.
o Cost Reductions. We have reduced the total operating, maintenance, general
and administrative expenses of those operations that we owned at the time
Kinder Morgan (Delaware), Inc. acquired our general partner in February
1997. In addition, we have made similar reductions in the operating,
maintenance, general and administrative expenses of many of the businesses
and assets that we acquired or have assumed operations of since February
1997, including our Pacific operations, Plantation Pipe Line Company, the
businesses we acquired from GATX Corporation and Kinder Morgan Tejas.
Generally, these reductions in expense have been achieved by eliminating
duplicative functions that we and the acquired businesses each maintained
prior to their combination. We intend to continue to seek further
reductions throughout our businesses where appropriate.
o Internal Growth. We intend to grow income from our current assets through
(a) increased utilization, and (b) internal expansion projects. We operate
classic fixed cost businesses with little variable costs. By controlling
these variable costs, any increase in utilization of our pipelines and
terminals generally results in an increase in income. Increases in
utilization are principally driven by increases in demand for gasoline, jet
fuel, natural gas and other energy products that we transport and/or
handle. Increases in demand for these products are typically driven by
demographic growth in markets we serve, including the rapidly growing
western and southeastern United States. In addition, we have undertaken a
number of expansion projects that management believes will also increase
revenues from existing operations, including the following:
o a $223 million investment project to expand our carbon dioxide business.
The project includes the construction of the new $40 million Centerline
Pipeline that will originate near Denver City, Texas, and transport carbon
dioxide to the Snyder, Texas area. The pipeline will consist of 113 miles
of 16-inch pipe and will primarily supply the SACROC Unit in the Permian
Basin of West Texas, but will also be available for existing and
prospective third-party carbon dioxide projects in the Horseshoe Atoll
area of the Permian Basin. Construction is expected to be completed by
mid-2003. The project also includes the spending of approximately $120
million to add additional infrastructure, including wells, injection and
compression facilities, to support the expanding carbon dioxide flooding
operations at the SACROC Unit. Based on positive response, by the end of
2002, we committed an additional $63 million to develop SACROC. These
expenditures are expected to quadruple carbon dioxide deliveries to the
SACROC Unit and triple oil production when compared to 2001 levels of 80
million cubic feet per day of carbon dioxide and 9,000 barrels per day of
crude oil;
o a $59 million expansion project on the Trailblazer pipeline. The
expansion project began in August 2001 and was completed in May 2002. The
expansion project increased transportation capacity on the pipeline by 60%
to 846,000 dekatherms per day of natural gas, and the increase has already
been fully subscribed by customers. The project included installing two
new compressor stations and adding 10,000 additional horsepower at an
existing compressor station;
52
o a $41.5 million investment in our growing terminals business. The
investment includes storage expansion and upgrade projects at our liquids
terminals located in Carteret, New Jersey, Pasadena, Texas and Dravosburg,
Pennsylvania. The major expansion work is taking place at Carteret and
Pasadena, and will follow the expansions that were initiated there in
2001. At Carteret, in the New York Harbor area, this expansion project
will add an additional 400,000 barrels of petroleum storage capacity and
will include the construction of a new 16-inch pipeline that will connect
to the Buckeye Pipeline system, a major products pipeline serving the East
Coast. The expansion work at our Carteret terminal is expected to be
completed in the third quarter of 2003. At Pasadena, on the Houston Ship
Channel, the expansion project will increase storage capacity by another
300,000 barrels of petroleum products and is expected to be completed in
the second quarter of 2003;
o a $30 million investment project that involves the construction of
pipeline, compression and storage facilities to accommodate an additional
6 billion cubic feet of natural gas storage capacity on Kinder Morgan
Interstate Gas Transmission LLC's Cheyenne Market Center. The additional
service has been fully subscribed under 10-year contracts. The Cheyenne
Market Center is a new service offering firm natural gas storage
capabilities that will allow for the receipt, storage and subsequent
re-delivery of natural gas supplies at applicable points located in the
vicinity of the Cheyenne Hub in Weld County, Colorado and our Huntsman
storage facility in Cheyenne County, Nebraska. The Cheyenne Market Center
is expected to begin service during the summer of 2004;
o a $116 million project to expand the capacity on a 190-mile segment of
the Plantation Pipe Line system. The project will entail replacing an
existing eight-inch pipeline between Bremen, Georgia and Knoxville,
Tennessee with a new 20-inch pipeline. The expansion will double capacity
on the segment of the pipeline to approximately 90,000 barrels per day of
refined petroleum products. Construction will be initiated only after
additional commitments from interested shippers are obtained;
o a $10.7 million investment in a storage expansion project at our liquids
terminal located in Perth Amboy, New Jersey. The expansion includes the
construction of an additional 300,000 barrels of storage and increases the
petroleum capacity at the facility by more than 20%. The expansion
accommodates a long-term storage agreement that we entered into with a
petroleum customer for storage services in the New York Harbor area. We
expect to complete this expansion project by the end of 2003;
o a $16.4 million investment in expansion projects at existing bulk
terminal facilities in 2002. The investments include the purchase of four
barge-mounted crane units from Stevedoring Services of America for use at
our International Marine Terminal located in Port Sulphur, Louisiana, new
storage facilities at several bulk terminal sites and continued marine
improvements at our Shipyard River Terminal located in Charleston, South
Carolina; and
o an $87 million investment project that involves the construction of the
95-mile, 30-inch Mier-Monterrey natural gas pipeline that stretches from
South Texas to Monterrey, Mexico, one of Mexico's fastest growing
industrial areas. The new pipeline will interconnect with the southern end
of the Kinder Morgan Texas Pipeline system in Starr County, Texas, and is
designed to initially transport up to 375,000 dekatherms per day of
natural gas. We have entered into 15-year contract with Pemex Gas Y
Petroquimica Basica, which has subscribed all of the pipeline's capacity.
The pipeline will connect to a 1,000-megawatt power plant complex and to
the Pemex natural gas transportation system. Construction of the pipeline
is expected to be completed during the second quarter of 2003.
For more information related to the financing of our expansion activities,
see "Liquidity and Capital Resources - Primary Cash Requirements."
o Strategic Acquisitions. Since January 1, 2002, we have made the following
acquisitions:
o Kinder Morgan Materials Services LLC, formerly Laser
Materials Services LLC January 1, 2002;
o 33 1/3% interest in International Marine Terminals January 1, 2002;
53
o Additional 33 1/3% interest in International
Marine Terminals February 1, 2002;
o Kinder Morgan Tejas January 31, 2002;
o Milwaukee Bagging Operations bulk terminal
assets May 1, 2002;
o Remaining 33 1/3% interest in Trailblazer
Pipeline Company May 6, 2002;
o Owensboro Gateway bulk terminal assets September 1, 2002;
o IC Terminal Holdings Company (St. Gabriel
Terminal) September 1, 2002; and
o M.J. Rudolph bulk terminal assets January 1, 2003.
The costs and methods of financing for each of these acquisitions are
discussed under "Liquidity and Capital Resources - Capital Requirements for
Recent Transactions."
We regularly seek opportunities to make additional strategic acquisitions, to
expand existing businesses and to enter into related businesses. We periodically
consider potential acquisition opportunities as they are identified, but we
cannot assure you that we will be able to consummate any such acquisition. Our
management anticipates that we will finance acquisitions by borrowings under our
bank credit facilities or by issuing commercial paper, and subsequently reduce
these short-term borrowings by issuing new long-term debt securities, common
units and/or i-units to KMR.
We are continuing to assess the effect of the terrorist attacks of September
11, 2001 on our businesses. In response to the attacks, we have increased
security at our assets. We face the possibility that during 2003, property
insurance carriers generally may terminate insurance coverage for incidents of
sabotage and terrorism or only offer it at prices that we believe are excessive.
Recent federal legislation provides an insurance framework that should cause
current insurers to continue to provide sabotage and terrorism coverage under
standard property insurance policies. Nonetheless, there is no assurance that
adequate sabotage and terrorism insurance will be available at reasonable rates
throughout 2003. Currently, we do not believe that the increased cost associated
with these measures will have a material effect on our operating results.
If demand for the products that we handle were to significantly decrease, our
shippers would decrease the volumes that they ship through our systems or that
we handle and store for them, which could have a negative impact on our
financial performance. As of December 31, 2002, we have not noticed a
significant decrease in the volumes of product, other than jet fuel, that we are
moving through our operations as a result of the September 11, 2001 attacks.
However, our deliveries of jet fuel showed steady improvement throughout 2002.
In addition, recent federal legislation signed into law in December 2002
includes new guidelines for the U.S. DOT and pipeline companies in the areas of
testing, education, training and communication. The Pipeline Safety Improvement
Act of 2002 provides a consistent set of guidelines for all operators to follow
and requires the riskiest 50% of products pipelines and natural gas pipelines in
the United States to be inspected within five years of the law's enactment. The
pipeline risk ratings are based on numerous factors, including the population
density in the geographic regions served by a particular pipeline, as well as
the age and condition of the pipeline and its protective coating. The remaining
50% of the natural gas pipelines must be inspected within ten years of the law's
enactment. The law requires pipelines to be re-evaluated every seven years
thereafter. Compliance with this legislation will increase our operating
expenses in the future.
With respect to certain related party transactions, see Note 12 to the
Consolidated Financial Statements included elsewhere in this report.
Liquidity and Capital Resources
The following table illustrates the sources of our invested capital. In
addition to our results of operations, these
54
balances are affected by our financing activities as discussed below
(dollars in thousands):
December 31,
----------------------------------
2002 2001 2000
--------- --------- -----------
Long-term debt, excluding market value
of interest rate swaps............... $3,659,533 $2,237,015 $1,255,453
Minority interest....................... 42,033 65,236 58,169
Partners' capital....................... 3,415,929 3,159,034 2,117,067
---------- ---------- -----------
Total capitalization................. 7,117,495 5,461,285 3,430,689
Short-term debt, less cash and cash
equivalents...................... (41,088) 497,417 589,630
---------- --------- -----------
Total invested capital................ $7,076,407 $5,958,702 $4,020,319
========== ========== ===========
Capitalization:
Long-term debt, excluding market value
of interest rate swaps.............. 51.4% 41.0% 36.6%
Minority interest..................... 0.6% 1.2% 1.7%
Partners' capital..................... 48.0% 57.8% 61.7%
----------- --------- ----------
100.0% 100.0% 100.0%
=========== ========= ==========
Invested Capital:
Total debt, less cash and cash
equivalents and excluding
market value of interest
rate swaps......................... 51.1% 45.9% 45.9%
Partners' capital and minority
interest........................... 48.9% 54.1% 54.1%
----------- -------- -----------
100.0% 100.0% 100.0%
=========== ======== ===========
Summary of Off Balance Sheet Financing
We have obligations with respect to other entities which are not consolidated
in our financial statements as shown below (in millions):
Our
Contingent
Investment Our Remaining Total Total Share of
Entity Type Interest Ownership Assets(4) Debt Entity Debt(5)
- -------------------- ------------ ---------- ------------ -------------- ---------- ----------------
Cortez Pipeline General 50% (1) $149 $256 $128 (2)
Company............... Partner
Plantation Pipe Line Common 51% Exxon Mobil $258 $178 $10
Company............... Shareholder Corporation
Red Cedar Gas General 49% Southern Ute $161 $55 $55
Gathering Company..... Partner Indian Tribe
Nassau County, Nassau County,
Florida Ocean Highway Florida Ocean
and Port Authority Highway and
(3)................ N/A N/A Port Authority N/A N/A $28
- -------------
(1)The remaining general partner interests are owned by ExxonMobil Cortez
Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil
Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of
M.E. Zuckerman Energy Investors Incorporated.
(2)We are severally liable for our percentage ownership share of the Cortez
Pipeline Company debt. Further, pursuant to a Throughput and Deficiency
Agreement, the owners of Cortez Pipeline Company are required to contribute
capital to Cortez in the event of a cash deficiency. The agreement
contractually supports the financings of Cortez Capital Corporation, a
wholly-owned subsidiary of Cortez Pipeline Company, by obligating the owners
of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including
anticipated deficiencies and cash deficiencies relating to the repayment of
principal and interest on the debt of Cortez Capital Corporation. Their
respective parent or other companies further severally guarantee the
obligations of the Cortez Pipeline owners under this agreement.
55
(3)Relates to our Vopak terminal acquisition in July 2001. See Note 3 to the
Consolidated Financial Statements.
(4) Principally property, plant and equipment.
(5)Represents the portion of the entity's debt that we may be responsible for
if the entity can not satisfy the obligation.
For the year ended December 31, 2002, our share of earnings, based on our
ownership percentage, before income taxes and amortization of excess investment
cost was $28.2 million from Cortez Pipeline Company, $26.4 million from
Plantation Pipe Line Company and $19.1 million from Red Cedar Gathering Company.
Additional information regarding these investments is included in Note 7 to the
Consolidated Financial Statements included elsewhere in this report.
Summary of Certain Contractual Obligations
Amount of Commitment Expiration per Period
-----------------------------------------------------------
Less than After 5
Total 1 Year 2-3 Years 4-5 Years Years
--------- ---------- ------------- --------- ---------
(In thousands)
Commercial paper outstanding....... $ 220,000 $220,000 $ -- $ -- $ --
SFPP First Mortgage Notes.......... 37,078 37,078 -- -- --
Other debt borrowings.............. 3,402,455 7,859 209,853 299,883 2,884,860
Operating leases................... 123,990 18,747 28,334 21,364 55,545
Other obligations.................. 6,000 600 1,200 1,200 3,000
--------- -------- ---------- --------- ----------
Total................................. $3,789,523 $284,284 $239,387 $322,447 $2,943,405
========== ======== ========= ========= ==========
Primary Cash Requirements
Our primary cash requirements, in addition to normal operating expenses, are
debt service, sustaining capital expenditures, expansion capital expenditures
and quarterly distributions to our common unitholders, Class B unitholders and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through borrowings under
our credit facilities, issuing short-term commercial paper, long-term notes or
additional common units or issuing additional i-units to KMR. In general, we
expect to fund:
o cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with cash
retained as a result of paying quarterly distributions on i-units in
additional i-units, additional borrowings, the issuance of additional
common units or the issuance of additional i-units to KMR;
o interest payments from cash flows from operating activities; and
o debt principal payments with additional borrowings as such debt principal
payments become due or by the issuance of additional common units or the
issuance of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors. Individual investors represent a small
segment of the total equity capital market. We believe institutional investors
prefer shares of KMR over our common units due to tax and other regulatory
considerations. Thus, KMR makes purchases of i-units issued by us with the
proceeds from the sale of KMR shares to institutions.
The scheduled maturities of our outstanding debt, excluding market value of
interest rate swaps, at December 31, 2002, are summarized as follows (in
thousands):
56
2003........... $264,937
2004........... 5,018
2005........... 204,836
2006........... 45,019
2007........... 254,863
Thereafter..... 2,884,860
----------
Total.......... $3,659,533
==========
Of the $264.9 million scheduled to mature in 2003, we intend and have the
ability to refinance the entire amount on a long-term basis under our existing
credit facilities. Accordingly, this amount has been classified as long-term
debt in our accompanying consolidated balance sheet at December 31, 2002.
Currently, we do not anticipate any liquidity problems.
At December 31, 2002, our current commitments for sustaining capital
expenditures were approximately $94.9 million. This amount has been committed
primarily for the purchase of plant and equipment and is based on the payments
we expect to need for our 2003 sustaining capital expenditure plan. All of our
capital expenditures, with the exception of sustaining capital expenditures, are
discretionary.
In addition, during the first quarter of 2003, we will need approximately $3
million to complete our acquisitions of assets from M.J. Rudolph Corporation and
Stevedoring Services of America. The Rudolph acquisition includes long-term
lease contracts used to operate four bulk terminal facilities at major ports
along the East Coast and in the southeastern United States. The acquisition also
includes the purchase of certain assets that provide stevedoring services at
these locations. For more information, see Items 1 and 2 "Business and
Properties -- Recent Developments" and Note 3 to our Consolidated Financial
Statements. The purchase of assets from Stevedoring Services of America
represents a barge-mounted floating crane that we currently lease at our bulk
terminal facility in Port Sulphur, Louisiana. We expect to fund the completion
of these investments with borrowings under our commercial paper program.
Some of our customers are experiencing severe financial problems that have
had a significant impact on their creditworthiness. We are working to implement,
to the extent allowable under applicable laws and regulations, prepayments and
other security requirements such as letters of credit to enhance our credit
position relating to amounts owed from these customers. We cannot assure that
one or more of our financially distressed customers will not default on their
obligations to us or that such a default or defaults will not have a material
adverse effect on our business, financial position or future results of
operations.
Operating Activities
Net cash provided by operating activities was $869.7 million in 2002 versus
$581.2 million in 2001. The $288.5 million increase in 2002 resulted mainly from
a $188.1 million increase in cash earnings, reflecting the strong performance
and growth that occurred across our business portfolio during 2002. Also
contributing to the overall increase in cash provided by operating activities
was a $134.3 million increase relative to net changes in working capital items
and a $8.9 million increase in the amount of distributions we received from our
equity investments. The favorable working capital change was primarily the
result of timing differences in the collection on and payments of our current
accounts. The increase in equity distributions related to higher distributions
from our 51% equity interest in Plantation Pipe Line Company and from our 50%
equity interest in Coyote Gas Treating, LLC. The year-to-year overall increase
in operating cash flows was partially reduced by higher payments made in 2002
under certain settlement agreements, primarily tariff-related agreements between
shippers and our Products Pipelines, and environmental settlement agreements.
Investing Activities
Net cash used in investing activities was $1,450.9 million for the year ended
December 31, 2002, compared to $1,818.9 million for the prior year. The $368.0
million decrease in funds utilized in investing activities was mainly
attributable to higher expenditures made for strategic acquisitions in 2001.
Outlays for acquisition of assets, new businesses and investments totaled $910.3
million in 2002, versus $1,523.5 million in 2001.
57
Our expenditures in 2002 included:
o $721.6 million for Kinder Morgan Tejas;
o $80.1 million for the remaining 33 1/3% ownership interest in Trailblazer
Pipeline Company and a contingent interest in Trailblazer from CIG
Trailblazer Gas Company;
o $29.9 million on December 31 for bulk terminal assets previously owned
by M.J. Rudolph Corporation; and
o $29.0 million for an additional 10% ownership interest in the Cochin
Pipeline system, which was made effective December 31, 2001.
Our expenditures in 2001 included:
o $982.7 million for the acquisition of GATX Corporation's domestic pipelines
and terminals business, including Kinder Morgan Liquids Terminals LLC,
CALNEV Pipe Line LLC and Central Florida Pipeline LLC;
o $359.1 million for KM Texas Pipeline, L.P.;
o $44.8 million for liquids terminals acquired from an affiliate of
Stolt-Nielsen, Inc.;
o $43.6 million for bulk terminal LLC's acquired from Koninklijke Vopak N.V.;
o $41.7 million for Pinney Dock & Transport LLC; and
o $18.0 million for bulk and liquids terminal assets acquired from The
Boswell Oil Company.
We continue to invest significantly in strategic acquisitions in order to
fuel future growth and increase unitholder value. Partially offsetting the
overall decline in funds used in investing activities in 2002 compared to
2001was a $247.1 million increase in funds used for capital expenditures and a
$8.0 million increase in contributions to equity investments. Including
expansion and maintenance projects, our capital expenditures were a record
$542.2 million in 2002. We spent $295.1 million for capital expenditures in
2001. The $247.1 million increase was primarily due to continued investment in
our Natural Gas Pipelines, CO2 Pipelines and Terminals business segments. We
continue to expand and grow our existing businesses and have current projects in
place that will significantly add storage and throughput capacity to our
terminaling, natural gas transmission and carbon dioxide flooding operations.
Our sustaining capital expenditures were $77.0 million for 2002, compared to
$56.1 million for 2001. The $8.0 million increase in investment contributions
was due to higher investments made to the natural gas gathering operations of
Thunder Creek Gas Services, LLC and the carbon dioxide operations of MKM
Partners, L.P.
Financing Activities
Net cash provided by financing activities amounted to $559.5 million in 2002,
compared to $1,241.2 million in 2001. This decrease of $681.7 million from the
prior year was chiefly due to lower cash inflows from equity financing
activities. In May 2001, we received $996.9 million as proceeds from our initial
sale of 29,750,000 i-units to KMR. In August 2002, we raised $331.2 million from
our sale of an additional 12,478,900 i-units to KMR. The overall decrease in
funds provided by financing activities also resulted from a $108.9 million
increase in distributions to our partners in 2002 versus 2001. Cash
distributions to all partners, including KMI, increased to $582.1 million in
2002 compared to $473.2 million in 2001. The increase in distributions was due
to:
o an increase in the per unit cash distributions paid;
o an increase in the number of units outstanding; and
o an increase in the general partner incentive distributions, which resulted
from both increased cash distributions per unit and an increase in the
number of common units and i-units outstanding.
The overall decrease in funds provided by financing activities was partly
offset by a $105.6 million increase from overall debt financing activities.
During each of the years 2001 and 2002, we purchased the pipeline and terminal
businesses we acquired primarily with borrowings under our commercial paper
program. We then raised funds by completing public and private debt offerings of
senior notes and by issuing additional i-units. We then used the proceeds from
these debt and equity issuances to reduce our borrowings under our commercial
paper program. In 2002, we closed a public offering of $750 million in principal
amount of senior notes, completed a private placement of $750 million in
principal amount of senior notes to qualified institutional buyers (we then
exchanged these notes with substantially identical notes that are registered
under the Securities Act of 1933 in the fourth quarter of 2002) and retired a
maturing amount of $200 million in principal amount of senior notes. In
comparison, in 2001, we closed a public offering of $1.0 billion in principal
amount of senior notes.
We paid distributions of $2.36 per unit in 2002 compared to $2.08 per unit in
2001. The 13% increase in paid distributions per unit resulted from favorable
operating results in 2002.
We also distributed 2,538,785 i-units in quarterly distributions during 2002
to KMR, our sole i-unitholder. In 2001, we distributed 886,361 i-units in
quarterly distributions to KMR. The amount of i-units distributed in each
quarter was based upon the amount of cash we distributed to the owners of our
common and Class B units during that quarter of 2002 and 2001. For each
outstanding i-unit that KMR held, a fraction of an i-unit was issued. The
fraction was determined by dividing:
o the cash amount distributed per common unit
by
o the average of KMR's shares' closing market prices for the ten consecutive
trading days preceding the date on which the shares began to trade
ex-dividend under the rules of the New York Stock Exchange.
Partnership Distributions
Our partnership agreement requires that we distribute 100% of available cash,
as defined in our partnership agreement, to our partners within 45 days
following the end of each calendar quarter in accordance with their respective
percentage interests. Available cash consists generally of all of our cash
receipts, including cash received by our 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 general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, maintenance capital expenditures, rate refunds
and distributions for the next four quarters. These reserves are not restricted
by magnitude, but only by type of future cash requirements with which they can
be associated. When KMR determines our quarterly distributions, it considers
current and expected reserve needs along with current and expected cash flows to
identify the appropriate sustainable distribution level. For 2002, 2001 and
2000, we distributed 97.6%, 100% and 102%, of the total of cash receipts less
cash disbursements, respectively (calculations assume that KMR unitholders
received cash). The difference between these numbers and 100% reflects net
additions to or reductions in reserves.
Typically, our general partner and owners of our common units and Class B
units receive distributions in cash, while KMR, the sole owner of our i-units,
receives distributions in additional i-units. For each outstanding i-unit, a
fraction of an i-unit will be issued. The fraction is calculated by dividing the
amount of cash being distributed per common unit by the average closing price of
KMR's shares over the ten consecutive trading days preceding the date on which
the shares begin to trade ex-dividend under the rules of the New York Stock
Exchange. The cash equivalent of distributions of i-units will be treated as if
it had actually been distributed for purposes of determining the distributions
to our general partner. We do not distribute cash to i-unit owners but retain
the cash for use in our business.
59
Available cash is initially distributed 98% to our limited partners and 2% to
our general partner. These distribution percentages are modified to provide for
incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the owners
of all classes of units have received a total of $0.17875 per unit in cash
or equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the owners
of all classes of units have received a total of $0.23375 per unit in cash
or equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units in
cash and to owners of i-units in the equivalent number of i-units, and 50%
to our general partner.
Incentive distributions are generally defined as all cash distributions paid
to our general partner that are in excess of 2% of the aggregate value of cash
and i-units being distributed. The general partner's incentive distribution that
we declared for 2002 was $267.4 million, while the incentive distribution paid
to our general partner during 2002 was $249.3 million. The difference between
declared and paid distributions is due to the fact that the partnership
distributions for the fourth quarter of each year are declared and paid in the
first quarter of the following year.
On February 14, 2003, we paid a quarterly distribution of $0.625 per unit for
the fourth quarter of 2002. This distribution was 14% greater than the $0.55
distribution per unit we paid for the fourth quarter of 2001 and 6% greater than
the $0.59 distribution per unit we paid for the first quarter of 2002. We paid
this distribution in cash to our common unitholders and to our Class B
unitholders. KMR, our sole i-unitholder, received additional i-units based on
the $0.625 cash distribution per common unit.
Debt and Credit Facilities
Our debt and credit facilities as of December 31, 2002, consisted primarily
of:
o a $530 million unsecured 364-day credit facility due October 14, 2003;
o a $445 million unsecured three-year credit facility due October 15, 2005;
o $37.1 million of Series F First Mortgage Notes due December 2004 (our
subsidiary, SFPP, L.P. is the obligor on the notes);
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal District
Revenue Bonds due March 15, 2006 (our 66 2/3% owned subsidiary,
International Marine Terminals, is the obligor on the bonds);
o $250 million of 5.35% Senior Notes due August 15, 2007;
o $30 million of 7.84% Senior Notes, with a final maturity of July 2008 (our
subsidiary, Central Florida Pipe Line LLC, is the obligor on the notes);
o $250 million of 6.30% Senior Notes due February 1, 2009;
60
o $250 million of 7.50% Senior Notes due November 1, 2010;
o $700 million of 6.75% Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $25 million of New Jersey Economic Development Revenue Refunding Bonds due
January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals LLC, is
the obligor on the bonds);
o $87.9 million of Industrial Revenue Bonds with final maturities ranging
from September 2019 to December 2024 (our subsidiary, Kinder Morgan
Liquids Terminals LLC, is the obligor on the bonds);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder Morgan
Operating L.P. "B", is the obligor on the bonds);
o $300 million of 7.40% Senior Notes due March 15, 2031;
o $300 million of 7.75% Senior Notes due March 15, 2032;
o $500 million of 7.30% Senior Notes due August 15, 2033; and
o a $975 million short-term commercial paper program (supported by our
credit facilities, the amount available for borrowing under our credit
facilities is reduced by our outstanding commercial paper borrowings).
None of our debt or credit facilities are subject to payment acceleration as
a result of any change to our credit ratings. However, the margin that we pay
with respect to LIBOR based borrowings under our credit facilities is tied to
our credit ratings.
Our outstanding short-term debt at December 31, 2002, consisted of:
o $220 million of commercial paper borrowings;
o $37.1 million under the SFPP, L.P. 10.7% First Mortgage Notes;
o $5 million under the Central Florida Pipeline LLC Notes; and
o $2.8 million in other borrowings.
We intend and have the ability to refinance our $264.9 million of short-term
debt on a long-term basis under our unsecured long-term credit facility.
Accordingly, such amounts have been classified as long-term debt in our
accompanying consolidated balance sheet. Currently, we do not anticipate any
liquidity problems. The weighted average interest rate on all of our borrowings
was approximately 5.015% during 2002 and 6.965% during 2001.
Credit Facilities
On December 31, 2000, we had two credit facilities, a $300 million unsecured
five-year credit facility expiring on September 29, 2004, and a $600 million
unsecured 364-day credit facility expiring on October 25, 2001. On December 31,
2000, the outstanding balance under our five-year credit facility was $207.6
million and the outstanding balance under our 364-day credit facility was $582
million.
During the first quarter of 2001, we obtained a third unsecured credit
facility, in the amount of $1.1 billion, expiring on December 31, 2001. The
credit facility was used to support the increase in our commercial paper program
to $1.7 billion for our acquisition of the GATX businesses. The terms of this
credit facility were substantially similar to the terms of the other two
facilities. Upon issuance of additional senior notes on March 12, 2001, this
short-term credit facility was reduced to $500 million. During the second
quarter of 2001, we terminated this $500 million credit facility, which was
scheduled to expire on December 31, 2001. On October 25, 2001, our
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364-day credit facility expired and we obtained a new $750 million unsecured
364-day credit facility expiring on October 23, 2002. The terms of this credit
facility were substantially similar to the terms of the expired facility. There
were no borrowings under either credit facility at December 31, 2001.
On February 21, 2002, we obtained a third unsecured 364-day credit facility,
in the amount of $750 million, expiring on February 20, 2003. The credit
facility was used to support the increase in our commercial paper program to
$1.8 billion for our acquisition of Tejas Gas, LLC, and the terms of this credit
facility were substantially similar to the terms of our other two credit
facilities. Upon issuance of additional senior notes in March 2002, this
short-term credit facility was reduced to $200 million.
In August 2002, upon the completion of our i-unit equity sale, we terminated,
under the terms of the agreement, our $200 million unsecured 364-day credit
facility that was due February 20, 2003. On October 16, 2002, we successfully
renegotiated our bank credit facilities by replacing our $750 million unsecured
364-day credit facility due October 23, 2002 and our $300 million unsecured
five-year credit facility due September 29, 2004 with two new credit facilities.
Our current facilities include:
o a $530 million unsecured 364-day credit facility due October 14, 2003;
and
o a $445 million unsecured three-year credit facility due October 15, 2005.
Our credit facilities are with a syndicate of financial institutions.
Wachovia Bank, National Association is the administrative agent under both
credit facilities. The terms of our two credit facilities are substantially
similar to the terms of our previous credit facilities. Interest on the two
credit facilities accrues at our option at a floating rate equal to either:
o the administrative agent's base rate (but not less than the Federal Funds
Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of our
long-term senior unsecured debt.
Our credit facilities include the following restrictive covenants as of
December 31, 2002:
o requirements to maintain certain financial ratios:
o total debt divided by earnings before interest, income taxes,
depreciation and amortization for the preceding four quarters may not
exceed 5.0;
o total indebtedness of all consolidated subsidiaries shall at no time
exceed 15% of consolidated indebtedness;
o tangible net worth as of the last day of any fiscal quarter shall not
be less than $2,100,000,000; and
o consolidated indebtedness shall at no time exceed 62.5% of total
capitalization;
o limitations on entering into mergers, consolidations and sales of assets;
o limitations on granting liens; and
o prohibitions on making any distribution to holders of units if an event of
default exists or would exist upon making such distribution.
There were no borrowings under either credit facility at December 31, 2002.
The amount available for borrowing under our credit facilities is reduced by:
o a $23.7 million letter of credit that supports Kinder Morgan Operating
L.P. "B"'s tax-exempt bonds;
o a $28 million letter of credit entered into on December 23, 2002 that
supports Nassau County, Florida Ocean Highway and Port Authority tax exempt
bonds (associated with the operations of our bulk terminal facility
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located at Fernandina Beach, Florida); and
o our outstanding commercial paper borrowings.
Our new three-year credit facility also permits us to obtain bids for fixed
rate loans from members of the lending syndicate.
Senior Notes
From time to time we issue long-term debt securities. All of our long-term
debt securities issued to date, other than those issued under our revolving
credit facilities, generally have the same terms except for interest rates,
maturity dates and prepayment restrictions. All of our outstanding debt
securities are unsecured obligations that rank equally with all of our other
senior debt obligations. Our outstanding long-term debt securities as of
December 31, 2002, consist of the following:
o $250 million in principal amount of 6.3% senior notes due February 1, 2009.
These notes were issued on January 29, 1999. In the offering, we received
proceeds, net of underwriting discounts and commissions, of approximately
$248 million. We used the proceeds to pay the outstanding balance on our
credit facility and for working capital and other partnership purposes;
o $200 million of 8.0% notes due March 15, 2005. These notes were issued on
March 22, 2000. In the offering, we received proceeds, net of underwriting
discounts and commissions of approximately $197.9 million. We used the
proceeds to reduce outstanding commercial paper;
o $250 million of 7.5% notes due November 1, 2010. These notes were issued on
November 8, 2000. The proceeds from this offering, net of underwriting
discounts, were $246.8 million. These proceeds were used to reduce our
outstanding commercial paper;
o $700 million of 6.75% notes due March 15, 2011 and $300 million of 7.40%
notes due March 15, 2031. These notes were issued March 12, 2001. In the
offering, we received proceeds, net of underwriting discounts and
commissions of approximately $990.0 million. We used the proceeds to pay
for our acquisition of Pinney Dock & Transport LLC and to reduce our
outstanding balance on our credit facilities and commercial paper
borrowings;
o $450 million of 7.125% notes due March 15, 2012 and $300 million of 7.75%
notes due March 15, 2032. These notes were issued March 14, 2002. In the
offering, we received proceeds, net of underwriting discounts and
commissions of approximately $740.9 million. We used the proceeds to reduce
our outstanding balance on our commercial paper borrowings; and
o $500 million of 7.30% notes due August 15, 2033 and $250 million of 5.35%
notes due August 15, 2007. These notes were issued August 23, 2002. In the
offering, we received proceeds, net of underwriting discounts and
commissions of approximately $743.0 million. We used the proceeds to reduce
our outstanding balance on our commercial paper borrowings.
The fixed rate notes provide that we may redeem the notes at any time at a
price equal to 100% of the principal amount of the notes plus accrued interest
to the redemption date plus a make-whole premium.
On March 22, 2002, we paid $200 million to retire the principal amount of our
Floating Rate senior notes that matured on that date. We borrowed the necessary
funds under our commercial paper program.
At December 31, 2002, our unamortized liability balance due on the various
series of our senior notes was as follows (in millions):
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8.0% senior notes due March 15, 2005 $ 199.8
5.35% senior notes due August 15, 2007 249.8
6.3% senior notes due February 1, 2009 249.5
7.5% senior notes due November 1, 2010 248.8
6.75% senior notes due March 15, 2011 698.3
7.125% senior notes due March 15, 2012 448.1
7.4% senior notes due March 15, 2031 299.3
7.75% senior notes due March 15, 2032 298.5
7.3% senior notes due August 15, 2033 499.0
----------
Total $ 3,191.1
==========
Commercial Paper Program
On December 31, 2000, our commercial paper program provided for the issuance
of up to $600 million of commercial paper. On that date, we had $52 million of
commercial paper outstanding with an interest rate of 7.02%. During the first
quarter of 2001, we increased our commercial paper program to provide for the
issuance of an additional $1.1 billion of commercial paper. We entered into a
$1.1 billion unsecured 364-day credit facility to support this increase in our
commercial paper program, and we used the program's increase in available funds
to close on the GATX acquisition.
In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares representing
limited liability company interests with limited voting rights to the public in
an initial public offering. Its shares were issued at a price of $35.21 per
share, less commissions and underwriting expenses, and it used substantially all
of the net proceeds from that offering to purchase i-units from us. After
commissions and underwriting expenses, we received net proceeds of approximately
$996.9 million for the issuance of 29,750,000 i-units to KMR. We used the
proceeds from the i-unit issuance to reduce the borrowings under our commercial
paper program.
Also during the second quarter of 2001, after the issuance of additional
senior notes on March 12, 2001 and the issuance of i-units in May 2001, we
decreased our commercial paper program back to $600 million. On October 17,
2001, we increased our commercial paper program to $900 million. As of December
31, 2001, we had $590.5 million of commercial paper outstanding with an interest
rate of 2.6585%.
On February 21, 2002, our commercial paper program increased to provide for
the issuance of up to $1.8 billion of commercial paper. We entered into a $750
million unsecured 364-day credit facility to support this increase in our
commercial paper program, and we used the program's increase in available funds
to close on the Tejas acquisition. After the issuance of additional senior notes
on March 14, 2002, we reduced our commercial paper program to $1.25 billion.
On August 6, 2002, KMR issued in a public offering, an additional 12,478,900
of its shares, including 478,900 shares upon exercise by the underwriters of an
over-allotment option, at a price of $27.50 per share, less commissions and
underwriting expenses. The net proceeds from the offering were used to buy
i-units from us. After commissions and underwriting expenses, we received net
proceeds of approximately $331.2 million for the issuance of 12,478,900 i-units.
We used the proceeds from the i-unit issuance to reduce the borrowings under our
commercial paper program and, in conjunction with our issuance of additional
i-units and as previously agreed upon under the terms of our credit facilities,
we reduced our commercial paper program to provide for the issuance of up to
$975 million of commercial paper as of December 31, 2002. On December 31, 2002,
we had $220.0 million of commercial paper outstanding with an average interest
rate of 1.58%.
The borrowings under our commercial paper program were used to finance
acquisitions made during 2001 and 2002. The borrowings under our commercial
paper program reduce the borrowings allowed under our credit facilities.
SFPP, L.P. Debt
At December 31, 2002, the outstanding balance under SFPP, L.P.'s Series F
notes was $37.1 million. The annual interest rate on the Series F notes is
10.70%, the maturity is December 2004, and interest is payable semiannually in
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June and December. We repaid $31.5 million and $29.5 million in 1999 and
2000, respectively, under the Series F notes prior to maturity as a result of
SFPP, L.P. taking advantage of certain optional prepayment provisions without
penalty. We expect to pay the remaining $37.1 million balance in December 2003.
Additionally, the Series F notes may be prepaid in full or in part at a price
equal to par plus, in certain circumstances, a premium. We agreed as part of the
acquisition of SFPP, L.P.'s operations (which constitute a significant portion
of our Pacific operations) not to take actions with respect to $190 million of
SFPP, L.P.'s debt that would cause adverse tax consequences for the prior
general partner of SFPP, L.P. The Series F notes are collateralized by mortgages
on substantially all of the properties of SFPP, L.P. The Series F notes contain
certain covenants limiting the amount of additional debt or equity that may be
issued by SFPP, L.P. and limiting the amount of cash distributions, investments,
and property dispositions by SFPP, L.P. We do not believe that these
restrictions will materially affect distributions to our partners.
Kinder Morgan Liquids Terminals LLC Debt
Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC.
As part of our purchase price, we assumed debt of $87.9 million, consisting of
five series of Industrial Revenue Bonds. The bonds consist of the following:
o 4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September
1, 2019;
o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,
2022;
o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September
1, 2022;
o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,
2023; and
o $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1, 2024.
In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey
from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As
part of our purchase price, we assumed $25.0 million of Economic Development
Revenue Refunding Bonds issued by the New Jersey Economic Development Authority.
These bonds have a maturity date of January 15, 2018. Interest on these bonds is
computed on the basis of a year of 365 or 366 days, as applicable, for the
actual number of days elapsed during Commercial Paper, Daily or Weekly Rate
Periods and on the basis of a 360-day year consisting of twelve 30-day months
during a Term Rate Period. As of December 31, 2002, the interest rate was 1.05%.
We have an outstanding letter of credit issued by Citibank in the amount of
$25.3 million that backs-up the $25.0 million principal amount of the bonds and
$0.3 million of interest on the bonds for up to 42 days computed at 12% on a per
annum basis on the principal thereof.
Central Florida Pipeline LLC Debt
Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part
of our purchase price, we assumed an aggregate principal amount of $40 million
of Senior Notes originally issued to a syndicate of eight insurance companies.
The Senior Notes have a fixed annual interest rate of 7.84% with repayments in
annual installments of $5 million beginning July 23, 2001. The final payment is
due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of
each year. At December 31, 2002, Central Florida's outstanding balance under the
Senior Notes was $30.0 million.
CALNEV Pipe Line LLC Debt
Effective March 30, 2001, we acquired CALNEV Pipe Line LLC. As part of our
purchase price, we assumed an aggregate principal amount of $6.8 million of
Senior Notes originally issued to a syndicate of five insurance companies. The
Senior Notes had a fixed annual interest rate of 10.07%. In June 2001, we
prepaid the balance outstanding under the Senior Notes, plus $0.9 million for
interest and a make-whole premium, from cash on hand.
