UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 2003
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. [X]
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 voting and non-voting common equity 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 30, 2003 was
approximately $4,577,450,989. 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,
2004, the registrant had 134,735,758 Common Units outstanding.
1
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
PART I
Items 1 and 2. Business and Properties............................ 3
Overview........................................... 3
General Development of Business.................... 3
Business Strategy.................................. 4
Recent Developments................................ 7
Financial Information about Segments............... 11
Narrative Description of Business.................. 11
Products Pipelines................................. 11
Natural Gas Pipelines.............................. 23
CO2................................................ 28
Terminals.......................................... 30
Major Customers.................................... 34
Regulation......................................... 34
Environmental Matters.............................. 37
Risk Factors....................................... 40
Other.............................................. 44
Financial Information about Geographic Areas....... 44
Available Information.............................. 44
Item 3. Legal Proceedings.................................. 45
Item 4. Submission of Matters to a Vote of Security Holders 45
PART II
Item 5. Market for Registrant's Common Equity and Related 46
Stockholder Matters................................
Item 6. Selected Financial Data............................ 47
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations................ 49
Critical Accounting Policies and Estimates......... 49
Results of Operations.............................. 50
Liquidity and Capital Resources.................... 61
New Accounting Pronouncements...................... 70
Information Regarding Forward-Looking Statements... 70
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk........................................ 71
Energy Financial Instruments....................... 71
Interest Rate Risk................................. 73
Item 8. Financial Statements and Supplementary Data........ 74
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure................ 74
Item 9A. Controls and Procedures............................ 74
PART III
Item 10. Directors and Executive Officers of the Registrant. 75
Directors and Executive Officers of our General 75
Partner and the Delegate...........................
Corporate Governance............................... 77
Section 16(a) Beneficial Ownership Reporting 79
Compliance.........................................
Item 11. Executive Compensation............................. 79
Item 12. Security Ownership of Certain Beneficial Owners
and Management..................................... 83
Item 13. Certain Relationships and Related Transactions..... 85
Item 14. Principal Accounting Fees and Services............. 86
PART IV
Item 15. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K............................. 88
Index to Financial Statements...................... 91
Signatures......................................................... 164
2
PART I
Items 1 and 2. Business and Properties.
Overview
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.
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." In addition, you should read the following discussion and analysis in
conjunction with our Consolidated Financial Statements included elsewhere in
this report.
(a) General Development of Business
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, generally avoiding
commodity price risks and taking advantage of the tax benefits of a limited
partnership structure. The portfolio of businesses we own or operate are grouped
into four reportable business segments according to the services we provide and
how our management makes decisions about allocating resources and measuring
financial performance. These segments are as follows:
o Products Pipelines: Delivers more than two million barrels per day of
gasoline, diesel fuel, jet fuel and natural gas liquids to various markets
on over 10,000 miles of products pipelines and 39 associated terminals
serving customers across the United States;
o Natural Gas Pipelines: Transports, stores and sells up to 7.8 billion cubic
feet per day of natural gas and has over 15,000 miles of natural gas
transmission pipelines, plus natural gas gathering and storage facilities;
o CO2: Produces, transports and markets carbon dioxide, commonly called CO2,
has over 1,100 miles of pipelines that transport carbon dioxide to oil
fields that use carbon dioxide to increase oil production in West Texas,
including interests in two oil fields we operate and interests in four
others, all of which are using or have used carbon dioxide injection
operations; and
o Terminals: Composed of approximately 52 owned or operated liquid and bulk
terminal facilities and approximately 57 rail transloading facilities
located throughout the United States, liquids terminal facilities
possessing a liquids storage capacity of approximately 55 million barrels
for refined petroleum products, chemicals and other liquid products, and
bulk and transloading facilities handling nearly 60 million tons of coal,
petroleum coke and other dry-bulk materials annually.
3
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. Since that time, our operations have
experienced significant growth, and our net income has increased from $17.7
million, for the year ended December 31, 1997, to $697.3 million, for the year
ended December 31, 2003.
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 35,000 miles of natural
gas and products pipelines and approximately 80 terminals. As of December 31,
2003, KMI and its consolidated subsidiaries owned, through its general and
limited partner interests, an approximate 19.0% 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 2003 distribution level, KMI received approximately 51% of all quarterly
distributions from us, of which approximately 41% was attributable to its
general partner interest and 10% was 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. As of December
31, 2003, KMR, through its ownership of our i-units, owned approximately 25.9%
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
elsewhere 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:
4
o providing, for a fee, transportation, storage and handling services which
are core to the energy infrastructure of 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 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.
Primarily, our business model consists of a solid asset base designed and
operated to generate stable, fee-based income and distributable cash flow that
together provides overall long-term value to our unitholders. We do not face
significant risks relating directly to movements in commodity prices for two
principal reasons. First, we primarily transport and/or handle products for a
fee and are not engaged in the unmatched purchase and resale of commodity
products. Second, in those areas of our business, primarily oil production in
our CO2 business segment, where we do face exposure to fluctuations in commodity
prices, we engage in a hedging program to mitigate this exposure.
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 and bulk materials that we transport, store, or handle. Increases in
demand for these products and services are generally driven by demographic
growth in the markets we serve, including the rapidly growing western and
southeastern United States.
The business strategies of our four business segments are as follows:
o 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
strategic pipeline and terminal acquisitions that we believe will enhance
our ability to serve our customers while increasing distributable cash
flow. On systems serving relatively mature markets, such as our North
System, we intend to focus on increasing product throughput by continuing
to increase the range of products transported and services offered while
remaining a reliable, cost-effective provider of transportation services;
o 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. On our two Rocky
Mountain natural gas pipeline systems, Kinder Morgan Interstate Gas
Transmission LLC and Trailblazer Pipeline Company, our goals are to
continue to operate our existing operations efficiently, to continue to
meet our customers' needs and to capitalize on expansion and growth
opportunities in expanding our role as a key player in moving natural gas
out of the Rocky Mountain region. Red Cedar Gas Gathering Company, our
partnership with the Southern Ute Indian Tribe, is pursuing additional
gathering and processing opportunities on tribal lands. Overall, we will
continue to explore expansion and storage opportunities to increase
utilization levels throughout our natural gas pipeline operations;
5
o CO2. Our carbon dioxide business has two primary strategies: (a) increase
the utilization of our carbon dioxide supply and transportation assets by
providing a full range of supply, transportation and technical support
services to third party customers and (b) increase, for our own account,
the economic benefits from our oil production activities by increasing oil
field carbon dioxide flooding and efficiently managing oil field operating
expenses. As a service provider, our strategy is to offer customers
"one-stop shopping" for carbon dioxide supply, transportation and technical
support service. In our production business, we plan to grow production
from our interests in oil fields located in the Permian Basin of West Texas
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 supply and
pipeline assets. Our management believes these projects will arise as other
oil producing basins mature and make the transition from primary production
to enhanced recovery methods; and
o 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. 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
our experience and expertise in managing and operating our liquids and bulk
terminals businesses in an integrated manner gives us a competitive
advantage in pursuing acquisitions of terminals that handle both bulk and
liquid materials.
To accomplish our strategy, we will continue to rely on the following
three-pronged approach:
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. 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 expense 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 primarily
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 and bulk
materials that we transport, store 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 our
management believes will increase revenues from existing operations; and
o Strategic Acquisitions. 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, including those from KMI or its affiliates, as they are
identified, but we cannot assure you that we will be able to consummate any
such acquisition. 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. 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. For more information
on the costs and methods of financing for each of our 2003 acquisitions,
see "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources - Capital
Requirements for Recent Transactions" included elsewhere in this report.
6
Achieving success in implementing our strategy will partly depend on the
following characteristics of our management's philosophy:
o Low cost asset operator and attention to detail. An important element of
our strategy to improve unitholder value is controlling costs whenever
possible. We believe that our overall cost and expense infrastructure has
been improved by numerous simplification and transformation efforts. We
continue to focus on improving employee and process productivity in order
to create a more efficient expense structure while, at the same time, we
insist on providing the highest level of expertise and uncompromising
service to our customers. We have recognized for years the need to have an
unwavering commitment to safety, and we employ full-time safety
professionals to provide training and awareness through ongoing programs
for every employee, especially those working with hazardous materials at
our pipeline and terminal facilities;
o Risk Management. We avoid businesses with direct commodity price exposure
wherever possible, and we hedge incidental commodity price risk. In the
normal course of business, we are exposed to risks associated with changes
in the market price of energy products; however, we attempt to limit these
risks by following established risk management policies and procedures,
including the use of energy financial instruments, also known as
derivatives. Our risk management process also includes identifying the
areas in our operations where assets are at risk of loss and areas where
exposures exist to third-party liabilities. Our management strives to
recognize and insure against such risk; and
o Alignment of incentives. Whenever possible, we align the compensation of
our management and employees with the interests of our unitholders. Under
KMI's stock option plan, all employees of KMI and its affiliates, including
employees of KMI's direct and indirect subsidiaries who operate our
businesses, are eligible to receive grants of options to acquire shares of
KMI common stock. The primary purpose for granting stock options under this
plan is to provide employees with an incentive to increase the value of
common stock of KMI. The value of KMI's common stock increases primarily
as a result of increases in distributions to our unitholders. KMI's ten
most senior executives (excluding Mr. Kinder, who receives $1 per year in
salary) have their base salaries capped at $200,000, are not eligible for
stock options, but instead are eligible to receive grants of KMI restricted
stock. Additionally, all employees, including the most senior executives,
are eligible for annual bonuses only when KMI and we meet annual earnings
per share and distributions per unit targets.
Recent Developments
During 2003, our assets increased 9% and our net income increased 15% from
2002 levels. In addition, distributions per unit increased 9% from $0.625 for
the fourth quarter of 2002 to $0.68 for the fourth quarter of 2003. The
following is a brief listing of significant developments since December 31,
2002. Additional information regarding most of these items is contained in the
rest of this report.
o Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk terminal
facilities at major ports along the East Coast and in the southeastern
United States. The acquisition also included the purchase of certain assets
that provide stevedoring services at these locations. The aggregate cost of
this acquisition was approximately $31.3 million. We paid $29.9 million of
the acquisition cost on December 31, 2002 and the remaining $1.4 million in
January 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 annually
transload nearly four million tons of products such as fertilizer, iron ore
and salt;
o On March 25, 2003, we announced the start of service on our new $89
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 interconnects 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. Additionally, we entered into a 15-year contract with Pemex
Gas Y Petroquimica Basica, which subscribed for all of the capacity on the
pipeline. The pipeline connects to a 1,000-megawatt power plant complex
near Monterrey and to the PEMEX natural gas transportation system;
7
o On May 2, 2003, we were notified by the staff of the Securities and
Exchange Commission that the staff is conducting an informal investigation
concerning our public disclosures regarding the allocation of purchase
price between assets and goodwill in connection with our 2002 acquisition
of the assets of Kinder Morgan Tejas. The staff has not asserted that we
have acted improperly or illegally. Furthermore, the staff has indicated
that the Commission has not issued a formal order. We have voluntarily
agreed to cooperate fully with the staff's informal investigation. Even if
adjustments were made to the allocation between assets and goodwill, any
adjustments would not have an effect on cash available for distributions to
our limited partners. The primary effect of any adjustments would be to
either increase or decrease depreciation and amortization expense with a
corresponding increase or decrease in net income. This difference arises
because, in general, assets are required to be depreciated over time while
goodwill is not;
o On May 6, 2003, we completed construction and placed into service our new
$28.5 million carbon dioxide Centerline pipeline. The Centerline pipeline
originates near Denver City, Texas and transports carbon dioxide to the
Snyder, Texas area. The pipeline consists of 113 miles of 16-inch pipe and
primarily supplies the SACROC oil field unit in the Permian Basin of West
Texas, but is also available for existing and prospective third-party
carbon dioxide projects in the Horseshoe Atoll area of the Permian Basin;
o Effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership
interest in the SACROC oil field unit for $23.3 million and the assumption
of $1.9 million of liabilities. The SACROC unit is one of the largest and
oldest oil fields in the United States using carbon dioxide flooding
technology. This transaction increased our ownership interest in the SACROC
unit to approximately 97%;
o On June 10, 2003, we announced that we had entered into a long-term natural
gas transportation contract with Praxair, Inc. Under the 15-year agreement,
we have agreed to supply Praxair with up to 90,000 dekatherms of natural
gas per day from our Texas intrastate natural gas pipeline system. The gas
will be used to supply Praxair's steam-methane reformers at two new
hydrogen facilities located in Texas City, Texas, and Port Arthur, Texas.
These new hydrogen facilities are scheduled to be in production in 2004;
o On June 23, 2003, we completed a public offering of an additional 4,600,000
of our common units, including 600,000 units issued upon exercise by the
underwriters of an over-allotment option, at a price of $39.35 per unit,
less commissions and underwriting expenses. We received net proceeds of
$173.3 million for the issuance of these common units and we used the
proceeds to reduce the borrowings under our commercial paper program;
o On June 24, 2003, a non-binding, phase one initial decision was issued by
an administrative law judge hearing a Federal Energy Regulatory Commission
case on the rates charged by our Pacific operations' interstate portion of
its pipelines. The Energy Policy Act of 1992 "grandfathered" most of our
Pacific operations' interstate rates, deeming them lawful. However,
pursuant to rate challenges made by certain shippers, the administrative
law judge recommended that the FERC "ungrandfather" our Pacific operations'
interstate rates. If these rates are "ungrandfathered," they could be
lowered prospectively and complaining shippers could be entitled to
reparations for prior periods. Initial decisions have no force or effect
and must be reviewed by the FERC. Furthermore, the FERC is not obliged to
follow any of the administrative law judge's findings and can accept or
reject this initial decision in whole or in part. Ultimate resolution of
phase one and phase two of this matter by the FERC is not expected before
early 2005;
o On July 30, 2003, we experienced a rupture on our Products Pipelines'
Pacific operations' Tucson to Phoenix line that carries refined petroleum
products from Tucson to Phoenix. Through a combination of increased
deliveries on our Los Angeles to Phoenix line and terminal modifications at
our Tucson terminal that allowed volumes of Phoenix-grade gasoline to be
trucked into Phoenix, we were able to deliver most of the volumes into the
Phoenix area which normally would have flowed through the ruptured line.