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Trailblazer Pipeline Company Debt
At December 31, 2000, Trailblazer Pipeline Company had a $10 million
borrowing under an intercompany account payable in favor of KMI. In January
2001, Trailblazer Pipeline Company entered into a 364-day revolving credit
agreement with Credit Lyonnais New York Branch, providing for loans up to $10
million. The borrowings were used to pay the account payable to KMI. The
agreement was to expire on December 27, 2001, and provided for an interest rate
of LIBOR plus 0.875%. Pursuant to the terms of the revolving credit agreement
with Credit Lyonnais New York Branch, Trailblazer Pipeline Company partnership
distributions were restricted by certain financial covenants.
On June 26, 2001, Trailblazer Pipeline Company prepaid the balance
outstanding under its Senior Secured Notes using a new two-year unsecured
revolving credit facility with a bank syndication. The new facility, as amended
August 24, 2001, provided for loans of up to $85.2 million and had a maturity
date of June 29, 2003. The agreement provided for an interest rate of LIBOR plus
a margin as determined by certain financial ratios. Pursuant to the terms of the
revolving credit facility, Trailblazer Pipeline Company partnership
distributions were restricted by certain financial covenants. On June 29, 2001,
Trailblazer Pipeline Company paid the $10 million outstanding balance under its
364-day revolving credit agreement and terminated that agreement. At December
31, 2001, the outstanding balance under Trailblazer Pipeline Company's two-year
revolving credit facility was $55.0 million, with a weighted average interest
rate of 2.875%, which reflects three-month LIBOR plus a margin of 0.875%. In
July 2002, we paid the $31.0 million outstanding balance under Trailblazer's
revolving credit facility and terminated the facility.
On September 23, 1992, pursuant to 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. The Senior Secured Notes had a fixed annual interest rate of 8.03%
and the $20.2 million balance as of December 31, 2000 was to be repaid in
semiannual installments of $5.05 million from March 1, 2001 through September 1,
2002, the final maturity date. Interest was payable semiannually in March and
September. Trailblazer Pipeline Company provided collateral for the notes
principally by an assignment of certain Trailblazer Pipeline Company
transportation contracts, and pursuant to the terms of this Note Purchase
Agreement, Trailblazer Pipeline Company's partnership distributions were
restricted by certain financial covenants. Effective April 29, 1997, Trailblazer
Pipeline Company amended the Note Purchase Agreement. This amendment allowed
Trailblazer Pipeline Company to include several additional transportation
contracts as collateral for the notes, added a limitation on the amount of
additional money that Trailblazer Pipeline Company could borrow and relieved
Trailblazer Pipeline Company from its security deposit obligation. On June 26,
2001, Trailblazer Pipeline Company prepaid the $15.2 million balance outstanding
under the Senior Secured Notes, plus $0.8 million for interest and a make-whole
premium, using its new two-year unsecured revolving credit facility.
Kinder Morgan Operating L.P. "B" Debt
The $23.7 million principal amount of tax-exempt bonds due 2024 were issued
by the Jackson-Union Counties Regional Port District. These bonds bear interest
at a weekly floating market rate. During 2002, the weighted-average interest
rate on these bonds was 1.39% per annum, and at December 31, 2002, the interest
rate was 1.59%. We have an outstanding letter of credit issued under our credit
facilities that supports our tax-exempt bonds. The letter of credit reduces the
amount available for borrowing under our credit facilities.
International Marine Terminals Debt
As of February 1, 2002, we owned a 66 2/3% interest in International Marine
Terminals partnership. The principal assets owned by IMT are dock and wharf
facilities financed by the Plaquemines Port, Harbor and Terminal District
(Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue
Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B.
The bonds mature on March 15, 2006. The bonds are backed by two letters of
credit issued by KBC Bank N.V. On March 19, 2002, an Amended and Restated Letter
of Credit Reimbursement Agreement relating to the letters of credit in the
amount of $45.5 million was entered into by IMT and KBC Bank. In connection with
that agreement, we agreed to guarantee the obligations of IMT in proportion to
our ownership interest. Our obligation is approximately $30.3 million for
principal, plus interest and other fees.
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Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers Pipeline
Company - 13% owner) are required, on a percentage ownership basis, to
contribute capital to Cortez Pipeline Company in the event of a cash deficiency.
The Throughput and Deficiency Agreement contractually supports the borrowings of
Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline
Company, by obligating the owners of Cortez Pipeline Company to fund cash
deficiencies at Cortez Pipeline Company, including cash deficiencies relating to
the repayment of principal and interest on borrowings by Cortez Capital
Corporation. Parent companies of the respective Cortez Pipeline Company owners
further severally guarantee, on a percentage basis, the obligations of the
Cortez Pipeline Company owners under the Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our guaranty obligations jointly
and severally through December 31, 2006 for Cortez Capital Corporation's debt
programs in place as of April 1, 2000.
At December 31, 2002, the debt facilities of Cortez Capital Corporation
consisted of:
o $115.7 million of Series D notes due May 15, 2013;
o a $175 million short-term commercial paper program; and
o a $175 million committed revolving credit facility due December 26, 2003
(to support the above-mentioned $175 million commercial paper program).
At December 31, 2002, Cortez Capital Corporation had $140.6 million of
commercial paper outstanding with an interest rate of 1.39%, the average
interest rate on the Series D notes was 6.9322% and there were no borrowings
under the credit facility.
Capital Requirements for Recent Transactions
During 2002, our cash outlays for the acquisitions of assets and equity
investments totaled $910.3 million. We utilized our short-term credit facilities
to fund these acquisitions and then reduced our short-term borrowings with the
proceeds from our August 2002 issuance of i-units and our March and August 2002
issuances of long-term senior notes. We intend to refinance the remainder of our
current short-term debt and any additional short-term debt incurred during 2003
through a combination of long-term debt, equity and the issuance of additional
commercial paper to replace maturing commercial paper borrowings.
Cochin Pipeline. Effective December 31, 2001, we acquired an additional 10%
ownership interest in the Cochin Pipeline system for approximately $29.0 million
in cash. We made the payment in January 2002 and we borrowed the necessary funds
under our commercial paper program.
Kinder Morgan Materials Services LLC. Effective January 1, 2002, we acquired
Kinder Morgan Materials Services LLC, formerly Laser Materials Services LLC, for
approximately $12.2 million in aggregate consideration, consisting of $8.9
million in cash, $0.4 million in assumed debt and $2.9 million in assumed
liabilities. We borrowed the necessary funds under our commercial paper program.
International Marine Terminals. Effective January 1, 2002, we acquired 33
1/3% of International Marine Terminals, and effective February 1, 2002, we
acquired an additional 33 1/3% ownership interest. For the two interests
combined, our purchase price totaled approximately $40.5 million, consisting of
$40.0 million in assumed debt, $4.3 million in assumed liabilities and an offset
of $3.8 million for cash received.
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Kinder Morgan Tejas. Effective January 31, 2002, we acquired Tejas Gas, LLC
for approximately $881.5 million in aggregate consideration, consisting of
$727.1 million in cash and $154.4 million in assumed liabilities. We borrowed
the necessary funds under our commercial paper program.
Milwaukee Bagging Operations. Effective May 1, 2002, we acquired certain bulk
terminal assets for approximately $8.5 million in cash. We borrowed the
necessary funds under our commercial paper program.
Trailblazer Pipeline Company. Effective May 6, 2002, we acquired the
remaining 33 1/3% of Trailblazer Pipeline Company that we did not already own
for approximately $80.1 million in cash. We borrowed the necessary funds under
our commercial paper program.
Owensboro Gateway Terminal. Effective September 1, 2002, we acquired certain
bulk and terminal assets from Lanham River Terminal, LLC for approximately $7.7
million in aggregate consideration, consisting of $7.2 million in cash and $0.5
million in a short-term liability. We borrowed the necessary funds under our
commercial paper program.
IC Terminal Holdings Company (St. Gabriel Terminal). Effective September 1,
2002, we acquired all of the shares of the capital stock of IC Terminal Holdings
Company from the Canadian National Railroad for approximately $17.8 million in
aggregate consideration, consisting of $17.6 million in cash and $0.2 million in
assumed liabilities. We borrowed the necessary funds under our commercial paper
program.
M.J. Rudolph. Effective January 1, 2003, we acquired certain bulk terminal
assets from M.J Rudolph Corporation for approximately $31.3 million in cash. We
paid $29.9 million on December 31, 2002 and we borrowed the necessary funds
under our commercial paper program.
New Accounting Pronouncements
On January 1, 2003, we adopted Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires
companies to record a liability relating to the retirement and removal of assets
used in their business. The liability is initially recorded at its fair value,
and the relative asset value is increased by the same amount. Over the life of
the asset, the liability will be accreted to its future value and eventually
extinguished when the asset is taken out of service. The provisions of this
statement are effective for fiscal years beginning after June 15, 2002. With
respect to our Natural Gas Pipelines and Products Pipelines business segments,
we have certain surface facilities that are required to be dismantled and
removed, with certain site reclamation to be performed. While, in general, our
right-of-way agreements do no require us to remove pipe or otherwise perform
remediation upon taking the pipeline permanently out of service, some
right-of-way agreements do provide for these actions. With respect to our CO2
Pipelines business segment, we generally are required to plug our oil production
wells when removed from service and we anticipate recording a liability for such
obligation. Our Terminals business segment has entered into certain facility
leases which require removal of improvements upon expiration of the lease term.
We anticipate recording a liability for such obligation. For the Natural Gas
Pipelines and Products Pipelines business segments, we expect that we will be
unable to reasonably estimate and record liabilities for the majority of our
obligations that fall under the provisions of this statement because we cannot
reasonably estimate when such obligations would be settled. For the CO2
Pipelines and Terminals business segments, the effect of adopting SFAS No. 143
is not material to the consolidated financial statements.
In April 2002, the Financial Accounting Standards Board issued SFAS No. 145,
"Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement
No. 13, and Technical Corrections." This Statement eliminates the current
requirement that gains and losses on debt extinguishment must be classified as
extraordinary items in the income statement. Instead, such gains and losses will
be classified as extraordinary items only if they are deemed to be unusual and
infrequent, in accordance with the current GAAP criteria for extraordinary
classification. In addition, SFAS No. 145 eliminates an inconsistency in lease
accounting by requiring that modifications of capital leases that result in
reclassification as operating leases be accounted for consistent with
sale-leaseback accounting rules. This Statement also contains other
nonsubstantive corrections to authoritative accounting literature. The changes
related to debt extinguishment will be effective for fiscal years beginning
after May 15, 2002, and the changes related to lease accounting will be
effective for transactions occurring after May 15,
68
2002. Adoption of this Statement will not have any immediate effect on our
consolidated financial statements. We will apply this guidance prospectively.
In June 2002, the Financial Accounting Standards Board issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities," which
addresses accounting for restructuring and similar costs. SFAS No. 146
supersedes previous accounting guidance, principally Emerging Issues Task Force
Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for restructuring
activities initiated after December 31, 2002. SFAS No. 146 requires that the
liability for costs associated with an exit or disposal activity be recognized
when the liability is incurred. Under EITF No. 94-3, a liability for an exit
cost was recognized at the date of the company's commitment to an exit plan.
SFAS No. 146 also establishes that the liability should initially be measured
and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of
recognizing future restructuring costs as well as the amounts recognized.
In November 2002, the Financial Accounting Standards Board issued
Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others". This
interpretation of Financial Accounting Standards Board Statements No. 5, 57 and
107, and rescission of Financial Accounting Standards Board Interpretation No.
34 elaborates on the disclosures to be made by a guarantor in its interim and
annual financial statements about its obligations under certain guarantees that
it has issued. It also clarifies that a guarantor is required to recognize, at
the inception of a guarantee, a liability for the fair value of the obligation
undertaken in issuing the guarantee. This interpretation incorporates, without
change, the guidance in Financial Accounting Standards Board Interpretation No.
34, "Disclosure of Indirect Guarantees of Indebtedness of Others", which is
being superceded. The initial recognition and initial measurement provisions of
this interpretation are applicable on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements in this
interpretation are effective for financial statements of interim or annual
periods after December 15, 2002. The interpretive guidance incorporated from
Interpretation No. 34 continues to be required for financial statements for
fiscal years ending after June 15, 1981.
In December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation - Transition and Disclosure". This
amendment to SFAS No. 123, "Accounting for Stock-Based Compensation", provides
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based employee compensation. In addition, this
statement amends the disclosure requirements of SFAS No. 123 to require
disclosures in both annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the method
used on reported results. The provisions of this statement are effective for
financial statements of interim or annual periods after December 15, 2002. Early
application of the disclosure provisions is encouraged, and earlier application
of the transition provisions is permitted, provided that financial statements
for the 2002 fiscal year have not been issued as of the date the statement was
issued.
Information Regarding Forward-Looking Statements
This filing includes forward-looking statements. 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," "believe,"
"intend," "plan," "projection," "forecast," "strategy," "position," "continue,"
"estimate," "expect," "may," "will," or the negative of those terms or other
variations of them or comparable terminology. In particular, statements, express
or implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and assumptions.
Future actions, conditions or events and future results of operations may differ
materially from those expressed in these forward-looking statements. Many of the
factors that will determine these results are beyond our ability to control or
predict. 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, oil, carbon dioxide, natural gas, coal and other bulk materials
and chemicals in the United States;
o economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
69
o changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
o our ability to integrate any acquired operations into our existing
operations;
o our ability to acquire new businesses and assets and to make expansions
to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships
or pipelines in delivering products to our terminals or pipelines;
o our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use or
supply our services;
o changes in laws or regulations, third party relations and approvals,
decisions of courts, regulators and governmental bodies may adversely
affect our business or our ability to compete;
o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion of
our business plan that contemplates growth through acquisitions of
operating businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds and/or
place us at competitive disadvantages compared to our competitors that have
less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other causes;
o acts of sabotage, terrorism or other similar acts causing damage greater
than our insurance coverage limits;
o the condition of the capital markets and equity markets in the United
States;
o the political and economic stability of the oil producing nations of the
world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
o the ability to achieve cost savings and revenue growth;
o rates of inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products; and
o the timing and success of business development efforts.
You should not put undue reliance on any forward-looking statements.
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. Our future results also could be adversely impacted
by unfavorable results of litigation and the fruition of contingencies referred
to in Note 16 to the Consolidated Financial
70
Statements included elsewhere in this report. When considering
forward-looking statements, one should keep in mind the risk factors described
in "Risk Factors" above. The risk factors could cause our actual results to
differ materially from those contained in any forward-looking statement. We
disclaim 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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Generally, our market risk sensitive instruments and positions are
characterized as "other than trading." Our 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 or commodity prices. Our 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 or commodity prices and the timing of transactions.
Energy Financial Instruments
We use energy financial instruments to reduce our risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil and
carbon dioxide. For a complete discussion of our risk management activities, see
Note 14 to the Consolidated Financial Statements included elsewhere in this
report.
To minimize the risks associated with changes in the market price of natural
gas, natural gas liquids, crude oil and carbon dioxide, we use certain financial
instruments for hedging purposes. These instruments include energy products
traded on the New York Mercantile Exchange and over-the-counter markets
including, but not limited to, futures and options contracts, fixed-price swaps
and basis swaps.
During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as hedges under Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities". Upon making that determination, we:
o ceased to account for those derivatives as hedges;
o entered into new derivative transactions on substantially similar terms
with other counterparties to replace our positions with Enron;
o designated the replacement derivative positions as hedges of the
exposures that had been hedged with the Enron positions; and
o recognized a $6.0 million loss (included with General and administrative
expenses in the accompanying Consolidated Statement of Income for 2001) in
recognition of the fact that it was unlikely that we would be paid the
amounts then owed under the contracts with Enron.
While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that additional losses will result from counterparty credit risk in the
future. The credit ratings of the primary parties from whom we purchase
financial instruments are as follows:
Credit Rating
J. Aron & Company / Goldman Sachs A+
Morgan Stanley.................. A+
Deutsche Bank................... AA-
Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated with:
71
o pre-existing or anticipated physical natural gas, natural gas liquids,
crude oil and carbon dioxide sales;
o natural gas purchases; and
o system use and storage.
Our risk management activities are only used in order to protect our profit
margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management group
are monitored by our Risk Management Committee, which is charged with the review
and enforcement of our management's risk management policy.
Through December 31, 2000, gains and losses on hedging positions were
deferred and recognized as cost of sales in the periods in which the underlying
physical transactions occurred. On January 1, 2001, we began accounting for
derivative instruments under Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities" (after
amendment by SFAS No. 137 and SFAS No. 138). As discussed above, our principal
use of derivative financial instruments is to mitigate the market price risk
associated with anticipated transactions for the purchase and sale of natural
gas, natural gas liquids, crude oil and carbon dioxide. SFAS No. 133 allows
these transactions to continue to be treated as hedges for accounting purposes,
although the changes in the market value of these instruments will affect
comprehensive income in the period in which they occur and any ineffectiveness
in the risk mitigation performance of the hedge will affect net income
currently. The change in the market value of these instruments representing
effective hedge operation will continue to affect net income in the period in
which the associated physical transactions are consummated. Our adoption of SFAS
No. 133 has resulted in $45.3 million of deferred net loss being reported as
Accumulated other comprehensive income in the accompanying Balance Sheet at
December 31, 2002, and $63.8 million of deferred net gain being reported as
Accumulated other comprehensive income in the accompanying Balance Sheet at
December 31, 2001.
We measure the risk of price changes in the natural gas, natural gas liquids,
crude oil and carbon dioxide markets utilizing a Value-at-Risk model.
Value-at-Risk is a statistical measure of how much the mark-to-market value of a
portfolio could change during a period of time, within a certain level of
statistical confidence. We utilize a closed form model to evaluate risk on a
daily basis. The Value-at-Risk computations utilize a confidence level of 97.7%
for the resultant price movement and a holding period of one day chosen for the
calculation. The confidence level used means that there is a 97.7% probability
that the mark-to-market losses for a single day will not exceed the
Value-at-Risk number presented. Financial instruments evaluated by the model
include commodity futures and options contracts, fixed price swaps, basis swaps
and over-the-counter options. For each of the years ended December 31, 2002 and
2001, Value-at-Risk reached a high of $12.8 million and $19.9 million,
respectively, and a low of $11.6 million and $12.8 million, respectively.
Value-at-Risk at December 31, 2002, was $12.8 million and averaged $11.9 million
for 2002. Value-at-Risk at December 31, 2001, was $14.6 million and averaged
$16.7 million for 2001.
Our calculated Value-at-Risk exposure represents an estimate of the
reasonably possible net losses that would be recognized on our portfolio of
derivatives assuming hypothetical movements in future market rates, and is not
necessarily indicative of actual results that may occur. It does not represent
the maximum possible loss or any expected loss that may occur, since actual
future gains and losses will differ from those estimated. Actual gains and
losses may differ from estimates due to actual fluctuations in market rates,
operating exposures and the timing thereof, as well as changes in our portfolio
of derivatives during the year. In addition, as discussed preceding, we enter
into these derivatives solely for the purpose of mitigating the risks that
accompany certain of our business activities and, therefore, the change in the
market value of our portfolio of derivatives is, with the exception of a minor
amount of hedging inefficiency, offset by changes in the value of the underlying
physical transactions.
Interest Rate Risk
The market risk inherent in our debt instruments and positions is the
potential change arising from increases or decreases in interest rates as
discussed below.
72
We utilize both variable rate and fixed rate debt in our financing strategy.
See Note 9 to the Consolidated Financial Statements included elsewhere in this
report for additional information related to our debt instruments. For fixed
rate debt, changes in interest rates generally affect the fair value of the debt
instrument, but not our 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 our future earnings and cash flows. We do 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 our fixed rate debt until we would be required to refinance such debt.
As of December 31, 2002 and 2001, the carrying values of our long-term fixed
rate debt were approximately $3,346.1 million and $1,900.6 million,
respectively, compared to fair values of $4,161.6 million and $2,197.9 million,
respectively. The increase in the excess of fair value over carrying value is
primarily due to the decrease in interest rates during 2002. 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 2002 and 2001, respectively, would result in changes of approximately $195.1
million and $77.4 million, respectively, in the fair values of these
instruments.
The carrying value and fair value of our variable rate debt, including
associated accrued interest and excluding market value of interest rate swaps,
was $293.4 million as of December 31, 2002 and $890.9 million as of December 31,
2001. 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 $1.6 million and $6.2 million in our 2002 and 2001
annualized pre-tax earnings, respectively.
As of December 31, 2002, we were party to interest rate swap agreements with
a notional principal amount of $1.95 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.
A hypothetical 10% change in the average interest rates related to these swaps
would not have a material effect on our annual pre-tax earnings in 2002 or 2001.
We monitor our mix of fixed rate 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 our variable rate debt with
fixed rate debt (or vice versa) or by entering into interest rate swaps or other
interest rate hedging agreements.
As of December 31, 2002, our cash and investment portfolio did not include
fixed-income securities. Due to the short-term nature of our investment
portfolio, a hypothetical 10% increase in interest rates would not have a
material effect on the fair market value of our portfolio. Since we have the
ability to liquidate this portfolio, we do not expect our 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 our investment portfolio.
Item 8. Financial Statements and Supplementary Data.
The information required in this Item 8 is included in this report as set
forth in the "Index to Financial Statements" on page 89.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
73
PART III
Item 10. Directors and Executive Officers of the Registrant.
Directors and Executive Officers of our General Partner and the Delegate
Set forth below is certain information concerning the directors and executive
officers of our general partner and KMR as the delegate of our general partner.
All directors of our general partner are elected annually by, and may be removed
by, Kinder Morgan (Delaware), Inc. as its sole shareholder, and all directors of
the delegate are elected annually by, and may be removed by, our general partner
as the sole holder of the delegate's voting shares. Kinder Morgan (Delaware),
Inc. is a wholly owned subsidiary of KMI. All officers of the general partner
and the delegate serve at the discretion of the board of directors of our
general partner. In addition to the individuals named below, KMI was a director
of the delegate until its resignation in January 2003.
Name Age Position with our General Partner and the Delegate
--------------- ---- --------------------------------------------------
Richard D. Kinder... 58 Director, Chairman and Chief Executive
Officer
Michael C. Morgan... 34 President
C. Park Shaper...... 34 Director, Vice President, Treasurer and
Chief Financial Officer
Edward O. Gaylord... 71 Director
Gary L. Hultquist... 59 Director
Perry M. Waughtal... 67 Director
Thomas A. Bannigan.. 49 President, Products Pipelines
R. Tim Bradley...... 47 President, CO2 Pipelines
David D. Kinder..... 28 Vice President, Corporate Development
Joseph Listengart... 34 Vice President, General Counsel and
Secretary
Deborah A. Macdonald 51 President, Natural Gas Pipelines
Thomas B. Stanley... 52 President, Terminals
James E. Street..... 46 Vice President, Human Resources and
Administration
Richard D. Kinder is Director, Chairman and Chief Executive Officer of
KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder has served as Director,
Chairman and Chief Executive Officer of KMR since its formation in February
2001. He was elected Director, Chairman and Chief Executive Officer of KMI
in October 1999. He was elected Director, Chairman and Chief Executive
Officer of Kinder Morgan G.P., Inc. in February 1997. Mr. Kinder is also a
director of Baker Hughes Incorporated. Mr. Kinder is the uncle of David
Kinder, Vice President, Corporate Development of KMR, Kinder Morgan G.P.,
Inc. and KMI.
Michael C. Morgan is President of KMR, Kinder Morgan G.P., Inc. and KMI.
Mr. Morgan was elected to each of these positions in July 2001. He was also
elected Director of KMI in January 2003. Mr. Morgan served as Vice
President-Strategy and Investor Relations of KMR from February 2001 to July
2001. He served as Vice President-Strategy and Investor Relations of KMI and
Kinder Morgan G.P., Inc. from January 2000 to July 2001. He served as Vice
President, Corporate Development of Kinder Morgan G.P., Inc. from February
1997 to January 2000. Mr. Morgan was the Vice President, Corporate
Development of KMI from October 1999 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, including
Assistant to the Chairman, at PSI Energy, Inc. Mr. Morgan received a
Bachelor of Arts in Economics and a Masters of Arts in Sociology from
Stanford University in 1990.
C. Park Shaper is Director, Vice President, Treasurer and Chief Financial
Officer of KMR and Kinder Morgan G.P., Inc. and Vice President, Treasurer and
Chief Financial Officer of KMI. Mr. Shaper was elected Director of KMR and
Kinder Morgan G.P., Inc. in January 2003. He was elected Vice President,
Treasurer and Chief Financial Officer of KMR upon its formation in February
2001. He has served as Treasurer of KMI since April 2000 and Vice President and
Chief Financial Officer of KMI since January 2000. Mr. Shaper was elected Vice
President, Treasurer and Chief Financial Officer of Kinder Morgan G.P., Inc. in
January 2000. From June 1999 to December 1999, 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 served as
Vice President and Chief Financial Officer of First Data Analytics, a
wholly-owned subsidiary of First Data Corporation, from 1997 to June 1999.
74
From 1995 to 1997, he was a consultant with The Boston Consulting Group. He
received a Masters in Business Administration degree from the J.L. Kellogg
Graduate School of Management at Northwestern University. Mr. Shaper also has a
Bachelor of Science degree in Industrial Engineering and a Bachelor of Arts
degree in Quantitative Economics from Stanford University.
Edward O. Gaylord is a Director of KMR and Kinder Morgan G.P., Inc. Mr.
Gaylord was elected Director of KMR upon its formation in February 2001. Mr.
Gaylord was elected Director of Kinder Morgan G.P., Inc. in February 1997.
Since 1989, Mr. Gaylord has been the Chairman of the Board of Directors of
Jacintoport Terminal Company, a liquid bulk storage terminal on the Houston,
Texas ship channel. Mr. Gaylord serves on the Board of Directors of Seneca
Foods Corporation. Mr. Gaylord currently serves as the chairman of the
compensation and audit committees of KMR and our general partner.
Gary L. Hultquist is a Director of KMR and Kinder Morgan G.P., Inc. Mr.
Hultquist was elected Director of KMR upon its formation in February 2001.
He was elected Director of Kinder Morgan G.P., Inc. in October 1999. Since
1995, Mr. Hultquist has been the Managing Director of Hultquist Capital, LLC,
a San Francisco-based strategic and merger advisory firm. Mr. Hultquist is a
member of the Board of Directors of netMercury, Inc., a supplier of automated
supply chain services, critical spare parts and consumables used in
semiconductor manufacturing. 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.
Perry M. Waughtal is a Director of KMR and Kinder Morgan G.P., Inc. Mr.
Waughtal was elected Director of KMR upon its formation in February 2001.
Mr. Waughtal was elected Director of Kinder Morgan G.P., Inc. in April 2000.
Mr. Waughtal is the Chairman, a limited partner and a 40% owner of Songy
Partners Limited, an Atlanta, Georgia based real estate investment company.
Mr. Waughtal advises Songy's management on real estate investments and has
overall responsibility for strategic planning, management and operations.
Previously, Mr. Waughtal served for over 30 years as Vice Chairman of
Development and Operations and as Chief Financial Officer for Hines Interests
Limited Partnership, a real estate and development entity based in Houston,
Texas.
Thomas A. Bannigan is President, Products Pipelines of KMR and Kinder
Morgan G.P., Inc. and President and Chief Executive Officer of Plantation
Pipe Line Company. Mr. Bannigan was elected President, Products Pipelines of
KMR upon its formation in February 2001. He was elected President, Products
Pipelines of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan has
served as President and Chief Executive Officer of Plantation Pipe Line
Company since May 1998. From 1985 to May 1998, Mr. Bannigan was Vice
President, General Counsel and Secretary of Plantation Pipe Line Company.
R. Tim Bradley is President, CO2 Pipelines of KMR and of Kinder Morgan G.P.,
Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was elected
President, CO2 Pipelines of KMR and Vice President (President, CO2 Pipelines) of
Kinder Morgan G.P., Inc. in April 2001. Mr. Bradley has been President of Kinder
Morgan CO2 Company, L.P. (which name changed from Shell CO2 Company, Ltd. in
April 2000) since March 1998. From May 1996 to March 1998, Mr. Bradley was
Manager of CO2 Marketing for Shell Western E&P, Inc. Mr. Bradley received a
Bachelor of Science in Petroleum Engineering from the University of Missouri at
Rolla.
David D. Kinder is Vice President, Corporate Development of KMR, Kinder
Morgan G.P., Inc. and KMI. Mr. Kinder was elected Vice President, Corporate
Development of KMR, Kinder Morgan G.P., Inc. and KMI in October 2002. He
served as manager of corporate development for KMI and Kinder Morgan G.P.,
Inc. from January 2000 to October 2002. He served as an associate in the
corporate development group of KMI and Kinder Morgan G.P., Inc. from February
1999 to January 2000. From June 1996 to February 1999, Mr. Kinder was in the
analyst and associate program at Enron Corp. Mr. Kinder graduated cum laude
with a Bachelors degree in Finance from Texas Christian University in 1996.
Mr. Kinder is the nephew of Richard D. Kinder.
Joseph Listengart is Vice President, General Counsel and Secretary of KMR,
Kinder Morgan G.P., Inc. and KMI. Mr. Listengart was elected Vice President,
General Counsel and Secretary of KMR upon its formation in February 2001. He
was elected Vice President and General Counsel of Kinder Morgan G.P., Inc.
and Vice President, General Counsel and Secretary of KMI in October 1999.
Mr. Listengart was elected Kinder Morgan G.P., Inc.'s Secretary in November
1998 and became an employee of Kinder Morgan G.P., Inc. in March 1998. From
March 1995 through February 1998, Mr. Listengart worked as an attorney for
Hutchins, Wheeler & Dittmar, a
75
Professional Corporation. Mr. Listengart received his Masters in Business
Administration from Boston University in January 1995, his Juris Doctor,
magna cum laude, from Boston University in May 1994, and his Bachelor of Arts
degree in Economics from Stanford University in June 1990.
Deborah A. Macdonald is President, Natural Gas Pipelines of KMR, Kinder
Morgan G.P., Inc. and KMI. She was elected as President, Natural Gas
Pipelines in June 2002. She also holds the title of President of Natural Gas
Pipeline Company of America, KMI's largest subsidiary. Ms. Macdonald has
served as President of NGPL since the merger of KMI in October 1999. Prior
to joining Kinder Morgan, Ms. Macdonald worked as Senior Vice President of
legal affairs for Aquila Energy Company from January 1999 to October 1999,
and was engaged in a private energy consulting practice from June 1996 to
December 1999. Ms. Macdonald received her Juris Doctor, summa cum laude,
from Creighton University in May 1980 and received a Bachelors degree, magna
cum laude, from Creighton University in December 1972.
Thomas B. Stanley is President, Terminals of KMR and Kinder Morgan G.P.,
Inc. Mr. Stanley became President of our Terminals segment in July 2001 when
we combined our previously separate Bulk Terminals and Liquids Terminals
segments. Prior to that, Mr. Stanley served as President, Bulk Terminals of
Kinder Morgan G.P., Inc. since August 1998 and of KMR since February 2001.
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 is Vice President, Human Resources and Administration of
KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Street was elected Vice
President, Human Resources and Administration of KMR upon its formation in
February 2001. He was elected Vice President, Human Resources and
Administration of Kinder Morgan G.P., Inc. and KMI in August 1999. From
October 1996 to August 1999, Mr. Street was Senior Vice President, Human
Resources and Administration for Coral Energy, a subsidiary of Shell Oil
Company. Mr. Street received a Masters of Business Administration degree
from the University of Nebraska at Omaha and a Bachelor of Science degree
from the University of Nebraska at Kearney.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Exchange Act requires our directors and officers, and
persons who own more than 10% of a registered class of our equity securities, to
file initial reports of ownership and reports of changes in ownership with the
Securities and Exchange Commission. Such persons are required by SEC regulation
to furnish us with copies of all Section 16(a) forms they file.
Based solely on our review of the copies of such forms furnished to us and
written representations from our executive officers and directors, we believe
that all Section 16(a) filing requirements were met during 2002, except for a
failure to file three reports by Mr. Richard D. Kinder covering eight
transactions for the purchase of a total of 756 common units acquired
unintentionally by Mr. Kinder's spouse under a distribution reinvestment program
implemented by her broker without Mr. Kinder's knowledge.
Item 11. Executive Compensation.
As is commonly the case for publicly traded limited partnerships, we have
no officers. Under our limited partnership agreement, Kinder Morgan G.P.,
Inc., as our general partner, is to direct, control and manage all of our
activities. Pursuant to a delegation of control agreement, Kinder Morgan G.P.,
Inc. has delegated to KMR, the management and control of our business and
affairs to the maximum extent permitted by our partnership agreement and
Delaware law, subject to our general partner's right to approve certain actions
by KMR. The executive officers and directors of Kinder Morgan G.P., Inc. serve
in the same capacities for KMR. Certain of those executive officers, including
all of the named officers below, also serve as executive officers of KMI. All
information in this report with respect to compensation of executive officers
describes the total compensation received by those persons in all capacities for
Kinder Morgan G.P., Inc., KMR, KMI and their respective affiliates.
76
Summary Compensation Table
Long-Term
Compensation Awards
------------------------
Annual Compensation Units/
------------------------ Restricted KMI Shares
Stock Underlying All Other
Name and Principal Position Year Salary Bonus(1) Awards(2) Options Compensation(3)
-------------------- ----------- -------- --------- ------------ ------------ ---------------
Richard D. Kinder........... 2002 $ 1 $ -- $ -- -- $ --
Director, Chairman and CEO 2001 1 -- -- -- --
2000 1 -- -- -- --
Michael C. Morgan........... 2002 200,000 950,000 -- -- 9,584
President 2001 200,000 350,000 569,900 -- 7,835
2000 200,000 300,000(4) 498,750 0/150,000(5) 10,836
C. Park Shaper............. 2002 200,000 950,000 -- 0/100,000(6) 8,336
Director, Vice President, 2001 200,000 350,000 569,900 -- 7,186
Treasurer and CFO 2000 175,000 -- 498,750 0/150,000(7) 10,836
Joseph Listengart.......... 2002 200,000 950,000 -- -- 8,336
Vice President, 2001 200,000 350,000 569,900 -- 7,186
General Counsel and 2000 181,250 225,000 498,750 0/6,300(8) 10,798
Secretary
Deborah A. Macdonald....... 2002 200,000 950,000 -- 0/50,000(9) 8,966
President, 2001 200,000 350,000 569,900 -- 32,816
Natural Gas Pipelines 2000 200,000 350,000 498,750 -- 77,231
- ----------
(1) Amounts earned in year shown and paid the following year.
(2)Represent shares of restricted KMI stock awarded in 2002 and 2001 that
relate to performance in 2001 and 2000, respectively. Value computed as the
number of shares awarded (10,000) times the closing price on date of grant
($56.99 at January 16, 2002 and $49.875 at January 17, 2001). Twenty-five
percent of the shares in each grant vest on each of the first four
anniversaries after the date of grant. The holders of the restricted stock
awards are eligible to vote and to receive dividends declared on such shares.
(3)For 2000, amounts represent our general partner's contributions to the
Kinder Morgan 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. For 2001,
amounts represent contributions to the Kinder Morgan Savings Plan, value of
group-term life insurance exceeding $50,000, parking subsidy and a $50 cash
payment. For 2002, amounts represent contributions to the Kinder Morgan
Savings Plan, value of group-term life insurance exceeding $50,000 and
taxable parking subsidy. Ms. Macdonald's amounts include additions in 2000
and 2001 resulting from relocation expenses.
(4)Does not include $7,010,000 paid to Mr. Morgan under our Executive
Compensation Plan. The payment made in 2000 was the last payment Mr. Morgan
is to receive under our Executive Compensation Plan. We do not intend to
compensate any employees providing services to us under the Executive
Compensation Plan on a going-forward basis. See "-- Executive Compensation
Plan."
(5)The 150,000 options to purchase KMI shares were granted and became fully
vested on April 20, 2000. The options were granted to Mr. Morgan in
connection with the execution of his employment agreement. The options have
an exercise price of $33.125 per share. See "-- Employment Agreement."
(6)The 100,000 options to purchase KMI shares were granted on January 16, 2002
with an exercise price of $56.99 per share and vest at the rate of
twenty-five percent on each of the first four anniversaries after the date of
grant.
(7)The year 2000 options to purchase KMI shares include 25,000 options that
were granted in 2001, but relate to performance in 2000. These options were
granted and became fully vested on January 17, 2001 with an exercise price of
$49.875 per share. The remaining 125,000 options were granted on January 20,
2000 with an exercise price of $24.75 per share. These options vest at the
rate of twenty-five percent on each of the first four anniversaries after the
date of grant.
(8)The 6,300 options to purchase KMI shares were granted in 2001, but relate to
performance in 2000. The options were granted and became fully vested on
January 17, 2001 with an exercise price of $49.875 per share.
77
(9)The 50,000 options to purchase KMI shares were granted on January 16, 2002
with an exercise price of $56.99 per share and vest at the rate of
twenty-five percent on each of the first four anniversaries after the date of
grant.
Executive Compensation Plan. Pursuant to our Executive Compensation Plan,
executive officers of our general partner are eligible for awards equal to a
percentage of the "incentive compensation value", which is defined as cash
distributions to our general partner during the four calendar quarters preceding
the date of redemption multiplied by eight (less a participant adjustment
factor, if any). Under the plan, no eligible employee may receive a grant in
excess of two percent of the incentive compensation value, and total awards
under the plan may not exceed ten percent of the incentive compensation value.
In general, participants may redeem vested awards in whole or in part from time
to time by written notice. We may, at our option, pay the participant in units
(provided, however, the unitholders approve the plan prior to issuing such
units) or in cash. We may not issue more than 400,000 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. However, the plan may be terminated before such
date, and upon such early termination, we 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 our general partner granted an award totaling two
percent of the incentive compensation value to Mr. Michael Morgan. Originally,
50 percent of such award was to vest on each of January 1, 2000 and January 1,
2002. No awards have been granted since July 1997.
On January 4, 1999, the award granted to Mr. Morgan was amended to provide
for the immediate vesting and pay-out of 50 percent of his award, or one percent
of the incentive compensation value. On April 28, 2000, the award granted to Mr.
Morgan was amended to provide for the immediate vesting and pay-out of the
remaining 50 percent of his award, or one percent of the incentive compensation
value. The board of directors of our general partner believes that accelerating
the vesting and pay-out of the award was in our best interest because it capped
the total payment Mr. Morgan was entitled to receive with respect to his award.
The payment made in 2000 was the last payment Mr. Morgan is to receive under our
Executive Compensation Plan. We do not intend to compensate any employees
providing service to us under the Executive Compensation Plan on a going-forward
basis.
Kinder Morgan Savings Plan. Effective July 1, 1997, our general partner
established the Kinder Morgan Retirement Savings Plan, a defined contribution
401(k) plan. This plan was subsequently amended and merged to form the Kinder
Morgan Savings Plan. The plan now permits all full-time employees of Kinder
Morgan, Inc. and KMGP Services Company, Inc. to contribute one percent to 50
percent of base compensation, on a pre-tax basis, into participant accounts. In
addition to a mandatory contribution equal to four percent of base compensation
per year for most plan participants, our general partner may make discretionary
contributions in years when specific performance objectives are met. Certain
employees' contributions are based on collective bargaining agreements. The
mandatory contributions are made each pay period on behalf of each eligible
employee. Any discretionary contributions are made during the first quarter
following the performance year. All contributions, including discretionary
contributions, are in the form of KMI stock that is immediately convertible into
other available investment vehicles at the employee's discretion. During the
first quarter of 2003, we do not believe that we will make any discretionary
contributions to individual accounts for 2002. 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 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.
Common Unit Option Plan. Pursuant to our Common Unit Option Plan, key
personnel are eligible to receive grants of options to acquire common units. The
total number of common units available under the option plan is 500,000. 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 common 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 common unit on the date of grant. Either the board of
directors of our general partner or a committee of the board of directors will
administer the option plan. The option plan terminates on March 5, 2008.
78
No individual employee may be granted options for more than 20,000 common
units in any year. Our board of directors or the committee referred to in the
prior paragraph will determine the duration and vesting of the options to
employees at the time of grant. As of December 31, 2002, outstanding options to
purchase 261,600 common units had been granted to 84 former Kinder Morgan G.P.,
Inc. employees who are now employees of Kinder Morgan, Inc. or KMGP Services
Company, Inc. Forty percent of such options will vest on the first anniversary
of the date of grant and 20 percent on each of the next three anniversaries. The
options expire seven years from the date of grant.
The option plan also granted to each of our then non-employee directors as of
April 1, 1998, an option to purchase 10,000 common units at an exercise price
equal to the fair market value of the common units at the end of the trading day
on such date. In addition, each new non-employee director is granted options to
acquire 10,000 common units on the first day of the month following his or her
election. Under this provision, as of December 31, 2002, outstanding options to
purchase 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s three non-employee directors. Forty percent of all such options will vest
on the first anniversary of the date of grant and 20 percent on each of the next
three anniversaries. The non-employee director options will expire seven years
from the date of grant.
No options to purchase common units were granted during 2002 to any of the
individuals named in the Summary Compensation Table above. The following table
sets forth certain information at December 31, 2002 with respect to common unit
options previously granted to the individuals named in the Summary Compensation
Table above. Mr. Listengart was the only person named in the Summary
Compensation Table who was granted common unit options. No common unit options
were granted at an option price below the fair market value on the date of
grant.
Aggregated Common Unit Option Exercises in 2002, and 2002 Year-End Common
Value of
Number of Units Unexercised
Underlying Unexercised In-the-Money Options
Options at 2002 Year-End at 2002 Year-End(1)
Units Acquired Value ----------------------------- ------------------------------
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
------------ -------------- --------- ----------- -------------- ----------- -------------
Joseph Listengart.. -- -- 10,000 -- $177,188 --
- ---------------
(1)Calculated on the basis of the fair market value of the underlying common
units at year-end 2002, minus the exercise price.
KMI Option Plan. Under KMI's stock option plan, employees of KMI and its
affiliates, including employees of KMI's direct and indirect subsidiaries, like
KMGP Services Company, Inc., are eligible to receive grants of options to
acquire shares of common stock of KMI. KMI's board of directors administers this
option plan. The primary purpose for granting stock options under this plan to
employees of KMI, KMGP Services Company, Inc. and our 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 our subsidiaries and us.
The following tables set forth certain information at December 31, 2002 and
for the fiscal year then ended with respect to KMI stock options granted to the
individuals named in the Summary Compensation Table above. Mr. Shaper and Ms.
Macdonald are the only persons named in the Summary Compensation Table who were
granted KMI stock options during 2002. None of these KMI stock options were
granted with an exercise price below the fair market value of the common stock
on the date of grant. The options were granted on January 16, 2002 and vest at
twenty-five percent on each of the first four anniversaries after the date of
grant. The options expire 10 years after the date of grant.
79
KMI Stock Option Grants in 2002
Potential Realizable Value
at Assumed Annual Rates
Number of % of Total of Stock Price Appreciation
Securities Options For Option Term(1)
Underlying Granted to Exercise ---------------------------
Options Employees Price Expiration
Name Granted in 2002 Per Share Date 5% 10%
----------- ----------- ----------- ------------ ---------- ------------- ------------
C. Park Shaper.. 100,000 8.15% $56.99 01/16/2012 $3,584,000 $9,083,000
Deborah A. Macdonald... 50,000 4.07% $56.99 01/16/2012 $1,792,000 $4,541,500
- ----------
(1)The dollar amounts under these columns use the 5% and 10% rates of
appreciation prescribed by the Securities and Exchange Commission. The 5% and
10% rates of appreciation would result in per share prices of $92.83 and
$147.82, respectively. We express no opinion regarding whether this level of
appreciation will be realized and expressly disclaim any representation to
that effect.
Aggregated KMI Stock Option Exercises in 2002 and 2002 Year-End KMI Stock
Option Values
Value of
Number of Shares Unexercised
Underlying Unexercised In-the-Money Options
Options at 2002 Year-End at 2002 Year-End(1)
Shares Acquired Value ----------------------------- ------------------------------
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
------------ -------------- --------- ----------- -------------- ----------- -------------
Michael C. Morgan.. -- -- 275,000 62,500 $3,678,938 $1,153,594
C. Park Shaper..... -- -- 87,500 162,500 $1,095,000 $1,095,000
Joseph Listengart.. -- -- 88,800 43,750 $1,522,744 $ 807,516
Deborah A. Macdonald 50,00 $1,437,850 50,000 100,000 $ 922,875 $ 922,875
- ----------
(1)Calculated on the basis of the fair market value of the underlying shares at
year-end, minus the exercise price.
Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and
KMI are eligible to participate in a Cash Balance Retirement Plan that was put
into effect on January 1, 2001. Certain employees continue to accrue benefits
through a career-pay formula, "grandfathered" according to age and years of
service on December 31, 2000, or collective bargaining arrangements. All other
employees will accrue benefits through a personal retirement account in the Cash
Balance Retirement Plan. Employees with prior service and not grandfathered
converted to the Cash Balance Retirement Plan and were credited with the current
fair value of any benefits they had previously accrued through the defined
benefit plan. Under the plan, we make contributions on behalf of participating
employees equal to three percent of eligible compensation every pay period. In
addition, discretionary contributions are made to the plan based on our and
KMI's performance. In the first quarter of 2002, an additional one percent
discretionary contribution was made to individual accounts. No additional
contributions were made for 2002 performance. Interest will be credited to the
personal retirement accounts at the 30-year U.S. Treasury bond rate in effect
each year. Employees will be fully vested in the plan after five years, and they
may take a lump sum distribution upon termination of employment or retirement.
The following table sets forth the estimated annual benefits payable under
normal retirement at age sixty-five, assuming current remuneration levels
without any salary projection, and participation until normal retirement at age
sixty-five, with respect to the named executive officers under the provisions of
the Kinder Morgan Cash Balance Retirement Plan.
80
Estimated Estimated
Current Credited Current Annual
Credited Years Compensation Benefit
Years of Service Age as of Covered by Upon
Name of Service at Age 65 Jan. 1, 2003 Plans Retirement(1)
---- ---------- ---------- ------------ ------------ ------------
Richard D. Kinder 2 8.8 58.2 $ 1 $ -
Michael C. Morgan 2 32.6 34.4 200,000 62,686
C. Park Shaper 2 32.6 34.4 200,000 62,686
Joseph Listengart 2 32.4 34.6 200,000 61,928
Deborah A. MacDonald 2 15.8 51.2 200,000 15,875
- ----------
(1)The estimated annual benefits payable are based on the straight-life annuity
form.
Compensation Committee Interlocks and Insider Participation. We do not have a
separate compensation committee. KMR's compensation committee, comprised of Mr.
Edward O. Gaylord, Mr. Gary L. Hultquist and Mr. Perry M. Waughtal, makes
compensation decisions regarding our executive officers. Mr. Richard D. Kinder
and Mr. C. Park Shaper, who are executive officers of KMR, participate in the
deliberations of the KMR compensation committee concerning executive officer
compensation. Mr. Kinder receives $1.00 annually in total salary compensation
for services to KMI, KMR and us.
Directors Fees. During 2002, each of the three non-employee members of the
boards of directors of KMR and our general partner was paid $10,000 in the
aggregate for each quarter in 2002 in which they served on such boards of
directors. Under the current plan, each is to receive $10,000 for each quarter
in 2003 in which they serve. In addition, the director who serves as chairman of
KMR's audit committee will be paid an additional $2,500 for each quarter in
2003. Directors are reimbursed for reasonable expenses in connection with board
meetings. Consistent with the current plan, each director received $10,000 in
cash compensation with respect to board service for the first quarter of 2003;
however, we plan to implement a phantom unit option plan for non-employee
directors, which will serve as the sole compensation for non-employee directors
for the remainder of 2003, other than the $2,500 which will be paid in cash each
quarter to the audit committee chairman.
Employment Agreement. In April 2000, Mr. Michael C. Morgan entered into a
four-year employment agreement with KMI and our general partner. Under the
employment agreement, Mr. Morgan receives an annual base salary of $200,000 and
bonuses at the discretion of the compensation committee of KMR. In connection
with the execution of the employment agreement, Mr. Morgan no longer
participates under our Executive Compensation Plan. In addition, he is prevented
from competing with KMI and us for a period of four years from the date of the
agreement, provided Mr. Richard D. Kinder or Mr. William V. Morgan continues to
serve as chief executive officer of KMI or its successor.
Retention Agreement. Effective January 17, 2002, KMI entered into a retention
agreement with Mr. C. Park Shaper, an officer of KMI, our general partner and
its delegate. Pursuant to the terms of the agreement, Mr. Shaper obtained a $5
million personal loan guaranteed by us. Mr. Shaper was required to purchase KMI
common shares and our common units in the open market with the loan proceeds. If
he voluntarily leaves us prior to the end of five years, then he must repay the
entire loan. On the fifth anniversary date of the agreement, provided Mr. Shaper
has continued to be employed by our general partner, we and KMI will assume Mr.
Shaper's obligations under the loan. The agreement contains provisions that
address termination for cause, death, disability and change of control.
Lines of Credit. We have agreed to guarantee potential borrowings under lines
of credit available from Wachovia Bank, National Association to Messrs.
Listengart, Shaper and Ms. Macdonald. Each of these officers is primarily liable
for any borrowing on his line of credit, and if we make any payment with respect
to an outstanding loan, the officer on behalf of whom payment is made must
surrender a percentage of his or her KMI stock options. To date, we have made no
payment with respect to these lines of credit. Furthermore, the lines of credit
and our related guaranty expire in October 2003 and will not be renewed.
81
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
The following table sets forth information as of January 31, 2003, regarding
(a) the beneficial ownership of (i) our common and Class B units, (ii) the
common stock of KMI, the parent company of our general partner, and (iii) KMR
shares by all directors of our general partner and its delegate, each of the
named executive officers and all directors and executive officers as a group and
(b) the beneficial ownership of our common and Class B units or shares of KMR by
all persons known by our general partner to own beneficially more than five
percent of our common and Class B units and KMR shares. Unless otherwise noted,
the address of each person below is c/o Kinder Morgan Energy Partners, L.P., 500
Dallas Street, Suite 1000, Houston, Texas 77002. All references to the number of
our common and Class B units and to the number of KMR shares have been restated
to reflect the effect of the two-for-one splits of our outstanding common and
Class B units and KMR shares that occurred on August 31, 2001.
Amount and Nature of Beneficial Ownership(1)
Kinder Morgan
Common Units Class B Units Management Shares KMI Voting Stock
---------------------- ---------------------- ---------------------- -----------------------
Number Percent Number Percent Number Percent Number Percent
of Units(2) of)Class of Units(3) of Class of Shareof(5) of Class of Shares(5) of Class
----------- -------- ----------- -------- ------------- -------- ------------ --------
Richard D. Kinder(6)... 315,956 * -- -- 32,522 * 23,995,398 19.68%
Michael C. Morgan(7)... 6,000 * -- -- 3,777 * 305,000 *
C. Park Shaper(8)...... 86,000 * -- -- 2,208 * 201,750 *
Edward O. Gaylord...... 33,000 * -- -- -- -- 2,000 *
Gary L. Hultquist(9)... 11,000 * -- -- -- -- -- --
Perry M.Waughtal(10)... 33,300 * -- -- 32,710 * 30,000 *
Joseph Listengart(11).. 14,198 * -- -- -- -- 109,300 *
Deborah A.Macdonald(12). -- -- -- -- -- -- 83,068 *
Directors and Executive
Officers As a group
(13 persons)(13)....... 652,972 * -- -- 75,361 * 25,099,094 20.58%
Kinder Morgan,Inc(14)... 12,955,735 9.97% 5,313,400 100.00 13,511,726 29.60% -- --
Fayez Sarofim (15)...... 7,019,652 5.40% -- -- -- -- -- --
Capital Group International,
Inc.(16)............... -- -- -- -- 4,543,590 9.95% -- --
Oppenheimer Funds,
Inc.(17).............. -- -- -- -- 3,827,803 8.38% -- --
- ----------
* Less than 1%.
(1) Except as noted otherwise, all units and KMI shares involve sole voting
power and sole investment power. For Kinder Morgan Management, see note (4).
(2) As of January 31, 2003, we had 129,971,518 common units issued and
outstanding.
(3) As of January 31, 2003, we had 5,313,400 Class B units issued and
outstanding.
(4) Represent the limited liability company shares of KMR. As of January 31,
2003, there were 45,654,048 issued and outstanding KMR shares. In all cases,
our i-units will be voted in proportion to the affirmative and negative
votes, abstentions and non-votes of owners of KMR shares. Through the
provisions in our partnership agreement and KMR's limited liability company
agreement, the number of outstanding KMR shares, including voting shares
owned by our general partner, and the number of our i-units will at all
times be equal.
(5) As of January 31, 2003, KMI had a total of 121,933,618 shares of issued and
outstanding voting common stock, which excludes 8,099,868 shares held in
treasury.
(6) Includes (a) 7,856 common units owned by Mr. Kinder's spouse, (b) 5,156 KMI
shares held by Mr. Kinder's spouse and (c) 250 KMI shares held by Mr. Kinder
in a custodial account for his nephew. Mr. Kinder disclaims any and all
beneficial or pecuniary interest in these units and shares.
(7) Includes options to purchase 275,000 KMI shares exercisable within 60 days
of January 31, 2003, and includes 12,500 shares of restricted KMI stock.
(8) Includes options to purchase 143,750 KMI shares exercisable within 60 days
of January 31, 2003, and includes 12,500 shares of restricted KMI stock.
(9) Includes options to purchase 8,000 common units exercisable within 60 days
of January 31, 2003.
82
(10)Includes options to purchase 6,000 common units exercisable within 60 days
of January 31, 2003.
(11)Includes options to purchase 10,000 common units and 88,800 KMI shares
exercisable within 60 days of January 31, 2003, and includes 12,500 shares
of restricted KMI stock.
(12)Includes options to purchase 62,500 KMI shares exercisable within 60 days
of January 31, 2003, and includes 12,500 shares of restricted KMI stock.
(13)Includes options to purchase 47,200 common units and 897,925 KMI shares
exercisable within 60 days of January 31, 2003, and includes 75,450 shares
of restricted KMI stock.
(14)Includes common units owned by KMI and its consolidated subsidiaries,
including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(15)As reported on the Schedule 13G/A filed February 14, 2003 by Fayez Sarofim
& Co. and Fayez Sarofim. Mr. Sarofim reports that he has sole voting power
over 2,000,000 common units, shared voting power over 3,967,893 common
units, sole disposition power over 2,000,000 common units and shared
disposition power over 5,019,652 common units. Mr. Sarofim is a director of
KMI. Fayez Sarofim & Co.'s and Mr. Sarofim's address is 2907 Two Houston
Center, Houston, Texas 77010.
(16)As reported on the Schedule 13G/A filed February 11, 2003 by Capital Group
International, Inc. and Capital Guardian Trust Company. Capital Group
International, Inc. and Capital Guardian Trust Company report that in regard
to KMR shares, they have sole voting power over 3,373,010 shares, shared
voting power over 0 shares, sole disposition power over 4,543,590 shares and
shared disposition power over 0 shares. Capital Group International, Inc.'s
and Capital Guardian Trust Company's address is 11100 Santa Monica Blvd.,
Los Angeles, California 90025.
(17)As reported on the Schedule 13G filed February 12, 2003 by Oppenheimer
Funds, Inc. and Oppenheimer Capital Income Fund. Oppenheimer Funds, Inc.
reports that in regard to KMR shares, it has sole voting power over 0
shares, shared voting power over 0 shares, sole disposition power over 0
shares and shared disposition power over 3,827,803 shares. Of these
3,827,803 KMR shares, Oppenheimer Capital Income Fund has sole voting power
over 2,425,000 shares, shared voting power over 0 shares, sole disposition
power over 0 shares and shared disposition power over 2,425,000 shares.
Oppenheimer Funds, Inc.'s address is 498 Seventh Avenue, New York, New York
10018, and Oppenheimer Capital Income Fund's address is 6803 Tucson Way,
Englewood, Colorado 80112.
Equity Compensation Plan Information
The following table sets forth information regarding our equity compensation
plans as of January 31, 2003. Specifically, the table refers to information
regarding our Common Unit Option Plan described in Item 11. "Executive
Compensation" as of January 31, 2003.
Number of securities
remaining available for
Number of securities Weighted average future issuance under equity
To be issued upon exercise exercise price compensation plans
of outstanding options, of outstanding options, (excluding securities reflected
Plan Category warrants and rights warrants and rights in column (a))
(a) (b) (c)
- ------------------------- ----------------------------- ------------------------ -------------------------------
Equity compensation plans
approved by security holders - - -
Equity compensation plans
Not approved by security
holders 281,600 $17.50 57,000
------- ------
Total 281,600 57,000
======= ======
83
Item 13. Certain Relationships and Related Transactions.
Odessa Lateral
We have proposed the purchase of a certain 13-mile, 6-inch carbon dioxide
pipeline lateral, referred to herein as the Odessa Lateral, from Morgan
Associates Proprietary, LP for approximately $700,000. The Odessa Lateral
connects to Kinder Morgan CO2 Company, L.P.'s Central Basin carbon dioxide
pipeline and serves, solely, the Emmons and South Cowden carbon dioxide flooding
projects located in the Permian Basin and operated by ConocoPhillips. Morgan
Associates is a limited partnership controlled by Mr. William V. Morgan and his
wife, Sara. Mr. and Mrs. Morgan are the parents of Michael C. Morgan, the
president of our general partner and KMR. Mr. William V. Morgan was Director and
Vice Chairman of our general partner and its delegate, KMR, at the time of his
retirement in January 2003.
Mr. William V. Morgan, through Morgan Associates and otherwise, has been an
active investor in carbon dioxide pipeline infrastructure since the mid-1980s.
In 1996, prior to our current management's acquisition of our general partner in
February 1997, Morgan Associates constructed the Odessa Lateral for
approximately $1.3 million, entered into a long-term transportation agreement
with KMCO2's ultimate predecessor in interest to transport carbon dioxide via
the Odessa Lateral and entered into an operating agreement with KMCO2's ultimate
predecessor in interest. Subsidiaries of Shell Oil Company and Mobil Corporation
initially provided the carbon dioxide that was ultimately sold to the South
Cowden and Emmons projects. Currently, KMCO2 sells to ConocoPhillips carbon
dioxide used in the Emmons and South Cowden carbon dioxide flooding
projects.
In 1998, we contributed our Central Basin Pipeline, our operator's interest
under the operating agreement and our rights and obligations under the
transportation agreement to Shell CO2 Company, Ltd., a joint venture owned 80%
by Shell Oil Company and 20% by us. In April 2000, Shell Oil Company elected to
sell its 80% interest in Shell CO2 Company, Ltd. and we successfully won the bid
and acquired such interest. We renamed Shell CO2 Company, Ltd. as Kinder Morgan
CO2 Company, L.P., and we own a 98.9899% limited partner interest in KMCO2 and
our general partner owns a direct 1.0101% general partner interest. KMCO2
operates and transports carbon dioxide via the Odessa Lateral, and following our
acquisition of Shell's joint-venture interest, our relationship with Morgan
Associates in respect of the Odessa Lateral has returned to the 1998 pre-joint
venture level.
In late 2002, ConocoPhillips approached KMCO2 to discuss transferring some
volumes that it was obligated to take or pay for from KMCO2 at Emmons to another
carbon dioxide flooding project it had in the Permian Basin. KMCO2 was receptive
to the proposal. However, any such transfer of volumes required the approval of
Morgan Associates. In the first quarter of 2003, following Mr. Morgan's
retirement, KMCO2 approached Morgan Associates regarding such consent and the
need to compensate Morgan Associates for any volumes transferred off of the
Odessa Lateral. The two parties agreed to pursue compensating Morgan Associates
by having KMCO2 acquire the Odessa Lateral from Morgan Associates.
The estimated purchase price was arrived at as follows: Pursuant to the
transportation agreement, KMCO2 is obligated to pay to Morgan Associates a
demand fee, plus a fee on volumes transported (or a minimum transport or pay
amount in the event the fee to be received for transported volumes does not
exceed such minimum amount) through the Odessa Lateral to the Emmons and South
Cowden carbon dioxide flooding projects. Accordingly, the estimated purchase
price was arrived at by discounting back, using a commercially reasonable
discount rate, the remaining demand fees, plus the remaining minimum transport
or pay amounts under Morgan Associates' transportation contracts with KMCO2 on
the Odessa Lateral.
Mr. Michael C. Morgan abstained from all negotiations related to the Odessa
Lateral. The transaction is subject to the approval of the Boards of Directors
of our general partner and KMR. We expect the transaction to close by the end of
March 2003.
For more information on our related party transactions, see Note 12 of the
Notes to the Consolidated Financial Statements included elsewhere in this
report.
84
Item 14. Controls and Procedures.
Within the 90-day period prior to the filing of this report, we carried out
an evaluation under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14(c) under the Securities Exchange Act of 1934.
Based upon that evaluation, our Chief Executive Officer and Chief Financial
Officer concluded that the design and operation of our disclosure controls and
procedures were effective. No significant changes were made in our internal
controls or in other factors that could significantly affect these controls and
procedures subsequent to the date of their evaluation.
86
PART IV
Item 15. 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 89.
(a)(3) Exhibits
*2.1 -- Purchase and Sale Agreement between Intergen (North America),
Inc. and Kinder Morgan Energy Partners, L.P. dated December 15, 2001
(filed as Exhibit 2.1 to Kinder Morgan Energy Partners, L.P. Form
8-K, filed on March 15, 2002).
*2.2 -- First Supplement to Purchase and Sale Agreement between Intergen
(North America), Inc. and Kinder Morgan Energy Partners, L.P. dated
February 28, 2002 (filed as Exhibit 2.2 to Kindger Morgan Energy
Partners, L.P. Form 8-K, filed on March 15, 2002).
*3.1 -- Third Amended and Restated Agreement of Limited Partnership of Kinder
Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan
Energy Partners, L.P. Form 10-Q for the quarter ended June 30, 2001,
filed on August 9, 2001).
*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 (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 -- Indenture dated March 22, 2000 between Kinder Morgan Energy Partners,
L.P. and First Union National Bank, as Trustee (filed as Exhibit 4.1 to
Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4
(file no. 333-35112) filed on April 19, 2000 (the "April 2000 Form
S-4")).
*4.6 -- Form of 8% Note (contained in the Indenture filed as Exhibit 4.1 to
the April 2000 Form S-4).
*4.7 -- Indenture dated November 8, 2000 between Kinder Morgan Energy
Partners, L.P. and First Union National Bank, as Trustee (filed as
Exhibit 4.8 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2001).
*4.8 -- Form of 7.50% Notes due November 1, 2010 (contained in the Indenture
filed as Exhibit 4.8 to the Kinder Morgan Energy Partners, L.P. Form
10-K for 2001).
*4.9 -- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners
and First Union National Bank, as trustee, relating to Senior Debt
Securities (including form of Senior Debt Securities) (filed as Exhibit
4.11 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2000).
*4.10 -- Indenture dated January 2, 2001 between Kinder Morgan Energy Partners
and First Union National Bank, as trustee, relating to Subordinated
Debt Securities (including form of Subordinated Debt Securities) (filed
as Exhibit 4.12 to Kinder Morgan Energy Partners, L.P. Form 10-K for
2000).
*4.11 -- Certificate of Vice President and Chief Financial Officer of Kinder
Morgan Energy Partners, L.P. establishing the terms of the 6.75% Notes
due March 15, 2011 and the 7.40% Notes due March 15, 2031 (filed as
Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed on
March 14, 2001).
*4.12 -- Specimen of 6.75% Notes due March 15, 2011 in book-entry form (filed
as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed
on March 14, 2001).
86
*4.13 -- Specimen of 7.40% Notes due March 15, 2031 in book-entry form (filed
as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed
on March 14, 2001).
*4.14 -- Certificate of Vice President and Chief Financial Officer of Kinder
Morgan Energy Partners, L.P. establishing the terms of the 7.125% Notes
due March 15, 2012 and the 7.750% Notes due March 15, 2032 (filed as
Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
quarter ended March 31, 2002, filed on May 10, 2002).
*4.15 -- Specimen of 7.125% Notes due March 15, 2012 in book-entry form (filed
as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
quarter ended March 31, 2002, filed on May 10, 2002).
*4.16 -- Specimen of 7.750% Notes due March 15, 2032 in book-entry form (filed
as Exhibit 4.3 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
quarter ended March 31, 2002, filed on May 10, 2002).
*4.17 -- Form of Indenture dated August 19, 2002 between Kinder Morgan Energy
Partners, L.P. and Wachovia Bank, National Association, as Trustee
(filed as Exhibit 4.1 to the Kinder Morgan Energy Partners, L.P.'s
Registration Statement on Form S-4 (Registration No. 333-100346) filed
on October 4, 2002 (the "October 4, 2002 Form S-4")).
*4.18 -- Form of First Supplemental Indenture to Indenture dated August 19,
2002, dated August 23, 2002 between Kinder Morgan Energy Partners, L.P.
and Wachovia Bank, National Association, as Trustee (filed as Exhibit
4.2 to the October 4, 2002 Form S-4).
*4.19 -- Form of 5.35% Note and Form of 7.30% Note (contained in the Indenture
filed as Exhibit 4.1 to the October 4, 2002 Form S-4).
4.20 -- Certain instruments with respect to long-term debt of Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries which relate to
debt that does not exceed 10% of the total assets of Kinder Morgan
Energy Partners, L.P. and its consolidated subsidiaries are omitted
pursuant to Item 601(b) (4) (iii) (A) of Regulation S-K, 17 C.F.R.
sec.229.601. Kinder Morgan Energy Partners, L.P. hereby agrees to
furnish supplementally to the Securities and Exchange Commission a copy
of each such instrument upon request.
*4.21 -- Form of Senior Indenture between Kinder Morgan Energy Partners, L.P.
and Wachovia Bank, National Association (filed as Exhibit 4.2 to the
Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-3
(Registration No. 333-102961) filed on February 4, 2003 (the "February
4, 2003 Form S-3")).
*4.22 -- Form of Senior Note of Kinder Morgan Energy Partners, L.P. (included
in the Form of Senior Indenture filed as Exhibit 4.2 to the February 4,
2003 Form S-3).
*4.23 -- Form of Subordinated Indenture between Kinder Morgan Energy Partners,
L.P. and Wachovia Bank, National Association (filed as Exhibit 4.4 to
the February 4, 2003 Form S-3).
*4.24 -- Form of Subordinated Note of Kinder Morgan Energy Partners, L.P.
(included in the Form of Subordinated Indenture filed as Exhibit 4.4 to
the February 4, 2003 Form S-3).
*10.1 -- Kinder Morgan Energy Partners, L.P. Common Unit Option Plan
(filed as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P.
1997 Form 10-K).
*10.2 -- Kinder Morgan Energy Partners, L.P. Executive Compensation Plan
(filed as Exhibit 10 to the Kinder Morgan Energy Partners, L.P. Form
10-Q for the quarter ended June 30, 1997).
*10.3 -- Employment Agreement dated April 20, 2000, by and among Kinder
Morgan, Inc., Kinder Morgan G.P., Inc. and Michael C. Morgan (filed
as Exhibit 10(b) to Kinder Morgan, Inc.'s Form 10-Q for the quarter
ended March 31, 2000).
*10.4 -- Delegation of Control Agreement among Kinder Morgan Management,
LLC, Kinder Morgan G.P., Inc. and Kinder Morgan Energy Partners, L.P.
and its operating partnerships (filed as Exhibit 10.1 to the Kinder
Morgan Energy Partners, L.P. Form 10-Q for the quarter ended June 30,
2001).
*10.5 -- Retention Agreement dated January 17, 2002, by and between Kinder
Morgan, Inc. and C. Park Shaper (filed as Exhibit 10(l) to Kinder
Morgan, Inc.'s Annual Report on Form 10-K for the period ending
December 31, 2001).
10.6 -- 364-day Credit Agreement dated as of October 15, 2002 among Kinder
Morgan Energy Partners, L.P., the lenders party thereto and Wachovia
Bank, National Association as Administrative Agent.
10.7 -- Modification of 364-day Credit Agreement Commitment dated effective
as of December 12, 2002 among Kinder Morgan Energy Partners, L.P.,
Credit Suisse First Boston and Wachovia Bank, National Association, as
Administrative Agent.
11.1 -- Statement re: computation of per share earnings.
21.1 -- List of Subsidiaries.
23.1 -- Consent of PricewaterhouseCoopers LLP.
99.1 -- Chief Executive Officer Certification.
87
99.2 -- Chief Financial Officer Certification.
- ----------
* Asterisk indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith, except as noted otherwise.
(b)Reports on Form 8-K
Current report dated October 28, 2002 on Form 8-K was filed on October 28,
2002, pursuant to Item 9 of that form. We provided notice that we, along with
Kinder Morgan, Inc., a subsidiary of which serves as our general partner, and
Kinder Morgan Management, LLC, a subsidiary of our general partner that manages
and controls our business and affairs, intended to make presentations during the
week of October 28, 2002 at various meetings with investors, analysts and others
to discuss the third quarter 2002 and year-to-date third quarter 2002 financial
results, business plans and objectives of us, Kinder Morgan, Inc. and Kinder
Morgan Management, LLC. Notice was also given that interested parties would be
able to view the materials presented at the meetings by visiting Kinder Morgan,
Inc.'s website at:
http://www.kindermorgan.com/investor_relations/presentations/.
88
INDEX TO FINANCIAL STATEMENTS
Page
----
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Accountants................................... 90
Consolidated Statements of Income for the years ended
December 31, 2002, 2001, and 2000.................................. 91
Consolidated Statements of Comprehensive Income for the years
ended December 31, 2002, 2001, and 2000............................ 92
Consolidated Balance Sheets as of December 31, 2002 and 2001....... 93
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001, and 2000.................................. 94
Consolidated Statements of Partners' Capital for the years ended
December 31, 2002, 2001, and 2000.................................. 95
Notes to Consolidated Financial Statements.......................... 96
89
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of
Kinder Morgan Energy Partners, L.P.
In our opinion, the consolidated financial statements listed in the accompanying
index present fairly, in all material respects, the financial position of Kinder
Morgan Energy Partners, L.P. and its subsidiaries (the Partnership) at December
31, 2002 and 2001, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America. 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 of America, 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 our opinion.
As discussed in Note 8 to the consolidated financial statements, the Partnership
changed its method of accounting for goodwill and other intangible assets
effective January 1, 2002.
As discussed in Note 14 to the consolidated financial statements, the
Partnership changed its method of accounting for derivative instruments and
hedging activities effective January 1, 2001.
PricewaterhouseCoopers LLP
Houston, Texas
February 21, 2003
90
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
2002 2001 2000
------- -------- --------
(In thousands except per
unit amounts)
Revenues
Natural gas sales................. $2,740,518 $1,627,037 $ 10,196
Services.......................... 1,272,640 1,161,643 726,462
Product sales and other........... 223,899 157,996 79,784
---------- ---------- ----------
4,237,057 2,946,676 816,442
---------- ---------- ----------
Costs and Expenses
Gas purchases and other costs of
sales........................... 2,704,295 1,657,689 124,641
Operations and maintenance........ 379,827 356,654 164,379
Fuel and power.................... 86,413 73,188 43,216
Depreciation and amortization..... 172,041 142,077 82,630
General and administrative........ 118,857 109,293 64,427
Taxes, other than income taxes.... 51,326 43,947 21,588
---------- --------- ----------
3,512,759 2,382,848 500,881
---------- --------- ----------
Operating Income.................... 724,298 563,828 315,561
Other Income (Expense)
Earnings from equity investments.. 89,258 84,834 71,603
Amortization of excess cost of
equity investments.............. (5,575) (9,011) (8,195)
Interest, net..................... (176,460) (171,457) (93,284)
Other, net........................ 1,698 1,962 14,584
Minority Interest................... (9,559) (11,440) (7,987)
--------- ---------- -----------
Income Before Income Taxes.......... 623,660 458,716 292,282
Income Taxes........................ 15,283 16,373 13,934
--------- ---------- -----------
Net Income.......................... $608,377 $442,343 $278,348
========= ========= ==========
Calculation of Limited Partners'
Interest in Net Income:
Net Income.......................... $608,377 $442,343 $278,348
Less: General Partner's interest in
Net Income.......................... (270,816) (202,095) (109,470)
--------- --------- ---------
Limited Partners' interest in Net
Income.............................. $337,561 $240,248 $168,878
========= ========= =========
Basic Limited Partners' Net Income
per Unit:........................... $ 1.96 $ 1.56 $ 1.34
========= ========= =========
Diluted Limited Partners' Net Income
per Unit:........................... $ 1.96 $ 1.56 $ 1.34
========= ========= =========
Weighted Average Number of Units used
in Computation of Limited Partners'
Net Income per Unit:
Basic............................. 172,017 153,901 126,212
========= ========= =========
Diluted........................... 172,186 154,110 126,300
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
91
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
2002 2001 2000
------- ------- ------
(In thousands)
Net Income............................... $608,377 $442,343 $ 278,348
Cumulative effect transition adjustment.. -- (22,797) --
Change in fair value of derivatives used
for hedging purposes................. (116,560) 35,162 --
Reclassification of change in fair value
of derivatives to net income......... 7,477 51,461 --
--------- --------- ---------
Comprehensive Income..................... $499,294 $ 506,169 $ 278,348
======== ========== =========
The accompanying notes are an integral part of these consolidated financial
statements.
92
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------------
2002 2001
--------- ----------
(Dollars in thousands)
ASSETS
Current Assets
Cash and cash equivalents............. $ 41,088 $ 62,802
Accounts and notes receivable
Trade.............................. 457,583 215,860
Related parties.................... 17,907 52,607
Inventories
Products........................... 4,722 2,197
Materials and supplies............. 7,094 6,212
Gas imbalances........................ 25,488 15,265
Gas in underground storage............ 11,029 18,214
Other current assets.................. 104,479 194,886
----------- ----------
669,390 568,043
------- ----------
Property, Plant and Equipment, net...... 6,244,242 5,082,612
Investments............................. 311,044 440,518
Notes receivable........................ 3,823 3,095
Goodwill................................ 856,940 546,734
Other intangibles, net.................. 17,324 16,663
Deferred charges and other assets....... 250,813 75,001
---------- -----------
TOTAL ASSETS............................ $8,353,576 $6,732,666
========== ===========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade................................. $ 373,368 $ 111,853
Related parties....................... 43,742 9,235
Current portion of long-term debt........ - 560,219
Accrued interest......................... 52,500 34,099
Deferred revenues........................ 4,914 2,786
Gas imbalances........................... 40,092 34,660
Accrued other liabilities................ 298,711 209,852
---------- -----------
813,327 962,704
---------- -----------
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding........................... 3,659,533 2,237,015
Market value of interest rate swaps 166,956 (5,441)
---------- -----------
3,826,489 2,231,574
Deferred revenues........................ 25,740 29,110
Deferred income taxes.................... 30,262 38,544
Other long-term liabilities and
deferred credits....................... 199,796 246,464
---------- ----------
4,082,287 2,545,692
---------- ----------
Commitments and Contingencies (Notes 13
and 16)
Minority Interest.......................... 42,033 65,236
---------- ----------
Partners' Capital
Common Units (129,943,218 and 129,855,018
units issued and outstanding at
December 31, 2002 and 2001,
respectively)............................ 1,844,553 1,894,677
Class B Units (5,313,400 and 5,313,400
units issued and outstanding at
December 31, 2002 and 2001,
respectively)............................. 123,635 125,750
i-Units (45,654,048 and 30,636,363
units issued and outstanding at
December 31, 2002 and 2001,
respectively)............................. 1,420,898 1,020,153
General Partner........................... 72,100 54,628
Accumulated other comprehensive income.... (45,257) 63,826
----------- ----------
3,415,929 3,159,034
TOTAL LIABILITIES AND PARTNERS' CAPITAL. $8,353,576 $6,732,666
=========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
93
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
----------------------------------
2002 2001 2000
-------- -------- --------
(In thousands)
Cash Flows From Operating Activities
Net income............................ $ 608,377 $ 442,343 $ 278,348
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization....... 172,041 142,077 82,630
Amortization of excess cost of
equity investments................. 5,575 9,011 8,195
Earnings from equity investments.... (89,258) (84,834) (71,603)
Distributions from equity investments 77,735 68,832 47,512
Changes in components of working
capital:
Accounts receivable............... (177,240) 174,098 6,791
Other current assets.............. (7,583) 22,033 (6,872)
Inventories....................... (1,713) 22,535 (1,376)
Accounts payable.................. 288,712 (183,179) (8,374)
Accrued liabilities............... 26,232 (47,692) 26,479
Accrued taxes..................... 2,379 8,679 (1,302)
Rate refunds settlement............. (100) (100) (52,467)
Other, net.......................... (35,462) 7,358 (6,394)
----------- ----------- -----------
Net Cash Provided by Operating
Activities........................... 869,695 581,161 301,567
----------- ----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets.............. (908,511) (1,523,454) (1,008,648)
Additions to property, plant and
equipment for expansion and
maintenance projects............... (542,235) (295,088) (125,523)
Sale of investments, property, plant
and equipment, net of removal
costs.............................. 13,912 9,043 13,412
Acquisitions of investments......... (1,785) -- (79,388)
Contributions to equity investments. (10,841) (2,797) (375)
Other............................... (1,420) (6,597) 2,956
----------- ----------- -----------
Net Cash Used in Investing Activities. (1,450,880) (1,818,893) (1,197,566)
----------- ----------- -----------
Cash Flows From Financing Activities
Issuance of debt.................... 3,803,414 4,053,734 2,928,304
Payment of debt..................... (2,985,322) (3,324,161) (1,894,904)
Loans to related party.............. -- (17,100) --
Debt issue costs.................... (17,006) (8,008) (4,298)
Proceeds from issuance of common
units.............................. 1,586 4,113 171,433
Proceeds from issuance of i-units... 331,159 996,869 --
Contributions from General Partner.. 3,353 11,716 7,434
Distributions to partners:
Common units...................... (306,590) (268,644) (194,691)
Class B units..................... (12,540) (8,501) --
General Partner................... (253,344) (181,198) (91,366)
Minority interest................. (9,668) (14,827) (7,533)
Other, net.......................... 4,429 (2,778) 887
----------- ----------- -----------
Net Cash Provided by Financing
Activities........................... 559,471 1,241,215 915,266
----------- ----------- -----------
Increase (Decrease) in Cash and Cash
Equivalents.......................... (21,714) 3,483 19,267
Cash and Cash Equivalents, beginning
of period............................ 62,802 59,319 40,052
----------- ----------- -----------
Cash and Cash Equivalents, end of
period............................... $41,088 $62,802 $59,319
=========== =========== ===========
Noncash Investing and Financing
Activities:
Assets acquired by the issuance of $ -- $ -- $ 179,623
units..............................
Assets acquired by the assumption of
liabilities........................ 213,861 293,871 333,301
Supplemental disclosures of
cash flow information:
Cash paid during the year for
Interest (net of capitalized
interest).......................... 161,840 165,357 88,821
Income taxes........................ 1,464 2,168 1,806
The accompanying notes are an integral part of
these consolidated financial statements.