The Tucson to Phoenix line resumed service on August 24, 2003. The impact
of the rupture on our results of operations was not material;
o On August 1, 2003, we received a favorable final order from the FERC
approving the rate methodology for shippers on the expansion of our Pacific
operations' East Line pipeline. In October 2002, we filed a petition
8
requesting that the FERC address several issues regarding the determination
of rates for our proposed $200million East Line expansion project. The East
Line is comprised of two parallel pipelines originating in El Paso, Texas,
extending to the west and connecting to our products terminal located in
Tucson, Arizona. One line continues running northwest and connects to our
products terminal located in Phoenix, Arizona. When completed, the
expansion will increase capacity on our El Paso to Tucson pipeline by
approximately 56% (53,000 barrels per day of refined petroleum products),
and on our Tucson to Phoenix pipeline by approximately 80% (44,000 barrels
per day of refined petroleum products). As part of this expansion project,
replacement of approximately 12 miles of pipeline within the city of Tucson
is underway and will be completed by mid-March 2004. The projected start-up
for the remainder of the expansion is sometime in the fourth quarter of
2005 or the first quarter of 2006;
o Effective August 1, 2003, we acquired reversionary interests in the Red
Cedar Gas Gathering Company held by the Southern Ute Indian Tribe. Our
purchase price was $10.0 million. The 4% reversionary interests were
scheduled to take effect September 1, 2004 and September 1, 2009. With the
elimination of these reversions, our ownership interest in Red Cedar will
remain at 49%;
o On August 5, 2003, we announced the formation of a joint venture with
Nicor, Inc. for the purpose of obtaining shipper commitments for the
proposed Advantage Southern Pipeline project. The 392-mile pipeline would
originate from the Cheyenne Hub, located in Weld County, Colorado, and
terminate near Greensburg, Kansas, where it would interconnect with several
major interstate pipeline systems. The pipeline would offer a competitive
alternative to shippers at the Cheyenne Hub by providing additional access
to natural gas produced in the Rocky Mountain region to meet growing demand
in the Midwest. On August 29, 2003, we concluded an open season on the
project, which gave interested shippers the opportunity to bid for firm
capacity on the proposed natural gas pipeline. As of January 31, 2004, we
were working with a number of shippers to remove contingencies, which would
then allow this project to go forward;
o Effective October 1, 2003, we acquired five refined petroleum products
terminals in the western United States for approximately $20.0 million from
Shell Oil Products U.S. In addition, as part of the transaction, Shell
entered into a long-term contract to store refined petroleum products in
the terminals. We plan to invest an additional $8.0 million in the
facilities in the near term. The terminals are located in Colton and
Mission Valley, California; Phoenix and Tucson, Arizona; and Reno, Nevada.
Combined, the terminals have 28 storage tanks with total capacity of
approximately 700,000 barrels for gasoline, diesel fuel and jet fuel. The
terminals also feature automated truck-loading equipment and offer a
variety of blending services;
o On October 9, 2003, following approval from the Federal Energy Regulatory
Commission, we announced the start of construction on our $30 million
project that involves the construction of pipeline, compression and storage
facilities to accommodate an additional six billion cubic feet of natural
gas storage capacity at our 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 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 Effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation for $231.0
million and the assumption of $28.0 million of liabilities. The assets
acquired included Marathon's approximate 42.5% interest in the Yates oil
field unit, Marathon's 100% interest in the crude oil gathering system
surrounding the Yates field and Marathon's 100% interest in Marathon Carbon
Dioxide Transportation Company. Marathon Carbon Dioxide Transportation
Company owns a 65% ownership interest in the Pecos Carbon Dioxide Pipeline
Company, which owns a 25-mile carbon dioxide pipeline. Adding the acquired
interest in the Yates field to the 7.5% ownership interest we previously
owned raised our working interest in the Yates field to nearly 50% and
allows us to operate the field. One of the largest oil fields ever
discovered in the United States, Yates originally held more than five
billion barrels of oil, of which approximately 28% has been produced. This
field is located approximately 90 miles south of Midland, Texas;
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o Effective November 1, 2003, we acquired the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP from an affiliate of
NiSource Inc. for $15.8 million and the assumption of $1.7 million of debt.
We now own 100% of MidTex Gas Storage Company, LLP, a Texas limited
liability partnership that owns two salt dome natural gas storage
facilities located in Matagorda County, Texas;
o On December 3, 2003, we announced that we had acquired a 172 mile segment
of a 24-inch diameter Texas crude oil pipeline from Teppco Crude Pipeline,
L.P. and expect to convert it from carrying crude oil to natural gas. We
will spend approximately $30.0 million to acquire the intrastate pipeline,
prepare it for natural gas transportation service and build an additional
five mile pipeline lateral. Approximately $23.3 million of our total
spending will be made to convert to natural gas service the 135 mile
pipeline segment which extends from an intersection with our Kinder Morgan
Texas Pipeline system just west of Katy, Texas to the west side of Austin,
Texas. When completed, the pipeline will provide approximately 170
dekatherms per day of natural gas to the Austin market. In addition, Austin
Energy, Austin's city-owned electric utility, has entered into a long-term
contract for firm transportation and storage services, primarily to provide
gas supply to its Sand Hill power plant. Texas Gas Service, Austin's local
natural gas distribution company, has also signed a long-term contract to
support the project. We expect to begin gas service on the pipeline by the
middle of 2004;
o Effective December 11, 2003, we acquired seven refined petroleum products
terminals in the southeastern United States from ConocoPhillips Company and
Phillips Pipe Line Company. Our purchase price was approximately $15.1
million, consisting of approximately $14.0 million in cash and $1.1 million
in assumed liabilities. The terminals are located in Charlotte and Selma,
North Carolina; Augusta and Spartanburg, South Carolina; Albany and
Doraville, Georgia; and Birmingham, Alabama. We will fully own and operate
all of these terminals except for the facility in Doraville, Georgia, where
our ownership interest will be 30% and the facility will be operated by
Citgo. Combined, the terminals have 35 storage tanks with total capacity of
approximately 1.15 million barrels for gasoline, diesel fuel and jet fuel.
The facilities feature automated truck-loading equipment and offer a
variety of blending and additive-injection services. In addition, as part
of the transaction, ConocoPhillips entered into a long-term contract to use
the terminals;
o On December 16, 2003, we announced that we expect to declare cash
distributions of $2.84 per unit for 2004, an 8% increase over our cash
distributions of $2.63 per unit for 2003. This expectation included
contributions from assets owned by us as of the announcement data and did
not include any projected benefits from unidentified acquisitions;
o In December 2003, we completed the acquisition of two terminals in Tampa,
Florida for an aggregate consideration of approximately $29.5 million,
consisting of $26.0 million in cash and $3.5 million in assumed
liabilities. The principal purchase was a marine terminal acquired from a
subsidiary of IMC Global, Inc. We also entered into a long-term agreement
with IMC to enable it to be the primary user of the facility, which we will
operate and refer to as the Kinder Morgan Tampaplex terminal. We closed on
this portion of the transaction on December 23, 2003. The terminal sits on
a 114-acre site, and serves as a storage and receipt point for imported
ammonia, as well as an export location for dry bulk products, including
fertilizer and animal feed. The second facility includes assets from the
former Nitram, Inc. bulk terminal, which we plan to use as an inland bulk
storage warehouse facility for overflow cargoes from our Port Sutton import
terminal, also located in Tampa. We closed on the Nitram portion of the
transaction on December 10, 2003;
o During 2003, we spent $577.0 million for additions to our property, plant
and equipment, including both expansion and maintenance projects. Our
capital expenditures included the following:
o $272.2 million in our CO2 segment, mostly related to additional
infrastructure, including wells, injection and compression facilities,
to support the expanding carbon dioxide flooding operations at the
SACROC oil field unit;
o $108.4 million in our Terminals segment, mostly related to expansions at
our liquid terminal facilities located in Carteret and Perth Amboy, New
Jersey and Pasadena and Galena Park, Texas, as well as other smaller
projects;
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o $101.7 million in our Natural Gas Pipelines segment, mostly related to
completing the construction and start up of our Mier-Monterrey Pipeline
and to the expansion at the Cheyenne Market Center, both described
above; and
o $94.7 million in our Products Pipelines segment, mostly related to
infrastructure modifications at many of our California terminals so that
our shippers can blend ethanol, expansions to our North System pipeline
and a storage expansion project at our combined Carson/Los Angeles
Harbor terminal system in the state of California;
o On February 3, 2004, we announced that we had priced a public offering of
5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We also granted to the underwriters
an option to purchase up to 795,000 additional common units to cover
over-allotments. On February 9, 2004, 5,300,000 common units were issued.
We received net proceeds of $237.8 million for the issuance of these common
units and we used the proceeds to reduce the borrowings under our
commercial paper program; and
o On February 4, 2004, we announced that we had reached an agreement with
Exxon Mobil Corporation to purchase seven refined petroleum products
terminals in the southeastern United States. The terminals are located in
Collins, Mississippi, Knoxville, Tennessee, Charlotte and Greensboro North
Carolina, and Richmond, Roanoke and Newington, Virginia. Combined, the
terminals have a total storage capacity of approximately 3.2 million
barrels for gasoline, diesel fuel and jet fuel. As part of the transaction,
Exxon Mobil has entered into a long-term contract to store products in the
terminals. The acquisition enhances our terminal operations in the
Southeast and complements our December 2003 acquisition of seven products
terminals from ConocoPhillips Company and Phillips Pipe Line Company. The
acquired operations will be included as part of our Products Pipelines
business segment.
(b) Financial Information about Segments
For financial information on our four reportable business segments, see Note
15 to our Consolidated Financial Statements.
(c) Narrative Description of Business
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 Commission and
certain non rate-regulated operations and terminal facilities.
Specifically, our Pacific operations include:
o our SFPP, L.P. operations, comprised of approximately 2,800 miles of
pipelines that transport refined petroleum products to some of the
fastest growing population centers in the United States, including
Southern 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 9.9 million barrels;
o our CALNEV pipeline operations, comprised of approximately 550-miles
of pipelines that transport refined petroleum products from Colton,
California to the growing Las Vegas, Nevada market, McCarran
International Airport in Las Vegas, Nevada, and 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;
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o our Central Florida Pipeline, two pipelines that total 195-miles and
transport 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
in both directions 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 the 3,100-mile
Plantation 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 newly-formed Kinder Morgan Southeast Terminals, currently consisting of
seven refined petroleum products terminals acquired in December 2003 from
ConocoPhillips and Phillips Pipe Line Company;
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 five
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 3,300 miles of refined petroleum products
pipeline and related terminal facilities.
Refined petroleum products and related uses are:
Product Use
------- ----------------------
Gasoline Transportation
Diesel fuel Transportation (auto, rail, marine), agricultural,
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 39
customer-owned terminals, eight commercial airports and 15 military bases. For
2003, the three main product types transported were gasoline (62%), diesel fuel
(22%) and jet fuel (16%). Our 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
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;
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o San Diego Line; and
o CALNEV Line.
The West Line consists of approximately 660 miles of primary pipeline and
currently transports products for 38 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 and domestic 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 diameter and 12-inch
diameter 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. We have
embarked on a major expansion of this pipeline system. The expansion consists of
replacing 160 miles of 8-inch diameter pipe between El Paso and Tucson and 84
miles of 8-inch diameter pipe between Tucson and Phoenix, with 16-inch and
12-inch diameter pipe, respectively.
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 Line consists of two parallel 248-mile, 14-inch and 8-inch
diameter pipelines from our facilities at Colton, California to Las Vegas,
Nevada. It also includes approximately 55 miles of pipeline serving Edwards Air
Force Base. CALNEV originates at Colton, California and serves two CALNEV
terminals at Barstow, California and Las Vegas, Nevada. The CALNEV pipeline also
serves McCarran International Airport, 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 820 miles of trunk 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 Francisco Bay Area and from various pipeline and
marine terminals that deliver products from foreign and domestic ports. The
14-inch diameter pipeline between Concord and Sacramento is currently being
replaced with a 20-inch diameter pipeline, expected to be in service by the end
of the fourth quarter of 2004.
The Bakersfield Line is a 100-mile, 8-inch diameter pipeline serving Fresno,
California. A refinery located in Bakersfield, California, which supplies
substantially all of the products shipped through the Bakersfield Line, has
announced that it will cease operations by the end of 2004. We are currently
evaluating the effects of this closure on our Pacific operations in the San
Joaquin Valley; however, we expect the effect to be relatively neutral to the
overall operating results of our Pacific operations' pipelines.
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The Oregon Line is a 114-mile pipeline serving 11 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 connected 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 is the largest marine fuel oil storage facility in
Puget Sound and also has a multi-component, in-line blending system for
providing customized bunker fuels to the marine 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 ten million barrels. The truck terminals are located
at most destination points on each of our Pacific operations' pipelines as well
as some intermediate points along each pipeline. The simultaneous truck-loading
capacity of each terminal ranges from two to 12 trucks. We provide the following
services at these terminals:
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o short-term product storage;
o truck-loading;
o vapor handling;
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. 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 68 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. If current
trends continue, we expect the majority of our Pacific operations' markets to
maintain growth rates that will 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 mandated the elimination of MTBE (methyl tertiary-butyl ether)
from gasoline by January 1, 2004. Since this date, MTBE-blended gasoline has
been replaced by ethanol-blended gasoline. Since ethanol cannot be shipped by
pipeline, we are realizing a downward adjustment in gasoline delivery volumes in
California; however, our overall revenues are not expected to be adversely
impacted as we charge a fee to blend ethanol at our terminals.
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.
15
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 to our Pacific operations 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 of trucks for product distribution from either shipper-owned
proprietary terminals or from their refining centers remains a competitive
threat for short haul movements by pipeline. The mandated elimination of MTBE
and required substitution of ethanol in California gasoline resulted in at least
a temporary increase in trucking distribution from shipper owned terminals. We
cannot predict with any certainty whether the use of short haul trucking will
decrease 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 2004. 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. Increased movements into the
Arizona market from El Paso would currently displace higher tariff volumes
supplied from Los Angeles on our West Line. However, our East Line is currently
running at full capacity and we have plans to increase East Line capacity to
meet market demand. The planned capacity increase will require significant
investment which should, under the FERC cost of service methodology, result in a
more balanced tariff between our East and West Lines. Such shift of supply
sourcing has not had, and is not expected to have, a material effect on our
operating results.