94
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
2002 2001 2000
----------------------- --------------------- ------------------------
Units Amount Units Amount Units Amount
--------- ---------- --------- ---------- --------- ----------
(Dollars in thousands)
Common Units:
Beginning Balance.................. 129,855,018 $ 1,894,677 129,716,218 $ 1,957,357 118,274,274 $ 1,759,142
Net income......................... -- 254,934 -- 203,559 -- 168,878
Units issued as consideration in the
acquisition of assets or
Businesses....................... -- -- -- -- 2,428,344 53,050
Units issued for cash.............. 88,200 1,532 138,800 2,405 9,013,600 170,978
Distributions...................... -- (306,590) -- (268,644) -- (194,691)
Ending Balance..................... 129,943,218 1,844,553 129,855,018 1,894,677 129,716,218 1,957,357
Class B Units:
Beginning Balance.................. 5,313,400 125,750 5,313,400 125,961 -- --
Net income......................... -- 10,427 -- 8,335 -- --
Units issued as consideration in the
acquisition of assets or
Businesses....................... -- -- -- -- 5,313,400 125,961
Units issued for cash.............. -- (2) -- (44) -- --
Distributions...................... -- (12,540) -- (8,502) -- --
Ending Balance..................... 5,313,400 123,635 5,313,400 125,750 5,313,400 125,961
i-Units:
Beginning Balance.................. 30,636,363 1,020,153 -- -- -- --
Net income......................... -- 72,200 -- 28,354 -- --
Units issued for cash.............. 12,478,900 328,545 29,750,000 991,799 -- --
Distributions...................... 2,538,785 -- 886,363 -- -- --
Ending Balance..................... 45,654,048 1,420,898 30,636,363 1,020,153 -- --
General Partner:
Beginning Balance.................. -- 54,628 -- 33,749 -- 15,656
Net income......................... -- 270,816 -- 202,095 -- 109,470
Units issued as consideration in the
acquisition of assets or
Businesses....................... -- -- -- -- -- (11)
Units issued for cash.............. -- -- -- (18) -- --
Distributions...................... -- (253,344) -- (181,198) -- (91,366)
Ending Balance..................... -- 72,100 -- 54,628 -- 33,749
Accumulated other comprehensive income:
Beginning Balance.................. -- 63,826 -- -- -- --
Cumulative effect transition adj... -- -- -- (22,797) -- --
Change in fair value of derivatives
used for hedging purposes........ -- (116,560) -- 35,162 -- --
Reclassification of change in fair
value of derivatives to net
Income........................... -- 7,477 -- 51,461 -- --
Ending Balance..................... -- (45,257) -- 63,826 -- --
Total Partners' Capital.............. 180,910,666 $ 3,415,929 165,804,781 $ 3,159,034 135,029,618 $ 2,117,067
The accompanying notes are an integral part of these consolidated financial statements.
95
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
General
Kinder Morgan Energy Partners, L.P., the "Partnership", is a Delaware limited
partnership formed in August 1992. We own and manage a diversified portfolio of
energy transportation and storage assets. We provide services to our customers
and create value for our unitholders primarily through the following activities:
o transporting, storing and processing refined petroleum products;
o transporting, storing and selling natural gas;
o transporting and selling carbon dioxide for use in, and selling crude
oil produced from, enhanced oil recovery operations; and
o transloading, storing and delivering a wide variety of bulk, petroleum and
petrochemical products at terminal facilities located across the United
States.
We focus on providing fee-based services to customers, avoiding commodity
price risks and taking advantage of the tax benefits of a limited partnership
structure. We trade on the New York Stock Exchange under the symbol "KMP" and
presently conduct our business through four reportable business segments:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o Terminals.
For more information on our reportable business segments, see Note 15.
Kinder Morgan, Inc.
Kinder Morgan, Inc., a Kansas corporation, is the sole stockholder of
Kinder Morgan (Delaware), Inc. Kinder Morgan (Delaware), Inc., a Delaware
corporation, is the sole stockholder of our general partner, Kinder Morgan
G.P., Inc. Kinder Morgan, Inc. is referred to as "KMI" in this report. KMI
trades on the New York Stock Exchange under the symbol "KMI" and is one of
the largest energy transportation and storage companies in the United States,
operating, either for itself or on our behalf, more than 30,000 miles of
natural gas and products pipelines. It also has significant retail
distribution, electric generation and terminal assets. At December 31, 2002,
KMI and its consolidated subsidiaries owned, through its general and limited
partner interests, an approximate 19.2% interest in us. As a result of
owning this significant interest in us, KMI receives a substantial portion of
its earnings from returns on this investment.
Kinder Morgan Management, LLC
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. It is referred to as "KMR" in this report. Our
general partner owns all of KMR's voting securities and, pursuant to a
delegation of control agreement, our general partner delegated to KMR, to the
fullest extent permitted under Delaware law and our partnership agreement, all
of its power and authority to manage and control our business and affairs,
except that KMR cannot take certain specified actions without the approval of
our general partner. Under
96
the delegation of control agreement, KMR manages and controls our business
and affairs and the business and affairs of our operating limited partnerships
and their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, KMR's activities are limited to being a limited partner in,
and managing and controlling the business and affairs of us, our operating
limited partnerships and their subsidiaries.
In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares to the public in
an initial public offering. KMR's shares were initially issued at a price of
$35.21 per share, less commissions and underwriting expenses, and the shares
trade on the New York Stock Exchange under the symbol "KMR". Substantially all
of the net proceeds from the offering were used to buy i-units from us. The
i-units are a separate class of limited partner interests in us and are issued
only to KMR. When it purchased i-units from us, KMR became a limited partner in
us. At December 31, 2002, KMR and its consolidated subsidiary owned
approximately 25.2% of our outstanding limited partner units. KMR receives all
of its earnings from returns on this investment.
2. Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements include our accounts and those of our
majority-owned and controlled subsidiaries and our operating partnerships. All
significant intercompany items have been eliminated in consolidation. Certain
amounts from prior years have been reclassified to conform to the current
presentation.
Our consolidated financial statements were prepared in accordance with
accounting principles generally accepted in the United States. Certain amounts
included in or affecting our financial statements and related disclosures must
be estimated, requiring us to make certain assumptions with respect to values or
conditions which cannot be known with certainty at the time the financial
statements are prepared.
The preparation of our financial statements in conformity with generally
accepted accounting principles requires our management to make estimates and
assumptions that affect:
o the amounts we report for assets and liabilities;
o our disclosure of contingent assets and liabilities at the date of the
financial statements; and
o the amounts we report for revenues and expenses during the reporting
period.
Therefore, the reported amounts of our assets and liabilities, revenues and
expenses and associated disclosures with respect to contingent assets and
obligations are necessarily affected by these estimates. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with experts and other methods we consider reasonable in the particular
circumstances. Nevertheless, actual results may differ significantly from our
estimates. Any effects on our business, financial position or results of
operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.
In preparing our financial statements and related disclosures, we must use
estimates in determining the economic useful lives of our assets, the fair
values used to determine possible asset impairment charges, provisions for
uncollectible accounts receivable, exposures under contractual indemnifications
and various other recorded or disclosed amounts. However, we believe that
certain accounting policies are of more significance in our financial statement
preparation process than others.
Cash Equivalents
We define cash equivalents as all highly liquid short-term investments with
original maturities of three months or less.
97
Accounts Receivables
Our policy for determining an appropriate allowance for doubtful accounts
varies according to the type of business being conducted and the customers being
served. An allowance for doubtful accounts is charged to expense monthly,
generally using a percentage of revenue or receivables, based on a historical
analysis of uncollected amounts, adjusted as necessary for changed circumstances
and customer-specific information. When specific receivables are determined to
be uncollectible, the reserve and receivable are relieved. The following tables
show the balance in the allowance for doubtful accounts and activity for the
years ended December 31, 2002, 2001 and 2000.
Valuation and Qualifying Accounts
(In thousands)
Year Ended December 31, 2002
----------------------------------------------------------------
Additions Additions
Balance at charged to charged to Balance at
beginning costs and other end of
of Period expenses accounts(1) Deductions(2) period
---------- ---------- ----------- ------------- ----------
Allowance for
Doubtful
Accounts..... $ 7,556 $ 822 $ 4 $ (290) $ 8,092
- ----------
(1)Additions represent the allowance recognized when we acquired IC Terminal
Holdings Company and Consolidated Subsidiaries.
(2)Deductions represent the write-off of receivables and the revaluation of the
allowance account.
Year Ended December 31, 2001
----------------------------------------------------------------
Additions Additions
Balance at charged to charged to Balance at
beginning costs and other end of
of Period expenses accounts(1) Deductions(2) period
---------- ---------- ----------- ------------- ----------
Allowance for
Doubtful
Accounts..... $ 4,151 $ 3,641 $ 1,362 $(1,598) $ 7,556
- ----------
(1)Additions represent the allowance recognized when we acquired CALNEV Pipe
Line LLC and Kinder Morgan Liquids Terminals LLC, as well as transfers from
other accounts.
(2)Deductions represent the write-off of receivables and the revaluation of the
allowance account.
Year Ended December 31, 2000
----------------------------------------------------------------
Additions Additions
Balance at charged to charged to Balance at
beginning costs and other end of
of Period expenses accounts(1) Deductions(2) period
---------- ---------- ----------- ------------- ----------
Allowance for
Doubtful
Accounts..... $ 6,717 $ -- $ 2,718 $(5,284) $ 4,151
- ----------
(1)Additions represent the allowance recognized when we acquired our Natural
Gas Pipelines.
(2)Deductions represent the write-off of receivables and the revaluation of the
allowance account.
In addition, at December 31, 2002, our balance of Accrued other current
liabilities in the accompanying consolidated balance sheet included
approximately $38.7 million related to customer prepayments.
Inventories
Our inventories of products consist of natural gas liquids, refined petroleum
products, natural gas, carbon dioxide and coal. We report these assets at the
lower of weighted-average cost or market. We report materials and supplies at
the lower of cost or market.
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Property, Plant and Equipment
We state property, plant and equipment at its acquisition cost. We expense
costs for maintenance and repairs in the period incurred. The cost of property,
plant and equipment sold or retired and the related depreciation are removed
from our balance sheet in the period of sale or disposition. We compute
depreciation using the straight-line method based on estimated economic lives.
Generally, we apply composite depreciation rates to functional groups of
property having similar economic characteristics. The rates range from 2.0% to
12.5%, excluding certain short-lived assets such as vehicles.
Our exploration and production activities are accounted for under the
successful efforts method of accounting. Under this method, costs of productive
wells and development dry holes, both tangible and intangible, as well as
productive acreage are capitalized and amortized on the unit-of-production
method. Proved developed reserves are used in computing units-of-production
rates for drilling and development costs, and total proved reserves are used for
depletion of leasehold costs. The basis for units-of-production rate
determination is by field. We charge the original cost of property sold or
retired to accumulated depreciation and amortization, net of salvage and cost of
removal. We do not include retirement gain or loss in income except in the case
of significant retirements or sales.
We review for the impairment of long-lived assets whenever events or
changes in circumstances indicate that our carrying amount of an asset may not
be recoverable. We would recognize an impairment loss when estimated future cash
flows expected to result from our use of the asset and its eventual disposition
is less than its carrying amount.
On January 1, 2002, we adopted Statement of Financial Accounting Standards
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" and we
now evaluate the impairment of our long-lived assets in accordance with this
Statement. This statement retains the requirements of SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of", however, this statement requires that long-lived assets that are to be
disposed of by sale be measured at the lower of book value or fair value less
the cost to sell it. Furthermore, the scope of discontinued operations is
expanded to include all components of an entity with operations of the entity in
a disposal transaction. The adoption of SFAS No. 144 has not had an impact on
our business, financial position or results of operations. In practice, the
composite life may not be determined with a high degree of precision, and hence
the composite life may not reflect the weighted average of the expected useful
lives of the asset's principal components.
Equity Method of Accounting
We account for investments in greater than 20% owned affiliates, which we do
not control, by the equity method of accounting. Under this method, an
investment is carried at our acquisition cost, plus our equity in undistributed
earnings or losses since acquisition.
Excess of Cost Over Fair Value
Effective January 1, 2002, we adopted SFAS No. 141, "Business Combinations"
and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141
supercedes Accounting Principles Board Opinion No. 16 and requires that all
transactions fitting the description of a business combination be accounted for
using the purchase method and prohibits the use of the pooling of interests for
all business combinations initiated after June 30, 2001. The Statement also
modifies the accounting for the excess of cost over the fair value of net assets
acquired as well as intangible assets acquired in a business combination. The
provisions of this Statement apply to all business combinations initiated after
June 30, 2001, and all business combinations accounted for by the purchase
method that are completed after July 1, 2001. In addition, this Statement
requires disclosure of the primary reasons for a business combination and the
allocation of the purchase price paid to the assets acquired and liabilities
assumed by major balance sheet caption.
SFAS No. 142 supercedes Accounting Principles Board Opinion No. 17 and
requires that goodwill no longer be amortized, but instead should be tested, at
least on an annual basis, for impairment. A benchmark assessment of potential
impairment must also be completed within six months of adopting SFAS No. 142.
After the first six
99
months, goodwill will be tested for impairment annually or as changes in
circumstances require. SFAS No. 142 applies to any goodwill acquired in a
business combination completed after June 30, 2001. Other intangible assets are
to be amortized over their useful life and reviewed for impairment in accordance
with the provisions of SFAS No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets". An intangible asset with an indefinite useful life can no
longer be amortized until its useful life becomes determinable. In addition,
this Statement requires disclosure of information about goodwill and other
intangible assets in the years subsequent to their acquisition that was not
previously required. Required disclosures include information about the changes
in the carrying amount of goodwill from period to period and the carrying amount
of intangible assets by major intangible asset class.
These accounting pronouncements required that we prospectively cease
amortization of all intangible assets having indefinite useful economic lives.
Such assets, including goodwill, are not to be amortized until their lives are
determined to be finite. In addition, a recognized intangible asset with an
indefinite useful life and goodwill should be tested for impairment annually or
on an interim basis if events or circumstances indicate that the fair value of
the asset has decreased below its carrying value. We completed this initial
transition impairment test in June 2002 and determined that our goodwill and
such intangible assets were not impaired as of January 1, 2002.
Prior to January 1, 2002, we amortized the excess cost over the underlying
net asset book value of our equity investments using the straight-line method
over the estimated remaining useful lives of the assets in accordance with
Accounting Principles Board Opinion No. 16 "Business Combinations". We amortized
this excess for undervalued depreciable assets over a period not to exceed 50
years and for intangible assets over a period not to exceed 40 years. For our
consolidated affiliates, we reported amortization of excess cost over fair value
of net assets (goodwill) as amortization expense in our accompanying
consolidated statements of income. For our investments accounted for under the
equity method, we reported amortization of excess cost on investments as
amortization of excess cost of equity investments in our accompanying
consolidated statements of income.
Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was approximately $716.6 million as of December 31, 2002
and $546.7 million as of December 31, 2001. Such amounts are included within
goodwill on our accompanying consolidated balance sheets. Our total unamortized
excess cost over underlying fair value of net assets accounted for under the
equity method was approximately $140.3 million as of December 31, 2002 and
December 31, 2001. Per our adoption of SFAS No. 142, the December 31, 2002
balance is included within goodwill on our accompanying consolidated balance
sheet and the December 31, 2001 balance is included within investments on our
accompanying consolidated balance sheet.
In addition to our annual impairment test, we periodically reevaluate the
amount at which we carry the excess of cost over fair value of net assets of
businesses we acquired, as well as the amortization period for such assets, to
determine whether current events or circumstances warrant adjustments to our
carrying value and/or revised estimates of useful lives in accordance with
Accounting Principles Board Opinion No. 18 "The Equity Method of Accounting for
Investments in Common Stock". At December 31, 2002, we believed no such
impairment had occurred and no reduction in estimated useful lives was
warranted.
For more information on our acquisitions, see Note 3. For more information on
our investments, see Note 7.
Revenue Recognition
We recognize revenues for our pipeline operations based on delivery of actual
volume transported or minimum obligations under take-or-pay contracts. We
recognize bulk terminal transfer service revenues based on volumes loaded. We
recognize liquids terminal tank rental revenue ratably over the contract period.
We recognize liquids terminal through-put revenue based on volumes received or
volumes delivered depending on the customer contract. Liquids terminal minimum
take-or-pay revenue is recognized at the end of the contract year or contract
term depending on the terms of the contract. We recognize transmix processing
revenues based on volumes processed or sold, and if applicable, when title has
passed. We recognize energy-related product sales revenues based on delivered
quantities of product.
Capitalized Interest
We capitalize interest expense during the new construction or upgrade of
qualifying assets. Interest expense
100
capitalized in 2002, 2001 and 2000 was $5.8 million, $3.1 million and $2.5
million, respectively.
Unit-Based Compensation
SFAS No. 123, "Accounting for Stock-Based Compensation", encourages, but does
not require, entities to adopt the fair value method of accounting for stock or
unit-based compensation plans. As allowed under SFAS No. 123, we apply
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," and related interpretations in accounting for common unit options
granted under our common unit option plan. Accordingly, compensation expense is
not recognized for common unit options unless the options are granted at an
exercise price lower than the market price on the grant date. Pro forma
information regarding changes in net income and per unit data, if the accounting
prescribed by SFAS No. 123 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. For more information on
unit-based compensation, see Note 13.
Environmental Matters
We expense or capitalize, as appropriate, environmental expenditures that
relate to current operations. We expense expenditures that relate to an existing
condition caused by past operations, which do not contribute to current or
future revenue generation. We do not discount environmental liabilities to a net
present value and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, our recording of these accruals coincides with our
completion of a feasibility study or our commitment to a formal plan of action.
We utilize both internal staff and external experts to assist us in
identifying environmental issues and in estimating the costs and timing of
remediation efforts. Often, as the remediation evaluation and effort progresses,
additional information is obtained, requiring revisions to estimated costs.
These revisions are reflected in our income in the period in which they are
reasonably determinable. In December 2002, after a thorough review of any
potential environmental issues that could impact our assets or operations and of
our need to correctly record all related environmental contingencies, we
recognized a $0.3 million non-recurring reduction in environmental expense and
in our overall accrued environmental liability, and we included this amount
within Other, net in the accompanying Consolidated Statement of Income for 2002.
The $0.3 million income item resulted from the necessity of properly adjusting
and realigning our environmental expenses and accrued liabilities between our
reportable business segments, specifically between our Products Pipelines and
our Terminals business segments. The $0.3 million reduction in environmental
expense resulted in a $15.7 million non-recurring loss to our Products Pipelines
business segment and a $16.0 million non-recurring gain to our Terminals
business segment.
Legal
We are subject to litigation and regulatory proceedings as the result of our
business operations and transactions. We utilize both internal and external
counsel in evaluating our potential exposure to adverse outcomes from orders,
judgments or settlements. To the extent that actual outcomes differ from our
estimates, or additional facts and circumstances cause us to revise our
estimates, our earnings will be affected. In general, we expense legal costs as
incurred. When we identify specific litigation that is expected to continue for
a significant period of time and require substantial expenditures, we identify a
range of possible costs expected to be required to litigate the matter to a
conclusion or reach an acceptable settlement. If no amount within this range is
a better estimate than any other amount, we record a liability equal to the low
end of the range. Any such liability recorded is revised as better information
becomes available.
Pension
We are required to make assumptions and estimates regarding the accuracy of
our pension investment returns. Specifically, these include:
o our investment return assumptions;
o the significant estimates on which those assumptions are based; and
101
o the potential impact that changes in those assumptions could have on our
reported results of operations and cash flows.
We consider our overall pension liability exposure to be minimal in relation
to the value of our total consolidated assets and net income. However, in
accordance with SFAS No. 87, "Employers' Accounting for Pensions", a component
of our net periodic pension cost includes the return on pension plan assets,
including both realized and unrealized changes in the fair market value of
pension plan assets.
A source of volatility in pension costs comes from this inclusion of
unrealized or market value gains and losses on pension assets as part of the
components recognized as pension expense. To prevent wide swings in pension
expense from occurring because of one-time changes in fund values, SFAS No. 87
allows for the use of an actuarial computed "expected value" of plan asset gains
or losses to be the actual element included in the determination of pension
expense. The actuarial derived expected return on pension assets not only
employs an expected rate of return on plan assets, but also assumes a
market-related value of plan assets, which is a calculated value that recognizes
changes in fair value in a systematic and rational manner over not more than
five years. As required, we disclose the weighted average expected long-run rate
of return on our plan assets, which is used to calculate our plan assets'
expected return. For more information on our pension disclosures, see Note 10.
Gas Imbalances and Gas Purchase Contracts
We value gas imbalances due to or due from interconnecting pipelines at the
lower of cost or market. Gas imbalances represent the difference between
customer nominations and actual gas receipts from and gas deliveries to our
interconnecting pipelines under various Operational Balancing Agreements.
Natural gas imbalances are settled in cash or made up in-kind subject to the
pipelines' various terms.
Minority Interest
As of December 31, 2002, minority interest consists of the following:
o the 1.0101% general partner interest in our operating partnerships;
o the 0.5% special limited partner interest in SFPP, L.P.;
o the 50% interest in Globalplex Partners, a Louisiana joint venture owned
50% and controlled by Kinder Morgan Bulk Terminals, Inc.;
o the approximate 32% interest in MidTex Gas Storage Company, L.L.P., a Texas
limited liability partnership owned approximately 68% and controlled by
Kinder Morgan Texas Pipeline L.P. and its consolidated subsidiaries; and
o the 33 1/3% interest in International Marine Terminals, a Louisiana
partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P.
"C".
Income Taxes
We are not a taxable entity for federal income tax purposes. As such, we do
not directly pay federal income tax. Our taxable income or loss, which may vary
substantially from the net income or net loss we report in our consolidated
statement of income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of our net assets for financial
and tax reporting purposes cannot be readily determined as we do not have access
to information about each partner's tax attributes in the Partnership.
Some of our corporate subsidiaries and corporations in which we have an
equity investment do pay federal and state income taxes. Deferred income tax
assets and liabilities for certain operations conducted through corporations are
recognized for temporary differences between the assets and liabilities for
financial reporting and tax purposes. Changes in tax legislation are included in
the relevant computations in the period in which such changes are
102
effective. Deferred tax assets are reduced by a valuation allowance for the
amount of any tax benefit not expected to be realized.
Comprehensive Income
Statement of Financial Accounting Standards No. 130, "Accounting for
Comprehensive Income", requires that enterprises report a total for
comprehensive income. For each of the years ended December 31, 2002 and 2001,
the only difference between our net income and our comprehensive income was the
unrealized gain or loss on derivatives utilized for hedging purposes. There was
no difference between our net income and our comprehensive income for the year
ended December 31, 2000. For more information on our risk management activities,
see Note 14.
Net Income Per Unit
We compute Basic Limited Partners' Net Income per Unit by dividing Limited
Partners' interest in Net Income by the weighted average number of units
outstanding during the period. Diluted Limited Partners' Net Income per Unit
reflects the potential dilution, by application of the treasury stock method,
that could occur if options to issue units were exercised, which would result in
the issuance of additional units that would then share in our net income.
Two-for-one Common Unit Split
On July 18, 2001, KMR, the delegate of our general partner, approved a
two-for-one unit split of its outstanding shares and our outstanding common
units representing limited partner interests in us. The common unit split
entitled our common unitholders to one additional common unit for each common
unit held. Our partnership agreement provides that when a split of our common
units occurs, a unit split on our Class B units and our i-units will be effected
to adjust proportionately the number of our Class B units and i-units. The
issuance and mailing of split units occurred on August 31, 2001 to unitholders
of record on August 17, 2001. All references to the number of KMR shares, the
number of our limited partner units and per unit amounts in our consolidated
financial statements and related notes, have been restated to reflect the effect
of the split for all periods presented.
Risk Management Activities
We utilize energy derivatives for the purpose of mitigating our risk
resulting from fluctuations in the market price of natural gas, natural gas
liquids, crude oil and carbon dioxide. In addition, we enter into interest rate
swap agreements for the purpose of hedging the interest rate risk associated
with our fixed rate debt obligations. Prior to December 31, 2000, our accounting
policy for these activities was based on a number of authoritative
pronouncements including SFAS No. 80, "Accounting for Futures Contracts". Our
new policy, which is based on SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", became effective on January 1, 2001.
Effective January 1, 2001, we adopted SFAS No. 133, as amended by SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No.133" and No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities". SFAS No. 133
established accounting and reporting standards requiring that every derivative
financial instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. If the derivatives meet those criteria, SFAS
No. 133 allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
designate a derivative as a hedge and document and assess the effectiveness of
derivatives associated with transactions that receive hedge accounting.
Furthermore, if the derivative transaction qualifies for and is designated as
a normal purchase and sale, it is exempted from the fair value accounting
requirements of SFAS No. 133 and is accounted for using traditional accrual
accounting. Our derivatives that hedge our commodity price risks involve our
normal business activities, which include the sale of natural gas, natural gas
liquids, oil and carbon dioxide, and these derivatives have been designated as
cash flow hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives
that hedge
103
exposure to variable cash flows of forecasted transactions as cash flow
hedges and the effective portion of the derivative's gain or loss is initially
reported as a component of other comprehensive income (outside earnings) and
subsequently reclassified into earnings when the forecasted transaction affects
earnings. The ineffective portion of the gain or loss is reported in earnings
immediately. See Note 14 for more information on our risk management activities.
3. Acquisitions and Joint Ventures
During 2000, 2001 and 2002, we completed the following significant
acquisitions. Each of the acquisitions was accounted for under the purchase
method and the assets acquired and liabilities assumed were recorded at their
estimated fair market values as of the acquisition date. The results of
operations from these acquisitions are included in our consolidated financial
statements from the date of acquisition.
Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc.
Effective January 1, 2000, we acquired all of the shares of the capital stock
of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminal, Inc. We paid an
aggregate consideration of approximately $31.0 million, including 1,148,344
common units, approximately $0.8 million in cash and the assumption of
approximately $7.0 million in liabilities. The Milwaukee terminal is located on
nine acres of property leased from the Port of Milwaukee. Its major cargoes are
coal, bulk de-icing salt and fertilizer. The Dakota terminal, located in St.
Paul, Minnesota, primarily handles bulk de-icing salt and grain products.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Common units issued.................... $23,319
Cash paid, including transaction costs 757
Liabilities assumed.................... 6,960
-------
Total purchase price................... $31,036
=======
Allocation of purchase price:
Current assets......................... $ 1,764
Property, plant and equipment.......... 15,201
Goodwill............................... 14,071
-------
$31,036
=======
Kinder Morgan CO2 Company, L.P.
Effective April 1, 2000, we acquired the remaining 78% limited partner
interest and the 2% general partner interest in Shell CO2 Company, Ltd. from
Shell for approximately $212.1 million and the assumption of approximately $37.1
million of liabilities. We renamed the limited partnership Kinder Morgan CO2
Company, L.P., and going forward from April 1, 2000, we have included its
results as part of our consolidated financial statements under our CO2 Pipelines
business segment. As is the case with all of our operating partnerships, we own
a 98.9899% limited partner interest in KMCO2 and our general partner owns a
direct 1.0101% general partner interest.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $212,081
Liabilities assumed................... 37,080
--------
Total purchase price.................. $249,161
========
Allocation of purchase price:
Current assets........................ $ 51,870
Property, plant and equipment......... 230,332
Goodwill.............................. 45,751
Equity investments.................... (79,693)(a)
Deferred charges and other assets..... 901
--------
$249,161
========
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(a) Represents reclassification of our original 20% equity investment in Shell
CO2 Company, L.P. of ($86.7) million and our allocation of purchase price to the
equity investment purchased in our acquisition of Shell CO2 Company, L.P. of
$7.0 million.
Devon Energy
Effective June 1, 2000, KMCO2 acquired significant interests in carbon
dioxide pipeline assets and oil-producing properties from Devon Energy
Production Company L.P. for $53.4 million. Included in the acquisition was an
approximate 81% equity interest in the Canyon Reef Carriers CO2 Pipeline, an
approximate 71% working interest in the SACROC oil field, and minority interests
in the Sharon Ridge unit and the Reinecke unit. All of the assets and properties
are located in the Permian Basin of West Texas.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $53,435
-------
Total purchase price.................. $53,435
=======
Allocation of purchase price:
Property, plant and equipment......... $53,435
-------
$53,435
=======
Buckeye Refining Company, LLC
On October 25, 2000, we acquired Kinder Morgan Transmix, LLC, formerly
Buckeye Refining Company, LLC, which owns and operates transmix processing
plants in Indianola, Pennsylvania and Wood River, Illinois and other related
transmix assets. As consideration for the purchase, we paid Buckeye
approximately $37.3 million for property, plant and equipment plus approximately
$8.4 million for net working capital and other items. We also assumed
approximately $11.5 million of liabilities.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $45,696
Liabilities assumed................... 11,462
-------
Total purchase price.................. $57,158
=======
Allocation of purchase price:
Current assets........................ $19,862
Property, plant and equipment......... 37,289
Deferred charges and other assets..... 7
-------
$57,158
=======
Cochin Pipeline
Effective November 3, 2000, we acquired from NOVA Chemicals Corporation an
undivided 32.5% interest in the Cochin Pipeline System for approximately $120.5
million. On June 20, 2001, we acquired an additional 2.3% ownership interest
from Shell Canada Limited for approximately $8.1 million. In January 2002, we
purchased an additional 10% ownership interest from NOVA Chemicals Corporation
for approximately $29 million. The January 2002 transaction was made effective
December 31, 2001. We now own approximately 44.8% of the Cochin Pipeline System
and the remaining interests are owned by subsidiaries of BP Amoco and
ConocoPhillips. We record our proportional share of joint venture revenues and
expenses and cost of joint venture assets with respect to the Cochin Pipeline
System as part of our Products Pipelines business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $157,613
--------
Total purchase price.................. $157,613
========
Allocation of purchase price:
Property, plant and equipment......... $157,613
--------
$157,613
========
105
Delta Terminal Services LLC
Effective December 1, 2000, we acquired all of the shares of the capital
stock of Delta Terminal Services LLC, formerly Delta Terminal Services, Inc.,
for approximately $118.1 million and the assumption of approximately $18.0
million of liabilities. The acquisition includes two liquid bulk storage
terminals in New Orleans, Louisiana and Cincinnati, Ohio.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $118,112
Liabilities assumed................... 17,976
--------
Total purchase price.................. $136,088
========
Allocation of purchase price:
Current assets........................ $ 1,137
Property, plant and equipment......... 70,610
Goodwill.............................. 64,304
Deferred charges and other assets..... 37
--------
$136,088
========
MKM Partners, L.P.
On December 28, 2000, we announced that KMCO2 had entered into a definitive
agreement to form a joint venture with Marathon Oil Company in the southern
Permian Basin of West Texas. The joint venture holds a nearly 13% interest in
the SACROC unit and a 49.9% interest in the Yates Field unit. The joint venture
was formed on January 1, 2001 and named MKM Partners, L.P. As of December 31,
2000, we paid $34.2 million plus committed 30 billion cubic feet of carbon
dioxide for our 7.5% interest in the Yates field unit. In January 2001, we
contributed our interest in the Yates field unit together with an approximate 2%
interest in the SACROC unit in return for a 15% interest in the joint venture.
In January 2001, Marathon Oil Company purchased an approximate 11% interest in
the SACROC unit from KMCO2 for $6.2 million. Marathon Oil Company then
contributed this interest in the SACROC unit and its 42.4% interest in the Yates
field unit for an 85% interest in the joint venture. Going forward from January
1, 2001, we accounted for this investment under the equity method of accounting.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $34,163
-------
Total purchase price.................. $34,163
=======
Allocation of purchase price:
Equity investments.................... $34,163
-------
$34,163
=======
2000 Kinder Morgan, Inc. Asset Contributions
Effective December 31, 2000, we acquired $621.7 million of assets from KMI.
We acquired Kinder Morgan Texas Pipeline, L.P. and MidCon NGL Corp. (both of
which were converted to single-member limited liability companies), the Casper
and Douglas natural gas gathering and processing systems, a 50% interest in
Coyote Gas Treating, LLC and a 25% interest in Thunder Creek Gas Services, LLC.
As consideration for these assets, we paid to KMI $192.7 million in cash and
approximately $156.3 million in units, consisting of 1,280,000 common units and
5,313,400 Class B units. We also assumed liabilities of approximately $272.7
million. The purchase price for the transaction was determined by the boards of
directors of KMI and our general partner based on pricing principles used in the
acquisition of similar assets. This transaction was approved unanimously by the
independent directors of our general partner, with the benefit of advice of
independent legal and financial advisors, including a fairness opinion from the
investment banking firm A.G. Edwards & Sons, Inc.
106
Our purchase price and our allocation to assets acquired and liabilities assumed
was as follows (in thousands):
Purchase price:
Common and Class B units issued....... $156,305
Cash paid, including transaction costs 192,677
Liabilities assumed................... 272,718
--------
Total purchase price.................. $621,700
========
Allocation of purchase price:
Current assets........................ $255,320
Property, plant and equipment......... 137,145
Intangible-leasehold Value............ 179,390
Equity investments.................... 45,225
Deferred charges and other assets..... 4,620
--------
$621,700
========
Colton Transmix Processing Facility
Effective December 31, 2000, we acquired the remaining 50% interest in the
Colton Transmix Processing Facility from Duke Energy Merchants for approximately
$11.2 million and the assumption of approximately $1.8 million of liabilities.
We now own 100% of the Colton facility. Prior to our acquisition of the
controlling interest in the Colton facility, we accounted for our ownership
interest in the Colton facility under the equity method of accounting.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $11,233
Liabilities assumed................... 1,788
-------
Total purchase price.................. $13,021
=======
Allocation of purchase price:
Current assets........................ $ 4,465
Property, plant and equipment......... 8,556
-------
$13,021
=======
Domestic Pipelines and Terminals Businesses from GATX
During the first quarter of 2001, we acquired GATX Corporation's domestic
pipeline and terminal businesses. The acquisition included:
o Kinder Morgan Liquids Terminals LLC (formerly GATX Terminals
Corporation), effective January 1, 2001;
o Central Florida Pipeline LLC (formerly Central Florida Pipeline
Company), effective January 1, 2001; and
o CALNEV Pipe Line LLC (formerly CALNEV Pipe Line Company), effective March
30, 2001.
KMLT's assets then included 12 terminals, located across the United States,
which stored approximately 35.6 million barrels of refined petroleum products
and chemicals. Five of the terminals are included in our Terminals business
segment, and the remaining assets are included in our Products Pipelines
business segment. Central Florida Pipeline LLC consists of a 195-mile pipeline
transporting refined petroleum products from Tampa to the growing Orlando,
Florida market. CALNEV Pipe Line LLC consists of a 550-mile refined petroleum
products pipeline originating in Colton, California and extending into the
growing Las Vegas, Nevada market. The pipeline interconnects in Colton with our
Pacific operations' West Line pipeline segment. Our purchase price was
approximately $1,233.4 million, consisting of $975.4 million in cash, $134.8
million in assumed debt and $123.2 million in assumed liabilities.
107
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 975,428
Debt assumed.......................... 134,746
Liabilities assumed................... 123,246
----------
Total purchase price.................. $1,233,420
==========
Allocation of purchase price:
Current assets........................ $ 32,364
Property, plant and equipment........ 928,736
Deferred charges and other assets.... 4,785
Goodwill............................. 267,535
----------
$1,233,420
==========
Pinney Dock & Transport LLC
Effective March 1, 2001, we acquired all of the shares of the capital stock
of Pinney Dock & Transport LLC, formerly Pinney Dock & Transport Company, for
approximately $51.7 million. The acquisition includes a bulk product terminal
located in Ashtabula, Ohio on Lake Erie. The facility handles iron ore, titanium
ore, magnetite and other aggregates. Our purchase price consisted of
approximately $41.7 million in cash and approximately $10.0 million in assumed
liabilities.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $41,674
Liabilities assumed................... 10,055
-------
Total purchase price.................. $51,729
=======
Allocation of purchase price:
Current assets........................ $ 1,970
Property, plant and equipment......... 32,467
Deferred charges and other assets..... 487
Goodwill.............................. 16,805
-------
$51,729
=======
Bulk Terminals from Vopak
Effective July 10, 2001, we acquired certain bulk terminal businesses, which
were converted or merged into six single-member limited liability companies,
from Koninklijke Vopak N.V. (Royal Vopak) of The Netherlands. Acquired assets
included four bulk terminals. Two of the terminals are located in Tampa, Florida
and the other two are located in Fernandina Beach, Florida and Chesapeake,
Virginia. As a result of the acquisition, our bulk terminals portfolio gained
entry into the Florida market. Our purchase price was approximately $44.3
million, consisting of approximately $43.6 million in cash and approximately
$0.7 million in assumed liabilities.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $43,622
Liabilities assumed................... 700
-------
Total purchase price.................. $44,322
=======
Allocation of purchase price:
Property, plant and equipment......... $44,322
=======
Kinder Morgan Texas Pipeline
Effective July 18, 2001, we acquired, from an affiliate of Occidental
Petroleum Corporation, K M Texas Pipeline, L.P., a partnership that owned a
natural gas pipeline system in the State of Texas. Prior to our acquisition of
this natural gas pipeline system, these assets were leased and operated by
Kinder Morgan Texas Pipeline, L.P., a business unit included in our Natural Gas
Pipelines business segment. As a result of this acquisition, we will be released
from lease payments of $40 million annually from 2002 through 2005 and $30
million annually from 2006
108
through 2026. The acquisition included 2,600 miles of pipeline that primarily
transports natural gas from south Texas and the Texas Gulf Coast to the greater
Houston/Beaumont area. In addition, we signed a five-year agreement to supply
approximately 90 billion cubic feet of natural gas to chemical facilities owned
by Occidental affiliates in the Houston area. Our purchase price was
approximately $326.1 million and the entire cost was allocated to property,
plant and equipment. We merged K M Texas Pipeline, L.P. into Kinder Morgan Texas
Pipeline, L.P. on August 1, 2002.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $359,059
Release SFAS No. 13 deferred credit
previously held...................... (32,918)
---------
Total purchase price................. $326,141
========
Allocation of purchase price:
Property, plant and equipment........ $326,141
--------
$326,141
Note: These assets were previously leased from a third party under an
operating lease. The released Statement of Financial Accounting Standards No.
13, "Accounting for Leases" deferred credit relates to a deferred credit
accumulated to spread non-straight line operating lease rentals over the period
expected to benefit from those rentals.
The Boswell Oil Company
Effective August 31, 2001, we acquired from The Boswell Oil Company three
terminals located in Cincinnati, Ohio; Pittsburgh, Pennsylvania; and Vicksburg,
Mississippi. The Cincinnati and Pittsburgh terminals handle both liquids and
dry-bulk materials. The Vicksburg terminal is a break-bulk facility, primarily
handling paper and steel products. As a result of the acquisition, we continued
the expansion of our bulk terminal businesses and entered new markets. Our
purchase price was approximately $22.4 million, consisting of approximately
$18.0 million in cash, a $3.0 million one-year note payable and approximately
$1.4 million in assumed liabilities.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $18,035
Note payable.......................... 3,000
Liabilities assumed................... 1,364
-------
Total purchase price.................. $22,399
=======
Allocation of purchase price:
Current assets........................ $ 1,658
Property, plant and equipment......... 9,867
Intangibles-Contract Rights........... 4,000
Goodwill.............................. 6,874
-------
$22,399
=======
The $6.9 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.
Liquids Terminals from Stolt-Nielsen
In November 2001, we acquired certain liquids terminals in Chicago,
Illinois and Perth Amboy, New Jersey from Stolthaven Perth Amboy Inc.,
Stolthaven Chicago Inc. and Stolt-Nielsen Transportation Group, Ltd. As a
result of the acquisition, we expanded our liquids terminals businesses into
strategic markets. The Perth Amboy facility provides liquid chemical and
petroleum storage and handling, as well as dry-bulk handling of salt and
aggregates, with liquid capacity exceeding 2.3 million barrels annually. We
closed on the Perth Amboy, New Jersey portion of this transaction on November
8, 2001. The Chicago terminal handles a wide variety of liquid chemicals
with a working capacity in excess of 0.7 million barrels annually. We closed
on the Chicago, Illinois portion of this transaction on November 29, 2001.
Our purchase price was approximately $70.8 million, consisting of
approximately $44.8 million in cash, $25.0 million in assumed debt and $1.0
million in assumed liabilities.
109
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $44,838
Debt assumed.......................... 25,000
Liabilities assumed................... 1,000
-------
Total purchase price.................. $70,838
=======
Allocation of purchase price:
Property, plant and equipment......... $70,763
Goodwill.............................. 75
-------
$70,838
=======
The $0.1 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.