Terminals owned by our Pacific operations also compete with terminals owned
by our shippers and by third party terminal operators in numerous locations.
Competing terminals are located in Reno, Sacramento, San Jose, Stockton, Colton,
Mission Valley, and San Diego, California and Phoenix and Tucson, Arizona and
Las Vegas, Nevada.
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 Pacific Energy, 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 diameter
pipeline that transports gasoline and an 85-mile, 10-inch diameter 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. 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 diameter 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 2003, the pipeline
16
transported approximately 96,000 barrels per day of refined products, with the
product mix being approximately 68% gasoline, 14% diesel fuel, and 18% jet fuel.
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. The balance of the market is
supplied primarily by trucking firms and marine transportation firms. 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 inMarch 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 via marine vessels 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 comes from trucks loading at 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. We believe it is unlikely that a new pipeline system
comparable in size and scope to our Central Florida Pipeline operations will be
constructed, due to the high cost of pipeline construction and environmental and
right-of-way permitting in Florida. However, the possibility of such a pipeline
being built is a continuing competitive factor.
North System
Our North System is an approximate 1,600-mile interstate common carrier
pipeline used to deliver 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.
17
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:
Product Use
Propane Residential heating, industrial and agricul-
tural uses, petrochemical feedstock
Isobutane Further processing
Natural gasoline Further processing or blending into gasoline
motor fuel
Ethane/Propane Mix Feedstock for petrochemical plants or peak-
shaving 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 pipelines are
comprised of approximately 1,400 miles of 8-inch and 10-inch diameter pipelines
and include:
o two pipelines 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 Magellan Midstream
Partners, L.P. that interconnects with our North System. This capacity lease
agreement requires us to pay $2.1 million per year, is in place until February
2013 and contains a five-year renewal option. In addition to our capacity lease
agreement with Magellan, we also have a reversal agreement with Magellan 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 Magellan for this agreement.
Our North System has approximately 5.6 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 ConocoPhillips 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 2004 lease fee will be approximately
$1.1 million.
In addition, our North System has seven propane truck-loading terminals at
various points in three states along the pipeline system 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 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
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geographic regions served by the Heartland pipeline system directly affect the
volume of refined petroleum products transported by Heartland.
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. 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 Magellan Midstream 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.
For the year 2003, Plantation delivered 612,451 barrels per day, a 3.9%
reduction from a record high in 2002. These delivered volumes were comprised of
gasoline (65%), diesel/heating oil (22%) and jet fuel (13%). The decline in
volume in 2003 compared to 2002 was primarily attributable to several unusual
events. First, three refineries in the State of Louisiana, ExxonMobil (Baton
Rouge), Marathon Ashland (Garyville), and Placid (Port Allen), experienced
extended refinery outages during February and March. Secondly, Chevron's
refinery in Pascagoula, Mississippi experienced an extended outage from February
into April. Finally, Murphy's refinery in Meraux, Louisiana experienced a major
fire in June and was down until November. Another factor affecting Plantation
was the implementation of a more stringent sulfur specification for the Atlanta
gasoline market. Due to limited availability of this grade of gasoline from
Plantation source refineries, much of this gasoline into the Atlanta market was
supplied from Colonial Pipeline.
Plantation is expecting a 1.8% improvement in overall volumes during 2004. It
is anticipated that this growth will primarily be driven by an improving economy
and a significantly reduced level of refinery outages.
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 eight 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.
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In addition, Plantation delivers jet fuel to the Atlanta, Georgia; Charlotte,
North Carolina; and Washington, D.C. airports (Ronald Reagan National and
Dulles). Combined jet fuel shipments to these four major airports increased 0.1%
(led by an 18.6% increase in shipments to Ronald Reagan National) in 2003. Jet
fuel demand at Atlanta and Dulles was negatively impacted due to continued weak
international travel. An improving domestic economy should help improve jet fuel
demand in 2004.
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 the Colonial pipeline system,
which also runs from Gulf Coast refineries throughout the southeastern United
States and extends into the northeastern states.
Kinder Morgan Southeast Terminals LLC
Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to
herein as KMST, was formed in 2003 for the purpose of acquiring and operating
high-quality liquid petroleum products terminals located primarily along the
Plantation/Colonial pipeline corridor in the Southeastern United States.
Terminals acquired and operated by KMST will be independent with no affiliation
to major oil companies or marketers.
On December 11, 2003, KMST acquired seven petroleum products terminals from
ConocoPhillips and Phillips Pipe Line for an aggregate consideration of
approximately $15.1 million, consisting of approximately $14.1 million in cash
and $1.0 million in assumed liabilities. These seven terminals contain
approximately 1.15 million barrels of storage capacity. The terminals are
located in the following markets: Selma, North Carolina; Charlotte, North
Carolina; Spartanburg, South Carolina; North Augusta, South Carolina; Doraville,
Georgia; Albany, Georgia; and Birmingham, Alabama. ConocoPhillips has entered
into a long-term contract to use the terminals. All seven terminals are served
by Colonial Pipeline and three are also connected to Plantation.
KMST has also recently reached agreement with ExxonMobil to purchase seven of
its refined petroleum products terminals at the following locations: Newington,
Virginia; Richmond, Virginia; Roanoke, Virginia; Greensboro, North Carolina;
Charlotte, North Carolina; Knoxville, Tennessee; and Collins, Mississippi. The
terminals have a combined storage capacity of approximately 3.2 million barrels
for gasoline, jet fuel and diesel fuel. ExxonMobil has entered into a long-term
contract to use the terminals. This transaction is expected to close during
March 2004. All seven of these terminals are served by Plantation and two are
also connected to Colonial.
Markets. KMST acquisition and marketing activities will be focused on the
Southeastern United States from Mississippi through Virginia, including
Tennessee. The primary marketing activity will involve receipt of petroleum
products from common carrier pipelines, short-term storage in terminal tankage,
and subsequent loading onto tank trucks. With the close of the ExxonMobil
acquisition, KMST will have a physical presence in markets representing over 75%
of the pipeline-supplied demand in the Southeast. KMST will offer a competitive
alternative to marketers seeking a relationship with a truly independent truck
terminal service provider.
Supply. Product supply will be predominately from either Plantation,
Colonial, or both. To the maximum extent practicable, connectivity to both
Plantation and Colonial will be sought.
Competition. There are relatively few independent terminal operators in the
Southeast. Most of the refined product terminals in this region are owned by
large oil companies (BP, Motiva, Citgo, Marathon Ashland, and Chevron) who use
these assets to support their own proprietary market demands as well as product
exchange activity. These oil companies are not generally seeking third party
throughput customers. Magellan Midstream Partners (formerly Williams Energy
Partners) and TransMontaigne Product Services represent the only two significant
independent terminal operators in this region.
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Cochin Pipeline System
We own 44.8% of the Cochin pipeline system, an approximate 1,900-mile,
12-inch diameter 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. 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.
Supply. Injection into the system can occur from:
o BP, EnerPro or Dow fractionation facilities at Fort Saskatchewan, Alberta;
o Provident Energy storage at five points within the provinces of Canada; or
o the Enterprise West Junction, in Minnesota.
Competition. The pipeline competes with railcars and 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 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.
Supply. The Cypress pipeline originates in Mont Belvieu where it is able to
receive ethane and ethane/propane mix from local storage facilities. Mont
Belvieu has facilities to fractionate 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.
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Competition. The pipeline's primary competition into the Lake Charles market
comes from Louisiana onshore and offshore natural gas liquids.
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 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 Colonial's 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. It primarily processes 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. It primarily
processes 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.
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 acquiring transmix supply at all facilities 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
22
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, which contains both interstate and
intrastate pipelines, consists of natural gas transportation, storage,
gathering, processing, treating and matched purchases/sales. 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 include the
following:
o our Texas intrastate natural gas pipeline group, which consists of
approximately 5,800 miles of intrastate natural gas pipeline with a peak
transport capacity of approximately five billion cubic feet per day of
natural gas and approximately 120 billion cubic feet of natural gas storage
capacity (including the West Clear Lake natural gas storage facility
located in Harris County, Texas, which is committed under a long term
contract to Coral Energy as part of our Kinder Morgan Tejas acquisition).
Our intrastate natural gas pipeline group operates primarily along the
Texas Gulf Coast and includes the following four pipeline systems: Kinder
Morgan Texas Pipeline, Kinder Morgan Tejas, Mier-Monterrey Mexico Pipeline,
and the North Texas Pipeline;
o our two Rocky Mountain interstate natural gas pipeline systems: Kinder
Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company.
KMIGT owns a 6,100-mile natural gas pipeline system, including the Pony
Express pipeline system, that extends from northwestern Wyoming east into
Nebraska and Missouri and south through Colorado and Kansas. Our
Trailblazer pipeline is a 436-mile pipeline that transports natural gas
from Colorado 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 two carbon dioxide
processing plants;
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
As described above, our Texas intrastate natural gas pipeline group consists
of the following four pipeline systems: Kinder Morgan Texas Pipeline, Kinder
Morgan Tejas, Mier-Monterrey Mexico Pipeline and the North Texas Pipeline.
Our Kinder Morgan Tejas system was acquired on January 31, 2002 from
Intergen, a joint venture owned by affiliates of the Royal Dutch Shell Group of
Companies, and Bechtel Enterprises Holding, Inc. The system has become
increasingly interconnected with our Kinder Morgan Texas Pipeline system, which
was acquired on December 31, 1999 from KMI. These pipelines essentially operate
as a single pipeline system, providing customers and suppliers with improved
flexibility and reliability. The combined assets include over 5,800 miles of
pipeline with a peak transport capacity of approximately five billion cubic feet
per day of natural gas and approximately 120 billion cubic feet of natural gas
storage capacity. In addition, the system has the capability to process over
23
one 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.
Collectively, the system primarily 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. It serves as a buyer and seller of natural gas, as well as a
transporter of natural gas. The 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.
Our North Texas Pipeline, a $65 million investment, was completed in August
2002. The system consists of an 86-mile, 30-inch diameter pipeline that
transports natural gas from an interconnect with KMI's Natural Gas Pipeline
Company of America in Lamar County, Texas to a 1,750-megawatt electric
generating facility located in Forney, Texas, 15 miles east of Dallas, Texas. It
has the capacity to transport 325,000 dekatherms per day of natural gas and is
fully subscribed under a 30 year contract. Our Mier-Monterrey Pipeline, an $89
million investment, was completed in March 2003. The system consists of a
95-mile, 30-inch diameter pipeline that stretches from south Texas to Monterrey,
Mexico and can transport up to 375,000 dekatherms per day of natural gas. The
pipeline connects to a 1,000-megawatt power plant complex and to the PEMEX
natural gas transportation system. We have entered into a 15 year contract with
Pemex Gas Y Petroquimica Basica, which has subscribed for all of the pipeline's
capacity.
Markets. Our Texas intrastate natural gas pipeline group's market area
consumes over eight 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 and utility power 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, we have
successfully attached these new generation facilities to our pipeline systems in
order to maintain our share of natural gas supply for power generation.
Mexico is an increasingly important market. We serve this market through
interconnection with the facilities of Pemex at the United States-Mexico border
near Arguellas, Mexico and Monterrey, Mexico. Current deliveries through the
existing interconnection near Arguellas are approximately 200,000 dekatherms per
day of natural gas and deliveries to Monterrey generally range from 200,000 to
300,000 dekatherms per day of natural gas. We primarily provide 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. We purchase our natural gas directly from producers attached to our
system in South Texas, East Texas and along the Texas Gulf Coast. We also
purchase gas at interconnects with third-party interstate and intrastate
pipelines. While our intrastate group does not produce gas, it does maintain an
active well connection program in order to offset natural declines in production
along its system and to secure supplies for additional demand in its market
area. Our intrastate system has access to both onshore and offshore sources of
supply, and is well positioned to interconnect with liquefied natural gas
projects currently under development by others along the Texas Gulf Coast.
Gathering, Processing and Treating. Our intrastate natural gas group owns and
operates various gathering systems in South and East Texas. These systems
aggregate pipeline quality natural gas supplies into our main transmission
pipelines, and in certain cases, aggregate natural gas that must be processed or
treated at its own facilities or the facilities of others. We own two processing
plants: our Texas City Plant in Galveston County, Texas and our Galveston Bay
Plant in Chambers County, Texas. Combined, these plants can process 150 million
cubic feet per day of natural gas for liquids extraction. In addition, we have
contractual rights to process approximately one billion cubic feet per day of
natural gas at various third-party owned facilities. We also own and operate
four natural gas treating plants that offer carbon dioxide and/or hydrogen
sulfide removal. We can treat up to 150 million cubic feet per day of natural
gas for carbon dioxide removal at our Fandango Complex in Zapata
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County, Texas, 60 million cubic feet per day of natural gas at our M.P. 16 Plant
in Webb County, Texas and approximately 40 million cubic feet per day of natural
gas at our Thompsonville Facility in Jim Hogg County, Texas. Not all of these
plants are currently operating. Economic conditions and gas quality conditions
dictate operations. In addition, we own and operate the Indian Rock Plant
located in Upshur County, Texas. The plant is capable of treating 45 million
cubic feet per day of natural gas for carbon dioxide and/or hydrogen sulfide
removal.
Storage. We own 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 we provides transportation service into and out of the
facility. We lease a salt dome storage facility located near Markham, Texas. The
facility consists of two salt dome caverns with approximately 7.5 billion cubic
feet of total natural gas storage capacity, over 4.8 billion cubic feet of
working natural gas capacity and up to 400 million cubic feet per day of peak
deliverability. We also lease 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 5.4 billion cubic feet and a peak day deliverability of up to 400
million cubic feet per day. In addition, we control, through contractual
arrangements, another ten billion cubic feet of third-party natural gas storage
capacity in the Houston, Texas area and 4.1 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. We compete with
interstate and intrastate pipelines, and their shippers, for attachments to new
markets and supplies and for transportation, processing and treating services.
Kinder Morgan Interstate Gas Transmission LLC
Kinder Morgan Interstate Gas Transmission LLC, referred to herein as KMIGT,
owns approximately 5,000 miles of transmission lines in Wyoming, Colorado,
Kansas, Missouri and Nebraska. It provides transportation and storage services
to KMI affiliates, third-party natural gas distribution utilities and other
shippers. Pursuant to transportation agreements and Federal Energy Regulatory
Commission 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 relatively
consistent volumes throughout the year.
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 contracted firm transportation
and storage capacity on KMIGT's system. Over 98% of the system's firm transport
capacity is currently subscribed.
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Competition. KMIGT competes with other interstate and intrastate gas
pipelines transporting gas from the supply sources in the Rocky Mountain and
Hugoton Basins to mid-continent pipelines and market centers.
Trailblazer Pipeline Company
Trailblazer Pipeline Company 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. Trailblazer has
a certificated capacity of 846 million cubic feet per day of natural gas. In May
2002, we completed a fully-subscribed, $48 million expansion project on the
Trailblazer system that expanded its transportation capacity by 324,000
dekatherms of natural gas per day. The expansion increased capacity on the
pipeline by approximately 60% and provides new firm long-term transportation
service. In conjunction with the expansion, the FERC also granted Trailblazer's
request to assess incremental rates and fuel for shippers taking capacity
related to the expansion facilities.
Supply. As of December 31, 2003, none of Trailblazer's firm contracts expire
before one year and 38%, by volume, 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. In October 2003, the FERC issued a preliminary determination approving
the Cheyenne Plains pipeline project that is being developed by Colorado
Interstate Gas Company. This project, which has a proposed in service date of
August 2005, would allow for the transportation of 560,000 dekatherms per day of
natural gas from Weld County, Colorado to Greensburg, Kansas and is expected to
compete with Trailblazer.
Casper and Douglas Natural Gas Gathering and Processing Systems
We own and operate our Casper and Douglas natural gas gathering and
processing facilities.
The Douglas gathering system is comprised of approximately 1,500 miles of
4-inch to 16-inch diameter pipe that gathers approximately 35 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.
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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 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 900 miles of
gathering pipeline connecting more than 700 producing wells, 76,000 horsepower
of compression at 21 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 750 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. Gulf Terra Energy Partners, L.P. owns the remaining 50%. 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.
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%. 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
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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 125 miles of 24-inch diameter
mainline pipeline, 308 miles of 4-inch to 12-inch diameter high and low pressure
laterals, 19,890 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
34 receipt points and can deliver treated gas to seven delivery points including
Colorado Interstate Gas, Wyoming Interstate Gas Company, KMIGT and three power
plants. The low pressure gathering assets include five systems consisting of 169
miles of 4-inch to 14-inch diameter gathering pipeline and 50,260 horsepower of
field compression. Gas is gathered from 79 receipt points and delivered to the
mainline at seven primary locations.
CO2
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates, referred to herein as KMCO2. Carbon dioxide is used in
enhanced oil recovery projects as a flooding medium for recovering crude oil
from mature oil fields. Our carbon dioxide pipelines and related
assets allow us to market a complete package of carbon dioxide supply,
transportation and technical expertise to the customer. Together, our CO2
business segment produces, transports and markets carbon dioxide for use in
enhanced oil recovery operations and owns interests in other related assets in
the continental United States, through the following:
o our interests in carbon dioxide reserves, including an approximate 45%
interest in the McElmo Dome unit and an approximate 11% interest in the
Bravo Dome unit;
o our carbon dioxide pipelines, including:
o our Central Basin pipeline, a 320-mile carbon dioxide pipeline system
located in the Permian Basin of West Texas between Denver City, Texas
and McCamey, Texas;
o our Centerline pipeline, a 113-mile carbon dioxide pipeline located
in the Permian Basin of West Texas between Denver City, Texas and
Snyder, Texas; and
o our interests in other carbon dioxide pipelines, including an
approximate 98% interest in the Canyon Reef Carriers pipeline, a 50%
interest in the Cortez pipeline, a 13% undivided interest in the
Bravo pipeline system and an approximate 69% interest in the Pecos
pipeline;
o our interests in oil-producing fields, including an approximate 97% working
interest in the SACROC unit, an approximate 50% working interest in the
Yates unit, a 22% net profits interest in the H.T. Boyd unit and minority
interests in the Sharon Ridge unit, the Reinecke unit and the MidCross
unit, all of which are located in the Permian Basin of West Texas; and
o our interests in gasoline plants, including an approximate 22% working
interest in and an additional 26% net profits 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.
Carbon Dioxide Reserves
We own approximately 45% of the McElmo Dome unit, and operate the unit which
contains more than 10 trillion cubic feet of nearly pure carbon dioxide.
Deliverability and compression capacity exceeds one billion cubic feet per day.
The McElmo Dome unit produces from the Leadville formation at approximately
8,000 feet with 47 wells that produce at individual rates of up to 60 million
cubic feet per day.
We also own approximately 11% of Bravo Dome unit, which holds reserves of
approximately two trillion cubic feet of carbon dioxide. The Bravo dome produces
approximately 310 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.
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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, California, Mexico 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 carbon dioxide reserves, and Petro-Source Carbon Company, 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
interest owners in McElmo Dome for transportation of carbon dioxide to the
Denver City, Texas market area. There is no assurance that new carbon dioxide
sources will not be discovered or developed, which could compete with us or that
new methodologies for enhanced oil recovery will not replace carbon dioxide
flooding.
Carbon Dioxide Pipelines
Placed in service in 1985, our Central Basin pipeline consists of
approximately 143 miles of 16-inch to 20-inch diameter pipe 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,
respectively). Central Basin's mainline terminates near McCamey where it
interconnects with the Canyon Reef Carriers pipeline and the Pecos pipeline. The
tariffs charged by the Central Basin pipeline are not regulated.
Our Centerline pipeline consists of approximately 113 miles of 16-inch
diameter pipe located in the Permian Basin between Denver City, Texas and
Snyder, Texas. The pipeline has a capacity of 250 million cubic feet per day. We
constructed this pipeline and placed it in service in May 2003. The tariffs
charged by the Centerline pipeline are not regulated.
As a result of our 50% ownership interest in Cortez Pipeline Company, we own
a 50% interest in and operate the 502-mile, 30-inch diameter Cortez pipeline.
The pipeline carries carbon dioxide from the McElmo Dome source reservoir in
Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline currently
transports nearly one billion cubic feet per day, including approximately 90% of
the carbon dioxide transported downstream on our Central Basin pipeline and our
Centerline pipeline.
We own a 13% undivided interest in the 218-mile, 20-inch diameter 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 98% of the Canyon Reef Carriers pipeline and
approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline
extends 138 miles from McCamey, Texas, to the SACROC unit. The pipeline has a
16-inch diameter, a capacity of approximately 290 million cubic feet per day and
makes deliveries to the SACROC, Sharon Ridge, Cogdell and Reinecke units. The
Pecos pipeline is a 25-mile, 8-inch diameter pipeline that runs from McCamey to
Iraan, Texas. We acquired an additional 65% ownership interest in the pipeline
on November 1, 2003 from a subsidiary of Marathon Oil Company and we are
currently bringing the pipeline back into service.
Oil Reserves
The SACROC unit is one of the largest and oldest oil fields in the United
States using carbon dioxide flooding technology. The field 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 1.26 billion barrels of oil
since inception, or approximately 47% of 2.7 billion barrels of original oil in
place. We have continued the development of the carbon
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dioxide project initiated by the previous owners and have reversed the decline
in production through increased carbon dioxide injection.
Effective June 1, 2003, we increased our interest in SACROC to approximately
97% by acquiring MKM Partners, L.P.'s 12.75% ownership interest. MKM Partners,
L.P. was an oil and gas joint venture formed on January 1, 2001 and owned 15% by
KMCO2 and 85% by subsidiaries of Marathon Oil Company. The joint venture's
assets consisted of a 12.75% interest in the SACROC field unit and a 49.9%
interest in the Yates field unit. MKM Partners, L.P. was dissolved effective
June 30, 2003, and its net assets were distributed to partners in accordance
with its partnership agreement.
As of December 2003, the SACROC unit had 255 producing wells, and the
purchased carbon dioxide injection rate was 317 million cubic feet per day, up
from an average of 140 million cubic as of December 2002. The oil production
rate as of December 2003 was approximately 23,000 barrels of oil per day, up
from approximately 17,000 barrels of oil per day as of December 2002. The
Yates unit is also one of the largest oil fields ever discovered in the United
States. It originally held more than five billion barrels of oil, of which about
28% has been produced. The field is comprised of approximately 26,400 acres
located about 90 miles south of Midland, Texas. The Yates field was discovered
in 1926. Effective November 1, 2003, we increased our interest in Yates and
became operator of the field by acquiring an additional 42.5% ownership interest
from subsidiaries of Marathon Oil Company. We now own a nearly 50% ownership
interest in the Yates field unit. We also acquired all of the crude oil
gathering lines and equipment surrounding the Yates field.
As of December 2003, the Yates unit was producing about 18,000 barrels of oil
per day. Our plan is to increase the production life of Yates by combining
horizontal drilling with carbon dioxide flooding to ensure a relatively steady
production profile over the next several years. Unlike our operations at SACROC,
where we use carbon dioxide and water to drive oil to the producing wells, we
plan on using carbon dioxide injection to replace nitrogen injection at Yates in
order to enhance the gravity drainage process, as well as to maintain reservoir
pressure. The differences in geology and reservoir mechanics between the two
fields mean that substantially less capital will be needed to develop the
reserves at Yates than is required at SACROC.
Gas Plant Interests
We operate and own an approximate 22% working interest plus an additional 26%
of the net profits of the Snyder gasoline plant, 51% of the Diamond M gas plant
and 100% of the North Snyder plant. The Snyder gasoline plant processes gas
produced from the SACROC unit and neighboring carbon dioxide projects,
specifically the Sharon Ridge and Cogdell units, all of which are located in the
Permian Basin area of West Texas. The Diamond M and the North Snyder plants
contract with the Snyder plant to process gas pursuant to contract agreements.
Production of natural gas liquids at the Snyder gasoline plant has increased
from approximately 7,102 barrels per day as of December 2002 to approximately
9,076 barrels per day as of December 2003.
Terminals
Our Terminals segment includes the business portfolio of approximately 52
terminals that transload and store coal, dry-bulk materials and
petrochemical-related liquids, as well as approximately 57 transload operations
located throughout the United States. Our liquids terminal operations primarily
store commercial liquids, including refined petroleum products and industrial
chemicals, in aboveground storage tanks and transfer products to and from
pipelines, tank trucks, tank barges and tank rail cars. Our bulk terminal
operations primarily involve bulk material handling services; however, we also
provide terminal engineering and design services and in-plant services covering
material handling, maintenance and repair services, rail car switching services,
ship agency and miscellaneous marine services.
Liquids Terminals
Kinder Morgan Liquids Terminals LLC, referred to herein as KMLT, is comprised
of 12 bulk liquids terminal facilities and 51 rail transloading and materials
handling operations. Together, these facilities have a total capacity
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of approximately 36.2 million barrels of liquid products, primarily gasoline,
distillates, petrochemicals and vegetable oil products. In 2003, our liquids
terminals handled approximately 514 million barrels of clean petroleum,
petrochemical and vegetable oil products for approximately 250 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 7.1 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 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 area. 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 three 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 own Kinder Morgan Materials Services LLC,
referred to herein as KMMS. KMMS operates approximately 57 rail transloading
facilities, of which 47 are located east of the Mississippi River. The CSX,
Norfolk Southern, Union Pacific, Kansas City Southern and A&W railroads provide
rail service for our terminal 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.
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Competition. We are one of the largest independent operators of liquids
terminals in North America. Our largest competitors are Magellan, ST Services,
IMTT, Vopak, Oil Tanking and Transmontaigne.
Bulk Terminals
Our Bulk Terminals consist of 40 bulk terminals, which handle approximately
60 million tons of bulk products annually. Collectively, our bulk terminals have
two million tons of covered storage and 14 million tons of open storage.
Coal Terminals
We handled approximately 25 million tons of coal in 2003, 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 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 began to operate a synfuel plant on site, and in
early 2004, Pier IX began to operate a second synfuel plant on site. Volumes of
synfuel produced in 2003 were 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, but continues to handle petroleum coke.
The facility is currently for sale and we will be dealing with a new owner
during 2004.
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 be 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 2003, four major customers accounted for approximately 90% of all the
coal loaded through our Cora Terminal.
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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 were 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 was approximately three 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 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 2003.
We own or operate an additional 13 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, ilmenite, fertilizer, ore and other industries seeking specialists who can
build, own and operate bulk terminals.
Included among these terminals is our Owensboro Gateway terminal, acquired on
September 1, 2002 and our 66 2/3% ownership interest in International Marine
Terminals Partnership, acquired on February 1, 2002. The Owensboro Gateway
terminal, located in Owensboro, Kentucky, 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. The IMT partnership
operates a bulk terminal site in Port Sulphur, Louisiana that handles
approximately eight million tons per year of iron ore, coal, petroleum coke and
barite. Additionally, on December 31, 2002, we purchased four barge-mounted
crane units from Stevedoring Services of America for use at the IMT terminal. We
had previously leased these cranes from a third-party under an operating lease
and our ownership of these cranes has reduced our overall operating costs during
2003 and ensured crane availability.
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.
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New Terminals
Effective January 1, 2003, we acquired the assets of Rudolph Stevedoring for
approximately $31.3 million. On December 31, 2002, we paid $29.9 million for the
Rudolph acquisition and in the first quarter of 2003, we paid the remaining $1.4
million. 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.
In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.5 million, consisting of
$26.0 million in cash and $3.5 million in assumed liabilities. The principal
purchase was a marine terminal acquired from a subsidiary of IMC Global, Inc. We
also entered into a long-term agreement with IMC to enable it to be the primary
user of the facility, which we will operate and refer to as the Kinder Morgan
Tampaplex terminal. The terminal sits on a 114-acre site, and serves as a
storage and receipt point for imported ammonia, as well as an export location
for dry bulk products, including fertilizer and animal feed. The second facility
includes assets from the former Nitram, Inc. bulk terminal, which we plan to use
as an inland bulk storage warehouse facility for overflow cargoes from our Port
Sutton import terminal.