Interests in Snyder and Diamond M Plants
On November 14, 2001, we announced that KMCO2 had purchased Mission
Resources Corporation's interests in the Snyder Gasoline Plant and Diamond M
Gas Plant. In December 2001, KMCO2 purchased Torch E&P Company's interest in
the Snyder Gasoline Plant and entered into a definitive agreement to purchase
Torch's interest in the Diamond M Gas Plant. We paid approximately $20.9
million for these interests. All of these assets are located in the Permian
Basin of West Texas. As a result of the acquisition, we increased our
ownership interests in both plants, each of which process gas produced by the
SACROC unit. The acquisition expanded our carbon dioxide-related operations
and complemented our working interests in oil-producing fields located in
West Texas. Currently, we own an approximate 22% ownership interest in the
Snyder Gasoline Plant and a 51% ownership interest in the Diamond M Gas
Plant. The acquired interests are included as part of our CO2 Pipelines
business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $20,872
-------
Total purchase price.................. $20,872
=======
Allocation of purchase price:
Property, plant and equipment......... $20,872
-------
$20,872
=======
Kinder Morgan Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of
Kinder Morgan Materials Services LLC for approximately $8.9 million and the
assumption of approximately $3.3 million of liabilities, including long-term
debt of $0.4 million. Kinder Morgan Materials Services LLC currently
operates more than 60 transload facilities in 20 states. The facilities
handle dry-bulk products, including aggregates, plastics and liquid
chemicals. The acquisition of Kinder Morgan Materials Services LLC expanded
our growing terminal operations and is part of our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $ 8,916
Debt assumed.......................... 357
Liabilities assumed................... 2,967
-------
Total purchase price.................. $12,240
=======
Allocation of purchase price:
Current assets........................ $ 879
Property, plant and equipment......... 11,361
-------
$12,240
=======
110
66 2/3% Interest in International Marine Terminals
Effective January 1, 2002, we acquired a 33 1/3% interest in International
Marine Terminals, referred to herein as IMT, from Marine Terminals
Incorporated. Effective February 1, 2002, we acquired an additional 33 1/3%
interest in IMT from Glenn Springs Holdings, Inc. Our combined purchase
price was approximately $40.5 million, including the assumption of $40
million of long-term debt. IMT is a partnership that operates a bulk
terminal site in Port Sulphur, Louisiana. This terminal is a multi-purpose
import and export facility, which handles approximately 8 million tons
annually of bulk products including coal, petroleum coke, iron ore and
barite. The acquisition complements our existing bulk terminal assets. IMT
is part of our Terminals business segment.
Our purchase price and our allocation to assets acquired, liabilities
assumed and minority interest was as follows (in thousands):
Purchase price:
Cash received, net of transaction costs $(3,781)
Debt assumed........................... 40,000
Liabilities assumed.................... 4,249
--------
Total purchase price................... $40,468
========
Allocation of purchase price:
Current assets......................... $6,600
Property, plant and equipment.......... 31,781
Deferred charges and other assets...... 139
Minority interest...................... 1,948
-------
$40,468
=======
Kinder Morgan Tejas
Effective January 31, 2002, we acquired all of the equity interests of
Tejas Gas, LLC, a wholly-owned subsidiary of InterGen (North America), Inc.,
for an aggregate consideration of approximately $881.5 million, consisting of
$727.1 million in cash and the assumption of $154.4 million of liabilities.
Tejas Gas, LLC consists primarily of a 3,400-mile natural gas intrastate
pipeline system that extends from south Texas along the Mexico border and the
Texas Gulf Coast to near the Louisiana border and north from near Houston to
east Texas. The acquisition expands our natural gas operations within the
State of Texas. The acquired assets are referred to as Kinder Morgan Tejas
in this report and are included in our Natural Gas Pipelines business segment.
The allocation of our purchase price to the assets and liabilities of
Kinder Morgan Tejas is preliminary, pending final purchase price adjustments
that should be made in the first quarter of 2003. The total purchase price
increased $49.0 million in the fourth quarter of 2002 due to adjustments in
the amount of assumed liabilities related primarily to gas purchase
contracts. Due to the seasonality of certain gas purchase activities, we
were not able to determine the fair value of these contracts until the fourth
quarter of 2002. This pre-acquisition contingency was appropriately recorded
during the allocation period specified by SFAS No. 141, "Business
Combinations". The allocation of our purchase price was based on an
independent appraisal of fair market values as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $727,094
Liabilities assumed................... 154,455
--------
Total purchase price.................. $881,549
========
Allocation of purchase price:
Current assets........................ $ 56,496
Property, plant and equipment,
including cushion gas ............... 674,147
Goodwill ............................. 150,906
========
$881,549
========
The $150.9 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.
Milwaukee Bagging Operations
Effective May 1, 2002, we purchased a bagging operation facility adjacent
to our Milwaukee, Wisconsin dry-bulk terminal for $8.5 million. The purchase
enhances the operations at our Milwaukee terminal, which is capable
111
of handling up to 150,000 tons per year of fertilizer and salt for
de-icing and livestock purposes. The Milwaukee bagging operations are
included in our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands)
Purchase price:
Cash paid, including transaction costs $ 8,500
-------
Total purchase price.................. $ 8,500
=======
Allocation of purchase price:
Current assets........................ $ 40
Property, plant and equipment......... 3,140
Goodwill.............................. 5,320
-------
$8,500
=======
The $5.3 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.
Trailblazer Pipeline Company
On May 6, 2002, we acquired the remaining 33 1/3% ownership interest in
Trailblazer Pipeline Company from Enron Trailblazer Pipeline Company for $68
million. We now own 100% of Trailblazer Pipeline Company. During the first
quarter of 2002, we paid $12.0 million to CIG Trailblazer Gas Company, an
affiliate of El Paso Corporation, in exchange for CIG's relinquishment of its
rights to become a 7% to 8% equity owner in Trailblazer Pipeline Company in
mid-2002. Trailblazer 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
Pipeline Company has a current certificated capacity of 846 million cubic
feet per day of natural gas.
Our purchase price and our allocation to assets acquired, liabilities
assumed and minority interest was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $80,125
-------
Total purchase price.................. $80,125
=======
Allocation of purchase price:
Property, plant and equipment......... $41,739
Goodwill.............................. 15,000
Minority interest..................... 23,386
-------
$80,125
=======
The $15.0 million of goodwill was assigned to our Natural Gas Pipelines
business segment and the entire amount is expected to be deductible for tax
purposes.
Owensboro Gateway Terminal
Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. As of December
31, 2002, we have paid approximately $7.2 million and established a $0.5
million liability for final purchase price settlements. The facility is one
of the nation's largest storage and handling points for bulk aluminum. The
terminal also handles a variety of other bulk products, including petroleum
coke, lime and de-icing salt. The terminal is situated on a 92-acre site
along the Ohio River, and the purchase expands our presence along the river,
complementing our existing facilities located near Cincinnati, Ohio and
Moundsville, West Virginia. The acquired terminal is now called the
Owensboro Gateway Terminal and is included in our Terminals business segment.
112
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $7,140
Purchase price reserve................ 500
Liabilities assumed................... 11
------
Total purchase price.................. $7,651
======
Allocation of purchase price:
Current assets........................ $ 42
Property, plant and equipment......... 4,265
Intangibles-agreements................ 54
Goodwill.............................. 3,290
------
$7,651
======
The $3.3 million of goodwill was assigned to our Terminals business
segment and the entire amount is expected to be deductible for tax purposes.
IC Terminal Holdings Company
Effective September 1, 2002, we acquired all of the shares of the capital
stock of IC Terminal Holdings Company from the Canadian National Railroad.
Our purchase price was approximately $17.8 million, consisting of $17.6
million and the assumption of $0.2 million in liabilities. The acquisition
includes the former ICOM marine terminal in St. Gabriel, Louisiana. The St.
Gabriel facility features 400,000 barrels of liquids storage capacity and a
related pipeline network that serves one of the fastest growing petrochemical
production areas in the country. The acquisition further expands our
terminal businesses along the Mississippi River. The acquired terminal will
be referred to as the Kinder Morgan St. Gabriel terminal and will be included
in our Terminals business segment.
Our purchase price and our allocation to assets acquired and liabilities
assumed was as follows (in thousands):
Purchase price:
Cash paid, including transaction costs $17,572
Liabilities assumed................... 253
-------
Total purchase price.................. $17,825
=======
Allocation of purchase price:
Current assets........................ $ 46
Property, plant and equipment......... 14,430
Investment in ICPT, LLC............... 1,785
Non-current note receivable........... 1,350
Deferred charges and other assets..... 214
-------
$17,825
=======
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the twelve months ended December 31, 2002 and 2001, assumes
the 2002 and 2001 acquisitions and joint ventures had occurred as of January
1, 2001. We have prepared these unaudited Pro Forma financial results for
comparative purposes only. These unaudited Pro Forma financial results may
not be indicative of the results that would have occurred if we had completed
the 2002 and 2001 acquisitions and joint ventures as of January 1, 2001 or
the results which will be attained in the future. Amounts presented below
are in thousands, except for the per unit amounts:
Pro Forma Year Ended
December 31,
------------------------
2002 2001
---------- ----------
(Unaudited)
Revenues........................... $4,510,960 $5,275,551
Operating Income................... 729,564 609,439
Income before extraordinary charge. 632,171 519,980
Net Income......................... 616,888 502,487
Basic and diluted Limited Partners'
Net Income per unit............... $ 1.93 $ 1.60
113
Acquisitions Subsequent to December 31, 2002
Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk facilities at major
ports along the East Coast and in the southeastern United States. The
acquisition also includes the purchase of certain assets that provide
stevedoring services at these locations. The cost of the acquisition will be
approximately $31.3 million. On December 31, 2002, we paid $29.9 million for
the Rudolph acquisition and this amount is included with Other current assets
on our accompanying balance sheet. We expect to pay the remaining
approximate amount of $1.4 million during the first quarter of 2003. The
acquired operations serve various terminals located at the ports of New York
and Baltimore, along the Delaware River in Camden, New Jersey, and in Tampa
Bay, Florida. Combined, these facilities transload nearly four million tons
annually of products such as fertilizer, iron ore and salt. The acquisition
expands our growing terminals business segment and complements certain of our
existing terminal facilities and will be included in our Terminals business
segment.
4. New Accounting Pronouncements
On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations". SFAS No. 143 requires companies to record a
liability relating to the retirement and removal of assets used in their
business. The liability is initially recorded at its fair value, and the
relative asset value is increased by the same amount. Over the life of the
asset, the liability will be accreted to its future value and eventually
extinguished when the asset is taken out of service. The provisions of this
statement are effective for fiscal years beginning after June 15, 2002. With
respect to our Natural Gas Pipelines and Products Pipelines business segments,
we have certain surface facilities that are required to be dismantled and
removed, with certain site reclamation to be performed. While, in general, our
right-of-way agreements do no require us to remove pipe or otherwise perform
remediation upon taking the pipeline permanently out of service, some
right-of-way agreements do provide for these actions. With respect to our CO2
Pipelines business segment, we generally are required to plug our oil production
wells when removed from service and we anticipate recording a liability for such
obligation. Our Terminals business segment has entered into certain facility
leases which require removal of improvements upon expiration of the lease term.
We anticipate recording a liability for such obligation. For the Natural Gas
Pipelines and Products Pipelines business segments, we expect that we will be
unable to reasonably estimate and record liabilities for the majority of our
obligations that fall under the provisions of this statement because we cannot
reasonably estimate when such obligations would be settled. For the CO2
Pipelines and Terminals business segments, the effect of adopting SFAS No. 143
is not material to the consolidated financial statements.
In April 2002, the Financial Accounting Standards Board issued SFAS No.
145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13, and Technical Corrections". This Statement eliminates the
current requirement that gains and losses on debt extinguishment must be
classified as extraordinary items in the income statement. Instead, such
gains and losses will be classified as extraordinary items only if they are
deemed to be unusual and infrequent, in accordance with the current GAAP
criteria for extraordinary classification. In addition, SFAS No. 145
eliminates an inconsistency in lease accounting by requiring that
modifications of capital leases that result in reclassification as operating
leases be accounted for consistent with sale-leaseback accounting rules.
This Statement also contains other nonsubstantive corrections to
authoritative accounting literature. The changes related to debt
extinguishment will be effective for fiscal years beginning after May 15,
2002, and the changes related to lease accounting will be effective for
transactions occurring after May 15, 2002. Adoption of this Statement will
not have any immediate effect on our consolidated financial statements. We
will apply this guidance prospectively.
In June 2002, the Financial Accounting Standards Board issued SFAS No.
146, "Accounting for Costs Associated with Exit or Disposal Activities",
which addresses accounting for restructuring and similar costs. SFAS No. 146
supersedes previous accounting guidance, principally Emerging Issues Task
Force Issue No. 94-3. We will adopt the provisions of SFAS No. 146 for
restructuring activities initiated after December 31, 2002. SFAS No. 146
requires that the liability for costs associated with an exit or disposal
activity be recognized when the liability is incurred. Under EITF No. 94-3,
a liability for an exit cost was recognized at the date of the company's
commitment to an exit plan. SFAS No. 146 also establishes that the liability
should initially be measured and recorded at fair value. Accordingly, SFAS
No. 146 may affect the timing of recognizing future restructuring costs as
well as the amounts recognized.
114
In November 2002, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others". This interpretation of Financial Accounting Standards Board
Statements No. 5, 57 and 107, and rescission of FIN No. 34 elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has
issued. It also clarifies that a guarantor is required to recognize, at the
inception of a guarantee, a liability for the fair value of the obligation
undertaken in issuing the guarantee. This interpretation incorporates,
without change, the guidance in FIN No. 34, "Disclosure of Indirect
Guarantees of Indebtedness of Others", which is being superceded. The
initial recognition and initial measurement provisions of FIN No. 45 are
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements in this interpretation are
effective for financial statements of interim or annual periods after
December 15, 2002, and have been adopted. For more information, see Note 13.
In December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation - Transition and Disclosure".
This amendment to SFAS No. 123, "Accounting for Stock-Based Compensation",
provides alternative methods of transition for a voluntary change to the fair
value based method of accounting for stock-based employee compensation. In
addition, this statement amends the disclosure requirements of SFAS No. 123
to require disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the effect
of the method used on reported results. The provisions of this statement are
effective for financial statements of interim or annual periods after
December 15, 2002. Early application of the disclosure provisions is
encouraged, and earlier application of the transition provisions is
permitted, provided that financial statements for the 2002 fiscal year have
not been issued as of the date the statement was issued.
5. Income Taxes
Components of the income tax provision applicable to continuing operations
for federal and state taxes are as follows (in thousands):
Year Ended December 31,
-------------------------------
2002 2001 2000
--------- --------- ---------
Taxes currently payable:
Federal................ $15,855 $ 9,058 $10,612
State.................. 3,116 1,192 1,416
Foreign................ 147 - -
--------- ------- -------
Total.................. 19,118 10,250 12,028
Taxes deferred:
Federal................ (3,280) 5,366 1,627
State.................. (555) 757 279
--------- ------- -------
Total.................. (3,835) 6,123 1,906
--------- ------- -------
Total tax provision..... $15,283 $16,373 $13,934
========= ======= ========
Effective tax rate..... 2.4% 3.5% 4.8%
The difference between the statutory federal income tax rate and our
effective income tax rate is summarized as follows:
Year Ended December 31,
----------------------------
2002 2001 2000
--------- -------- ---------
Federal income tax rate................ 35.0% 35.0% 35.0%
Increase (decrease) as a result of:
Partnership earnings not subject to
tax................................. (35.0)% (35.0)% (35.0)%
Corporate subsidiary earnings subject
to tax.............................. 0.6% 1.3% 0.6%
Income tax expense attributable to
corporate equity earnings........... 1.6% 1.8% 4.1%
State taxes.......................... 0.2% 0.4% 0.1%
Effective tax rate..................... 2.4% 3.5% 4.8%
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Deferred tax assets and liabilities result from the following (in
thousands):
December 31,
----------------
2002 2001
------- -------
Deferred tax assets:
Book accruals.................... $ 97 $ 404
Net Operating Loss/Alternative
minimum tax credits............. 3,556 1,846
------- -------
Total deferred tax assets.......... 3,653 2,250
Deferred tax liabilities:
Property, plant and equipment.... 33,915 40,794
------- -------
Total deferred tax liabilities..... 33,915 40,794
------- -------
Net deferred tax liabilities....... $30,262 $38,544
======= =======
We had available, at December 31, 2002, approximately $1.4 million of
alternative minimum tax credit carryforwards, which are available
indefinitely, and $2.1 million of net operating loss carryforwards, which
will expire between the years 2003 and 2022. We believe it is more likely
than not that the net operating loss carryforwards will be utilized prior to
their expiration; therefore, no valuation allowance is necessary.
6. Property, Plant and Equipment
Property, plant and equipment consists of the following (in thousands):
December 31,
-------------------
2002 2001
-------- --------
Natural gas, liquids and carbon dioxide
pipelines............................... $2,544,987 $2,246,930
Natural gas, liquids and carbon dioxide
pipeline station equipment.............. 2,801,729 2,168,924
Coal and bulk tonnage transfer, storage
and services............................ 281,713 214,040
Natural gas and transmix processing...... 98,094 97,155
Other.................................... 292,881 217,245
Accumulated depreciation and depletion... (452,408) (302,012)
----------- -----------
5,566,996 4,642,282
Land and land right-of-way............... 340,507 283,878
Construction work in process............. 336,739 156,452
----------- -----------
$6,244,242 $5,082,612
=========== ===========
Depreciation and depletion expense charged against property, plant and
equipment consists of the following (in thousands):
2002 2001 2000
-------- -------- -------
Depreciation and
depletion expense........ $171,461 $126,641 $79,740
7. Investments
Our significant equity investments at December 31, 2002 consisted of:
o Plantation Pipe Line Company (51%);
o Red Cedar Gathering Company (49%);
o MKM Partners, L.P. (15%);
o Thunder Creek Gas Services, LLC (25%);
o Coyote Gas Treating, LLC (Coyote Gulch) (50%);
o Cortez Pipeline Company (50%); and
o Heartland Pipeline Company (50%).
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On April 1, 2000, we acquired the remaining 80% ownership interest in
Shell CO2 Company, Ltd. and renamed the entity Kinder Morgan CO2 Company,
L.P. On December 31, 2000, we acquired the remaining 50% ownership interest
in the Colton Transmix Processing Facility. Due to these acquisitions, we no
longer report these two investments under the equity method of accounting.
In addition, we had an equity investment in International Marine Terminals
(33 1/3%) for one month of 2002. We acquired an additional 33 1/3% interest
in International Marine Terminals effective February 1, 2002, and after this
date, the financial results of IMT were no longer reported under the equity
method.
We own approximately 51% of Plantation Pipe Line Company, and an affiliate
of ExxonMobil owns the remaining approximate 49%. Each investor has an equal
number of directors on Plantation's board of directors, and board approval is
required for certain corporate actions that are considered participating
rights. Therefore, we do not control Plantation Pipe Line Company, and we
account for our investment under the equity method of accounting.
On January 1, 2001, Kinder Morgan CO2 Company, L.P. acquired our 15%
interest in MKM Partners, L.P., a joint venture with Marathon Oil Company in
the southern Permian Basin of West Texas. The joint venture consists of a
nearly 13% interest in the SACROC unit and a 49.9% interest in the Yates oil
field. We account for our 15% investment in the joint venture under the
equity method of accounting because our ownership interest includes 50% of
the joint venture's general partner interest, and the ownership of this
general partner interest gives us the ability to exercise significant
influence over the operating and financial policies of the joint venture.
We acquired our investment in Cortez Pipeline Company as part of our KMCO2
acquisition. We acquired our investments in Coyote Gas Treating, LLC and
Thunder Creek Gas Services, LLC from KMI on December 31, 2000. Please refer
to Note 3 for more information on our acquisitions.
On January 1, 2002, we adopted SFAS No. 142 and, accordingly, we reclassed
the $140.3 million representing the balance, on that date, of our total
unamortized excess cost over underlying fair value of net assets accounted
for under the equity method from our investments to our goodwill.
Our total investments consisted of the following (in thousands):
December 31,
--------------------
2002 2001
--------- ---------
Plantation Pipe Line Company............. $126,024 $217,473
Red Cedar Gathering Company.............. 64,459 99,484
MKM Partners, L.P........................ 60,795 58,633
Thunder Creek Gas Services, LLC.......... 36,921 30,159
Coyote Gas Treating, LLC................. 2,344 16,323
Cortez Pipeline Company.................. 10,486 9,599
Heartland Pipeline Company............... 5,459 5,608
All Others............................... 4,556 3,239
-------- --------
Total Equity Investments................. $311,044 $440,518
======== ========
Our earnings from equity investments were as follows (in thousands):
Year Ended December 31,
---------------------------
2002 2001 2000
-------- -------- --------
Plantation Pipe Line Company.......... $26,426 $25,314 $31,509
Cortez Pipeline Company............... 28,154 25,694 17,219
Red Cedar Gathering Company........... 19,082 18,814 16,110
MKM Partners, L.P..................... 8,174 8,304 --
Coyote Gas Treating, LLC.............. 2,651 2,115 --
Thunder Creek Gas Services, LLC....... 2,154 1,629 --
Heartland Pipeline Company............ 998 882 1,581
Shell CO2 Company, Ltd................ -- -- 3,625
Coltonn Transmix Processing Facility.. -- -- 1,815
Trailblazer Pipeline Company.......... -- -- (24)
All Others............................ 1,619 2,082 (232)
-------- -------- --------
Total................................. $89,258 $84,834 $71,603
======== ======== ========
Amortization of excess costs.......... $(5,575) $(9,011) $(8,195)
======== ======== ========
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Summarized combined unaudited financial information for our significant
equity investments is reported below (in thousands; amounts represent 100% of
investee financial information):
Year Ended December 31,
----------------------------
Income Statement 2002 2001 2000
-------------------------------- -------- -------- --------
Revenues........................... $505,602 $449,259 $399,335
Costs and expenses................. 309,291 280,100 276,000
Earnings before extraordinary items 196,311 169,159 123,335
Net income......................... 196,311 169,159 123,335
December 31,
-------------------
Balance Sheet 2002 2001
-------------------- --------- ---------
Current assets.......... $ 83,410 $ 101,015
Non-current assets...... 1,101,057 1,079,053
Current liabilities..... 243,636 242,438
Non-current liabilities. 374,132 392,739
Partners'/owners' equity 566,699 544,891
8. Intangibles
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards No. 141 "Business Combinations" and Statement of Financial
Accounting Standards No. 142 "Goodwill and Other Intangible Assets". These
accounting pronouncements require that we prospectively cease amortization of
all intangible assets having indefinite useful economic lives. Such assets,
including goodwill, are not to be amortized until their lives are determined
to be finite. A recognized intangible asset with an indefinite useful life
should be tested for impairment annually or on an interim basis if events or
circumstances indicate that the fair value of the asset has decreased below
its carrying value. We completed this initial transition impairment test in
June 2002 and determined that our goodwill was not impaired as of January 1,
2002.
Our intangible assets include goodwill, lease value, contracts and
agreements. We acquired our intangible lease value as part of our
acquisition of Kinder Morgan Texas Pipeline, L.P. on December 31, 2000 from
KMI. In our July 2001 acquisition of K M Texas Pipeline, L.P., we acquired
the leased pipeline asset from Occidental Petroleum and our operating lease
was terminated. We then allocated the balance of the Kinder Morgan Texas
Pipeline, L.P. intangible lease value between goodwill and property.
On January 1, 2002, we adopted SFAS No. 142 and, accordingly, we reclassed
the $140.3 million representing the balance, on that date, of our total
unamortized excess cost over underlying fair value of net assets accounted
for under the equity method from our investments to our intangibles.
All of our intangible assets having definite lives are being amortized on
a straight-line basis over their estimated useful lives. SFAS Nos. 141 and
142 also require that we disclose the following information related to our
intangible assets still subject to amortization and our goodwill (in
thousands):
December 31,
-----------------
2002 2001
--------- ---------
Goodwill.................. $876,839 $566,633
Accumulated amortization.. (19,899) (19,899)
--------- ---------
Goodwill.................. 856,940 546,734
Lease value............... 6,124 6,124
Contracts and other....... 11,580 10,739
Accumulated amortization.. (380) (200)
--------- ---------
Other intangibles, net 17,324 16,663
--------- ---------
Total intangibles, net $874,264 $563,397
========= =========
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Changes in the carrying amount of goodwill for the twelve months ended
December 31, 2002 are summarized as follows (in thousands):
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
--------- ----------- --------- --------- -----
Balance at Dec. 31, 2000 $ - $ - $ 50,324 $107,746 $158,070
Goodwill acquired 267,816 87,452 (2,999) 46,359 398,628
Goodwill dispositions, net - - - - -
Amortized to expense (5,051) - (1,224) (3,689) (9,964)
Impairment losses - - - - -
------------- ----------- ------------ --------- ---------
Balance at Dec. 31, 2001 $ 262,765 $ 87,452 $ 46,101 $150,416 $546,734
============= =========== ============ ========= =========
Transfer from investments 86,276 54,054 - - 140,330
Goodwill acquired 417 165,906 - 3,553 169,876
Goodwill dispositions, net - - - - -
Impairment losses - - - - -
------------- ----------- ------------ --------- ---------
Balance at Dec. 31, 2002 $ 349,458 $ 307,412 $ 46,101 $ 153,969 $ 856,940
============= =========== ============ ========= =========
Amortization expense on intangibles, including amortization of excess
intangible costs of equity investments, consists of the following (in
thousands):
2002 2001 2000
------ ------ ------
Goodwill............ $ - $13,416 $5,460
Lease value......... 140 4,999 140
Contracts and other. 40 60 40
----- ------- ------
Total amortization.. $ 180 $18,475 $5,640
===== ======= ======
Our weighted average amortization period for our intangible assets is
approximately 41 years. The following table shows the estimated amortization
expense for these assets for each of the five succeeding fiscal years (in
thousands):
Year Expense
---- -------
2003 $180
2004 $180
2005 $180
2006 $180
2007 $180
Had SFAS No. 142 been in effect prior to January 1, 2002, our reported
limited partners' interest in net income and net income per unit would have
been as follows (in thousands, except per unit amounts):
Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
Reported limited partners' interest in
net income $ 337,561 $ 240,248 $ 168,878
Add: limited partners' interest in
goodwill amortization -- 13,280 5,405
--------- --------- ---------
Adjusted limited partners' interest in
net income $ 337,561 $ 253,528 $ 174,283
========= ========= =========
Basic limited partners' net income per
unit:
Reported net income $ 1.96 $ 1.56 $ 1.34
Goodwill amortization -- 0.09 0.04
--------- --------- ---------
Adjusted net income $ 1.96 $ 1.65 $ 1.38
========= ========= =========
Diluted limited partners' net income
per unit:
Reported net income $ 1.96 $ 1.56 $ 1.34
Goodwill amortization
-- 0.09 0.04
--------- --------- ---------
Adjusted net income $ 1.96 $ 1.65 $ 1.38
========= ========= =========
9. Debt
Our debt and credit facilities as of December 31, 2002, consisted
primarily of:
o a $530 million unsecured 364-day credit facility due October 14, 2003;
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o a $445 million unsecured three-year credit facility due October 15, 2005;
o $37.1 million of Series F First Mortgage Notes due December 2004 (our
subsidiary, SFPP, L.P. is the obligor on the notes);
o $200 million of 8.00% Senior Notes due March 15, 2005;
o $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal
District Revenue Bonds due March 15, 2006 (our 66 2/3% owned
subsidiary, International Marine Terminals, is the obligor on the
bonds);
o $250 million of 5.35% Senior Notes due August 15, 2007;
o $30 million of 7.84% Senior Notes, with a final maturity of July 2008
(our subsidiary, Central Florida Pipe Line LLC, is the obligor on the
notes);
o $250 million of 6.30% Senior Notes due February 1, 2009;
o $250 million of 7.50% Senior Notes due November 1, 2010;
o $700 million of 6.75% Senior Notes due March 15, 2011;
o $450 million of 7.125% Senior Notes due March 15, 2012;
o $25 million of New Jersey Economic Development Revenue Refunding Bonds
due January 15, 2018 (our subsidiary, Kinder Morgan Liquids Terminals
LLC, is the obligor on the bonds);
o $87.9 million of Industrial Revenue Bonds with final maturities ranging
from September 2019 to December 2024 (our subsidiary, Kinder Morgan
Liquids Terminals LLC, is the obligor on the bonds);
o $23.7 million of tax-exempt bonds due 2024 (our subsidiary, Kinder
Morgan Operating L.P. "B", is the obligor on the bonds);
o $300 million of 7.40% Senior Notes due March 15, 2031;
o $300 million of 7.75% Senior Notes due March 15, 2032;
o $500 million of 7.30% Senior Notes due August 15, 2033; and
o a $975 million short-term commercial paper program (supported by our
credit facilities, the amount available for borrowing under our credit
facilities is reduced by our outstanding commercial paper borrowings).
None of our debt or credit facilities are subject to payment acceleration
as a result of any change to our credit ratings. However, the margin that we
pay with respect to LIBOR based borrowings under our credit facilities is
tied to our credit ratings.
Our outstanding short-term debt at December 31, 2002, consisted of:
o $220 million of commercial paper borrowings;
o $37.1 million under the SFPP, L.P. 10.7% First Mortgage Notes;
o $5 million under the Central Florida Pipeline LLC Notes; and
o $2.8 million in other borrowings.
We intend and have the ability to refinance our $264.9 million of
short-term debt on a long-term basis under our
120
unsecured long-term credit facility. Accordingly, such amounts have been
classified as long-term debt in our accompanying consolidated balance sheet.
Currently, we do not anticipate any liquidity problems. The weighted average
interest rate on all of our borrowings was approximately 5.015% during 2002
and 6.965% during 2001.
Credit Facilities
On December 31, 2000, we had two credit facilities, a $300 million
unsecured five-year credit facility expiring on September 29, 2004, and a
$600 million unsecured 364-day credit facility expiring on October 25, 2001.
On December 31, 2000, the outstanding balance under our five-year credit
facility was $207.6 million and the outstanding balance under our 364-day
credit facility was $582 million.
During the first quarter of 2001, we obtained a third unsecured credit
facility, in the amount of $1.1 billion, expiring on December 31, 2001. The
credit facility was used to support the increase in our commercial paper
program to $1.7 billion for our acquisition of the GATX businesses. The
terms of this credit facility were substantially similar to the terms of the
other two facilities. Upon issuance of additional senior notes on March 12,
2001, this short-term credit facility was reduced to $500 million. During
the second quarter of 2001, we terminated this $500 million credit facility,
which was scheduled to expire on December 31, 2001. On October 25, 2001, our
364-day credit facility expired and we obtained a new $750 million unsecured
364-day credit facility expiring on October 23, 2002. The terms of this
credit facility were substantially similar to the terms of the expired
facility. There were no borrowings under either credit facility at December
31, 2001.
On February 21, 2002, we obtained a third unsecured 364-day credit
facility, in the amount of $750 million, expiring on February 20, 2003. The
credit facility was used to support the increase in our commercial paper
program to $1.8 billion for our acquisition of Tejas Gas, LLC, and the terms
of this credit facility were substantially similar to the terms of our other
two credit facilities. Upon issuance of additional senior notes in March
2002, this short-term credit facility was reduced to $200 million.
In August 2002, upon the completion of our i-unit equity sale, we
terminated, under the terms of the agreement, our $200 million unsecured
364-day credit facility that was due February 20, 2003. On October 16, 2002,
we successfully renegotiated our bank credit facilities by replacing our $750
million unsecured 364-day credit facility due October 23, 2002 and our $300
million unsecured five-year credit facility due September 29, 2004 with two
new credit facilities. Our current facilities include:
o a $530 million unsecured 364-day credit facility due October 14, 2003;
and
o a $445 million unsecured three-year credit facility due October 15, 2005.
Our credit facilities are with a syndicate of financial institutions.
Wachovia Bank, National Association is the administrative agent under both
credit facilities. The terms of our two credit facilities are substantially
similar to the terms of our previous credit facilities. Interest on the two
credit facilities accrues at our option at a floating rate equal to either:
o the administrative agent's base rate (but not less than the Federal
Funds Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of
our long-term senior unsecured debt.
Our credit facilities include the following restrictive covenants as of
December 31, 2002:
o requirements to maintain certain financial ratios:
o total debt divided by earnings before interest, income taxes,
depreciation and amortization for the preceding four quarters may not
exceed 5.0;
o total indebtedness of all consolidated subsidiaries shall at no time
exceed 15% of consolidated indebtedness;
o tangible net worth as of the last day of any fiscal quarter shall not
be less than $2,100,000,000; and
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o consolidated indebtedness shall at no time exceed 62.5% of total
capitalization;
o limitations on entering into mergers, consolidations and sales of assets;
o limitations on granting liens; and
o prohibitions on making any distribution to holders of units if an event
of default exists or would exist upon making such distribution.
There were no borrowings under either credit facility at December 31,
2002. The amount available for borrowing under our credit facilities is
reduced by:
o a $23.7 million letter of credit that supports Kinder Morgan Operating
L.P. "B"'s tax-exempt bonds;
o a $28 million letter of credit entered into on December 23, 2002 that
supports Nassau County, Florida Ocean Highway and Port Authority tax
exempt bonds (associated with the operations of our bulk terminal
facility located at Fernandina Beach, Florida); and
o our outstanding commercial paper borrowings.
Our new three-year credit facility also permits us to obtain bids for
fixed rate loans from members of the lending syndicate.
Senior Notes
On March 12, 2001, we closed a public offering of $1.0 billion in
principal amount of senior notes, consisting of $700 million in principal
amount of 6.75% senior notes due March 15, 2011 at a price to the public of
99.705% per note, and $300 million in principal amount of 7.40% senior notes
due March 15, 2031 at a price to the public of 99.748% per note. In the
offering, we received proceeds, net of underwriting discounts and
commissions, of approximately $693.4 million for the 6.75% notes and $296.6
million for the 7.40% notes. We used the proceeds to pay for our acquisition
of Pinney Dock & Transport LLC (see Note 3) and to reduce our outstanding
balance on our credit facilities and commercial paper borrowings.
On March 14, 2002, we closed a public offering of $750 million in
principal amount of senior notes, consisting of $450 million in principal
amount of 7.125% senior notes due March 15, 2012 at a price to the public of
99.535% per note, and $300 million in principal amount of 7.75% senior notes
due March 15, 2032 at a price to the public of 99.492% per note. In the
offering, we received proceeds, net of underwriting discounts and
commissions, of approximately $445.0 million for the 7.125% notes and $295.9
million for the 7.75% notes. We used the proceeds to reduce our outstanding
balance on our commercial paper borrowings.
On March 22, 2002, we paid $200 million to retire the principal amount of
our Floating Rate senior notes that matured on that date. We borrowed the
necessary funds under our commercial paper program.
Under an indenture dated August 19, 2002, and a First Supplemental
Indenture dated August 23, 2002, we completed a private placement of $750
million in debt securities. The notes consisted of $500 million in principal
amount of 7.30% Senior Notes due August 15, 2033 and $250 million in
principal amount of 5.35% Senior Notes due August 15, 2007. In the offering,
we received proceeds, net of underwriting discounts and commissions, of
approximately $494.7 million for the 7.30% notes and $248.3 million for the
5.35% notes. The proceeds were used to reduce the borrowings under our
commercial paper program. On November 18, 2002, we exchanged these notes
with substantially identical notes that were registered under the Securities
Act of 1933.
122
At December 31, 2002, our unamortized liability balance due on the various
series of our senior notes was as follows (in millions):
8.0% senior notes due March 15, 2005 $ 199.8
5.35% senior notes due August 15, 2007 249.8
6.3% senior notes due February 1, 2009 249.5
7.5% senior notes due November 1, 2010 248.8
6.75% senior notes due March 15, 2011 698.3
7.125% senior notes due March 15, 2012 448.1
7.4% senior notes due March 15, 2031 299.3
7.75% senior notes due March 15, 2032 298.5
7.3% senior notes due August 15, 2033 499.0
--------
Total $3,191.1
========
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate debt and variable rate debt. As of
December 31, 2002, we have entered into interest rate swap agreements with a
notional principal amount of $1.95 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt
obligations.
These interest rate swaps have been designated as fair value hedges as
defined by SFAS No. 133. These swaps also meet the conditions required to
assume no ineffectiveness under SFAS No. 133 and, therefore, we have
accounted for them using the "shortcut" method prescribed for fair value
hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each
swap to its fair value each quarter, with an offsetting entry to adjust the
carrying value of the debt securities whose fair value is being hedged. At
December 31, 2002, we recognized an asset of $167.0 million for the net fair
value of our swap agreements and we included this amount with Deferred
charges and other assets on the accompanying balance sheet. At December 31,
2001, we recognized a liability of $5.4 million for the net fair value of our
swap agreements and we included this amount with Other long-term liabilities
and deferred Credits on the accompanying balance sheet. For more information
on our risk management activities, see Note 14.
Commercial Paper Program
On December 31, 2000, our commercial paper program provided for the
issuance of up to $600 million of commercial paper. On that date, we had $52
million of commercial paper outstanding with an interest rate of 7.02%.
During the first quarter of 2001, we increased our commercial paper program
to provide for the issuance of an additional $1.1 billion of commercial
paper. We entered into a $1.1 billion unsecured 364-day credit facility to
support this increase in our commercial paper program, and we used the
program's increase in available funds to close on the GATX acquisition.
In May 2001, KMR issued 2,975,000 of its shares representing limited
liability company interests to KMI and 26,775,000 of its shares representing
limited liability company interests with limited voting rights to the public
in an initial public offering. Its shares were issued at a price of $35.21
per share, less commissions and underwriting expenses, and it used
substantially all of the net proceeds from that offering to purchase i-units
from us. After commissions and underwriting expenses, we received net
proceeds of approximately $996.9 million for the issuance of 29,750,000
i-units to KMR. We used the proceeds from the i-unit issuance to reduce the
borrowings under our commercial paper program.
Also during the second quarter of 2001, after the issuance of additional
senior notes on March 12, 2001 and the issuance of i-units in May 2001, we
decreased our commercial paper program back to $600 million. On October 17,
2001, we increased our commercial paper program to $900 million. As of
December 31, 2001, we had $590.5 million of commercial paper outstanding with
an interest rate of 2.6585%.
On February 21, 2002, our commercial paper program increased to provide
for the issuance of up to $1.8 billion of commercial paper. We entered into
a $750 million unsecured 364-day credit facility to support this increase in
our
123
commercial paper program, and we used the program's increase in available
funds to close on the Tejas acquisition. After the issuance of additional
senior notes on March 14, 2002, we reduced our commercial paper program to
$1.25 billion.
On August 6, 2002, KMR issued in a public offering, an additional
12,478,900 of its shares, including 478,900 shares upon exercise by the
underwriters of an over-allotment option, at a price of $27.50 per share,
less commissions and underwriting expenses. The net proceeds from the
offering were used to buy i-units from us. After commissions and
underwriting expenses, we received net proceeds of approximately $331.2
million for the issuance of 12,478,900 i-units. We used the proceeds from
the i-unit issuance to reduce the borrowings under our commercial paper
program and, in conjunction with our issuance of additional i-units and as
previously agreed upon under the terms of our credit facilities, we reduced
our commercial paper program to provide for the issuance of up to $975
million of commercial paper as of December 31, 2002. On December 31, 2002,
we had $220.0 million of commercial paper outstanding with an average
interest rate of 1.58%.
The borrowings under our commercial paper program were used to finance
acquisitions made during 2001 and 2002. The borrowings under our commercial
paper program reduce the borrowings allowed under our credit facilities.