Major Customers
Our total operating revenues are derived from a wide customer base. For each
of the years ended December 31, 2003, 2002 and 2001, one customer accounted for
more than 10% of our total consolidated revenues. Total transactions with
CenterPoint Energy accounted for 16.8% of our total consolidated revenues during
2003 and 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. The high percentage of our total revenues
attributable to CenterPoint Energy directly relates to the growth of our Natural
Gas Pipelines segment, especially since our acquisition of Kinder Morgan Texas
Pipeline on December 31, 2000 and Kinder Morgan Tejas on January 31, 2002. Due
to these acquisitions and the subsequent formation of our Texas intrastate
natural gas group, we have realized significant increases in the volumes of
natural gas we buy and sell within the State of Texas. As a result, both our
total consolidated revenues and our total consolidated purchases (cost of sales)
have increased considerably since 2000 due to the inclusion of the cost of gas
in both financial statement line items. These higher revenues and higher
purchased gas cost do not necessarily translate into increased margins in
comparison to those situations in which we charge to transport gas owned by
others. We do not believe that a loss of revenues from any single customer would
have a material adverse effect on our business, financial position, results of
operations or cash flows.
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 products 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 addition, during the first quarter of 2003,
the FERC made a significant positive adjustment to the index which petroleum
products pipelines use to adjust their regulated tariffs for inflation. The old
index used percent growth in the producer price index for finished goods, and
then subtracted one percent. The new index eliminated the one percent reduction.
As a result, we have filed for rate adjustments on a number of our petroleum
products pipelines and have realized benefits from the new index beginning in
the second quarter of 2003. In 2002 and 2001, application of the indexing
methodology did not significantly affect rates on our petroleum products
pipelines.
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The ICA requires, among other things, that such rates on interstate common
carrier pipelines 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 products pipeline tariff 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 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 and rates charged by companies performing interstate
natural gas transportation and storage 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, the 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 between interstate natural gas
pipelines and their marketing affiliates and imposing certain disclosure
requirements regarding that interaction; and
o Order 636 (1992) which required interstate natural gas 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 interstate natural gas industry, including:
o requiring the unbundling of sales services from other services;
o permitting holders of firm capacity on interstate natural gas pipelines 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.
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We are also subject to the requirements of FERC Order Nos. 497, et seq., and
566, et. seq., the Marketing Affiliate Rules, which prohibit preferential
treatment by an interstate natural gas pipeline of its marketing affiliates
and govern, in particular, the provision of information by an interstate natural
gas pipeline to its marketing affiliates. The FERC, in a Notice of Proposed
Rulemaking in RM01-10-000, has proposed standards of conduct to govern
interactions between interstate natural gas pipelines and electric transmission
utilities and their energy affiliates. These standards would entirely replace
the current standards of conduct related to affiliate interaction. Numerous
parties, including KMI's Natural Gas Pipeline Company of America, have filed
comments on the proposed rulemaking.
FERC Order 637
See Note 16 of the Notes to our Consolidated Financial Statements included
elsewhere in this report.
Cash Management
See Note 16 of the Notes to our Consolidated Financial Statements included
elsewhere in this report.
Standards of Conduct Rulemaking
See Note 16 of the Notes to our Consolidated Financial Statements included
elsewhere in this report.
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
operations' 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. 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.
The Pipeline Safety Improvement Act of 2002 was signed into law on December
17, 2002, providing guidelines in the areas of testing, education, training and
communication. The Act requires pipeline companies to perform integrity tests on
natural gas transmission pipelines that exist in high population density areas
that are designated as High Consequence Areas. Pipeline companies are required
to perform the integrity tests within ten years of the date of enactment and
must perform subsequent integrity tests on a seven year cycle. At least 50% of
the highest risk segments must be tested within five years of the enactment
date. The 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. Testing
consists of hydrostatic testing, internal electronic testing, or direct
assessment of the piping. In addition to the pipeline integrity tests, 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 believe that we are in substantial compliance with this law's requirements
and have integrated appropriate aspects of this pipeline safety law into our
Operator Qualification Program, which is already
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in place and functioning. A similar integrity management rule for refined
petroleum products pipelines became effective May 29, 2001. All baseline
assessments for products pipelines must be completed by March 31, 2008.
On March 25, 2003, the U.S. DOT issued their final rules on Hazardous
Materials: Security Requirements for Offerors and Transporters of Hazardous
Materials. We believe that we are in substantial compliance with these rules and
have made revisions to our Facility Security Plan to remain consistent with the
requirements of these rules. The revisions relate primarily to three areas:
o training, the plan now incorporates provisions for conducting awareness
level training and in-depth level training for employees working with
hazardous materials;
o hiring practices, the plan now includes provisions to verify information
provided by job applicants; and
o transportation route security, the plan now calls for verification from
carriers that they have addressed route security from point of origin to
destination.
We are also subject to the requirements of the Federal Occupational Safety
and Health Act and other comparable federal and 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. Some of these changes, such as
U.S. DOT implementation of additional hydrostatic testing requirements, could
significantly increase the amount of these expenditures. Such expenditures
cannot be accurately estimated at this time.
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, and some foreign 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 operation of our businesses. Moreover, it is possible that other
developments, such as
37
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 $39.6
million as of December 31, 2003. For additional information related to
environmental matters, 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
38
part of the costs required to clean up sites at which such materials are
present, in addition to compensation for 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
accordance 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.
Methyl Tertiary-Butyl Ether
Methyl tertiary-butyl ether (MTBE) is used as an additive in gasoline. It is
manufactured by chemically combining a portion of petrochemical production with
purchased methanol. Due to environmental and health concerns, California
mandated the elimination of MTBE from gasoline by January 1, 2004. Furthermore,
both the
39
United States House of Representatives and the United States Senate introduced
legislation in 2003 that would bar the use of MTBE within four years of
enactment. Both bills contain provisions that would gradually phase out the
use of MTBE as a gasoline blendstock. We cannot provide assurances regarding the
likelihood of the passage of either of these bills in any form.
In California, MTBE-blended gasoline has been replaced by an ethanol blend.
However, ethanol cannot be shipped through pipelines and therefore, we will
realize some reduction in California gasoline volumes transported by our Pacific
operations' pipelines. The conversion from MTBE to ethanol in California has
resulted in an increase in ethanol blending services at refined petroleum
product terminal facilities, and we believe the fees we earn for new
ethanol-related services at our terminals will more than offset the expected
reduction in pipeline transportation fees. Furthermore, we have aggressively
pursued additional ethanol opportunities.
Our role in conjunction with ethanol is proving beneficial to our various
business segments as follows:
o our Products Pipelines' terminals are blending ethanol because unlike MTBE,
it cannot flow through pipelines;
o our Natural Gas Pipelines segment is delivering natural gas through our
pipelines to service new ethanol plants that are being constructed in the
Midwest (natural gas is the feedstock for ethanol plants); and
o our Terminals segment is entering into liquid storage agreements for
ethanol around the country, in such areas as Houston, Nebraska and on the
East Coast.
Risk Factors
Like all businesses, we face various obstacles, including rising legal fees,
environmental issues and escalating employee health and benefit costs.
Regulatory challenges to our pipeline transportation rates, including the
current case involving our Pacific operations' pipelines, and possible policy
changes and/or reparation and refund payments ordered by governmental regulatory
entities could negatively affect our future financial performance.
Further, we are well-aware of the general uncertainty associated with the
current world economic and political environments in which we exist and we
recognize that we are not immune to the fact that our financial performance is
impacted by overall marketplace spending and demand. We are continuing to assess
the effect that terrorism would have on our businesses and in response, we have
increased security at our assets. 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 2004. Currently, we
do not believe that the increased cost associated with these measures will have
a material effect on our operating results.
Some of our specifically identified risk factors include the following:
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 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. Hearings on the second of
these two proceedings began in October 2001.
On June 24, 2003, a non-binding, phase one initial decision was issued by an
administrative law judge hearing a FERC case on the rates charged by our Pacific
operations' interstate portion of its pipelines. In his phase one initial
decision, the administrative law judge recommended that the FERC "ungrandfather"
our Pacific operations'
40
interstate rates and found most of our Pacific operations'rates at issue to be
unjust and unreasonable. The administrative law judge has indicated that a phase
two initial decision will address prospective rates and whether reparations are
necessary. Initial decisions have no force or effect and must be reviewed by the
FERC. The FERC is not obliged to follow any of the administrative law judge's
findings and can accept or reject this initial decision in whole or in part. If
the FERC ultimately finds that these rates should be "ungrandfathered" and are
unjust and unreasonable, they could be lowered prospectively and complaining
shippers could be entitled to reparations for prior periods. Ultimate resolution
of phase one and phase two of this matter by the FERC is not expected before
early 2005.
The complaints filed before the CPUC challenge the rates charged for
intrastate transportation of refined petroleum products through our 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 $154 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, federal legislation
signed into law in December 2002 includes 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, such as U.S. DOT implementation of additional hydrostatic
testing requirements, could significantly increase the amount of these
expenditures.
Our rapid growth may cause difficulties integrating new operations, and we
may not be able to achieve the expected benefits from any future acquisitions.
Part of our business strategy includes acquiring additional businesses that will
allow us to increase distributions to our unitholders. If we do no successfully
integrate acquisitions, we may not realize anticipated operating advantages and
cost savings. The integration of companies that have previously operated
separately involves a number of risks, including:
o demands on management related to the increase in our size after an
acquisition;
o the diversion of our management's attention from the management of daily
operations;
o difficulties in implementing or unanticipated costs of accounting,
estimating, reporting and other systems;
o difficulties in the assimilation and retention of employees; and
o potential adverse effects on operating results.
We may not be able to maintain the levels of operating efficiency that
acquired companies will have achieved or might achieve separately. Successful
integration of each of their operations will depend upon our ability to manage
41
those operations and to eliminate redundant and excess costs. Because of
difficulties in combining operations, we may not be able to achieve the cost
savings and other size-related benefits that we hoped to achieve after these
acquisitions, which would harm our financial condition and results of
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, 2003, we made a significant number of acquisitions that
increased our asset base over 30 times and increased our net income over 58
times. We regularly consider and enter into discussions regarding potential
acquisitions and are 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. The
Jobs and Growth Tax Relief Reconciliation Act of 2003 generally reduces the
maximum tax rate on dividends paid by corporations to individuals to 15% in 2003
and, for taxpayers in the 10% and 15% ordinary income tax brackets, to 5% in
2003 through 2007 and to zero in 2008. This legislation may cause some
investments in corporations to be more attractive to individual investors than
they used to be when compared to an investment in partnerships, thereby
exerting downward pressure on the market price of our common units and
potentially making it more difficult for us to access the capital markets.
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 on us of Environmental Protection Agency standards or
future environmental measures 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 on
railroad rights-of-way. 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.
42
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 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 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 or more
restrictive restrictions. Our ability to respond to changes in business and
economic conditions and to obtain additional financing, if needed, may be
restricted.
If interest rates increase, our earnings could be adversely affected. As of
December 31, 2003, we had approximately $2.4 billion of debt, excluding market
value of interest rate swaps, subject to variable interest rates. Approximately
$2.0 billion of this debt was long-term fixed rate debt converted to floating
rate debt through the use of interest rate swaps. Should interest rates increase
significantly, our earnings could be adversely affected.
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.
In addition, 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 contracts, tariffs and
regulations, prepayments and other security requirements, such as letters of
credit, to enhance our credit position
43
relating to amounts owed from these customers. We cannot provide assurance 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, future results of operations
or future cash flows.
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 and the KMR limited liability company agreement
restrict or eliminate a number of the fiduciary duties that would otherwise be
owed by our general partner and/or its delegate 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 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. It also 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. It is not necessary for a limited
partner to sign our limited partnership agreement in order for the limited
partnership agreement to be enforceable against that person.
Other
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, 2003, KMGP Services Company,
Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately 5,539
employees. Approximately 997 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. For more information on
our related party transactions, see Note 12 of the Notes to the Consolidated
Financial Statements included elsewhere in this report.
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 which do
not materially detract from the value of such property or the interests therein
or the use of such properties in our businesses. We generally do not own the
land on which our pipelines are constructed. Instead, we obtain the right to
construct and operate the pipelines on other people's land for a period of time.
Amounts we have spent during 2003, 2002 and 2001 on research and development
activities were not material.
(d) Financial Information about Geographic Areas
The amount of our assets and operations that are located outside of the
continental United States of America are not material.
(e) Available Information
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 Securities Exchange Act
of 1934 as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the Securities and Exchange Commission.
44
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 2003.
45
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.
Price Range
------------------ Cash i-unit
High Low Distributions Distributions
------- ------- ------------- -------------
2003
First Quarter $ 37.00 $ 34.25 $ 0.6400 0.018488
Second Quarter 40.00 36.55 0.6500 0.017138
Third Quarter 42.80 39.01 0.6600 0.016844
Fourth Quarter 49.69 42.84 0.6800 0.015885
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
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 February 12, 2004, there were approximately 141,000 beneficial owners
of our common units, one holder of our Class B units and one holder of our
i-units.
For information on our equity compensation plans, see Item 12 "Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters -- Equity Compensation Plan Information".
We did not repurchase any units during the fourth quarter of 2003.
46
Item 6. Selected Financial Data
The following tables set forth, for the periods and at the dates indicated,
summary historical financial and operating data for us. The table is derived
from our consolidated financial statements and notes thereto, and should be read
in conjunction with those audited financial statements. See also Item 7
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in this report for more information.
Year Ended December 31,
--------------------------------------------
2003(3) 2002(4) 2001(5) 2000(6) 1999(7)
----------- ----------- ----------- ----------- ----------
(In thousands, except per unit data)
Income and Cash Flow Data:
Revenues............................................ $ 6,624,322 $ 4,237,057 $ 2,946,676 $ 816,442 $ 428,749
Cost of product sold................................ 4,880,118 2,704,295 1,657,689 124,641 16,241
Operating expense................................... 459,936 427,805 396,354 182,445 104,970
Fuel and power...................................... 108,112 86,413 73,188 43,216 31,745
Depreciation, depletion and amortization............ 219,032 172,041 142,077 82,630 46,469
General and administrative.......................... 150,435 122,205 113,540 67,949 41,917
----------- ----------- ----------- ----------- -----------
Operating income.................................... 806,689 724,298 563,828 315,561 187,407
Earnings from equity investments.................... 92,199 89,258 84,834 71,603 42,918
Amortization of excess cost of equity investments... (5,575) (5,575) (9,011) (8,195) (4,254)
Interest expense.................................... (182,777) (178,279) (175,930) (97,102) (54,336)
Interest income and other, net...................... (33) (6,042) (5,005) 10,415 20,393
Income tax provision................................ (16,631) (15,283) (16,373) (13,934) (9,826)
----------- ----------- ----------- ----------- -----------
Income before cumulative effect of a change in
accounting principle............................. 693,872 608,377 442,343 278,348 182,302
Cumulative effect of a change in accounting
principle........................................ 3,465 -- -- -- --
----------- ----------- ----------- ----------- -----------
Net income.......................................... $ 697,337 $ 608,377 $ 442,343 $ 278,348 $ 182,302
General Partner's interest in net income............ 326,524 270,816 202,095 109,470 56,273
Limited Partners' interest in net income............ $ 370,813 $ 337,561 $ 240,248 $ 168,878 $ 126,029
Basic and Diluted Limited Partners' Net Income per
unit:
Income before cumulative effect of a change in
accounting principle(1).......................... $ 1.98 $ 1.96 $ 1.56 $ 1.34 $ 1.29
Cumulative effect of a change in accounting
principle........................................ 0.02 -- -- -- --
----------- ----------- ----------- ----------- -----------
Net income.......................................... $ 2.00 $ 1.96 $ 1.56 $ 1.34 $ 1.29
Per unit cash distribution paid..................... $ 2.58 $ 2.36 $ 2.08 $ 1.60 $ 1.39
Additions to property, plant and equipment.......... $ 576,979 $ 542,235 $ 295,088 $ 125,523 $ 82,725
Balance Sheet Data (at end of period):
Net property, plant and equipment $ 7,091,558 $ 6,244,242 $ 5,082,612 $ 3,306,305 $ 2,578,313
Total assets............... $ 9,139,182 $ 8,353,576 $ 6,732,666 $ 4,625,210 $ 3,228,738
Long-term debt(2).......... $ 4,316,678 $ 3,659,533 $ 2,237,015 $ 1,255,453 $ 989,101
Partners' capital.......... $ 3,510,927 $ 3,415,929 $ 3,159,034 $ 2,117,067 $ 1,774,798
- ----------
(1) Represents income before cumulative effect of a change in accounting
principle per unit adjusted for the two-for-one split of units on August
31, 2001. Basic Limited Partners' income per unit before cumulative effect
of a change in accounting principle was computed by dividing the interest
of our unitholders in income before cumulative effect of a change in
accounting principle 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.
(2) Excludes market value of interest rate swaps.
(3) Includes results of operations for the bulk terminal operations acquired
from M.J. Rudolph Corporation, the additional 12.75% interest in the SACROC
unit, the five refined petroleum products terminals acquired from Shell,
the additional 42.5% interest in the Yates field unit, the crude oil
gathering operations surrounding the Yates field unit, an additional 65%
interest in the Pecos Carbon Dioxide Company, the remaining approximate 32%
interest in MidTex Gas Storage Company, LLP, the seven refined petroleum
products terminals acquired from ConocoPhillips and two bulk terminal
facilities located in Tampa, Florida since dates of acquisition. We
acquired certain bulk terminal operations from M.J. Rudolph on January 1,
2003. The additional 12.75% interest in SACROC was acquired on June 1,
2003. The five refined petroleum products terminals were acquired October
1, 2003. The additional 42.5% interest in the Yates field unit, the Yates
gathering system
47
and the additional 65% interest in Pecos Carbon Dioxide Company were
acquired on November 1, 2003. The additional 32% ownership interest in
MidTex was acquired November 1, 2003. The seven refined petroleum products
terminals were acquired December 11, 2003, and the two bulk terminal
facilities located in Tampa, Florida were acquired on December 10 and 23,
2003.
(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, 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.
48
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.
Additional sections in this report which should be helpful to your reading of
our Management Discussion include the following:
o a description of our business strategy and management philosophy, found in
Items 1 and 2 "Business and Properties-Business Strategy";
o a description of recent developments during 2003, found in Items 1 and 2
"Business and Properties-Recent Developments"; and
o a description of our risk factors, found in Items 1 and 2 "Business and
Properties-Risk Factors."
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. These estimates and
assumptions affect the amounts we report for assets and liabilities and our
disclosure of contingent assets and liabilities at the date of the financial
statements. 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 covering the matters discussed below are of more
significance in our financial statement preparation process than others.
Environmental Matters
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 potential environmental issues that
could impact our assets or operations, we recognized a $0.3 million 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
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 from a $15.7 million loss in our Products
Pipelines business segment and a $16.0 million gain in our Terminals business
segment.
Legal Matters
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
49
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.
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 $154 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. For more information on our Pacific operations' regulatory
proceedings, see Note 16 to the Consolidated Financial Statements included
elsewhere in this report.
Intangible Assets
With respect to goodwill and other intangible assets having indefinite useful
economic lives, 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 introduced the concept of indefinite life intangible
assets and required us to prospectively cease amortizing all of our intangible
assets having indefinite useful economic lives, including goodwill. Such assets
are not to be amortized until their lives are determined to be finite. The new
rules also 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. Additionally, 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. We have selected an impairment
measurement test date of January 1 of each year and we have determined that our
goodwill was not impaired as of January 1, 2004. As of January 1, 2004, our
goodwill was $729.5 million.
Results of Operations
Year Ended December 31,
------------------------------------
2003 2002 2001
---------- ---------- ----------
(In thousands)
Earnings before depreciation, depletion and
amortization expense and amortization of excess
cost of equity investments
Products Pipelines............................. $ 441,600 $ 411,604 $ 383,920
Natural Gas Pipelines.......................... 373,350 325,454 226,770
CO2............................................ 203,599 132,196 111,666
Terminals...................................... 240,776 224,963 167,512
---------- ---------- ----------
Segment earnings before DD&A and amort. of
excess cost of equity investments(a)....... 1,259,325 1,094,217 889,868
Total consolidated DD&A expense................ (219,032) (172,041) (142,077)
Total consolidated amort. of excess cost of
invests...................................... (5,575) (5,575) (9,011)
Interest and corporate administrative
expenses(b).................................. (337,381) (308,224) (296,437)
---------- ---------- ----------
Net income................................... $ 697,337 $ 608,377 $ 442,343
========== ========== ==========
- ----------
(a) Includes revenues, earnings from equity investments, income taxes and
other, net, less operating expenses.
50
(b) Includes interest and debt expense, general and administrative expenses,
minority interest expense and cumulative effect adjustment from a change in
accounting principle (2003 only).
In 2003, we again achieved record levels of net income, earnings per unit,
earnings before depreciation, depletion and amortization, and revenues. The
fiscal year ended December 31, 2003 marked the sixth successive year since the
change in control of our general partner in February 1997 that we have improved
on all four of these operating measures.
In 2003, our net income was $697.3 million ($2.00 per diluted unit) on
revenues of $6,624.3 million, compared to net income of $608.4 million ($1.96
per diluted unit) on revenues of $4,237.1 million in 2002, and net income of
$442.3 million ($1.56 per diluted unit) on revenues of $2,946.7 million in 2001.
In 2003, we benefited from a cumulative effect adjustment of $3.4 million
related to a change in accounting for asset retirement obligations pursuant to
our adoption of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" on January 1, 2003. Our 2003 income before the
cumulative effect adjustment totaled $693.9 million ($1.98 per diluted unit).
For more information on this cumulative effect adjustment from a change in
accounting principle, see Note 4 to our Consolidated Financial Statements,
included elsewhere in this report. Equity earnings from our investments
accounted for under the equity method of accounting, net of expense from
amortization of excess investment costs, were $86.6 million in 2003, $83.7
million in 2002 and $75.8 million in 2001.
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis, we look at each period's
earnings before all non-cash depreciation, depletion and amortization expenses
(including amortization of excess cost of equity investments) as an important
measure of our success in maximizing returns to our partners. Available cash, as
defined in our partnership agreement, consists primarily of all cash receipts,
less cash disbursements and net additions to reserves. Our general partner and
our common and Class B unitholders receive quarterly distributions in cash,
while KMR, the sole owner of our i-units, receives quarterly distributions in
additional i-units. The value of the quarterly per-share distribution of i-units
is based on the value of the quarterly per-share cash distribution made to our
common and Class B unitholders.
In both 2003 and 2002, all four of our reportable business segments reported
year-to-year increases in earnings before depreciation, depletion and
amortization. The increases in our earnings before depreciation, depletion and
amortization in 2003 over 2002 were primarily due to higher earnings from our
CO2 and Natural Gas Pipelines business segments. Our CO2 segment benefited from
both increased activity in oil field operations and the acquisition of
additional working interests in oil producing properties. These acquisitions
included the following:
o effective June 1, 2003, we acquired MKM Partners, L.P.'s 12.75% ownership
interest in the SACROC oil field unit for $23.3 million and the assumption
of $1.9 million of liabilities. This transaction increased our ownership
interest in the SACROC unit to approximately 97%; and
o effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation for $231.0
million and the assumption of $28.0 million of liabilities. The assets
acquired included Marathon's approximate 42.5% interest in the Yates oil
field unit, the crude oil gathering system surrounding the Yates field and
Marathon's 65% ownership interest in the Pecos Carbon Dioxide Pipeline
Company. This transaction increased our ownership interest in the Yates
unit to nearly 50% and allowed us to become operator of the field.
Our Natural Gas Pipelines segment benefited from increases in natural gas
transportation, storage and sales activities. This increase was primarily due to
the further integration of our Kinder Morgan Tejas and Kinder Morgan Texas
Pipeline systems, and to our newly completed North Texas and Mier-Monterrey,
Mexico pipeline systems. We acquired Kinder Morgan Tejas, formerly Tejas Gas,
LLC, effective January 31, 2002. Our North Texas and Mier-Monterrey pipeline
systems began operations in August 2002 and March 2003, respectively. We also
benefited from the inclusion of a full year of expanded operations on our
Trailblazer Pipeline. In May 2002, we completed an expansion project that
increased Trailblazer's transportation capacity by approximately 60%. The
acquisition, construction and subsequent integration of all of our natural gas
related operations, especially within and around the State of Texas, has
resulted in an integrated and valuable portfolio of natural gas businesses.
51
The increase in total segment earnings before depreciation, depletion and
amortization in 2002 over 2001 was primarily due to higher earnings from our
Natural Gas Pipelines and Terminals business segments. The increase was
attributable to both solid internal growth and to contributions from acquired
assets. Our significant acquisitions included the purchase of Kinder Morgan
Tejas, as well as the acquisition of various bulk and liquid terminal businesses
acquired since the end of 2001. For more information on our acquisitions, please
see Note 3 to our Consolidated Financial Statements, included elsewhere in this
report.
Additionally, we declared a record cash distribution of $0.68 per unit for
the fourth quarter of 2003 (an annualized rate of $2.72). Our distribution for
the fourth quarter of 2003 was 9% higher than the $0.625 per unit distribution
we made for the fourth quarter of 2002, and 24% higher than the $0.55 per unit
distribution we made for the fourth quarter of 2001. We expect to declare cash
distributions of at least $2.84 per unit for 2004, however, no assurance can be
given that we will be able to achieve this level of distribution.
Products Pipelines
Year Ended December 31,
---------------------------------------------
2003 2002 2001
------------- ------------- -------------
(In thousands, except operating statistics)
Revenues....................................... $ 585,376 $ 576,542 $ 605,392
Operating expenses(a).......................... (169,526) (169,782) (240,537)
Earnings from equity investments............... 30,948 28,998 28,278
Other, net(b).................................. 6,471 (14,000) 440
Income taxes................................... (11,669) (10,154) (9,653)
------------- ------------- -------------
Earnings before DD&A and amort. of excess
cost of equity investments................. 441,600 411,604 383,920
Depreciation, depletion and amortization expense (67,345) (64,388) (65,864)
Amortization of excess cost of equity
investments................................... (3,281) (3,281) (5,592)
------------- ------------- -------------
Segment earnings............................. $ 370,974 $ 343,935 $ 312,464
============= ============= =============
Refined product volumes (MMBbl)................ 723.7 733.0 724.6
Natural gas liquids (MMBbl).................... 42.2 44.4 45.5
------------ ------------ ------------
Total delivery volumes (MMBbl)(c).............. 765.9 777.4 770.1
============ ============ ============
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Amounts for 2002 include 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.
(c) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
Our Products Pipelines segment reported earnings before depreciation,
depletion and amortization of $441.6 million on revenues of $585.4 million in
2003. This compared to earnings before depreciation, depletion and amortization
of $411.6 million on revenues of $576.5 million in 2002 and earnings before
depreciation, depletion and amortization of $383.9 million on revenues of $605.4
million in 2001.
52
As noted in the table above, the segment's 2002 earnings include a $15.7
million loss from the adjustment and realignment of our environmental
liabilities referred to above in our "Critical Accounting Policies and
Estimates." Excluding this 2002 environmental loss, segment earnings before
depreciation, depletion and amortization increased $14.3 million (3%) in 2003
compared to 2002. This increase resulted from higher earnings from our Pacific
operations, North System, CALNEV Pipe Line LLC, Transmix operations, Central
Florida Pipeline, our approximate 51% ownership interest in Plantation Pipe Line
Company and our West Coast product terminals. Earnings in 2003 were positively
impacted by higher revenues, mainly from fees for ethanol blending services at
our Pacific operations and West Coast terminals and revenues from product
deliveries related to overall strong demand for diesel fuel. The overall
increase was offset by lower earnings before depreciation, depletion and
amortization from both our 44.8% ownership interest in the Cochin pipeline
system and our Cypress Pipeline mainly due to lower operating revenues. In
addition, due to the continuing process of converting from methyl tertiary-butyl
ether (MTBE) to ethanol in the State of California, we realized a small
reduction in California gasoline volumes. MTBE-blended gasoline is being
replaced by an ethanol blend and ethanol is not shipped in our pipelines;
however, fees that we earn from ethanol-related services at our terminals
positively contribute to our earnings. As of December 31, 2003, we had ethanol
blending facilities in place at all of our California terminals necessary to
serve all of our customers. We do not anticipate that the switch to ethanol from
MTBE will have a material adverse effect on our Products Pipeline segment.