SFPP, L.P. Debt
At December 31, 2002, the outstanding balance under SFPP, L.P.'s Series F
notes was $37.1 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. We expect to repay the Series F notes prior to
maturity as a result of SFPP, L.P. taking advantage of certain optional
prepayment provisions without penalty in 1999 and 2000. We expect to pay the
remaining $37.1 million balance in December 2003. Additionally, the Series F
notes may be prepaid in full or in part at a price equal to par plus, in
certain circumstances, a premium. We agreed as part of the acquisition of
SFPP, L.P.'s operations (which constitute a significant portion of our
Pacific operations) not to take actions with respect to $190 million of SFPP,
L.P.'s debt that would cause adverse tax consequences for the prior general
partner of SFPP, L.P. The Series F notes are collateralized by mortgages on
substantially all of the properties of SFPP, L.P. The Series F notes contain
certain covenants limiting the amount of additional debt or equity that may
be issued by SFPP, L.P. and limiting the amount of cash distributions,
investments, and property dispositions by SFPP, L.P. We do not believe that
these restrictions will materially affect distributions to our partners.
Kinder Morgan Liquids Terminals LLC Debt
Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC
(see Note 3). As part of our purchase price, we assumed debt of $87.9
million, consisting of five series of Industrial Revenue Bonds. The bonds
consist of the following:
o $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due September
1, 2019;
o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,
2022;
o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due September
1, 2022;
o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,
2023; and
o $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,
2024.
In November 2001, we acquired a liquids terminal in Perth Amboy, New
Jersey from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation
Group, Ltd. (see Note 3). As part of our purchase price, we assumed $25.0
million of Economic Development Revenue Refunding Bonds issued by the New
Jersey Economic Development Authority. These bonds have a maturity date of
January 15, 2018. Interest on these bonds is computed on the basis of a year
of 365 or 366 days, as applicable, for the actual number of days elapsed
during Commercial Paper, Daily or Weekly Rate Periods and on the basis of a
360-day year consisting of twelve 30-day months during a Term Rate Period.
As of December 31, 2002, the interest rate was 1.05%. We have an outstanding
letter of credit issued by Citibank in the amount of $25.3 million that
backs-up the $25.0 million principal amount of the bonds and $0.3
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million of interest on the bonds for up to 42 days computed at 12% on a
per annum basis on the principal thereof.
Central Florida Pipeline LLC Debt
Effective January 1, 2001, we acquired Central Florida Pipeline LLC (see
Note 3). As part of our purchase price, we assumed an aggregate principal
amount of $40 million of Senior Notes originally issued to a syndicate of
eight insurance companies. The Senior Notes have a fixed annual interest
rate of 7.84% with repayments in annual installments of $5 million beginning
July 23, 2001. The final payment is due July 23, 2008. Interest is payable
semiannually on January 1 and July 23 of each year. At December 31, 2002,
Central Florida's outstanding balance under the Senior Notes was $30.0
million.
CALNEV Pipe Line LLC Debt
Effective March 30, 2001, we acquired CALNEV Pipe Line LLC (see Note 3).
As part of our purchase price, we assumed an aggregate principal amount of
$6.8 million of Senior Notes originally issued to a syndicate of five
insurance companies. The Senior Notes had a fixed annual interest rate of
10.07%. In June 2001, we prepaid the balance outstanding under the Senior
Notes, plus $0.9 million for interest and a make-whole premium, from cash on
hand.
Trailblazer Pipeline Company Debt
Credit Facility
At December 31, 2000, Trailblazer Pipeline Company had a $10 million
borrowing under an intercompany account payable in favor of KMI. In January
2001, Trailblazer Pipeline Company entered into a 364-day revolving credit
agreement with Credit Lyonnais New York Branch, providing for loans up to $10
million. The borrowings were used to pay the account payable to KMI. The
agreement was to expire on December 27, 2001, and provided for an interest
rate of LIBOR plus 0.875%. Pursuant to the terms of the revolving credit
agreement with Credit Lyonnais New York Branch, Trailblazer Pipeline Company
partnership distributions were restricted by certain financial covenants.
On June 26, 2001, Trailblazer Pipeline Company prepaid the balance
outstanding under its Senior Secured Notes using a new two-year unsecured
revolving credit facility with a bank syndication. The new facility, as
amended August 24, 2001, provided for loans of up to $85.2 million and had a
maturity date of June 29, 2003. The agreement provided for an interest rate
of LIBOR plus a margin as determined by certain financial ratios. Pursuant
to the terms of the revolving credit facility, Trailblazer Pipeline Company
partnership distributions were restricted by certain financial covenants. On
June 29, 2001, Trailblazer Pipeline Company paid the $10 million outstanding
balance under its 364-day revolving credit agreement and terminated that
agreement. At December 31, 2001, the outstanding balance under Trailblazer
Pipeline Company's two-year revolving credit facility was $55.0 million, with
a weighted average interest rate of 2.875%, which reflects three-month LIBOR
plus a margin of 0.875%. In July 2002, we paid the $31.0 million outstanding
balance under Trailblazer's revolving credit facility and terminated the
facility.
Senior Notes
On September 23, 1992, pursuant to 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. The Senior Secured Notes had a fixed annual interest rate of
8.03% and the $20.2 million balance as of December 31, 2000 was to be repaid
in semiannual installments of $5.05 million from March 1, 2001 through
September 1, 2002, the final maturity date. Interest was payable
semiannually in March and September. Trailblazer Pipeline Company provided
collateral for the notes principally by an assignment of certain Trailblazer
Pipeline Company transportation contracts, and pursuant to the terms of this
Note Purchase Agreement, Trailblazer Pipeline Company's partnership
distributions were restricted by certain financial covenants. Effective
April 29, 1997, Trailblazer Pipeline Company amended the Note Purchase
Agreement. This amendment allowed Trailblazer Pipeline Company to include
several additional transportation contracts as collateral for the notes,
added a limitation on the amount of additional money that Trailblazer
Pipeline Company could borrow and relieved Trailblazer
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Pipeline Company from its security deposit obligation. On June 26, 2001,
Trailblazer Pipeline Company prepaid the $15.2 million balance outstanding
under the Senior Secured Notes, plus $0.8 million for interest and a
make-whole premium, using its new two-year unsecured revolving credit
facility.
Kinder Morgan Operating L.P. "B" Debt
The $23.7 million principal amount of tax-exempt bonds due 2024 were
issued by the Jackson-Union Counties Regional Port District. These bonds
bear interest at a weekly floating market rate. During 2002, the
weighted-average interest rate on these bonds was 1.39% per annum, and at
December 31, 2002, the interest rate was 1.59%. We have an outstanding
letter of credit issued under our credit facilities that supports our
tax-exempt bonds. The letter of credit reduces the amount available for
borrowing under our credit facilities.
International Marine Terminals Debt
As of February 1, 2002, we owned a 66 2/3% interest in International
Marine Terminals partnership (see Note 3). The principal assets owned by IMT
are dock and wharf facilities financed by the Plaquemines Port, Harbor and
Terminal District (Louisiana) $40,000,000 Adjustable Rate Annual Tender Port
Facilities Revenue Refunding Bonds (International Marine Terminals Project)
Series 1984A and 1984B. The bonds mature on March 15, 2006. The bonds are
backed by two letters of credit issued by KBC Bank N.V. On March 19, 2002,
an Amended and Restated Letter of Credit Reimbursement Agreement relating to
the letters of credit in the amount of $45.5 million was entered into by IMT
and KBC Bank. In connection with that agreement, we agreed to guarantee the
obligations of IMT in proportion to our ownership interest. Our obligation
is approximately $30.3 million for principal, plus interest and other fees.
Maturities of Debt
The scheduled maturities of our outstanding debt, excluding market value
of interest rate swaps, at December 31, 2002, are summarized as follows (in
thousands):
2003......... $264,937
2004......... 5,018
2005......... 204,836
2006......... 45,019
2007......... 254,863
Thereafter... 2,884,860
---------
Total........ $3,659,533
==========
Of the $264.9 million scheduled to mature in 2003, we intend and have the
ability to refinance the entire amount on a long-term basis under our
existing credit facilities.
Fair Value of Financial Instruments
The estimated fair value of our long-term debt, excluding market value of
interest rate swaps, is based upon prevailing interest rates available to us
at December 31, 2002 and December 31, 2001 and is disclosed below.
Fair value as used in SFAS No. 107 "Disclosures About Fair Value of
Financial Instruments" represents the amount at which an instrument could be
exchanged in a current transaction between willing parties.
December 31, 2002 December 31, 2001
--------------------- ----------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
-------- ---------- -------- ----------
(In thousands)
Total Debt $3,659,533 $4,475,058 $2,797,234 $3,094,530
10. Pensions and Other Post-retirement Benefits
In connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired
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certain liabilities for pension and post-retirement benefits. We provide
medical and life insurance benefits to current employees, their covered
dependents and beneficiaries of SFPP and Kinder Morgan Bulk Terminals. We
also provide the same benefits to former salaried employees of SFPP.
Additionally, we will continue to fund these costs for those employees
currently in the plan during their retirement years.
The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Employee Benefit Plan for
Employees of Hall-Buck Marine Services Company and the benefits under this
plan were based primarily upon years of service and final average pensionable
earnings. Benefit accruals were frozen as of December 31, 1998 for the
Hall-Buck plan. Effective December 31, 2000, the Hall-Buck plan, along with
the K N Energy, Inc. Retirement Plan for Bargaining Employees, was merged
into the K N Energy, Inc. Retirement Plan for Non-Bargaining employees, with
the Non-Bargaining Plan being the surviving plan. The merged plan was
renamed the Kinder Morgan, Inc. Retirement Plan.
SFPP's post-retirement benefit plan is frozen and no additional
participants may join the plan.
Net periodic benefit costs and weighted-average assumptions for these
plans include the following components (in thousands):
2002 2001 2000
---------- ---------- ---------------------
Other Other Other
Post- Post- Post-
retirement retirement Pension retirement
Benefits Benefits Benefits Benefits
---------- ---------- -------- ----------
Net periodic benefit cost
Service cost............. $ 165 $ 120 $ -- $ 46
Interest cost............ 906 804 145 755
Expected return on plan
assets................... -- -- (170) --
Amortization of prior
service cost............ (545) (545) -- (493)
Actuarial gain........... -- (27) -- (290)
------- ------- ------ -------
Net periodic benefit cost $ 526 $ 352 $ (25) $ 18
======= ======= ====== =======
Additional amounts
recognized
Curtailment (gain) loss $ -- $ -- $ -- $ --
Weighted-average
assumptions as of
December 31:
Discount rate............ 6.50% 7.00% 7.5% 7.75%
Expected return on plan
assets.................. -- -- 8.5% --
Rate of compensation
increase................ 3.9% -- -- --
Information concerning benefit obligations, plan assets, funded status and
recorded values for these plans follows (in thousands):
2002 2001
--------------- ---------------
Other Other
Post-retirement Post-retirement
Benefits Benefits
--------------- ---------------
Change in benefit obligation
Benefit obligation at Jan. 1...... $ 13,368 $ 10,897
Service cost...................... 165 120
Interest cost..................... 906 804
Participant contributions......... 143 --
Amendments........................ (493) --
Actuarial (gain) loss............. (264) 2,350
Benefits paid from plan assets.... (550) (803)
--------- ---------
Benefit obligation at
Dec. 31.......................... $ 13,275 $ 13,368
========= =========
Change in plan assets
Fair value of plan assets
at Jan. 1........................ $ -- $ --
Actual return on plan assets...... -- --
Employer contributions............ 407 803
Participant contributions......... 143 --
Benefits paid from plan assets.... (550) (803)
--------- ---------
Fair value of plan assets
at Dec. 31....................... $ -- $ --
========= =========
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2002 2001
--------------- ---------------
Other Other
Post-retirement Post-retirement
Benefits Benefits
--------------- ---------------
Funded status.................... $(13,275) $(13,368)
Unrecognized net acturiral
(gain) loss..................... 729 993
Unrecognized prior
service (benefit)............... (1,059) (1,111)
Adj. for 4th qtr.
employer contributions........... 105 --
--------- ---------
Prepaid (accrued) benefit
cost............................ $(13,500) $(13,486)
========= =========
In 2001, SFPP modified benefits associated with its post-retirement
benefit plan. This plan amendment resulted in a $2.5 million increase in its
benefit obligation for 2001. The unrecognized prior service credit is
amortized on a straight-line basis over the remaining expected service to
retirement (2.5 years). For measurement purposes, a 11% annual rate of
increase in the per capita cost of covered health care benefits was assumed
for 2003. The rate was assumed to decrease gradually to 5% by 2009 and
remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A 1% change in assumed health
care cost trend rates would have the following effects:
1-Percentage 1-Percentage
Point Increase Point Decrease
-------------- --------------
Effect on total of service and
interest cost components............. $ 106 $ (89)
Effect on postretirement benefit
obligation........................... $1,148 $ (974)
Multiemployer Plans and Other Benefits
As a result of acquiring several terminal operations, primarily our
acquisition of Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, we
participate in several multi-employer pension plans for the benefit of
employees who are union members. We do not administer these plans and
contribute to them 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 $1.3 million for the year ended 2002 and $0.6 million for the year
ended 2001.
We assumed River Consulting, Inc.'s (a consolidated affiliate of Kinder
Morgan Bulk Terminals) savings plan under Section 401(k) of the Internal
Revenue Code. This savings plan allowed eligible employees to contribute up
to 10% of their compensation on a pre-tax basis, with us matching 2.5% of the
first 5% of the employees' wage. Matching contributions are vested at the
time of eligibility, which is one year after employment. Effective January
1, 1999, we merged this savings plan into the retirement savings plan of our
general partner (see next paragraph).
The Kinder Morgan Savings Plan, formerly the Kinder Morgan Retirement
Savings Plan, permits all full-time employees of KMGP Services Company, Inc.
and KMI to contribute 1% to 50% of base compensation, on a pre-tax basis,
into participant accounts. In addition to a mandatory contribution equal to
4% of base compensation per year for most plan participants, KMGP Services
Company, Inc. and KMI may make discretionary contributions in years when
specific performance objectives are met. Certain employees' contributions
are based on collective bargaining agreements. Our mandatory contributions
are made each pay period on behalf of each eligible employee. Any
discretionary contributions are made during the first quarter following the
performance year. All contributions, including discretionary contributions,
are in the form of KMI stock that is immediately convertible into other
available investment vehicles at the employee's discretion. In the first
quarter of 2003, no discretionary contributions were made to individual
accounts for 2002. The total amount charged to expense for our Savings Plan
was $5.6 million during 2002. 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 pursuant to a trust
agreement.
Effective January 1, 2001, employees of KMGP Services Company, Inc. and
KMI became eligible to participate in a new Cash Balance Retirement Plan.
Certain employees continue to accrue benefits through a career-pay formula,
"grandfathered" according to age and years of service on December 31, 2000,
or collective bargaining arrangements. All other employees will accrue
benefits through a personal retirement account in the new Cash Balance
Retirement Plan. Employees with prior service and not grandfathered convert
to the Cash Balance
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Retirement Plan and will be credited with the current fair value of any
benefits they have previously accrued through the defined benefit plan. We
will then begin contributions on behalf of these employees equal to 3% of
eligible compensation every pay period. In addition, discretionary
contributions are made to the plan based on our and KMI's performance. In the
first quarter of 2002, an additional 1% discretionary contribution was made to
individual accounts. No additional contributions were made for 2002 performance.
Interest will be credited to the personal retirement accounts at the 30-year
U.S. Treasury bond rate in effect each year. Employees become fully vested in
the plan after five years, and they may take a lump sum distribution upon
termination of employment or retirement.
11. Partners' Capital
At December 31, 2002, our partners' capital consisted of:
o 129,943,218 common units;
o 5,313,400 Class B units; and
o 45,654,048 i-units.
Together, these 180,910,666 units represent the limited partners' interest
and an effective 98% economic interest in the Partnership, exclusive of our
general partner's incentive distribution. Our general partner has an
effective 2% interest in the Partnership, excluding our general partner's
incentive distribution. At December 31, 2002, our common unit total
consisted of 116,987,483 units held by third parties, 11,231,735 units held
by KMI and its consolidated affiliates (excluding our general partner); and
1,724,000 units held by our general partner. Our Class B units were held
entirely by KMI and our i-units were held entirely by KMR.
At December 31, 2001, our Partners' capital consisted of:
o 129,855,018 common units;
o 5,313,400 Class B units; and
o 30,636,363 i-units.
Our total common units outstanding at December 31, 2001, consisted of
110,071,392 units held by third parties, 18,059,626 units held by KMI and its
consolidated affiliates (excluding our general partner) and 1,724,000 units
held by our general partner. Our Class B units were held entirely by KMI and
our i-units were held entirely by KMR.
All of our Class B units were issued in December 2000. The Class B units
are similar to our common units except that they are not eligible for trading
on the New York Stock Exchange. We initially issued 29,750,000 i-units in
May 2001. The i-units are a separate class of limited partner interests in
us. All of our i-units are owned by KMR and are not publicly traded. In
accordance with its limited liability company agreement, KMR's activities are
restricted to being a limited partner in, and controlling and managing the
business and affairs of, the Partnership, our operating partnerships and our
subsidiaries.
On August 6, 2002, KMR issued in a public offering, an additional
12,478,900 of its shares, including 478,900 shares upon exercise by the
underwriters of an over-allotment option, at a price of $27.50 per share,
less commissions and underwriting expenses. The net proceeds from the
offering were used to buy additional i-units from us. After commissions and
underwriting expenses, we received net proceeds of approximately $331.2
million for the issuance of 12,478,900 i-units. We used the proceeds from
the i-unit issuance to reduce the debt we incurred in our acquisition of
Kinder Morgan Tejas during the first quarter of 2002.
Through the combined effect of the provisions in our partnership agreement
and the provisions of KMR's limited liability company agreement, the number
of outstanding KMR shares and the number of i-units will at all times be
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equal. Furthermore, under the terms of our partnership agreement, we
agreed that we will not, except in liquidation, make a distribution on an
i-unit other than in additional i-units or a security that has in all
material respects the same rights and privileges as our i-units. The number
of i-units we distribute to KMR is based upon the amount of cash we
distribute to the owners of our common units. When cash is paid to the
holders of our common units, we will issue additional i-units to KMR. The
fraction of an i-unit paid per i-unit owned by KMR will have the same value
as the cash payment on the common unit.
The cash equivalent of distributions of i-units will be treated as if it
had actually been distributed for purposes of determining the distributions
to our general partner. We will not distribute the related cash but will
retain the cash and use the cash in our business. If additional units are
distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on
the preceding, KMR received a distribution of 937,658 i-units on November 14,
2002. These additional i-units distributed were based on the $0.61 per unit
distributed to our common unitholders on that date. For the year ended
December 31, 2002, KMR received distributions of 2,538,785 i-units. These
additional i-units distributed were based on the $2.36 per unit distributed
to our common unitholders during 2002.
For the purposes of maintaining partner capital accounts, our partnership
agreement specifies that items of income and loss shall be allocated among
the partners, other than owners of i-units, in accordance with their
percentage interests. Normal allocations according to percentage interests
are made, however, only after giving effect to any priority income
allocations in an amount equal to the incentive distributions that are
allocated 100% to our general partner. Incentive distributions are generally
defined as all cash distributions paid to our general partner that are in
excess of 2% of the aggregate value of cash and i-units being distributed.
Incentive distributions allocated to our general partner are determined by
the amount quarterly distributions to unitholders exceed certain specified
target levels. For the years ended December 31, 2002, 2001 and 2000, we
declared distributions of $2.435, $2.15 and $1.7125, respectively, per unit.
Our distributions to unitholders for 2002, 2001 and 2000 required incentive
distributions to our general partner in the amount of $267.4 million, $199.7
million and $107.8 million, respectively. The increased incentive
distributions paid for 2002 over 2001 and 2001 over 2000 reflect the increase
in amounts distributed per unit as well as the issuance of additional units.
On January 15, 2003, we declared a cash distribution for the quarterly
period ended December 31, 2002, of $0.625 per unit. This distribution was
paid on February 14, 2003, to unitholders of record as of January 31, 2003.
Our common unitholders and Class B unitholders received cash. KMR, our sole
i-unitholder, received a distribution in the form of additional i-units based
on the $0.625 distribution per common unit. The number of i-units
distributed was 858,981. For each outstanding i-unit that KMR held, a
fraction of an i-unit was issued. The fraction was determined by dividing:
o $0.625, the cash amount distributed per common unit
by
o $33.219, the average of KMR's limited liability shares' closing market
prices from January 14-28, 2003, the ten consecutive trading days
preceding the date on which the shares began to trade ex- dividend under
the rules of the New York Stock Exchange.
This February 14, 2003 distribution required an incentive distribution to
our general partner in the amount of $72.5 million. Since this distribution
was declared after the end of the quarter, no amount is shown in the December
31, 2002 balance sheet as a Distribution Payable.
12. Related Party Transactions
General and Administrative Expenses
KMGP Services Company, Inc. provides employees and KMR, through its wholly
owned subsidiary, Kinder Morgan Services LLC, provides centralized payroll
and employee benefits services to us, our operating partnerships
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and subsidiaries, Kinder Morgan G.P., Inc. and KMR (collectively, the
"Group"). Employees of KMGP Services Company, Inc. are assigned to work for
one or more members of the Group. The direct costs of all compensation,
benefits expenses, employer taxes and other employer expenses for these
employees are allocated and charged by Kinder Morgan Services LLC to the
appropriate members of the Group, and the members of the Group reimburse
Kinder Morgan Services LLC for their allocated shares of these direct costs.
There is no profit or margin charged by Kinder Morgan Services LLC to the
members of the Group. The administrative support necessary to implement
these payroll and benefits services is provided by the human resource
department of KMI, and the related administrative costs are allocated to
members of the Group in accordance with existing expense allocation
procedures. The effect of these arrangements is that each member of the
Group bears the direct compensation and employee benefits costs of its
assigned or partially assigned employees, as the case may be, while also
bearing its allocable share of administrative costs. Pursuant to our limited
partnership agreement, we provide reimbursement for our share
of these administrative costs and such reimbursements will be accounted for
as described above.
The named executive officers of our general partner and KMR and some other
employees that provide management or services to both KMI and the Group are
employed by KMI. Additionally, other KMI employees assist in the operation
of our Natural Gas Pipeline assets formerly owned by KMI. These KMI
employees' expenses are allocated without a profit component between KMI and
the appropriate members of the Group.
Partnership Distributions
Kinder Morgan G.P., Inc.
Kinder Morgan G.P., Inc. serves as our sole general partner. Pursuant to
our partnership agreements, our general partner's interests represent a 1%
ownership interest in the Partnership, and a direct 1.0101% ownership
interest in each of our five operating partnerships. Collectively, our
general partner owns an effective 2% interest in the operating partnerships,
excluding incentive distributions as follows:
o its 1.0101% direct general partner ownership interest (accounted for as
minority interest in the consolidated financial statements of the
Partnership); and
o its 0.9899% ownership interest indirectly owned via its 1% ownership
interest in the Partnership.
At December 31, 2002, our general partner owned 1,724,000 common units,
representing approximately 0.95% of our outstanding limited partner units.
Our partnership agreement requires that we distribute 100% of available cash
as defined in our partnership agreement to our partners within 45 days
following the end of each calendar quarter in accordance with their
respective percentage interests. Available cash consists generally of all of
our cash receipts, including cash received by our 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 general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement,
which discretion has been delegated to KMR, subject to the approval of our
general partner in certain cases, to establish, maintain and adjust reserves
for future operating expenses, debt service, maintenance capital
expenditures, rate refunds and distributions for the next four quarters.
These reserves are not restricted by magnitude, but only by type of future
cash requirements with which they can be associated. When KMR determines our
quarterly distributions, it considers current and expected reserve needs
along with current and expected cash flows to identify the appropriate
sustainable distribution level.
Our general partner and owners of our common units and Class B units
receive distributions in cash, while KMR, the sole owner of our i-units,
receives distributions in additional i-units or fractions of i-units. For
each outstanding i-unit, a fraction of an i-unit will be issued. The
fraction is calculated by dividing the amount of cash being distributed per
common unit by the average market price of KMR's limited liability shares
over the ten consecutive trading days preceding the date on which the shares
begin to trade ex-dividend under the rules of the New York Stock Exchange.
The cash equivalent of distributions of i-units will be treated as if it had
actually been distributed, including for purposes of determining the
distributions to our general partner and calculating available cash for
future periods. We will not distribute the related cash but will retain the
cash and use the cash in our business.
131
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to
provide for incentive distributions to be paid to our general partner in the
event that quarterly distributions to unitholders exceed certain specified
targets.
Available cash for each quarter is distributed as follows;
o first, 98% to the owners of all classes of units pro rata and 2% to our
general partner until the owners of all classes of units have received a
total of $0.15125 per unit in cash or equivalent i-units for such
quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the
owners of all classes of units have received a total of $0.17875 per
unit in cash or equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the
owners of all classes of units have received a total of $0.23375 per
unit in cash or equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units
in cash and to owners of i-units in the equivalent number of i-units,
and 50% to our general partner.
Incentive distributions are generally defined as all cash distributions
paid to our general partner that are in excess of 2% of the aggregate value
of cash and i-units being distributed. Our general partner's declared
incentive distributions for the years ended December 31, 2002, 2001 and 2000
were $267.4 million, $199.7 million and $107.8 million, respectively.
Kinder Morgan, Inc.
KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the
sole stockholder of our general partner. At December 31, 2002, KMI directly
owned 6,523,650 common units and 5,313,400 Class B units, indirectly owned
6,432,085 common units owned by its consolidated affiliates, including our
general partner and owned 13,511,726 KMR shares, representing an indirect
ownership interest of 13,511,726 i-units. Together, these units represent
approximately 17.6% of our outstanding limited partner units. Including both
its general and limited partner interests in us, at the 2002 distribution
level, KMI received approximately 51% of all quarterly distributions from us,
of which approximately 40% is attributable to its general partner interest
and 11% is attributable to its limited partner interest. The actual level of
distributions KMI will receive in the future will vary with the level of
distributions to the limited partners determined in accordance with our
partnership agreement.
Kinder Morgan Management, LLC
KMR, our general partner's delegate, remains the sole owner of our
45,654,048 i-units.
Asset Acquisitions
2000 Kinder Morgan, Inc. Asset Contributions
Effective December 31, 2000, we acquired over $621.7 million of assets
from KMI. As consideration for these assets, we paid to KMI $192.7 million
in cash and approximately $156.3 million in units, consisting of 1,280,000
common units and 5,313,400 Class B units. We also assumed liabilities of
approximately $272.7 million. We acquired Kinder Morgan Texas Pipeline, L.P.
and MidCon NGL Corp. (both of which were converted to single-member limited
liability companies), the Casper and Douglas natural gas gathering and
processing systems, a 50% interest in Coyote Gas Treating, LLC and a 25%
interest in Thunder Creek Gas Services, LLC. The purchase price for the
transaction was determined by the boards of directors of KMI and our general
partner based on pricing principles used in the acquisition of similar
assets. The transaction was approved unanimously by the independent
132
directors of our general partner, with the benefit of independent financial and
legal advisors, including a fairness opinion from the investment banking firm
A.G. Edwards & Sons, Inc.
Mexican Entity Transfer
In the fourth quarter of 2002, KMI transferred to us its interests in
Kinder Morgan Natural Gas de Mexico, S. de R.L. de C.V., hereinafter referred
to as KM Mexico. KM Mexico is the entity through which we are developing the
Mexican portion of our Mier-Monterrey natural gas pipeline that connects to
the southern tip of Kinder Morgan Texas Pipeline, L.P.'s intrastate pipeline,
hereinafter referred to the Monterrey Project. The Monterrey Project was
initially conceived at KMI in 1996 and between 1996 and 1998 KMI and its
subsidiaries paid, on behalf of KM Mexico, approximately $2.5 million in
connection with the Monterrey Project to explore the feasibility of and to
obtain permits for the Mexican portion of the project. Following 1998, the
Monterrey Project was dormant at KMI.
In December 2000, when KMI contributed to us Kinder Morgan Texas Pipeline,
L.P., the entity that had been primarily responsible for the Monterrey
Project, the Monterrey Project was still dormant (and thought likely to
remain dormant indefinitely). Consequently, KM Mexico was not contributed to
us at that time.
In 2002, Kinder Morgan Texas Pipeline, L.P. reassessed the Monterrey
Project and determined that the Monterrey Project was an economically
feasible project for us. Accordingly, KMI's Board of Directors on the one
hand, and KMR and our general partner's Boards of Directors on the other
hand, unanimously determined, respectively, that KMI should transfer KM
Mexico to us for approximately $2.5 million, the amount paid by KMI and its
subsidiaries, on KM Mexico's behalf, in connection with the Monterrey Project
between 1996 and 1998.
Operations
KMI or its subsidiaries operate and maintain for us the assets comprising
our Natural Gas Pipelines business segment. Natural Gas Pipeline Company of
America, a subsidiary of KMI, operates Trailblazer Pipeline Company's assets
under a long-term contract pursuant to which Trailblazer Pipeline Company
incurs the costs and expenses related to NGPL's operating and maintaining the
assets. Trailblazer Pipeline Company provides the funds for capital
expenditures. NGPL does not profit from or suffer loss related to its
operation of Trailblazer Pipeline Company's assets.
The remaining assets comprising our Natural Gas Pipelines business segment
are operated under agreements between KMI and us. The agreements have
five-year terms and contain automatic five-year extensions. Pursuant to the
applicable underlying agreements, we pay KMI either a fixed amount or actual
costs incurred as reimbursement for the corporate general and administrative
expenses incurred in connection with the operation of these assets. The
amounts paid to KMI for corporate general and administrative costs, including
amounts related to Trailblazer Pipeline Company, were $13.3 million of fixed
costs and $2.8 million of actual costs incurred for 2002, and $9.5 million of
fixed costs and $3.2 million of actual costs incurred for 2001. Commencing in
2003, KMI will be operating additional pipeline assets, including our North
System and Cypress Pipeline, which are part of our Products Pipelines business
segment, as well as our Monterrey Pipeline, which is currently under
construction and will be part of our Natural Gas Pipelines business segment. We
estimate the total reimbursement to be paid to KMI in respect of all pipeline
assets operated by KMI and its subsidiaries for us for 2003 will be
approximately $19.7 million, which includes $14.4 million of fixed costs
(adjusted for inflation) and $5.3 million of actual costs. We believe the
amounts paid to KMI for the services they provided each year fairly reflect the
value of the services performed. However, due to the nature of the allocations,
these reimbursements may not have exactly matched the actual time and overhead
spent. We believe the agreed-upon amounts were, at the time the contracts were
entered into, a reasonable estimate of the corporate general and administrative
expenses to be incurred by KMI and its subsidiaries in performing such services.
We also reimburse KMI and its subsidiaries for operating and maintenance costs
and capital expenditures incurred with respect to these assets.
Other
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to
herein as Coyote Gulch. Coyote Gulch is a joint venture, and El Paso Field
Services Company owns the remaining 50% equity interest. We are the managing
partner of Coyote Gulch. As of December 31, 2002, Coyote's balance sheet has
current notes payable to
133
each partner in the amount of $17.1 million. These notes are due on June
30, 2003. At that time, the partners can either renew the notes or make
capital contributions which enable Coyote to payoff the existing notes.
Generally, KMR makes all decisions relating to the management and control
of our business. Our general partner owns all of KMR's voting securities and is
its sole managing member. KMI, through its wholly owned and controlled
subsidiary Kinder Morgan (Delaware), Inc., owns all the common stock of our
general partner. Certain conflicts of interest could arise as a result of the
relationships among KMR, our general partner, KMI and us. 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, KMR has a fiduciary duty to
manage us in a manner beneficial to our unitholders. The partnership agreements
for us and our operating partnerships contain provisions that allow KMR to take
into account the interests of parties in addition to us in resolving conflicts
of interest, thereby limiting its fiduciary duty to our 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 partnership agreements provide that in the absence of bad faith by
KMR, the resolution of a conflict by KMR will not be a breach of any duties. The
duty of the directors and officers of KMI to the shareholders of KMI may,
therefore, come into conflict with the duties of KMR and its directors and
officers to our unitholders. The Conflicts and Audit Committee of KMR's board of
directors will, at the request of KMR, 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 us, on the other hand.
13. Leases and Commitments
Operating Leases
We have entered into certain operating leases. Including probable
elections to exercise renewal options, the remaining terms on our leases
range from one to 41 years. Future commitments related to these leases at
December 31, 2002 are as follows (in thousands):
2003...................... $ 18,747
2004...................... 15,128
2005...................... 13,206
2006...................... 11,819
2007...................... 9,545
Thereafter................ 55,545
--------
Total minimum payments.... $123,990
========
We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $1.6 million. Total lease and rental
expenses, including related variable charges were $21.6 million for 2002,
$41.1 million for 2001 and $7.5 million for 2000.
Common Unit Option Plan
During 1998, we established a common unit option plan, which provides that
key personnel of KMGP Services Company, Inc. and KMI are eligible to receive
grants of options to acquire common units. The number of common units
available under the option plan is 500,000. The option plan terminates in
March 2008. As of December 31, 2002 and 2001, outstanding options for
261,600 and 379,400 common units had been granted to certain personnel with a
term of seven years at an average exercise price of approximately $17.30 per
unit. During 2002, 88,200 options were exercised at an average price of
$17.77 per unit. These options had an average fair market value of $34.24
per unit. During 2001, 55,200 options were exercised at an average price of
$17.52 per unit. These options had an average fair market value of $33.26
per unit. In addition, as of December 31, 2002, outstanding options for
20,000 common units, at an average exercise price of $20.58 per unit, had
been granted to two of Kinder Morgan G.P., Inc.'s three non-employee
directors. The options granted generally have a term of seven years, vest
40% on the first anniversary of the date of grant and 20% on each of the next
three anniversaries, and have exercise prices equal to the market price of
the common units at the grant date.
We apply Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations in accounting for common
unit options granted under our common unit 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
134
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.
Other
Effective January 17, 2002, our general partner entered into a retention
agreement with C. Park Shaper, an officer of our general partner and its
delegate. Pursuant to the terms of the agreement, Mr. Shaper obtained a $5
million personal loan guaranteed by us. Mr. Shaper was required to purchase
KMI common shares and our common units in the open market with the loan
proceeds. If he voluntarily leaves us prior to the end of five years, then
he must repay the entire loan. After five years, provided Mr. Shaper has
continued to be employed by our general partner, we and KMI will assume Mr.
Shaper's obligations under the loan. The agreement contains provisions that
address termination for cause, death, disability and change of control.
We have an Executive Compensation Plan for certain executive officers of
our general partner. We may, at our option and with the approval of our
unitholders, pay the participants in units instead of cash. Eligible awards
are equal to a percentage of an incentive compensation value, which is equal
to a formula based upon the cash distributions paid to our general partner
during the four calendar quarters preceding the date of redemption multiplied
by eight. The amount of these awards are accrued as compensation expense and
adjusted quarterly. Under the plan, no eligible employee may receive a grant
in excess of 2% of the incentive compensation value and total awards under
the plan may not exceed 10% of the incentive compensation value. The plan
terminates January 1, 2007, and any unredeemed awards will be automatically
redeemed. At December 31, 2002, there were no outstanding awards granted
under our Executive Compensation Plan.
Contingent Debt
Cortez Pipeline Company Debt
Pursuant to a certain Throughput and Deficiency Agreement, the owners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% owner; a
subsidiary of Exxon Mobil Corporation - 37% owner; and Cortez Vickers
Pipeline Company - 13% owner) are required, on a percentage ownership basis,
to contribute capital to Cortez Pipeline Company in the event of a cash
deficiency. The Throughput and Deficiency Agreement contractually supports
the borrowings of Cortez Capital Corporation, a wholly-owned subsidiary of
Cortez Pipeline Company, by obligating the owners of Cortez Pipeline Company
to fund cash deficiencies at Cortez Pipeline Company, including cash
deficiencies relating to the repayment of principal and interest on
borrowings by Cortez Capital Corporation. Parent companies of the respective
Cortez Pipeline Company owners further severally guarantee, on a percentage
basis, the obligations of the Cortez Pipeline Company owners under the
Throughput and Deficiency Agreement.
Due to our indirect ownership of Cortez Pipeline Company through Kinder
Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez
Capital Corporation. Shell Oil Company shares our guaranty obligations
jointly and severally through December 31, 2006 for Cortez Capital
Corporation's debt programs in place as of April 1, 2000.
At December 31, 2002, the debt facilities of Cortez Capital Corporation
consisted of:
o $115.7 million of Series D notes due May 15, 2013;
o a $175 million short-term commercial paper program; and
o a $175 million committed revolving credit facility due December 26, 2003
(to support the above-mentioned $175 million commercial paper program).
At December 31, 2002, Cortez Capital Corporation had $140.6 million of
commercial paper outstanding with an interest rate of 1.39%, the average
interest rate on the Series D notes was 6.9322% and there were no borrowings
under the credit facility.
135
Plantation Pipeline Company Debt
On April 30, 1997, Plantation Pipeline Company entered into a $10 million,
ten-year floating-rate term credit agreement. We, as an owner of Plantation
Pipeline Company, severally guarantee this debt on a pro rata basis
equivalent to our respective 51% ownership interest. During 1999, this
agreement was amended to reduce the maturity date by three years. The $10
million is outstanding at December 31, 2002.
Red Cedar Gas Gathering Company Debt
In October 1998, Red Cedar Gas Gathering Company sold $55 million in
aggregate principal amount of Senior Notes due October 31, 2010. The $55
million was sold in 10 different notes in varying amounts with identical
terms.
The Senior Notes are secured by a first priority lien on the ownership
interests, including our 49% ownership interest, in Red Cedar Gas Gathering
Company. The Senior Notes are also guaranteed by us and the other owner of
Red Cedar Gas Gathering Company. The principal is to be repaid in seven
equal installments beginning on October 31, 2004 and ending on October 31,
2009, with any remainder due October 31, 2010. The $55 million is
outstanding at December 31, 2002.
Nassau County, Florida Ocean Highway and Port Authority Debt
Nassau County, Florida Ocean Highway and Port Authority is a political
subdivision of the state of Florida. During 1990, Ocean Highway and Port
Authority issued its Adjustable Demand Revenue Bonds in the aggregate
principal amount of $38.5 million for the purpose of constructing certain
port improvements located in Fernandino Beach, Nassau County, Florida. A
letter of credit was issued as security for the Adjustable Demand Revenue
Bonds and was guaranteed by the parent company of Nassau Terminals, Inc., the
operator of the port facilities. In July 2002, we acquired Nassau Terminals,
Inc. and became guarantor under the letter of credit agreement. In December
2002, we issued a $28 million letter of credit under our credit facilities
and the former letter of credit guarantee was terminated.
14. Risk Management
Hedging Activities
Certain of our business activities expose us to risks associated with
changes in the market price of natural gas, natural gas liquids, crude oil
and carbon dioxide. Through KMI, we use energy financial instruments to
reduce our risk of changes in the prices of natural gas, natural gas liquids
and crude oil markets (and carbon dioxide to the extent contracts are tied to
crude oil prices) as discussed below. The fair value of these risk
management instruments reflects the estimated amounts that we would receive
or pay to terminate the contracts at the reporting date, thereby taking into
account the current unrealized gains or losses on open contracts. We have
available market quotes for substantially all of the financial instruments
that we use.
The energy risk management products that we use include:
o commodity futures and options contracts;
o fixed-price swaps; and
o basis swaps.
Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated
with:
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o pre-existing or anticipated physical natural gas, natural gas liquids
and crude oil sales;
o pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;
o natural gas purchases; and
o system use and storage.
Our risk management activities are only used in order to protect our
profit margins and our risk management policies prohibit us from engaging in
speculative trading. Commodity-related activities of our risk management
group are monitored by our Risk Management Committee, which is charged with
the review and enforcement of our management's risk management policy.
As a result of our adoption of SFAS No. 133, as discussed in Note 2, we
recorded a cumulative effect adjustment in other comprehensive income of
$22.8 million representing the fair value of our derivative financial
instruments utilized for hedging activities as of January 1, 2001. During
the year ended December 31, 2001, $16.6 million of this initial adjustment
was reclassified to earnings as a result of hedged sales and purchases during
the period. During 2001, we reclassified a total of $51.5 million to
earnings as a result of hedged sales and purchases during the period.
The gains and losses included in Accumulated other comprehensive income
will be reclassified into earnings as the hedged sales and purchases take
place. Approximately $42.5 million of the Accumulated other comprehensive
loss balance of $45.3 million representing unrecognized net losses on
derivative activities at December 31, 2002 is expected to be reclassified
into earnings during the next twelve months. During 2002, we reclassified
$7.5 million of the accumulated other comprehensive income balance of $63.8
million representing unrecognized net losses on derivative activities at
December 31, 2001 into earnings. For each of the years ended December 31,
2002 and 2001, we did not reclassify any gains or losses into earnings as a
result of the discontinuance of cash flow hedges due to a determination that
the forecasted transactions will no longer occur by the end of the originally
specified time period.
Purchases or sales of commodity contracts require a dollar amount to be
placed in margin accounts. In addition, through KMI, we are required to post
margins with certain over-the-counter swap partners. These margin
requirements are determined based upon credit limits and mark-to-market
positions. Our margin deposits associated with commodity contract positions
were $1.9 million at December 31, 2002 and $20.0 million on December 31,
2001. Our margin deposits associated with over-the-counter swap partners
were $0.0 million on December 31, 2002 and ($42.1) million on December 31,
2001.
We recognized a gain of $0.7 million during 2002 and a loss of $1.3
million during 2001 as a result of ineffective hedges. These amounts are
reported within the caption Operations and maintenance in the accompanying
Consolidated Statements of Income. For each of the years ended December 31,
2002 and 2001, we did not exclude any component of the derivative
instruments' gain or loss from the assessment of hedge effectiveness.
The differences between the current market value and the original physical
contracts value associated with our hedging activities are primarily
reflected as Other current assets and Accrued other current liabilities in
the accompanying consolidated balance sheets. At December 31, 2002, our
balance of $104.5 million of Other current assets included approximately
$57.9 million related to risk management hedging activities, and our balance
of $298.7 million of Accrued other current liabilities included approximately
$101.3 million related to risk management hedging activities. At December
31, 2001, our balance of $194.9 million of Other current assets included
approximately $163.7 million related to risk management hedging activities,
and our balance of $209.9 million of Accrued other current liabilities
included approximately $117.8 million related to risk management hedging
activities.
The remaining differences between the current market value and the
original physical contracts value associated with our hedging activities are
reflected as deferred charges or deferred credits in the accompanying
consolidated balance sheets. At December 31, 2002, our balance of $250.8
million of Deferred charges and other assets included
137
approximately $5.7 million related to risk management hedging activities,
and our balance of $199.8 million of Other long-term liabilities and deferred
credits included approximately $8.5 million related to risk management
hedging activities. At December 31, 2001, our balance of $75.0 million of
Deferred charges and other assets included approximately $22.0 million
related to risk management hedging activities, and our balance of $246.5
million of Other long-term liabilities and deferred credits included
approximately $4.7 million related to risk management hedging activities.
Prior to 2001, we accounted for gain/loss on our over-the-counter swaps
and marked our open futures position to market value. Such items were
deferred on the balance sheet and reflected in current receivables, other
current assets, accrued other current liabilities, deferred charges or
deferred credits in our consolidated balance sheets. In all instances, these
deferrals are offset by the corresponding value of the underlying physical
transactions. In the event energy financial instruments are terminated prior
to the period of physical delivery of the items being hedged, the gains and
losses on the energy financial instruments at the time of termination remain
deferred until the period of physical delivery.
Given our portfolio of businesses as of December 31, 2002, our principal
uses of derivative financial instruments will be to mitigate the risk
associated with market movements in the price of energy commodities. Our net
short natural gas derivatives position primarily represents our hedging of
anticipated future natural gas purchases and sales. Our net short crude oil
derivatives position represents our crude oil derivative purchases and sales
made to hedge anticipated oil purchases and sales. In addition, crude oil
contracts have been sold to hedge anticipated carbon dioxide purchases and
sales that have pricing tied to crude oil prices. Finally, our net short
natural gas liquids derivatives position reflects the hedging of our
forecasted natural gas liquids purchases and sales. As of December 31, 2002,
the maximum length of time over which we have hedged our exposure to the
variability in future cash flows associated with commodity price risk is
through December 2007.
As of December 31, 2002, our commodity contracts and over-the-counter
swaps and options (in thousands) consisted of the following:
Over the
Counter
Swaps and
Commodity Options
Contracts Contracts Total
--------- --------- --------
(Dollars in thousands)
Deferred Net (Loss) Gain........................ $ (926) $ (49,323) $ (50,249)
Contract Amounts-- Gross........................ $ 117,778 $ 881,609 $ 999,387
Contract Amounts-- Net.......................... $ (862) $ (465,082) $ (465,944)
(Number of contracts(1))
Natural Gas
Notional Volumetric Positions: Long........... 1,439 5,208 6,647
Notional Volumetric Positions: Short.......... (1,028) (6,854) (7,882)
Net Notional Totals to Occur in 2003.......... 411 (1,391) (980)
Net Notional Totals to Occur in 2004 and Beyond -- (255) (255)
Crude Oil
Notional Volumetric Positions: Long........... 84 678 762
Notional Volumetric Positions: Short.......... (879) (18,457) (19,336)
Net Notional Totals to Occur in 2003.......... (795) (5,005) (5,800)
Net Notional Totals to Occur in 2004 and Beyond -- (12,774) (12,774)
Natural Gas Liquids
Notional Volumetric Positions: Long........... -- -- --
Notional Volumetric Positions: Short.......... -- (964) (964)
Net Notional Totals to Occur in 2003.......... -- (588) (588)
Net Notional Totals to Occur in 2004 and Beyond -- (376) (376)
__________
(1) A term of reference describing a unit of commodity trading. One natural
gas contract equals 10,000 MMBtus. One crude oil or natural gas liquids
contract equals 1,000 barrels.
Our over-the-counter swaps and options are with a number of parties, each
of which has an investment grade credit rating. We both owe money and are
owed money under these financial instruments. At December 31, 2002, if all
parties owing us failed to pay us amounts due under these arrangements, our
credit loss would be $9.5 million.
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At December 31, 2002, our largest credit exposure to a single
counterparty was $4.2 million. In addition, defaults by counterparties under
over-the-counter swaps and options could expose us to additional commodity
price risks in the event that we are unable to enter into replacement
contracts for such swaps and options on substantially the same terms.
Alternatively, we may need to pay significant amounts to the new
counterparties to induce them to enter into replacement swaps and options on
substantially the same terms.
During the fourth quarter of 2001, we determined that Enron Corp. was no
longer likely to honor the obligations it had to us in conjunction with
derivatives we were accounting for as hedges under SFAS No. 133. Upon making
that determination, we:
o ceased to account for those derivatives as hedges;
o entered into new derivative transactions on substantially similar terms
with other counterparties to replace our position with Enron;
o designated the replacement derivative positions as hedges of the
exposures that had been hedged with the Enron positions; and
o recognized a $6.0 million loss (included with General and administrative
expenses in the accompanying Consolidated Statement of Operations for
2001) in recognition of the fact that it was unlikely that we would be
paid the amounts then owed under the contracts with Enron.
While we enter into derivative transactions only with investment grade
counterparties and actively monitor their credit ratings, it is nevertheless
possible that additional losses will result from counterparty credit risk in
the future.
Interest Rate Swaps
In order to maintain a cost effective capital structure, it is our policy
to borrow funds using a mix of fixed rate debt and variable rate debt. As of
December 31, 2002 and 2001, respectively, we were a party to interest rate
swap agreements with a notional principal amount of $1.95 billion and $900
million, respectively, for the purpose of hedging the interest rate risk
associated with our fixed and variable rate debt obligations.
As of December 31, 2002, a notional principal amount of $1.75 billion of
these agreements effectively converts the interest expense associated with
the following series of our senior notes from fixed rates to variable rates
based on an interest rate of LIBOR plus a spread:
o $200 million principal amount of our 8.0% senior notes due March 15,
2005;
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February 1,
2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
o $300 million principal amount of our 7.40% senior notes due March 15,
2031;
o $200 million principal amount of our 7.75% senior notes due March 15,
2032; and
o $400 million principal amount of our 7.30% senior notes due August 15,
2033.
These swap agreements have termination dates that correspond to the
maturity dates of the related series of senior notes, therefore, as of
December 31, 2002, the maximum length of time over which we have hedged our
exposure to the variability in future cash flows associated with interest
rate risk is through August 2033. The swap agreements related to our 7.40%
senior notes contain mutual cash-out provisions at the then-current economic
value every seven years. The swap agreements related to our 7.125% senior
notes contain cash-out provisions at the then-current economic value at March
15, 2009. The swap agreements related to our 7.75% senior notes and our
7.30%
139
senior notes contain mutual cash-out provisions at the then-current
economic value every five years. These interest rate swaps have been
designated as fair value hedges as defined by SFAS No. 133. SFAS No. 133
designates derivatives that hedge a recognized asset or liability's exposure
to changes in their fair value as fair value hedges and the gain or loss on
fair value hedges are to be recognized in earnings in the period of change
together with the offsetting loss or gain on the hedged item attributable to
the risk being hedged. The effect of that accounting is to reflect in
earnings the extent to which the hedge is not effective in achieving
offsetting changes in fair value.
As of December 31, 2002, we also have swap agreements that effectively
convert the interest expense associated with $200 million of our variable
rate debt to fixed rate. The maturity dates of these swap agreements range
from September 2, 2003 to August 1, 2005. In the prior year, this hedge was
designated a fair value hedge on our $200 million Floating Rate Senior Notes,
which were retired in March 2002. Subsequent to the repayment of our
Floating Rate Senior Notes, the swaps were designated as a cash flow hedge of
the risk associated with changes in the designated benchmark interest rate
(in this case, one-month LIBOR) related to forecasted payments associated
with interest on an aggregate of $200 million of our portfolio of commercial
paper.
In addition, our interest rate swaps meet the conditions required to
assume no ineffectiveness under SFAS No. 133 and, therefore, we have
accounted for them using the "shortcut" method prescribed for fair value
hedges by SFAS No. 133. Accordingly, we adjust the carrying value of each
swap to its fair value each quarter, with an offsetting entry to adjust the
carrying value of the debt securities whose fair value is being hedged. We
record interest expense equal to the variable rate payments or fixed rate
payments under the swaps. Interest expense is accrued monthly and paid
semi-annually. At December 31, 2002, we recognized an asset of $179.1
million and a liability of $12.1 million for the $167.0 million net fair
value of our swap agreements, and we included these amounts with Deferred
charges and other assets and Other long-term liabilities and deferred credits
on the accompanying balance sheet. The offsetting entry to adjust the
carrying value of the debt securities whose fair value was being hedged was
recognized as Market value of interest rate swaps on the accompanying balance
sheet. At December 31, 2001, we recognized a liability of $5.4 million for
the net fair value of our swap agreements and we included this amount with
Other long-term liabilities and deferred credits on the accompanying balance
sheet, and again, the offsetting entry to adjust the carrying value of the
debt securities whose fair value was being hedged was recognized as Market
value of interest rate swaps on the accompanying balance sheet.
We are exposed to credit related losses in the event of nonperformance by
counterparties to these interest rate swap agreements. While we enter into
derivative transactions only with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that from
time to time losses will result from counterparty credit risk.
15. Reportable Segments
We divide our operations into four reportable business segments (see Note 1):
o Products Pipelines;
o Natural Gas Pipelines;
o CO2 Pipelines; and
o Terminals.
Each segment uses the same accounting policies as those described in the
summary of significant accounting policies (see Note 2). We evaluate
performance based on each segments' earnings, which exclude general and
administrative expenses, third-party debt costs, interest income and expense
and minority interest. Our reportable segments are strategic business units
that offer different products and services. Each segment is managed
separately because each segment involves different products and marketing
strategies.
Our Products Pipelines segment derives its revenues primarily from the
transportation of refined petroleum products, including gasoline, diesel
fuel, jet fuel and natural gas liquids. Our Natural Gas Pipelines segment
derives
140
its revenues primarily from the sale, gathering, transmission and storage
of natural gas. Our CO2 Pipelines segment derives its revenues primarily
from the marketing and transportation of carbon dioxide used as a flooding
medium for recovering crude oil from mature oil fields and from the
production of crude oil from fields in the Permian Basin of West Texas. Our
Terminals segment derives its revenues primarily from the transloading and
storing of refined petroleum products and dry and liquid bulk products,
including coal, petroleum coke, cement, alumina, salt, and chemicals.
Financial information by segment follows (in thousands):
2002 2001 2000
---- ---- ----
Revenues
Products Pipelines............. $ 576,542 $ 605,392 $ 420,272
Natural Gas Pipelines.......... 3,086,187 1,869,315 174,187
CO2 Pipelines.................. 146,280 122,094 89,214
Terminals...................... 428,048 349,875 132,769
----------- ----------- -----------
Total consolidated revenues.... $4,237,057 $2,946,676 $ 816,442
=========== =========== ===========
Operating income
Products Pipelines............. $ 342,372 $ 298,991 $ 195,057
Natural Gas Pipelines.......... 253,498 171,899 97,349
CO2 Pipelines.................. 66,560 59,559 48,059
Terminals...................... 180,725 142,672 39,523
----------- ----------- -----------
Total segment operating income. 843,155 673,121 379,988
Corporate administrative
expenses..................... (118,857) (109,293) (64,427)
----------- ----------- -----------
Total consolidated operating
income........................ $ 724,298 $ 563,828 $ 315,561
=========== =========== ===========
Earnings from equity investments, net of
amortization of excess costs
Products Pipelines............ $ 25,717 $ 22,686 $ 29,105
Natural Gas Pipelines......... 23,610 21,156 14,975
CO2 Pipelines................. 34,311 31,981 19,328
Terminals..................... 45 -- --
----------- ----------- -----------
Consolidated equity earnings,
net of amortization.......... $ 83,683 $ 75,823 $ 63,408
=========== =========== ===========
Interest revenue
Products Pipelines.............. $ -- $ -- $ --
Natural Gas Pipelines........... -- -- --
CO2 Pipelines................... -- -- --
Terminals....................... -- -- --
----------- ----------- -----------
Total segment interest revenue.. -- -- --
----------- ----------- -----------
Unallocated interest revenue.... 1,819 4,473 3,818
----------- ----------- -----------
Total consolidated interest $ 1,819 $ 4,473 $ 3,818
revenue........................
=========== =========== ===========
Interest (expense)
Products Pipelines.............. $ -- $ -- $ --
Natural Gas Pipelines........... -- -- --
CO2 Pipelines................... -- -- --
Terminals....................... -- -- --
----------- ----------- -----------
Total segment interest (expense) -- -- --
----------- ----------- -----------
Unallocated interest (expense).. (178,279) (175,930) (97,102)
----------- ----------- -----------
Total consolidated interest $ (178,279) $ (175,930) $ (97,102)
(expense)......................
=========== =========== ===========
Other, net(a)
Products Pipelines.............. $ (14,000) $ 440 $ 10,492
Natural Gas Pipelines........... 36 749 744
CO2 Pipelines................... 112 547 741
Terminals....................... 15,550 226 2,607
----------- ----------- -----------
Total consolidated Other, net... $ 1,698 $ 1,962 $ 14,584
=========== =========== ===========
(a) 2002 amounts include non-recurring environmental expense adjustments
resulting in a $15.7 million loss to our Products Pipelines business
segment and a $16.0 million gain to our Terminals business segment.
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2002 2001 2000
---- ---- ----
Income tax benefit (expense)
Products Pipelines.............. $ (10,154) $ (9,653) $ (11,960)
Natural Gas Pipelines........... (378) -- --
CO2 Pipelines................... -- -- --
Terminals....................... (4,751) (6,720) (1,974)
----------- ----------- -----------
Total consolidated income tax
benefit (expense).............. $ (15,283) $ (16,373) $ (13,934)
=========== =========== ===========
Segment earnings
Products Pipelines.............. $ 343,935 $ 312,464 $ 222,694
Natural Gas Pipelines........... 276,766 193,804 113,068
CO2 Pipelines................... 100,983 92,087 68,128
Terminals....................... 191,569 136,178 40,156
----------- ----------- -----------
Total segment earnings.......... 913,253 734,533 444,046
Interest and corporate
administrative expenses(a)..... (304,876) (292,190) (165,698)
----------- ----------- -----------
Total consolidated net income... $ 608,377 $ 442,343 $ 278,348
=========== =========== ===========
(a) Includes interest and debt expense, general and administrative
expenses, minority interest expense and other insignificant items.
Assets at December 31
Products Pipelines............ $3,088,799 $3,095,899 $ 2,220,984
Natural Gas Pipelines......... 3,121,674 2,058,836 1,552,506
CO2 Pipelines................. 613,980 503,565 417,278
Terminals..................... 1,165,096 990,760 357,689
----------- ----------- -----------
Total segment assets.......... 7,989,549 6,649,060 4,548,457
Corporate assets(a)........... 364,027 83,606 76,753
----------- ----------- -----------
Total consolidated assets..... $8,353,576 $6,732,666 $4,625,210
=========== =========== ===========
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
Depreciation and amortization
Products Pipelines............ $ 64,388 $ 65,864 $ 40,730
Natural Gas Pipelines......... 48,411 31,564 21,709
CO2 Pipelines................. 29,196 17,562 10,559
Terminals..................... 30,046 27,087 9,632
----------- ----------- -----------
Total consolidated depreciation
and amortization............. $ 172,041 $ 142,077 $ 82,630
=========== =========== ===========
Investments at December 31
Products Pipelines............ $ 133,927 $ 225,561 $ 231,651
Natural Gas Pipelines......... 103,724 146,566 141,613
CO2 Pipelines................. 71,283 68,232 9,559
Terminals..................... 2,110 159 59
----------- ----------- -----------
Total consolidated equity
investments.................. 311,044 440,518 382,882
Investment in oil and gas assets
to be contributed to joint
venture........................ -- -- 34,163
----------- ----------- -----------
$ 311,044 $ 440,518 $ 417,045
=========== =========== ===========
Capital expenditures
Products Pipelines............ $ 62,199 $ 84,709 $ 69,243
Natural Gas Pipelines......... 194,485 86,124 14,496
CO2 Pipelines................. 163,183 65,778 16,115
Terminals..................... 122,368 58,477 25,669
----------- ----------- -----------
Total consolidated capital
expenditures................. $ 542,235 $ 295,088 $ 125,523
=========== =========== ===========
Our total operating revenues are derived from a wide customer base. For
each of the years ended December 31, 2002 and 2001, one customer accounted
for more than 10% of our total consolidated revenues. Total transactions
within our Natural Gas Pipelines segment in 2002 with CenterPoint Energy
accounted for 15.6% of our total consolidated revenues during 2002. Total
transactions within our Natural Gas Pipelines and Terminals segment in 2001
with the Reliant Energy group of companies, including the entities which
became CenterPoint Energy in October 2002, accounted for 20.2% of our total
consolidated revenues during 2001. For the year ended December 31, 2000, no
revenues from transactions with a single external customer amounted to 10% or
more of our total consolidated revenues.
142
16. Litigation and Other Contingencies
The tariffs charged for interstate common carrier pipeline transportation
for our pipelines are subject to rate regulation by the Federal Energy
Regulatory Commission, referred to herein as FERC, under the Interstate
Commerce Act. The Interstate Commerce Act requires, among other things, that
interstate petroleum products pipeline rates be just and reasonable and
non-discriminatory. Pursuant to FERC Order No. 561, effective January 1,
1995, interstate petroleum products 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 interstate petroleum products 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, 2002, 2001 and
2000, the application of the indexing methodology did not significantly
affect our tariff rates.
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P., referred to herein as SFPP, is the subsidiary limited
partnership that owns our Pacific operations, excluding CALNEV Pipe Line LLC
and related terminals acquired from GATX Corporation. Tariffs charged by
SFPP are subject to certain proceedings at the FERC involving shippers'
complaints regarding the interstate rates, as well as practices and the
jurisdictional nature of certain facilities and services, on our Pacific
operations' pipeline systems. Generally, the interstate rates on our Pacific
operations' pipeline systems are "grandfathered" under the Energy Policy Act
of 1992 unless "substantially changed circumstances" are found to exist. To
the extent "substantially changed circumstances" are found to exist, our
Pacific operations may be subject to substantial exposure under these FERC
complaints.
The complainants have alleged a variety of grounds for finding
"substantially changed circumstances." 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 "substantially
changed circumstances". Given the relative newness of the grandfathering
standard under the Energy Policy Act and limited precedent, we cannot predict
how these allegations will be viewed by the FERC.
If "substantially changed circumstances" are found, SFPP rates previously
"grandfathered" under the Energy Policy Act will lose their "grandfathered"
status. If these rates are found to be unjust and unreasonable, shippers may
be entitled to a prospective rate reduction and a complainant may be entitled
to reparations for periods from the date of its complaint to the date of the
implementation of the new rates.
We currently believe that these FERC complaints seek approximately $197
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million.
We are not able to predict with certainty the final outcome of the pending
FERC proceedings involving SFPP, should they be carried through to their
conclusion, or whether we can reach a settlement with some or all of the
complainants.
However, even if "substantially changed circumstances" are found to exist,
we believe that the resolution of these FERC complaints will be for amounts
substantially less than the amounts sought and that the resolution of such
matters will not have a material adverse effect on our business, financial
position or results of operations.
OR92-8, et al. proceedings. In September 1992, El Paso Refinery, L.P.
filed a protest/complaint with the FERC:
o challenging SFPP's East Line rates from El Paso, Texas to Tucson and
Phoenix, Arizona;
o challenging SFPP's proration policy; and
o seeking to block the reversal of the direction of flow of SFPP's
six-inch pipeline between Phoenix and Tucson.
143
At various subsequent dates, the following other shippers on SFPP's South
System filed separate complaints, and/or motions to intervene in the FERC
proceeding, challenging SFPP's rates on its East and/or West Lines:
o Chevron U.S.A. Products Company;
o Navajo Refining Company;
o ARCO Products Company;
o Texaco Refining and Marketing Inc.;
o Refinery Holding Company, L.P. (a partnership formed by El Paso
Refinery's long-term secured creditors that purchased its refinery in
May 1993);
o Mobil Oil Corporation; and
o Tosco Corporation.
Certain of these parties also claimed that a gathering enhancement fee at
SFPP's Watson Station in Carson, California was charged in violation of the
Interstate Commerce Act.
The FERC consolidated these challenges in Docket Nos. OR92-8-000, et al.,
and ruled that they are complaint proceedings, with the burden of proof on
the complaining parties. These parties must show that SFPP's rates and
practices at issue violate the requirements of the Interstate Commerce Act.
A FERC administrative law judge held hearings in 1996, and issued an
initial decision on September 25, 1997. The initial decision agreed with
SFPP's position that "changed circumstances" had not been shown to exist on
the West Line, and therefore held that all West Line rates that were
"grandfathered" under the Energy Policy Act of 1992 were deemed to be just
and reasonable and were not subject to challenge, either for the past or
prospectively, in the Docket No. OR92-8 et al. proceedings. SFPP's Tariff
No. 18 for movement of jet fuel from Los Angeles to Tucson, which was
initiated subsequent to the enactment of the Energy Policy Act, was
specifically excepted from that ruling.
The initial decision also included rulings generally adverse to SFPP on
such cost of service issues as:
o the capital structure to be used in computing SFPP's 1985 starting rate
base ;
o the level of income tax allowance; and
o the recovery of civil and regulatory litigation expenses and certain
pipeline reconditioning costs.
The administrative law judge also ruled that SFPP's gathering enhancement
service at Watson Station was subject to FERC jurisdiction and ordered SFPP
to file a tariff for that service, with supporting cost of service
documentation.
SFPP and other parties asked the FERC to modify various rulings made in
the initial decision. On January 13, 1999, the FERC issued its Opinion No.
435, which affirmed certain of those rulings and reversed or modified
others.
With respect to SFPP's West Line, the FERC affirmed 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 rate stated in Tariff No. 18 did not require rate reduction.
Accordingly, the FERC dismissed all complaints against the West Line rates
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 made several changes
in the initial decision's methodology for calculating the rate base. It held
that the June 1985 capital structure of SFPP's parent company at that time,
144
rather than SFPP's 1988 partnership capital structure, should be used to
calculate the starting rate base and modified the accumulated deferred income
tax and allowable cost of equity used to calculate the rate base. It also
ruled that SFPP would not owe reparations to any complainant for any period
prior to the date on which that complainant's complaint was filed, thus
reducing by two years the potential reparations period claimed by most
complainants.
SFPP and certain complainants sought rehearing of Opinion No. 435 by the
FERC. In addition, ARCO, RHC, Navajo, Chevron and SFPP filed petitions for
review of Opinion No. 435 with the U.S. Court of Appeals for the District of
Columbia Circuit, all of which were either dismissed as premature or held in
abeyance pending FERC action on the rehearing requests.
On March 15, 1999, as required by the FERC's order, SFPP submitted a
compliance filing implementing the rulings made in Opinion No. 435,
establishing the level of rates to be charged by SFPP in the future, and
setting forth the amount of reparations that would be owed by SFPP to the
complainants under the order. The complainants contested SFPP's compliance
filing.
On May 17, 2000, the FERC issued its Opinion No. 435-A, which modified
Opinion No. 435 in certain respects. It denied requests to reverse its
rulings that SFPP's West Line rates and Watson Station gathering enhancement
facilities fee are entitled to be treated as "grandfathered" rates under the
Energy Policy Act. It suggested, however, that if SFPP had fully recovered
the capital costs of the gathering enhancement facilities, that might form
the basis of an amended "changed circumstances" complaint.
Opinion No. 435-A granted a request by Chevron and Navajo to require that
SFPP's December 1988 partnership capital structure be used to compute the
starting rate base from December 1983 forward, as well as a request by SFPP
to vacate a ruling that would have required the elimination of approximately
$125 million from the rate base used to determine capital structure. It also
granted two clarifications sought by Navajo, to the effect that SFPP's return
on its starting rate base should be based on SFPP's capital structure in each
given year (rather than a single capital structure from the outset) and that
the return on deferred equity should also vary with the capital structure for
each year. Opinion No. 435-A denied the request of Chevron and Navajo that
no income tax allowance be recognized for the limited partnership interests
held by SFPP's corporate parent, as well as SFPP's request that the tax
allowance should include interests owned by certain non-corporate entities.
However, it granted Navajo's request to make the computation of interest
expense for tax allowance purposes the same as for debt return.
Opinion No. 435-A reaffirmed that SFPP may recover certain litigation
costs incurred in defense of its rates (amortized over five years), but
reversed a ruling that those expenses may include the costs of certain civil
litigation with Navajo and El Paso. It also reversed a prior decision that
litigation costs should be allocated between the East and West Lines based on
throughput, and instead adopted SFPP's position that such expenses should be
split equally between the two systems.
As to reparations, Opinion No. 435-A held that no reparations would be
awarded to West Line shippers and that only Navajo was eligible to recover
reparations on the East Line. It reaffirmed that a 1989 settlement with SFPP
barred Navajo from obtaining reparations prior to November 23, 1993, but
allowed Navajo reparations for a one-month period prior to the filing of its
December 23, 1993 complaint. Opinion No. 435-A also confirmed that FERC's
indexing methodology should be used in determining rates for reparations
purposes and made certain clarifications sought by Navajo.
Opinion No. 435-A denied Chevron's request for modification of SFPP's
prorationing policy. That policy required customers to demonstrate a need
for additional capacity if a shortage of available pipeline space existed.
SFPP's prorationing policy has since been changed to eliminate the
"demonstrated need" test.
Finally, Opinion No. 435-A directed SFPP to revise its initial compliance
filings to reflect the modified rulings. It eliminated the refund obligation
for the compliance tariff containing the Watson Station gathering enhancement
fee, but required SFPP to pay refunds to the extent that the initial
compliance tariff East Line rates exceeded the rates produced under Opinion
No. 435-A.
145
In June 2000, several parties filed requests for rehearing of rulings made
in Opinion No. 435-A. Chevron and RHC both sought reconsideration of the
FERC's ruling that only Navajo is entitled to reparations for East Line
shipments. SFPP sought rehearing of the FERC's:
o decision to require use of the December 1988 partnership capital
structure for the period 1984-88 in computing the starting rate base;
o elimination of civil litigation costs;
o refusal to allow any recovery of civil litigation settlement payments;
and
o failure to provide any allowance for regulatory expenses in prospective
rates.
On July 17, 2000, SFPP submitted a compliance filing implementing the
rulings made in Opinion No. 435-A, together with a calculation of reparations
due to Navajo and refunds due to other East Line shippers. SFPP also filed a
tariff stating revised East Line rates based on those rulings.
ARCO, Chevron, Navajo, RHC, Texaco and SFPP sought judicial review of
Opinion No. 435-A in the U.S. Court of Appeals for the District of Columbia
Circuit. All of those petitions except Chevron's were either dismissed as
premature or held in abeyance pending action on the rehearing requests. On
September 19, 2000, the court dismissed Chevron's petition for lack of
prosecution, and subsequently denied a motion by Chevron for reconsideration
of that dismissal.
On September 13, 2001, the FERC issued Opinion No. 435-B, which ruled on
requests for rehearing and comments on SFPP's compliance filing. Based on
those rulings, the FERC directed SFPP to submit a further revised compliance
filing, including revised tariffs and revised estimates of reparations and
refunds.
Opinion No. 435-B denied SFPP's requests for rehearing, which involved the
capital structure to be used in computing starting rate base, SFPP's ability
to recover litigation and settlement costs incurred in connection with the
Navajo and El Paso civil litigation, and the provision for regulatory costs
in prospective rates. However, it modified the FERC's prior rulings on
several other issues. It reversed the ruling that only Navajo is eligible
to seek reparations, holding that Chevron, RHC, Tosco and Mobil are also
eligible to recover reparations for East Line shipments. It ruled, however,
that Ultramar is not eligible for reparations in the Docket No. OR92-8 et al.
proceedings.
The FERC also changed prior rulings that had permitted SFPP to use certain
litigation, environmental and pipeline rehabilitation costs that were not
recovered through the prescribed rates to offset overearnings (and potential
reparations) and to recover any such costs that remained by means of a
surcharge to shippers. Opinion No. 435-B required SFPP to pay reparations to
each complainant without any offset for unrecovered costs. It required SFPP
to subtract from the total 1995-1998 supplemental costs allowed under Opinion
No. 435-A any overearnings not paid out as reparations, and allowed SFPP to
recover any remaining costs from shippers by means of a five-year surcharge
beginning August 1, 2000. Opinion No. 435-B also ruled that SFPP would only
be permitted to recover certain regulatory litigation costs through the
surcharge, and that the surcharge could not include environmental or pipeline
rehabilitation costs.
Opinion No. 435-B directed SFPP to make additional changes in its revised
compliance filing, including:
o using a remaining useful life of 16.8 years in amortizing its starting
rate base, instead of 20.6 years;
o removing the starting rate base component from base rates as of August
1, 2001;
o amortizing the accumulated deferred income tax balance beginning in
1992, rather than 1988;
o listing the corporate unitholders that were the basis for the income tax
allowance in its compliance filing and certifying that those companies
are not Subchapter S corporations; and
146
o "clearly" excluding civil litigation costs and explaining how it limited
litigation costs to FERC-related expenses and assigned them to
appropriate periods in making reparations calculations.
On October 15, 2001, Chevron and RHC filed petitions for rehearing of
Opinion No. 435-B. Chevron asked the FERC to clarify:
o the period for which Chevron is entitled to reparations; and
o whether East Line shippers that have received the benefit of
FERC-prescribed rates for 1994 and subsequent years must show that there
has been a substantial divergence between the cost of service and the
change in the FERC's rate index in order to have standing to challenge
SFPP rates for those years in pending or subsequent proceedings.
RHC's petition contended that Opinion No. 435-B should be modified on
rehearing, to the extent it:
o suggested that a "substantial divergence" standard applies to complaint
proceedings challenging the total level of SFPP's East Line rates
subsequent to the Docket No. OR92-8 et al. proceedings;
o required a substantial divergence to be shown between SFPP's cost of
service and the change in the FERC oil pipeline index in such subsequent
complaint proceedings, rather than a substantial divergence between the
cost of service and SFPP's revenues; and
o permitted SFPP to recover 1993 rate case litigation expenses through a
surcharge mechanism.
ARCO, Ultramar and SFPP filed petitions for review of Opinion No. 435-B
(and in SFPP's case, Opinion Nos. 435 and 435-A) in the U.S. Court of Appeals
for the District of Columbia Circuit. The court consolidated the Ultramar
and SFPP petitions with the consolidated cases held in abeyance and ordered
that the consolidated cases be returned to its active docket.
On November 7, 2001, the FERC issued an order ruling on the petitions for
rehearing of Opinion No. 435-B. The FERC held that Chevron's eligibility for
reparations should be measured from August 3, 1993, rather than the September
23, 1992 date sought by Chevron. The FERC also clarified its prior ruling
with respect to the "substantial divergence" test, holding that in order to
be considered on the merits, complaints challenging the SFPP rates set by
applying the FERC's indexing regulations to the 1994 cost of service derived
under the Opinion No. 435 orders must demonstrate a substantial divergence
between the indexed rates and the pipeline's actual cost of service.
Finally, the FERC held that SFPP's 1993 regulatory costs should not be
included in the surcharge for the recovery of supplemental costs.
On November 20, 2001, SFPP submitted its compliance filing and tariffs
implementing Opinion No. 435-B and the FERC's November 7, 2001 order.
Motions to intervene and protest were subsequently filed by ARCO, Mobil
(which now submits filings under the name ExxonMobil), RHC, Navajo and
Chevron, alleging that SFPP:
o should have calculated the supplemental cost surcharge differently;
o did not provide adequate information on the taxpaying status of its
unitholders; and
o failed to estimate potential reparations for ARCO.
On December 7, 2001, Chevron filed a petition for rehearing of the FERC's
November 7, 2001 order. The petition requested the FERC to specify whether
Chevron would be entitled to reparations for the two year period prior to the
August 3, 1993 filing of its complaint.
On December 10, 2001, SFPP filed a response to those claims. On December
14, 2001, SFPP filed a revised compliance filing and new tariff correcting an
error that had resulted in understating the proper surcharge and tariff
rates.
147
On December 20, 2001, the FERC's Director of the Division of Tariffs and
Rates Central issued two letter orders rejecting SFPP's November 20, 2001 and
December 14, 2001 tariff filings because they were not made effective
retroactive to August 1, 2000. On January 11, 2002, SFPP filed a request for
rehearing of those orders by the FERC, on the ground that the FERC has no
authority to require retroactive reductions of rates filed pursuant to its
orders in complaint proceedings.
On January 7, 2002, SFPP and RHC filed petitions for review of the FERC's
November 7, 2001 order in the U.S. Court of Appeals for the District of
Columbia Circuit. On January 8, 2002, the court consolidated those petitions
with the petitions for review of Opinion Nos. 435, 435-A and 435-B. On
January 24, 2002, the court ordered the consolidated proceedings to be held
in abeyance until the FERC acts on Chevron's request for rehearing of the
November 7, 2001 order.
Motions to intervene and protest the December 14, 2001 corrected
submissions were filed by Navajo, ARCO and ExxonMobil. Ultramar requested
leave to file an out-of-time intervention and protest of both the November
20, 2001 and December 14, 2001 submissions. On January 14, 2002, SFPP
responded to those filings to the extent they were not mooted by the orders
rejecting the tariffs in question.
On February 15, 2002, the FERC denied rehearing of the Director of the
Division of Tariffs and Rates Central's letter orders. On February 21, 2002,
SFPP filed a motion requesting that the FERC clarify whether it intended SFPP
to file a retroactive tariff or simply make a compliance filing calculating
the effects of Opinion No. 435-B back to August 1, 2000; in the event the
order was clarified to require a retroactive tariff filing, SFPP asked the
FERC to stay that requirement pending judicial review.
On April 8, 2002, SFPP filed a petition for review of the FERC's February
15, 2002 Order in the U.S. Court of Appeals for the District of Columbia
Circuit. BP West Coast Products, LLC (formerly ARCO); ExxonMobil; Tosco
Corporation; and Ultramar, Inc. and Valero Energy Corporation filed motions
to intervene in that proceeding. On April 9, 2002, the Court of Appeals
consolidated SFPP's petition with the petitions for review of the FERC's
prior orders and directed the parties "to file motions to govern future
proceedings" by May 9, 2002. Motions were filed by SFPP, RHC, Navajo,
Chevron and the "Indicated Parties" (BP West Coast Products, ExxonMobil,
Ultramar and Tosco). The FERC requested that the Court of Appeals continue
to hold the consolidated cases in abeyance pending the completion of
proceedings before the agency on rehearing.
On June 25, 2002, the Court of Appeals granted the ExxonMobil and Valero
Energy motions to intervene, and directed intervenors on the side of
petitioners to notify the court of that status and provide a statement of
issues to be raised. ExxonMobil filed a notice on July 2, 2002; Ultramar,
Inc. and Valero Energy on July 10, 2002. On July 12, 2002, SFPP responded to
the ExxonMobil notice in order to urge the Court of Appeals not to rely on
ExxonMobil's categorization of the issues and party alignments in allocating
briefing.
On May 31, 2002, SFPP filed FERC Tariff No. 70, which implemented the
FERC's annual indexing adjustment. Motions to intervene and protest were
filed by Navajo and Chevron, contesting any indexing adjustment to the
litigation surcharge permitted by Opinion No. 435-B. On June 28, 2002, the
FERC's Director of the Division of Tariffs and Rates rejected Tariff No. 70
on the ground that the surcharge should not be indexed. On July 2, 2002,
SFPP filed FERC Tariff No. 73 to replace Tariff No. 70 in compliance with
that decision, which resulted in an average reduction from Tariff No. 70 of
approximately $.0002 per barrel.
On September 26, 2002, the FERC issued an order ruling on the protests
against SFPP's November 20, 2001 and December 14, 2001 compliance filings
implementing Opinion No. 435-B and the November 7, 2001 Order. The FERC held
that:
o SFPP must measure supplemental costs against the total amount of
reparations for the entire reparations period (as opposed to
year-by-year);
o SFPP will not be permitted to include in its supplemental costs
(a) litigation expenses incurred during 1999 and 2000 or (b) payments
made to Navajo and RHC to settle certain FERC litigation;
o the tariff surcharge collected by SFPP for all shipments between August
1, 2000 and December 1, 2001 is subject to refund; and
148
o in calculating its tax allowance, SFPP must exclude the ownership
interest attributable to an entity that the FERC found to be a mutual
fund.
The FERC rejected the requests by Navajo, BP West Coast Products and
ExxonMobil to extend the period for which they are entitled to reparations
beyond the periods specified in prior orders.
The September 26, 2002 Order also ruled on SFPP's request for
clarification of the February 15, 2002 Order as to whether it was required to
make a retroactive tariff filing or rather a compliance filing calculating
the effects of Opinion No. 435-B beginning August 1, 2000. The FERC held
that SFPP was required to file a tariff retroactive to August 1, 2000. The
FERC did not rule on SFPP's alternative request for a stay. The FERC also
ruled on Chevron's request for rehearing of the November 7, 2001 Order,
clarifying that Chevron was eligible for reparations for shipments on the
East Line for the two years prior to the filing of its complaint.
On October 22, 2002, ExxonMobil filed a Request for Clarification or, in
the Alternative, Rehearing of the September 26, 2002 Order. ExxonMobil
requested that the FERC clarify that ExxonMobil was eligible for reparations
for East Line rates.
On October 25, 2002, SFPP filed Tariff No. 75 implementing changes
required by the September 26, 2002 Order, and on October 28, 2002, SFPP
submitted a compliance filing pursuant to that order. Valero Marketing and
Supply Company filed a motion to intervene and protest regarding the
compliance filing and tariff, and Tosco Corporation protested the compliance
filing. Navajo Refining Company, L.P. moved to intervene in proceedings
relating to the tariff, and Chevron Products Company and Equilon Enterprises
LLC filed comments and related pleadings challenging the compliance filing
and seeking additional relief.