Excluding the 2002 environmental loss, segment earnings before depreciation,
depletion and amortization increased $43.4 million (11%) in 2002 compared to
2001. All of our Products Pipelines businesses reported year-over-year
increases, with the exception of Plantation, where earnings were essentially
flat across both years. The overall increase was driven by higher earnings
before depreciation, depletion and amortization from our CALNEV pipeline and
terminal operations, where we benefited from including a full year of operations
in 2002 versus nine months in 2001. We acquired CALNEV Pipe Line LLC on March
30, 2001. In addition to CALNEV, we realized higher earnings before
depreciation, depletion and amortization expenses in 2002 compared to 2001 from
all of the following businesses: our proportionate interest in Cochin, our
Pacific operations, Central Florida Pipeline, Transmix operations, West Coast
terminals, North System and our Cypress Pipeline.
The $8.9 million (2%) increase in segment revenues in 2003 compared to 2002
was driven by a $7.1 million (2%) increase in combined revenues from our Pacific
operations and West Coast terminals, largely due to increased terminal services.
Revenues from our North System increased $3.9 million (11%) in 2003 versus 2002.
Although throughput deliveries on our North System dropped by 4% in 2003, we
benefited from a 15% increase in average tariff rates as a result of an
increased cost of service tariff agreement filed with the Federal Energy
Regulatory Commission in May 2003. Revenues from our CALNEV Pipeline increased
$2.9 million (6%) in 2003 versus 2002, due to higher revenues from both refined
product deliveries and fees associated with ethanol blending operations. CALNEV
benefited from a 5% increase in the average tariff per barrel moved, due mostly
to an increase in transportation of longer-haul, higher margin barrels. Revenues
from our Transmix operations increased $1.6 million (6%) in 2003 compared to
2002, primarily due to higher processing volumes at our transmix facilities
located in Richmond, Virginia and Indianola, Pennsylvania. Revenues from our
Central Florida Pipeline operations also increased by $1.6 million (5%) in 2003
versus 2002, due to higher storage revenues at our liquids terminal located in
Tampa, Florida and to higher refined product delivery revenues associated with a
2% increase in delivery volumes.
The overall increase in segment revenues in 2003 compared to the prior year
was offset by a $7.5 million (23%) decrease in revenues from our investment in
the Cochin pipeline system and a $1.1 million (16%) decrease in revenues earned
from our Cypress Pipeline. In 2003, Cochin's earnings and revenues were
negatively impacted by lower delivery volumes associated with decreased propane
production in western Canada and by a pipeline rupture and fire in July. The
drop in propane production was a reaction to lower profit margins from the
extraction and sale of natural gas liquids caused by the rise in natural gas
prices since the end of 2002, and the pipeline rupture and fire led to the shut
down of the system for 29 days during the third quarter. The year-to-year drop
in Cypress' revenues was due to lower throughput volumes and to customers
catching up on liquids volumes earned but not delivered in prior periods.
Combining all of the segment's operations, total throughput delivery of refined
petroleum products, consisting of gasoline, diesel fuel and jet fuel, decreased
1.3% in 2003 compared to 2002. This decrease reflects the impact of the 2003
transition from MTBE-blended gasoline to ethanol-blended gasoline, and the fact
that ethanol cannot be transported via pipeline but must instead be blended at
terminals. Our combined diesel and jet fuel deliveries, however, increased 1.8%
in 2003 versus 2002, mainly due to a 5.7% increase in diesel delivery volumes
and to improvement in jet fuel delivery volumes in the fourth quarter of 2003.
53
The $28.9 million (5%) decrease in revenues and the $70.8 million (29%)
decrease in operating expenses in 2002 compared to 2001 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.
Excluding the decrease in transmix revenues, segment revenues increased $38.9
million (6%) in 2002 compared to the prior year. The increase was mainly due to
a $14.7 million (40%) increase in revenues earned from our CALNEV Pipeline, the
result of an almost 2% increase in average pipeline tariff rates 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 (59%) in 2002 compared to 2001 as a result of higher volumes and tariffs
as well as increases related to our additional 10% ownership interest acquired
on December 31, 2001. 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. For all products pipelines owned or operated at
both December 31, 2002 and 2001, total throughput delivery of refined petroleum
products was up 1.2% in 2002 over 2001. Our gasoline delivery volumes increased
4.5% in 2002, compared to a 2.6% increase nationally. Although our total jet
fuel delivery volumes were down 3.8% in 2002, reflecting the effects of the
September 11, 2001 terrorist attacks, deliveries of jet fuel improved steadily
throughout the year.
The segment's operating expenses remained flat in 2003, compared to 2002,
and, excluding the $68.6 million decrease in our transmix cost of sales expense
referred to above, the segment's operating expenses increased only $2.2 million
(1%) in 2002, compared to 2001. This increase was primarily due to higher
operating and maintenance expenses on the Cochin pipeline system, due to the
increase in delivery volumes and our additional ownership interest.
Earnings from equity investments consist primarily of earnings from our
approximate 51% ownership interest in Plantation Pipe Line Company and our 50%
ownership interest in Heartland Pipeline Company, both accounted for under the
equity method of accounting. Earnings from our Products Pipelines' equity
investments were $30.9 million in 2003, $29.0 million in 2002 and $28.3 million
in 2001.
The $1.9 million (7%) increase in equity earnings in 2003 versus 2002 was
primarily due to a $1.5 million (5%) increase in equity earnings related to our
ownership interest in Plantation. The increase resulted primarily from higher
litigation settlement costs recognized during the fourth quarter of 2002,
partially offset by lower earnings from product deliveries in 2003. The decrease
in earnings from product deliveries were mainly due to lower revenues associated
with a 4% decrease in product delivery volumes in 2003 compared to 2002. The
decrease in delivery volumes in 2003 compared to 2002 resulted from longer than
anticipated refinery maintenance, weather and a new specification for Atlanta,
Georgia gasoline, which some of the refiners that supply Plantation did not make
in 2003. In 2002, Plantation delivered a record level of refined products. The
$0.7 million (2%) increase in equity earnings in 2002 versus 2001 was again due
to an increase in our proportionate share of Plantation's earnings. In 2002,
Plantation had both higher revenues, lower operating expenses and lower interest
expenses than in 2001. 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. In December
2000, we assumed the operating duties of Plantation Pipe Line Company pursuant
to an agreement reached with the other owner of Plantation.
Excluding the 2002 environmental loss, other income items increased $4.7
million in 2003 versus 2002, mainly due to gains realized from sales of
property, plant and equipment by our Pacific operations. The year-to-year
increases in income taxes from 2001 to 2002 and from 2002 to 2003 primarily
related to the overall growth in taxable income related to the operations of
Plantation Pipe Line Company.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were $70.6 million, $67.7 million
and $71.5 million in each of the years ended December 31, 2003, 2002 and 2001,
54
respectively. The $2.9 million (4%) increase in 2003 versus 2002 was driven by
higher property and plant depreciation expenses from our Pacific operations,
CALNEV Pipeline and West Coast terminals. This increase was related to the
capital spending we have made since the end of 2002 in order to strengthen and
enhance our business operations on the West Coast. The $3.8 million (5%)
decrease in 2002 versus 2001 was primarily due to a $2.3 million decrease in
expenses from the amortization of excess investment costs, 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. For more
information on our adoption of SFAS No. 142, see Note 8 to our Consolidated
Financial Statements, included elsewhere in this report.
In addition, on July 30, 2003, we experienced a rupture on our Pacific
operations' Tucson to Phoenix line. Through a combination of increased
deliveries on our Los Angeles to Phoenix line and terminal modifications at our
Tucson terminal that allowed volumes of Phoenix-grade gasoline to be trucked
into Phoenix, we were able to deliver most of the volumes into the Phoenix area
which normally flow through the ruptured line. The 8-inch diameter line, which
was temporarily taken out of service on August 8, 2003, resumed service on
August 24, 2003. The impact of the rupture on our results of operations for 2003
was not material.
For 2004, we currently expect that our Products Pipelines segment will report
earnings before depreciation, depletion and amortization expense of
approximately $483 million, an approximate 9% increase over 2003. The earnings
increase is expected to be driven by a continued improvement in gasoline and jet
fuel delivery volumes, planned capital improvements and expansions, terminal
acquisitions and expected adjustments to FERC-indexed tariff rates.
Natural Gas Pipelines
Year Ended December 31,
---------------------------------------------
2003 2002 2001
------------- ------------- -------------
(In thousands, except operating statistics)
Revenues....................................... $ 5,316,853 $ 3,086,187 $ 1,869,315
Operating expenses(a).......................... (4,967,531) (2,784,278) (1,665,852)
Earnings from equity investments............... 24,012 23,887 22,558
Other, net..................................... 1,082 36 749
Income taxes................................... (1,066) (378) -
------------- ------------- -------------
Earnings before DD&A and amort. of excess
cost of equity investments................. 373,350 325,454 226,770
Depreciation, depletion and amortization
expense....................................... (53,785) (48,411) (31,564)
Amortization of excess cost of equity
investments................................... (277) (277) (1,402)
------------- ------------- -------------
Segment earnings............................. $ 319,288 $ 276,766 $ 193,804
============= ============= =============
Natural gas transport volumes (Bcf)(b)......... 1,244.9 1,105.3 977.1
============= ============= =============
Natural gas sales volumes (Bcf)(c)............. 906.0 882.8 359.5
============= ============= =============
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas Intrastate group
and Trailblazer pipeline volumes.
(c) Represents Texas Intrastate group. Sales volumes for 2002 include first
quarter sales volumes for Kinder Morgan Tejas, which was under prior
management, and may not be comparable. Sales volumes for 2001 include KMTP
only.
Our Natural Gas Pipelines segment reported earnings before depreciation,
depletion and amortization of $373.4 million on revenues of $5,316.9 million in
2003. This compared to earnings before depreciation, depletion and amortization
of $325.5 million on revenues of $3,086.2 million in 2002 and earnings before
depreciation, depletion and amortization of $226.8 million on revenues of
$1,869.3 million in 2001.
The segment's $47.9 million (15%) increase in earnings before depreciation,
depletion and amortization as well as its increases in both revenues and
operating expenses in 2003 compared to 2002, were primarily attributable to
55
internal growth on our Texas intrastate gas pipeline systems and to
contributions from two pipeline expansion projects: our North Texas Pipeline,
completed in August 2002, and our Mier-Monterrey Mexico Pipeline, completed in
March 2003.
The combined operations of Kinder Morgan Tejas and Kinder Morgan Texas
Pipeline, the two major components of our Texas Intrastate group, accounted for
$30.7 million of the segment's total increase in earnings before depreciation,
depletion and amortization in 2003, compared to 2002. The increase was driven by
higher natural gas sale volumes and higher earnings from storage and
transportation services. Our Kinder Morgan Tejas' operations include a
3,400-mile intrastate natural gas pipeline system that has access to a number of
natural gas supply basins in Texas. The acquisition and subsequent integration
of Kinder Morgan Tejas' assets with our Kinder Morgan Texas Pipeline, has
produced a strategic and complementary intrastate pipeline business that
purchases, sells and transports significant volumes of natural gas. Since our
acquisition of Kinder Morgan Tejas, we have increased the interconnection
capability between its system and Kinder Morgan Texas Pipeline, improved systems
processes and controls and further refined the management of risk associated
with the sale and transmission of natural gas. Our objective is to match every
purchase and sale, thus locking-in the equivalent of a transportation fee. We
manage any remaining price risk by the use of energy financial instruments.
Combined, our North Texas Pipeline and our Mier-Monterrey Pipeline accounted
for $14.9 million of the segment's total increase in earnings before
depreciation, depletion and amortization in 2003, compared to 2002. Included in
this amount are 2003 earnings before depreciation, depletion and amortization
of $9.2 million from the start-up of our Mier-Monterrey Pipeline. The pipeline
stretches from south Texas to Monterrey, Mexico and can 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 connects to a 1,000-megawatt power plant complex and
to the PEMEX natural gas transportation system. By integrating the operations of
our North Texas and Mier-Monterrey pipeline systems with our Texas intrastate
systems, by entering into new long-term transportation, storage and sales
contracts with customers like BP and Pemex, and by extending existing contracts
with other customers, the segment increased total natural gas transport volumes
by 13% and natural gas sales volumes by nearly 3% in 2003, compared to 2002.
The segment's $98.7 million (44%) increase in earnings before depreciation,
depletion and amortization in 2002 compared to 2001, as well as the significant
increases in both revenues and operating expenses between these two years,
related primarily to our January 31, 2002 acquisition of Kinder Morgan Tejas and
its subsequent integration with Kinder Morgan Texas Pipeline. The intrastate
systems accounted for $83.4 million of the segment's total increase in earnings
before depreciation, depletion and amortization in 2002, compared to 2001. Both
Kinder Morgan Tejas and Kinder Morgan Texas Pipeline operate intrastate natural
gas pipelines within the State of Texas and both purchase and sell significant
volumes of natural gas, which is transported through their pipeline systems. The
purchase and sale activity results in considerably higher revenues and operating
expenses compared to our Rocky Mountain interstate natural gas pipeline systems:
Kinder Morgan Interstate Gas Transmission and Trailblazer Pipeline Company. Both
KMIGT and Trailblazer charge a transportation fee for gas transmission service
but neither system has significant gas purchases and resales.
Together, our Rocky Mountain pipelines accounted for $4.6 million and $12.4
million of the segment's total year-to-year increases in earnings before
depreciation, depletion and amortization for the years 2003 and 2002,
respectively. The increase in both years was mainly due to the benefits
resulting from an expansion of our Trailblazer pipeline system. In May 2002, we
completed a $48 million expansion project that increased transportation capacity
on the pipeline by approximately 60%. As a result, Trailblazer realized a 12%
increase in natural gas transportation volumes in 2003 compared to 2002, and a
24% increase in natural gas transportation volumes in 2002 compared to 2001. In
2003, the segment also benefited from higher operational sales of natural gas at
higher margins by KMIGT. The overall increase in segment earnings before
depreciation, depletion and amortization in 2003 compared to 2002 included a
$2.4 million (14%) decrease in earnings from our Casper and Douglas natural gas
gathering and processing system, primarily due to higher natural gas liquids
producer settlement payments, in 2003, resulting from increases in natural gas
prices in the Rocky Mountain region since the end of 2002.