On January 29, 2003, the FERC issued an order accepting the October 28,
2002 compliance filing subject to the condition that SFPP recalculate gross
reparations in determining its per barrel surcharge and submit a revised
tariff reflecting that change within fifteen days of the order. The FERC
rejected all other challenges to that compliance filing.
Following the September 26, 2002 Order, several parties filed motions to
govern future proceedings with the U.S. Court of Appeals for the District of
Columbia Circuit. BP West Coast Products LLC and ExxonMobil (the "Indicated
Parties") and Valero Energy Corporation, Ultramar Inc. and Tosco Corporation
(the "Joint Parties") requested that the court return the petitions for
review to its active docket but sever the docket involving compliance filing
issues. The FERC filed a motion that did not take a definitive position on
whether the petitions for review should continue to be held in abeyance, but
noted that compliance filing issues were still pending before the FERC.
SFPP, Chevron, Navajo and RHC filed responses to the motions to govern future
proceedings. On December 6, 2002, the Court of Appeals granted the motion of
the "Indicated Parties" and "Joint Parties" to return the petitions for
review to the Court's active docket. The Court also severed the docket
relating to compliance filing issues and directed the parties to submit a
proposed briefing schedule and format. On January 6, 2003, SFPP and FERC
filed a joint briefing proposal, and the shipper parties jointly filed a
separate briefing proposal.
On October 18, 2002, Chevron filed a petition for review of Opinion Nos.
435, 435-A and 435-B in the U.S. Court of Appeals for the District of
Columbia Circuit. The Court of Appeals consolidated that petition with the
main docket on November 20, 2002. Tosco Corporation and BP West Coast
Products LLC moved to intervene in that docket, and those motions were
granted on December 10, 2002.
Petitions for review of the September 26, 2002 Order have been filed in
the U.S. Court of Appeals for the District of Columbia Circuit by Navajo, on
October 24, 2002, and by SFPP, on November 8, 2002. The Court consolidated
those petitions with the main docket on November 5, 2002 and November 12,
2002, respectively. Valero Marketing and Supply Company moved to intervene
in both dockets and Tosco Corporation moved to intervene in the docket for
the SFPP petition. On January 6, 2003, Valero Marketing and Supply Company
filed a motion to substitute itself for Ultramar Diamond Shamrock Corporation
in Ultramar's petition for review of Opinion No. 435-B. On January 21, 2003
SFPP filed a response, stating that it did not object to the proposed
substitution provided Valero Marketing and Supply Corporation was not
permitted to create or enlarge any claim for damages.
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On January 24, 2003, ConocoPhillips filed a motion to substitute itself
for Tosco Corporation in the consolidated dockets, and on January 27, 2003,
filed a similar motion in the severed docket relating to compliance filing
issues.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at FERC
(Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipelines
(Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were
subject to FERC's jurisdiction under the Interstate Commerce Act, and, if so,
claimed that the rate for that service was unlawful. Texaco sought to have
its claims addressed in the OR92-8 proceeding discussed above. Several other
West Line shippers filed similar complaints and/or motions to intervene. The
FERC consolidated all of these filings into Docket No. OR96-2 and set the
claims for a separate hearing. A hearing before an administrative law judge
was held in December 1996.
In March 1997, the judge issued an initial decision holding that the
movements on the Sepulveda pipelines were not subject to FERC jurisdiction.
On August 5, 1997, the FERC reversed that decision. On October 6, 1997, SFPP
filed a tariff establishing the initial interstate rate for movements on the
Sepulveda pipelines at the preexisting rate of five cents per barrel.
Several shippers protested that rate. In December 1997, SFPP filed an
application for authority to charge a market-based rate for the Sepulveda
service, which application was protested by several parties. On September
30, 1998, the FERC issued an order finding that SFPP lacks market power in
the Watson Station destination market and that, while SFPP appeared to lack
market power in the Sepulveda origin market, a hearing was necessary to
permit the protesting parties to substantiate allegations that SFPP possesses
market power in the origin market. A hearing before a FERC administrative
law judge on this limited issue was held in February 2000.
On December 21, 2000, the FERC administrative law judge issued his initial
decision finding that SFPP possesses market power over the Sepulveda origin
market. The ultimate disposition of SFPP's application is pending before the
FERC.
Following the issuance of the initial decision in the Sepulveda case, the
FERC judge indicated an intention to proceed to consideration of the justness
and reasonableness of the existing rate for service on the Sepulveda
pipelines. On February 22, 2001, the FERC granted SFPP's motion to block
such consideration and to defer consideration of the pending complaints
against the Sepulveda rate until after FERC's final disposition of SFPP's
market rate application.
OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar filed a
complaint at FERC (Docket No. OR97-2) challenging SFPP's West Line rates,
claiming they were unjust and unreasonable and no longer subject to
grandfathering. In October 1997, ARCO, Mobil and Texaco filed a complaint at
the FERC (Docket No. OR98-1) challenging the justness and reasonableness of
all of SFPP's interstate rates, raising claims against SFPP's East and West
Line rates similar to those that have been at issue in Docket Nos. OR92-8, et
al. discussed above, but expanding them to include challenges to SFPP's
grandfathered interstate rates from the San Francisco Bay area to Reno,
Nevada and from Portland to Eugene, Oregon - the North Line and Oregon Line.
In November 1997, Ultramar Diamond Shamrock Corporation filed a similar,
expanded complaint (Docket No. OR98-2). Tosco Corporation filed a similar
complaint in April 1998. The shippers seek both reparations and prospective
rate reductions for movements on all of the lines. SFPP answered each of
these complaints. FERC issued orders accepting the complaints and
consolidating them into one proceeding (Docket No. OR96-2, et al.), but
holding them in abeyance pending a FERC decision on review of the initial
decision in Docket Nos. OR92-8, et al.
In a companion order to Opinion No. 435, the FERC gave the complainants an
opportunity to amend their complaints in light of Opinion No. 435, which the
complainants did in January 2000. On May 17, 2000, the FERC issued an order
finding that the various complaining parties had alleged sufficient grounds
for their complaints to go forward to a hearing to assess whether any of the
challenged rates that are grandfathered under the Energy Policy Act will
continue to have such status and, if the grandfathered status of any rate is
not upheld, whether the existing rate is just and reasonable.
In August 2000, Navajo and RHC filed complaints against SFPP's East Line
rates and Ultramar filed an additional complaint updating its pre-existing
challenges to SFPP's interstate pipeline rates. In September 2000, FERC
accepted these new complaints and consolidated them with the ongoing
proceeding in Docket No. OR96-2, et al.
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A hearing in this consolidated proceeding was held from October 2001 to
March 2002. An initial decision by the administrative law judge is expected
in the first half of 2003.
OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the
OR96-2 proceeding, filed a complaint against SFPP in Docket No. OR02-4 along
with a motion to consolidate the complaint with the OR96-2 proceeding. On
May 21, 2002, the FERC dismissed Chevron's complaint and motion to
consolidate. Chevron filed a request for rehearing and on September 25,
2002, the FERC dismissed Chevron's rehearing request. In October 2002,
Chevron filed a request for rehearing of the FERC's September 25 order. The
FERC has indicated that it intends to rule on Chevron's request in February
2003. Chevron continues to participate in the OR96-2 proceeding as an
intervenor.
CALNEV Pipe Line LLC
We acquired CALNEV Pipe Line LLC in March 2001. CALNEV provides
interstate and intrastate transportation from an interconnection with SFPP at
Colton, California to destinations in and around Las Vegas, Nevada.
In April 2002, Chevron filed a complaint against CALNEV's interstate
rates, making allegations of unjust and unreasonable rates. CALNEV answered
Chevron's complaint on May 16, 2002, and Chevron moved for leave to respond
to CALNEV's answer on June 17, 2002.
In September of 2002, CALNEV and Chevron were able to reach a mutually
agreeable resolution of the disputed claims, and a settlement was executed.
In the settlement agreement, the parties agreed, among other things, that
for a period of five years, CALNEV would not seek a rate increase at the FERC
or the California Public Utilities Commission except as permitted under four
specific exceptions and that Chevron would not file complaints against
CALNEV's rates, provided it complies with such exceptions. On October 10,
2002, the FERC granted the parties' joint motion to dismiss the complaint
with prejudice.
Trailblazer Pipeline Company
As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at FERC on November 29, 2002. The filing
provides for a small rate decrease and also includes a number of non-rate
tariff changes. By an order issued December 31, 2002, FERC effectively
bifurcated the proceeding. The rate change was accepted to be effective on
January 1, 2003, subject to refund and a hearing. Most of the non-rate
tariff changes were suspended until June 1, 2003, subject to refund and a
technical conference procedure.
Trailblazer has sought rehearing of the FERC order with respect to the
refund condition on the rate decrease. The Indicated Shippers have sought
rehearing as to FERC acceptance of certain non-rate tariff provisions. A
prehearing conference on the rate issues was held on January 16, 2003. A
procedural schedule was established under which the hearing will commence on
October 8, 2003, if the case is not settled. Discovery has commenced as to
rate issues.
The technical conference on non-rate issues was held on February 6, 2003.
Those issues include:
o capacity award procedures;
o credit procedures;
o imbalance penalties; and
o the maximum length of bid terms considered for evaluation in the right
of first refusal process.
Initial and reply comments on these issues as discussed at the technical
conference are due March 7, 2003 and March 18, 2003, respectively.
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California Public Utilities Commission Proceeding
ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission on April 7, 1997. 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.
On March 16, 2000, SFPP filed an application with the CPUC seeking
authority to justify its rates for intrastate transportation of refined
petroleum products on competitive, market-based conditions rather than on
traditional, cost-of-service analysis.
On April 10, 2000, ARCO and Mobil filed a new complaint with the CPUC
asserting that SFPP's California intrastate rates are not just and reasonable
based on a 1998 test year and requesting the CPUC to reduce SFPP's rates
prospectively. The amount of the reduction in SFPP rates sought by the
complainants is not discernible from the complaint.
The rehearing complaint was heard by the CPUC in October 2000 and the
April 2000 complaint and SFPP's market-based application were heard by the
CPUC in February 2001. All three matters stand submitted as of April 13,
2001, and a decision addressing the submitted matters is expected within
three to four months.
The CPUC has recently issued a resolution approving a 2001 request by SFPP
to raise its California rates to reflect increased power costs. The
resolution approving the requested rate increase also requires SFPP to submit
cost data for 2001, 2002, and 2003 to assist the CPUC in determining whether
SFPP's overall rates for California intrastate transportation services are
reasonable. The resolution reserves the right to require refunds, from the
date of issuance of the resolution, to the extent the CPUC's analysis of cost
data to be submitted by SFPP demonstrates that SFPP's California
jurisdictional rates are unreasonable in any fashion.
There is no way to quantify the potential extent to which the CPUC could
determine that SFPP's existing California rates are unreasonable or estimate
the amount of dollars potentially subject to refund as a consequence of the
CPUC resolution requiring the provision by SFPP of cost-of-service data.
SFPP believes that submission of the required, representative cost data
required by the CPUC will indicate that SFPP's existing rates for California
intrastate services remain reasonable and that no refunds are justified.
We believe that the resolution of such matters will not have a material
adverse effect on our business, financial position or results of operations.
FERC Order 637
Kinder Morgan Interstate Gas Transmission LLC
On June 15, 2000, Kinder Morgan Interstate Gas Transmission LLC made its
filing to comply with FERC's Orders 637 and 637-A. That filing contained
KMIGT's compliance plan to implement the changes required by FERC dealing
with the way business is conducted on interstate natural gas pipelines. All
interstate natural gas pipelines were required to make such compliance
filings, according to a schedule established by FERC. From October 2000
through June 2001, KMIGT held a series of technical and phone conferences to
identify issues, obtain input, and modify its Order 637 compliance plan,
based on comments received from FERC staff and other interested parties and
shippers. On June 19, 2001, KMIGT received a letter from FERC encouraging it
to file revised pro-forma tariff sheets, which reflected the latest
discussions and input from parties into its Order 637 compliance plan.
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KMIGT made such a revised Order 637 compliance filing on July 13, 2001.
The July 13, 2001 filing contained little substantive change from the
original pro-forma tariff sheets that KMIGT originally proposed on June 15,
2000. On October 19, 2001, KMIGT received an order from FERC, addressing its
July 13, 2001 Order 637 compliance plan. In the Order addressing the July
13, 2001 compliance plan, KMIGT's plan was accepted, but KMIGT was directed
to make several changes to its tariff, and in doing so, was directed that it
could not place the revised tariff into effect until further order of the
FERC. KMIGT filed its compliance filing with the October 19, 2001 Order on
November 19, 2001 and also filed a request for rehearing/clarification of the
FERC's October 19, 2001 Order on November 19, 2001. Several parties
protested the November 19, 2001 compliance filing. KMIGT filed responses to
those protests on December 14, 2001. At this time, it is unknown when this
proceeding will be finally resolved. The full impact of implementation of
Order 637 on the KMIGT system is under evaluation. We believe that these
matters will not have a material adverse effect on our business, financial
position or results of operations.
Separately, numerous petitioners, including KMIGT, have filed appeals of
Order 637 in the D.C. Circuit, potentially raising a wide array of issues
related to Order 637 compliance. Initial briefs were filed on April 6, 2001,
addressing issues contested by industry participants. Oral arguments on the
appeals were held before the court in December 2001. On April 5, 2002, the
D.C. Circuit issued an order largely affirming Order Nos. 637, et seq. The
D.C. Circuit remanded the FERC's decision to impose a 5-year cap on bids that
an existing shipper would have to match in the right of first refusal
process. The D.C. Circuit also remanded the FERC's decision to allow
forward-hauls and backhauls to the same point. Finally, the D.C. Circuit
held that several aspects of the FERC's segmentation policy and its policy on
discounting at alternate points were not ripe for review. The FERC requested
comments from the industry with respect to the issues remanded by the D.C.
Circuit. They were due July 30, 2002.
On October 31, 2002, the FERC issued an order in response to the D.C.
Circuit's remand of certain Order 637 issues. The order:
o eliminated the requirement of a 5-year cap on bid terms that an existing
shipper would have to match in the right of first refusal process, and
found that no term matching cap is necessary given existing regulatory
controls;
o affirmed FERC's policy that a segmented transaction consisting of both
a forwardhaul up to contract demand and a backhaul up to contract
demand to the same point is permissible; and
o accordingly required, under Section 5 of the NGA, pipelines that the
FERC had previously found must permit segmentation on their systems to
file tariff revisions within 30 days to permit such segmented
forwardhaul and backhaul transactions to the same point.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply
with FERC's Order Nos. 637 and 637-A. Trailblazer's compliance filing
reflected changes in:
o segmentation;
o scheduling for capacity release transactions;
o receipt and delivery point rights;
o treatment of system imbalances;
o operational flow orders;
o penalty revenue crediting; and
o right of first refusal language.
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On October 15, 2001, FERC issued its order on Trailblazer's Order No. 637
compliance filing. FERC approved Trailblazer's proposed language regarding
operational flow orders and the right of first refusal, but required
Trailblazer to make changes to its tariff related to the other issues listed
above.
On November 14, 2001, Trailblazer made its compliance filing pursuant to
the FERC order of October 15, 2001. That compliance filing has been
protested. Separately, also on November 14, 2001, Trailblazer filed for
rehearing of that FERC order. These pleadings are pending FERC action.
Trailblazer anticipates no adverse impact on its business as a result of
the implementation of Order No. 637.
Standards of Conduct Rulemaking
On September 27, 2001, FERC issued a Notice of Proposed Rulemaking in
Docket No. RM01-10 in which it proposed new rules governing the interaction
between an interstate natural gas pipeline and its affiliates. If adopted as
proposed, the Notice of Proposed Rulemaking could be read to limit
communications between KMIGT, Trailblazer and their respective affiliates.
In addition, the Notice could be read to require separate staffing of KMIGT
and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties,
including KMIGT, have filed comment on the Proposed Standards of Conduct
Rulemaking. On May 21, 2002, FERC held a technical conference dealing with
the FERC's proposed changes in the Standard of Conduct Rulemaking. On June
28, 2002, KMIGT and numerous other parties flied additional written comments
under a procedure adopted at the technical conference. The Proposed
Rulemaking is awaiting further FERC action. We believe that these matters,
as finally adopted, will not have a material adverse effect on our business,
financial position or results of operations.
The FERC also issued a Notice of Proposed Rulemaking in Docket No.
RM02-14-000 in which it proposed new regulations for cash management
practices, including establishing limits on the amount of funds that can be
swept from a regulated subsidiary to a non-regulated parent company. Kinder
Morgan Interstate Gas Transmission LLC filed comments on August 28, 2002. We
believe that these matters, as finally adopted, will not have a material
adverse effect on our business, financial position or results of operations.
Southern Pacific Transportation Company Easements
SFPP and Southern Pacific Transportation Company 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 claims that the rent
payable for each of the years 1994 through 2004 should be approximately $4.4
million and SPTC claims it should be approximately $15.0 million. We believe
SPTC's position in this case is without merit and we have set aside reserves
that we believe are adequate to address any reasonably foreseeable outcome of
this matter. As of early-February 2003, the matter is currently in trial.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P. directly or indirectly through its
ownership interest in the Cortez Pipeline Company, along with other entities,
is a defendant in several actions in which the plaintiffs allege that the
defendants undervalued carbon dioxide produced from the McElmo Dome field and
overcharged for transportation costs, thereby allegedly underpaying royalties
and severance tax payments. The plaintiffs, who are seeking monetary damages
and injunctive relief, are comprised of royalty, overriding royalty and small
share working interest owners who claim that they were underpaid by the
defendants. These cases are: CO2 Claims Coalition, LLC v. Shell Oil Co., et
al., No. 96-Z-2451 (U.S.D.C. Colo. filed 8/22/96); Rutter & Wilbanks et al.
v. Shell Oil Co., et al., No. 00-Z-1854 (U.S.D.C. Colo. filed 9/22/00);
Watson v. Shell Oil Co., et al., No. 00-Z-1855 (U.S.D.C. Colo. filed
9/22/00); Ainsworth et al. v. Shell Oil Co., et al., No. 00-Z-1856 (U.S.D.C.
Colo. filed 9/22/00); United
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States ex rel. Crowley v. Shell Oil Company, et al., No. 00-Z-1220
(U.S.D.C. Colo. filed 6/13/00); Shell Western E&P Inc. v. Bailey, et al., No
98-28630 (215th Dist. Ct. Harris County, Tex. filed 6/17/98); Shores, et al.
v. Mobil Oil Corporation, et al., No. GC-99-01184 (Texas Probate Court,
Denton County filed 12/22/99); First State Bank of Denton v. Mobil Oil
Corporation, et al., No. PR-8552-01 (Texas Probate Court, Denton County filed
3/29/01); and Celeste C. Grynberg v. Shell Oil Company, et al., No. 98-CV-43
(Colo. Dist. Ct. Montezuma County filed 3/21/98).
At a hearing conducted in the United States District Court for the
District of Colorado on April 8, 2002, the Court orally announced that it had
approved the certification of proposed plaintiff classes and approved a
proposed settlement in the CO2 Claims Coalition, LLC, Rutter & Wilbanks,
Watson, Ainsworth and United States ex rel. Crowley cases. The Court entered
a written order approving the Settlement on May 6, 2002; plaintiffs counsel
representing Shores, et al. appealed the court's decision to the 10th Circuit
Court of Appeals. On December 26, 2002, the 10th Circuit Court of Appeals
affirmed in all respects the District Court's Order approving settlement.
Following the decision of the 10th Circuit, the Plaintiffs and Defendants
jointly filed motions to abate the Shell Western E&P Inc., Shores and First
State Bank of Denton cases in order to afford the parties time to discuss
potential settlement. These Motions were granted on February 6, 2003. In
the Celeste C. Grynberg case, the parties are currently engaged in discovery.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et al.
Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District. On October 15, 2001, Kinder Morgan Energy Partners, L.P. was
served with the First Supplemental Petition filed by RSM Production
Corporation on behalf of the County of Zapata, State of Texas and Zapata
County Independent School District as plaintiffs. Kinder Morgan Energy
Partners, L.P. was sued in addition to 15 other defendants, including two
other Kinder Morgan affiliates. Certain entities we acquired in the Kinder
Morgan Tejas acquisition are also defendants in this matter. The Petition
alleges that these taxing units relied on the reported volume and analyzed
heating content of natural gas produced from the wells located within the
appropriate taxing jurisdiction in order to properly assess the value of
mineral interests in place. The suit further alleges that the defendants
undermeasured the volume and heating content of that natural gas produced
from privately owned wells in Zapata County, Texas. The Petition further
alleges that the County and School District were deprived of ad valorem tax
revenues as a result of the alleged undermeasurement of the natural gas by
the defendants. On December 15, 2001, the defendants filed motions to
transfer venue on jurisdictional grounds. There are no further pretrial
proceedings at this time.
Will Price, et al. v. Gas Pipelines, et al., (f/k/a Quinque Operating
Company et al. v. Gas Pipelines, et al.)
Stevens County, Kansas District Court, Case No. 99 C 30. In May, 1999,
three plaintiffs, Quinque Operating Company, Tom Boles and Robert Ditto,
filed a purported nationwide class action in the Stevens County, Kansas
District Court against some 250 natural gas pipelines and many of their
affiliates. The District Court is located in Hugoton, Kansas. Certain
entities we acquired in the Kinder Morgan Tejas acquisition are also
defendants in this matter. The Petition (recently amended) alleges a
conspiracy to underpay royalties, taxes and producer payments by the
defendants' undermeasurement of the volume and heating content of natural gas
produced from nonfederal lands for more than twenty-five years. The named
plaintiffs purport to adequately represent the interests of unnamed
plaintiffs in this action who are comprised of the nation's gas producers,
State taxing agencies and royalty, working and overriding owners. The
plaintiffs seek compensatory damages, along with statutory penalties, treble
damages, interest, costs and fees from the defendants, jointly and
severally. This action was originally filed on May 28, 1999 in Kansas State
Court in Stevens County, Kansas as a class action against approximately 245
pipeline companies and their affiliates, including certain Kinder Morgan
entities. Subsequently, one of the defendants removed the action to Kansas
Federal District Court and the case was styled as Quinque Operating Company,
et al. v. Gas Pipelines, et al., Case No. 99-1390-CM, United States District
Court for the District of Kansas. Thereafter, we filed a motion with the
Judicial Panel for Multidistrict Litigation to consolidate this action for
pretrial purposes with the Grynberg False Claim Act cases referred to below,
because of common factual questions. On April 10, 2000, the MDL Panel
ordered that this case be consolidated with the Grynberg federal False Claims
Act cases discussed below. On January 12, 2001, the Federal District Court
of Wyoming issued an oral ruling remanding the case back to the State Court
in Stevens County, Kansas. The Court in Kansas has issued a case management
order addressing the initial phasing of the case. In this initial phase, the
court will rule on motions to dismiss (jurisdiction and sufficiency of
pleadings), and if the action is not dismissed, on class certification.
Merits discovery has been stayed.
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Recently, the defendants filed a motion to dismiss on grounds other than
personal jurisdiction, which was denied by the Court in August, 2002. The
Motion to Dismiss for lack of Personal Jurisdiction of the nonresident
defendants has been briefed and is awaiting decision. The current named
plaintiffs are Will Price, Tom Boles, Cooper Clark Foundation and Stixon
Petroleum, Inc. Quinque Operating Company has been dropped from the action
as a named plaintiff. On January 13, 2003, a motion to certify the class was
argued. A decision on this moton is pending.
United States of America, ex rel., Jack J. Grynberg v. K N Energy
Civil Action No. 97-D-1233, filed in the U.S. District Court, District of
Colorado. This action was filed on June 9, 1997 pursuant to the federal
False Claim Act and involves allegations of mismeasurement of natural gas
produced from federal and Indian lands. The Department of Justice has
decided not to intervene in support of the action. The complaint is part of
a larger series of similar complaints filed by Mr. Grynberg against 77
natural gas pipelines (approximately 330 other defendants). Certain entities
we acquired in the Kinder Morgan Tejas acquisition are also defendants in
this matter. An earlier single action making substantially similar
allegations against the pipeline industry was dismissed by Judge Hogan of the
U.S. District Court for the District of Columbia on grounds of improper
joinder and lack of jurisdiction. As a result, Mr. Grynberg filed individual
complaints in various courts throughout the country. In 1999, these cases
were consolidated by the Judicial Panel for Multidistrict Litigation, and
transferred to the District of Wyoming. The multidistrict litigation matter
is called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293.
Motions to dismiss were filed and an oral argument on the motion to dismiss
occurred on March 17, 2000. On July 20, 2000 the United States of America
filed a motion to dismiss those claims by Grynberg that deal with the manner
in which defendants valued gas produced from federal leases, referred to as
valuation claims. Judge Downes denied the defendant's motion to dismiss on May
18, 2001. The United States' motion to dismiss most of plaintiff's valuation
claims has been granted by the court. Grynberg has appealed that dismissal to
the 10th Circuit, which has requested briefing regarding its jurisdiction over
that appeal. Discovery is now underway to determine issues related to the
Court's subject matter jurisdiction, arising out of the False Claim Act.
Sweatman and Paz Gas Corporation v. Gulf Energy Marketing, LLC, et al.
Mel R. Sweatman and Paz Gas Corporation vs. Gulf Energy Marketing, LLC, et
al. On July 25, 2002, we were served with this suit for breach of contract,
tortious interference with existing contractual relationships, conspiracy to
commit tortuous interference and interference with prospective business
relationship. Mr. Sweatman and Paz Gas Corporation claim that, in connection
with our acquisition of Tejas Gas, LLC, we wrongfully caused gas volumes to
be shipped on our Kinder Morgan Texas Pipeline system instead of our Kinder
Morgan Tejas system. Mr. Sweatman and Paz Gas Corporation allege that this
action eliminated profit on Kinder Morgan Tejas, a portion of which Mr.
Sweatman and Paz Gas Corporation claim they are entitled under an agreement
with a subsidiary of ours acquired in the Tejas Gas acquisition. We have
filed a motion to remove the case from venue in Dewitt County, Texas to
Harris County, Texas, and our motion was denied in a venue hearing in
November 2002.
In a Second Amended Original Petition, Sweatman and Paz assert new and
distinct allegations against us, principally that we were a party to an
alleged commercial bribery committed by us, Gulf Energy Marketing, and
Intergen inasmuch as we, in our role as acquirer of Kinder Morgan Tejas,
allegedly paid Intergen to non-renew the underlying Entex contracts belonging
to the Tejas/Paz joint venture. Moreoever, new and distinct allegations of
breach of fiduciary and bribery of a fiduciary are also raised in this
amended petition for the first time.
Based on the information available to date and our preliminary
investigation, we believe this suit is without merit and we intend to defend
it vigorously.
Maher et ux. v. Centerpoint Energy, Inc. d/b/a Reliant Energy,
Incorporated, Reliant Energy Resources Corp., Entex Gas Marketing Company,
Kinder Morgan Texas Pipeline, L.P., Kinder Morgan Energy Partners, L.P.,
Houston Pipeline Company, L.P. and AEP Gas Marketing, L.L.C., No. 30875
(District Court, Wharton County Texas).
On October 21, 2002, Kinder Morgan Texas Pipeline, L.P. and Kinder Morgan
Energy Partners, L.P. were served with the above-entitled Complaint. A First
Amended Complaint was served on October 23, 2002, adding additional
defendants Kinder Morgan G.P., Inc., Kinder Morgan Tejas Pipeline GP, Inc.,
Kinder Morgan Texas Pipeline GP, Inc., Tejas Gas, LLC and HPL GP, LLC. The
First Amended Complaint purports to bring a class action on behalf of those
Texas residents who purchased natural gas for residential purposes from the
so-called "Reliant Defendants" in Texas at any time during the period
encompassing "at least the last ten years."
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The Complaint alleges that Reliant Energy Resources Corp., by and through
its affiliates, has artificially inflated the price charged to residential
consumers for natural gas that it allegedly purchased from the non-Reliant
defendants, including the above-listed Kinder Morgan entities. The Complaint
further alleges that in exchange for Reliant Energy Resources Corp.'s
purchase of natural gas at above market prices, the non-Reliant defendants,
including the above-listed Kinder Morgan entities, sell natural gas to Entex
Gas Marketing Company at prices substantially below market, which in turn
sells such natural gas to commercial and industrial consumers and gas
marketers at market price. The Complaint purports to assert claims for
fraud, violations of the Texas Deceptive Trade Practices Act, and violations
of the Texas Utility Code against some or all of the Defendants, and civil
conspiracy against all of the defendants, and seeks relief in the form of,
inter alia, actual, exemplary and statutory damages, civil penalties,
interest, attorneys' fees and a constructive trust ab initio on any and all
sums which allegedly represent overcharges by Reliant and Reliant Energy
Resources Corp.
On November 18, 2002, the Kinder Morgan defendants filed a Motion to
Transfer Venue and, Subject Thereto, Original Answer to the First Amended
Complaint. The parties are currently engaged in preliminary discovery.
Based on the information available to date and our preliminary investigation,
the Kinder Morgan defendants believe that the claims against them are without
merit and intend to defend against them vigorously.
Marie Snyder, et al v. City of Fallon, United States Department of the
Navy, Exxon Mobil Corporation, Kinder Morgan Energy Partners, L.P., Speedway
Gas Station and John Does I-X, No. cv-N-02-0251-ECR-RAM (United States
District Court, District of Nevada)("Snyder"); and Frankie Sue Galaz, et al
v. United States of America, City of Fallon, Exxon Mobil Corporation, Kinder
Morgan Energy Partners, L.P., Berry Hinckley, Inc., and John Does I-X, No.
cv-N-02-0630-DWH-RAM (United States District Court, District of
Nevada)("Galaz").
On July 9, 2002, we were served with a purported Complaint for Class
Action in the Snyder case, in which the plaintiffs, on behalf of themselves
and others similarly situated, assert that a leukemia cluster has developed
in the City of Fallon, Nevada. The Complaint alleges that the plaintiffs
have been exposed to unspecified "environmental carcinogens" at unspecified
times in an unspecified manner and are therefore "suffering a significantly
increased fear of serious disease." The plaintiffs seek a certification of a
class of all persons in Nevada who have lived for at least three months of
their first ten years of life in the City of Fallon between the years 1992
and the present who have not been diagnosed with leukemia.
The Complaint purports to assert causes of action for nuisance and
"knowing concealment, suppression, or omission of material facts" against all
defendants, and seeks relief in the form of "a court-supervised trust fund,
paid for by defendants, jointly and severally, to finance a medical
monitoring program to deliver services to members of the purported class
that include, but are not limited to, testing, preventative screening and
surveillance for conditions resulting from, or which can potentially result
from exposure to environmental carcinogens," incidental damages, and
attorneys' fees and costs.
The defendants responded to the Complaint by filing Motions to Dismiss on
the grounds that it fails to state a claim upon which relief can be granted.
On November 7, 2002, the United States District Court granted the Motion to
Dismiss filed by the United States, and further dismissed all claims against
the remaining defendants for lack of Federal subject matter jurisdiction.
Plaintiffs filed a Motion for Reconsideration and Leave to Amend, which was
denied by the Court on December 30, 2002. Plaintiffs have filed a Notice of
Appeal to the United States Court of Appeals for the 9th Circuit, which
appeal is currently pending.
On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz matter asserting the same claims in the same Court on
behalf of the same purported class against virtually the same defendants,
including us. On February 10, 2003, the defendants filed Motions to Dismiss
the Galaz Complaint on the grounds that it also fails to state a claim upon
which relief can be granted. This motion is currently pending before the
court.
Based on the information available to date and our preliminary
investigation, we believe that the claims against us in the Snyder and Galaz
matters are without merit and intend to defend against them vigorously.
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions, that, to the extent an assessment of the
matter is possible, we have established an adequate reserve to cover
potential
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liability, and that these matters will not have a material adverse effect
on our business, financial position or results of operations.
Walter Chandler v. Plantation Pipe Line Company
On October 2, 2001, the jury rendered a verdict against Plantation Pipe
Line Company in the case of Walter Chandler v. Plantation Pipe Line Company.
The jury awarded the plaintiffs a total of $43.8 million. The judge reduced
the award to $42.6 million due to a prior settlement with the plaintiffs by a
third party.
This case was filed in April 1997 by the landowner (Evelyn Chandler Trust)
and two residents of the property (Buster Chandler and his son, Clay
Chandler). The suit was filed against Chevron, Plantation and two
individuals. The two individuals were later dismissed from the suit.
Chevron settled with the plaintiffs in December 2000. The property and
residences are directly across the street from the location of a former
Chevron products terminal. The Plantation pipeline system traverses the
Chevron terminal property. The suit alleges that gasoline released from the
terminal and pipeline contaminated the groundwater under the plaintiffs'
property. As noted above, a current remediation effort is taking place among
Chevron, Plantation and Alabama Department of Environmental Management.
In addition to the Chandler case, in 1998 and 1999, other entities and
individuals living in close proximity to the Chandlers filed lawsuits against
Plantation, Chevron and an environmental consulting firm, CH2MHill, alleging
property damage and personal injuries from groundwater contaminated with
petroleum hydrocarbons. In February 2003, Plantation settled, through a
confidential settlement, all of these lawsuits as well as the Chandler
litigation. Plantation believes that the settlement of these lawsuits and
the Chandler litigation will not have a material adverse effect on its
business, financial position or results of operations.
Marion County, Mississippi Litigation
In 1968, Plantation discovered a release from its 12-inch pipeline in
Marion County, Mississippi. The pipeline was immediately repaired. In 1998
and 1999, 62 lawsuits were filed on behalf of 263 plaintiffs in the Circuit
Court of Marion County, Mississippi. The majority of the claims are based on
alleged exposure from the 1968 release, including claims for property damage
and personal injury. Plantation has resolved some of the lawsuits but
lawsuits by 236 of the plaintiffs are still pending. Although a trial date
has not been set for any of the remaining cases, it is anticipated that a
trial on a portion of the lawsuits will be scheduled in 2003. Plantation
believes that the ultimate resolution of these Marion County, Mississippi
cases will not have a material effect on its business, financial position or
results of operations.
Environmental Matters
We are subject to environmental cleanup and enforcement actions from time
to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners
and operators of a site, without regard to fault or the legality of the
original conduct. Our operations are also subject to federal, state and
local laws and regulations relating to protection of the environment.
Although we believe our operations are in substantial compliance with
applicable environmental regulations, risks of additional costs and
liabilities are inherent in pipeline and terminal operations, and there can
be no assurance that we will not incur significant costs and liabilities.
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 our
operations, could result in substantial costs and liabilities to us.
We are currently involved in the following governmental proceedings
related to compliance with environmental regulations associated with our
assets and have established a reserve to address the costs associated with
the cleanup:
o 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;
158
o several ground water hydrocarbon remediation efforts under
administrative orders issued by the California Regional Water Quality
Control Board and two other state agencies;
o groundwater and soil remediation efforts under administrative orders
issued by various regulatory agencies on those assets purchased from
GATX Corporation, comprising Kinder Morgan Liquids Terminals LLC, CALNEV
Pipe Line LLC and Central Florida Pipeline LLC; and
o a ground water remediation effort taking place between Chevron,
Plantation Pipe Line Company and the Alabama Department of Environmental
Management.
In addition, we are from time to time involved in civil proceedings
relating to damages alleged to have occurred as a result of accidental leaks
or spills of refined petroleum products, natural gas liquids, natural gas and
carbon dioxide.
Furthermore, our review of assets related to Kinder Morgan Interstate Gas
Transmission LLC indicates possible environmental impacts from petroleum and
used oil releases into the soil and groundwater at nine sites. Additionally,
our review of assets related to Kinder Morgan Texas Pipeline indicates
possible environmental impacts from petroleum releases into the soil and
groundwater at six sites. Further delineation and remediation of any
environmental impacts from these matters will be conducted. Reserves have
been established to address the closure of these issues.
Although no assurance can be given, we believe that the ultimate
resolution of the environmental matters set forth in this note will not have
a material adverse effect on our business, financial position or results of
operations. We have recorded a total reserve for environmental claims in the
amount of $52.7 million at December 31, 2002. As of December 31, 2002, we
were not able to reasonably estimate when the eventual settlements of these
claims will occur.
Other
We are a defendant in various lawsuits arising from the day-to-day
operations of our businesses. Although no assurance can be given, we
believe, based on our experiences to date, that the ultimate resolution of
such items will not have a material adverse impact on our business, financial
position or results of operations.
In addition to the matters described above, we may face additional
challenges to our rates in the future. Shippers on our pipelines do have
rights to challenge the rates we charge under certain circumstances
prescribed by applicable regulations. There can be no assurance that we will
not face challenges to the rates we receive for services on our pipeline
systems in the future. In addition, since many of our assets are subject to
regulation, we are subject to potential future changes in applicable rules
and regulations that may have an adverse effect on our business, financial
position or results of operations.
17. Quarterly Financial Data (unaudited)
Basic Diluted
Operating Operating Net Income Net Income
Revenues Income Net Income per Unit per Unit
--------- --------- ---------- ---------- ----------
(In thousands, except per unit amounts)
2002
First Quarter..... $ 803,065 $ 165,856 $ 141,433 $ 0.48 $ 0.48
Second Quarter.... 1,090,936 172,347 144,517 0.48 0.48
Third Quarter..... 1,121,320 189,403 158,180 0.50 0.50
Fourth Quarter.... 1,221,736 196,692 164,247 0.50 0.50
2001
First Quarter..... $1,028,645 $ 138,351 $ 101,667 $ 0.45 $ 0.45
Second Quarter.... 735,755 138,596 104,226 0.36 0.36
Third Quarter..... 638,544 144,892 115,792 0.37 0.37
Fourth Quarter.... 543,732 141,989 120,658 0.40 0.40
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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.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware Limited Partnership)
By: KINDER MORGAN G.P., INC.,
its General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
its Delegate
By: /s/ JOSEPH LISTENGART
________________________________________________________________________________
Joseph Listengart,
Vice President, General Counsel and Secretary
Date: February 26, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and
on the dates indicated.
Signature Title Date
----------------------------- ------------------------------- -----------------
- ----- /s/ RICHARD D. KINDER Chairman of the Board and Chief February 26, 2003
Executive Officer of Kinder
- ---------------------------------- Morgan Management, LLC, Delegate
Richard D. Kinder of Kinder Morgan G.P., Inc.
- ----- /s/ EDWARD O. GAYLORD Director of Kinder Morgan February 26, 2003
Management, LLC, Delegate of
- ---------------------------------- Kinder Morgan G.P., Inc.
Edward O. Gaylord
- ----- /s/ GARY L. HULTQUIST Director of Kinder Morgan February 26, 2003
Management, LLC, Delegate of
- ---------------------------------- Kinder Morgan G.P., Inc.
Gary L. Hultquist
- ----- /s/ PERRY M. WAUGHTAL Director of Kinder Morgan February 26, 2003
Management, LLC, Delegate of
- ---------------------------------- Kinder Morgan G.P., Inc.
Perry M. Waughtal
- ----- /s/ C. PARK SHAPER Director, Vice President, February 26, 2003
Treasurer and Chief Financial
Officer of
- ---------------------------------- Kinder Morgan Management, LLC,
C. Park Shaper Delegate of Kinder Morgan G.P.,
Inc. (principal financial
officer and principal accounting
officer)
160
CERTIFICATIONS
I, Richard D. Kinder, certify that:
1. I have reviewed this annual report on Form 10-K of Kinder Morgan Energy
Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the periods covered
by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
/s/ Richard D. Kinder
------------------------------
Richard D. Kinder
Chairman and Chief Executive Officer
Date: February 26, 2003
161
I, C. Park Shaper, certify that:
1. I have reviewed this annual report on Form 10-K of Kinder Morgan Energy
Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the periods covered
by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual
report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
/s/ C. Park Shaper
------------------------------
C. Park Shaper
Vice President, Treasurer and Chief Financial Officer
Date: February 26, 2003
162