We account for this 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
56
investments were relatively flat across all three years. In 2003, higher
earnings from our investment in Thunder Creek were offset by lower earnings from
our investment in Red Cedar. In 2002, the $1.3 million (6%) increase in equity
earnings compared to 2001 resulted primarily from increases of $0.5 million from
each of our 50% ownership interest in Coyote and our 25% ownership interest in
Thunder Creek.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were up $5.4 million (11%) in 2003
compared to 2002, primarily due to depreciation charges on the newly completed
North Texas and Mier-Monterrey pipeline systems. The $15.7 million (48%)
increase in depreciation, depletion and amortization charges in 2002 over 2001
were primarily the result of our Kinder Morgan Tejas
acquisition and higher depreciation expense related to the completed expansion
of our Trailblazer pipeline system.
For 2004, we currently expect that our Natural Gas Pipelines segment will
report earnings before depreciation, depletion and amortization expense of
approximately $384 million, an approximate 3% increase over 2003. The earnings
increase is expected to be driven by increases in storage and transportation
services, additional earnings realized from the sale of natural gas at higher
margins and the benefits of reaching new markets and customers by planned
capital spending.
CO2
Year Ended December 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
(In thousands, except operating statistics)
Revenues.......................... $ 248,535 $ 146,280 $ 122,094
Operating expenses(a)............. (82,055) (50,524) (44,973)
Earnings from equity investments 37,198 36,328 33,998
Other, net........................ (40) 112 547
Income taxes...................... (39) - -
--------- --------- ---------
Earnings before DD&A and
amort. of excess cost of
equity investments............. 203,599 132,196 111,666
Depreciation, depletion and
amortization expense............. (60,827) (29,196) (17,562)
Amortization of excess cost of (2,017) (2,017) (2,017)
equity investments...............
--------- --------- ---------
Segment earnings................ $ 140,755 $ 100,983 $ 92,087
========= ========= =========
Carbon dioxide volumes
transported (Bcf)(b)............. 504.7 431.7 387.4
========= ========= =========
SACROC Oil production (MBbl/d).... 20.2 13.0 9.1
========= ========= =========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes.
(b) Includes Cortez, Central Basin, Canyon Reef Carriers and Centerline
pipeline volumes.
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. In 2003, our CO2 segment reported earnings before
depreciation, depletion and amortization of $203.6 million on revenues of $248.5
million. This compared to earnings before depreciation, depletion and
amortization of $132.2 million on revenues of $146.3 million in 2002 and
earnings before depreciation, depletion and amortization of $111.7 million on
revenues of $122.1 million in 2001.
Both the $71.4 million (54%) increase in earnings before depreciation,
depletion and amortization and the $31.5 million (62%) increase in operating
expenses in 2003 over 2002, and the $20.5 million (18%) increase in earnings
before depreciation, depletion and amortization and the $5.6 million (12%)
increase in operating expenses in 2002 over 2001, were chiefly due to higher oil
production volumes and higher carbon dioxide pipeline delivery volumes. The
increase in oil production was driven by both expansion projects at SACROC and
by acquisitions of additional ownership interests in the SACROC and Yates oil
field units, as referred to above.
Oil production at SACROC, located in the Permian Basin of West Texas,
increased 55% in 2003 compared to 2002, and 43% in 2002 compared to 2001. In
2003, we also benefited from an almost 6% increase in our realized
57
weighted average price of oil per barrel (from $22.45 per barrel in 2002 to
$23.73 per barrel in 2003). As a result of our oil reserve ownership interests,
we are exposed to commodity price risk, but the risk is mitigated by our
long-term hedging strategy that is intended to generate more stable realized
prices. For more information on our hedging activities, see Note 14 to our
Consolidated Financial Statements, included elsewhere in this report.
Increases in oil field operations throughout the Permian Basin since the end
of 2001 resulted in higher delivery volumes of carbon dioxide, including
deliveries on our Central Basin Pipeline, our majority-owned Canyon Reef
Carriers Pipeline, our 50% owned Cortez Pipeline and our new Centerline
Pipeline, which began operations in May 2003. For these four pipelines combined,
carbon dioxide delivery volumes increased 17% in 2003 and 11% in 2002. The
Centerline Pipeline consists of approximately 113 miles of 16-inch diameter pipe
located in the Permian Basin between Denver City, Texas and Snyder, Texas, and
primarily transports carbon dioxide to the SACROC oil field unit. The pipeline
transported 50.5 billion cubic feet of carbon dioxide during 2003. We do not
recognize profits on carbon dioxide sales to ourselves.
As discussed in Note 2 to our Consolidated Financial Statements, included
elsewhere in this report, we capitalize the cost of CO2 that is injected into
the SACROC unit as part of our enhanced oil recovery process. The CO2 costs
incurred and capitalized as development costs for the SACROC unit were $45.1
million, $30.3 million and $12.5 million for the years ended December 31, 2003,
2002 and 2001, respectively. We estimate that such costs will be approximately
$56.0 million, $62.1 million and $52.8 million in 2004, 2005 and 2006,
respectively. It is expected that, due to the nature of this enhanced recovery
process and the underlying reservoir, the capitalized cost for CO2 in the 2005
through 2006 period will represent a peak and will decline thereafter.
The year-to-year increases in operating expenses were primarily related to
higher operating, maintenance, and fuel and power costs, all as a result of the
higher oil production volumes. The $0.9 million (2%) increase in earnings from
equity investments in 2003 compared to 2002 reflects the net of a $4.1 million
(14%) increase in equity earnings from our 50% investment in Cortez Pipeline
Company, partially offset by a $3.2 million (39%) decrease in equity earnings
from our previous 15% interest in MKM Partners, L.P. The increase in earnings
from our equity interest in Cortez was mainly due to higher carbon dioxide
delivery volumes, lower average debt balances and slightly lower borrowing
rates. Equity earnings from MKM Partners, L.P. was lower during 2003 due to the
fact that we acquired the partnership's 12.75% ownership interest in the SACROC
unit effective June 1, 2003, and the partnership was dissolved effective June
30, 2003. The $2.3 million (7%) increase in earnings from equity investments in
2002 compared to 2001 resulted from higher earnings from the segment's
investment in Cortez, again mainly due to lower average debt balances and lower
average borrowing rates, partially offset by slightly lower carbon dioxide
delivery volumes in 2002 compared to 2001.
Non-cash depreciation, depletion and amortization charges were up $31.6
million (101%) in 2003 compared to 2002, primarily due to higher production
volumes, capital investments, and acquisitions of property interests since the
end of 2002. The $11.6 million (59%) increase in depreciation, depletion and
amortization charges in 2002 over 2001 were primarily the result of the capital
expenditures we have made since the end of 2001, which resulted in a higher
unit-of-production depletion rate.
For 2004, we currently expect that our CO2 segment will report earnings
before depreciation, depletion and amortization expense of approximately $322
million, an approximate 58% increase over 2003. The earnings increase is
expected to be driven by the continuing development of the SACROC oil field
unit, increased ownership interests in the Yates oil field unit for the full
year (with oil production expected to be essentially even with 2003), and
increased transportation of carbon dioxide volumes across all of our carbon
dioxide pipelines.
58
Terminals
Year Ended December 31,
2003 2002 2001
------------- ------------- -------------
(In thousands, except operating statistics)
Revenues....................................... $ 473,558 $ 428,048 $ 349,875
Operating expenses(a).......................... (229,054) (213,929) (175,869)
Earnings from equity investments............... 41 45 -
Other, net(b).................................. 88 15,550 226
Income taxes................................... (3,857) (4,751) (6,720)
------------- ------------- -------------
Earnings before DD&A and amort. of excess
cost of equity investments................. 240,776 224,963 167,512
Depreciation, depletion and amortization expense (37,075) (30,046) (27,087)
Amortization of excess cost of equity
investments................................... - - -
------------- ------------- -------------
Segment earnings............................. $ 203,701 $ 194,917 $ 140,425
============= ============= =============
Bulk transload tonnage (MMtons)(c)............. 56.2 58.7 58.3
============= ============= =============
Liquids leaseable capacity (MMBbl)............. 36.2 35.3 34.0
============= ============= =============
Liquids utilization %.......................... 96.0% 97.0% 97.0%
============= ============= =============
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
(b) Amounts for 2002 include 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.
(c) Includes Cora, Grand Rivers and Kinder Morgan Bulk Terminals aggregate
terminal throughputs; excludes operatorship of LAXT bulk terminal.
Our Terminals segment includes the operations of approximately 52 terminals
that transload and store coal, dry-bulk materials and petrochemical-related
liquids, as well as approximately 57 transload operations located throughout the
United States. The segment reported earnings before depreciation, depletion and
amortization of $240.8 million on revenues of $473.6 million in 2003. This
compared to earnings before depreciation, depletion and amortization of $225.0
million on revenues of $428.0 million in 2002 and earnings before depreciation,
depletion and amortization of $167.5 million on revenues of $349.9 million in
2001.
As noted in the above table, the segment's 2002 earnings include a $16.0
million gain from the adjustment and realignment of our environmental
liabilities referred to above in our "Critical Accounting Policies and
Estimates." Excluding the 2002 environmental gain, segment earnings before
depreciation and amortization increased $31.8 million (15%) in 2003 compared to
2002. Approximately half of this year-to-year increase was attributable to
expansion projects at existing liquids terminals, and the remainder was
attributable to solid contributions from the bulk and liquid terminal businesses
we have acquired since September 1, 2002. The internal growth was driven by the
ongoing expansion projects undertaken to increase leaseable liquids capacity at
our liquid terminal facility located in Carteret, New Jersey on the New York
Harbor, and at our Pasadena and Galena Park, Texas facilities, located along the
Houston Ship Channel. These expansion projects have contributed to a 2.5%
increase in our overall liquids terminals' leaseable capacity in 2003 compared
to 2002, more than offsetting the slight 1% drop in our overall utilization
percentage. Over half of the decline in utilization during 2003 was associated
with tank maintenance.
The acquisition of new terminal businesses acquired since September 1, 2002,
included the following:
o the Owensboro Gateway Terminal, acquired effective September 1, 2002;
o the St. Gabriel Terminal, acquired effective September 1, 2002;
o the purchase of four floating cranes at our bulk terminal facility in Port
Sulphur, Louisiana in December 2002;
o the bulk terminal businesses acquired from M.J. Rudolph Corporation,
effective January 1, 2003; and
59
o the two bulk terminal businesses in Tampa, Florida, acquired in December
2003.
The above acquisitions accounted for $30.7 million of the total $45.6 million
(11%) increase in revenues in 2003, compared to 2002. The remaining increase
includes year-to-year increases of $9.1 million from our Carteret and Galena
Park liquids terminal facilities and $5.1 million from our 66 2/3% ownership
interest in the International Marine Terminals Partnership. The increase from
Carteret and Galena Park was driven by expansion projects, additional liquids
storage contracts and escalations in annual contract provisions. We have
completed the construction of five 100,000 barrel petroleum products storage
tanks at our Carteret facility since the end of the third quarter of 2002. The
increase from IMT, which operates a bulk commodity transfer terminal facility
located in Port Sulphur, Louisiana, was driven by an almost 10% increase in bulk
tonnage transfer volume, primarily coal and iron ore, and by higher dockage
revenues.
The segment's overall increases in both earnings before depreciation,
depletion and amortization and revenues in 2003 compared to 2002 included
decreases of $1.8 million (24%) and $3.0 million (23%), respectively, from our
Cora coal terminal facility located near Cora, Illinois. The decrease in coal
revenues and earnings was primarily related to an expected decrease in coal
tonnage handled under contract for the Tennessee Valley Authority. The TVA has
diverted some of its business to new competing coal terminals that have come
on-line since the end of 2002. The $15.1 million (7%) increase in operating
expenses in 2003 compared to 2002 was due to the above acquisitions and to
higher operating, maintenance and rental expenses at IMT, all resulting from
the increase in transfer volumes.
Excluding the 2002 environmental item mentioned above, segment earnings
before depreciation, depletion and amortization increased $41.5 million (25%) in
2002, compared to 2001. Revenues and operating expenses increased $78.1 million
(22%) and $38.1 million (22%) in 2002 versus 2001, respectively. This growth in
earnings before depreciation, depletion and amortization, revenues and operating
expenses was driven by the acquisitions and asset purchases that we have made
since the last half of 2001 and internal growth.
In addition to the acquisitions referred to above, these acquisitions
included the following;
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); and
o the Milwaukee Bagging Operations, acquired effective May 1, 2002.
Combined, all of our acquisitions since the last half of 2001 accounted for
incremental amounts of $29.5 million in earnings before depreciation, depletion
and amortization, $88.5 million in revenues and $58.5 million in operating
expenses in 2002, compared to 2001. The remaining $12.0 million increase in
segment earnings before depreciation, depletion and amoritization was
attributable to internal growth at existing facilities, primarily driven by the
expansion work at various terminals that were completed since the end of 2001.
Expansion projects undertaken during 2002 at our Carteret and Pasadena terminals
contributed to a 3.8% increase in the segment's leaseable capacity of liquids
products, compared to the prior year. 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. The segment's overall increases in
earnings before depreciation, depletion and amortization, revenues and operating
expenses in 2002 compared to 2001, included decreases of $3.9 million, $15.7
million and $11.7 million, respectively, related to a decline in engineering
services resulting from a general downturn in business since the end of 2001.
60
Income tax expenses totaled $3.9 million in 2003, $4.8 million in 2002 and
$6.7 million in 2001. Both the $0.9 million (19%) decrease in 2003 compared to
2002, and the $1.9 million (28%) decrease in 2002 compared to 2001 were
primarily due to favorable tax adjustments related to the taxable income and
tax-paying obligations of Kinder Morgan Bulk Terminals, Inc. and its
consolidated subsidiaries.
Non-cash depreciation, depletion and amortization charges were $37.1 million,
$30.0 million and $27.1 million in each of the years ended December 31, 2003,
2002 and 2001, respectively. The $7.1 million (24%) increase in 2003 versus 2002
was primarily driven by higher depreciation charges on property, plant and
equipment utilized in our bulk terminal operations. The increase was mainly due
to higher bulk terminal property acquisitions and capital spending, and to
adjustments made to the estimated remaining useful lives of depreciable property
since the end of 2002. The $2.9 million (11%) increase in 2002 compared to 2001
was primarily due to additional acquisitions and expansions that were
capitalized since the end of 2001.
For 2004, we currently expect that our Terminals segment will report earnings
before depreciation, depletion and amortization expense of approximately $257
million, an approximate 7% increase over 2003. The earnings increase is expected
to be driven by the on-going capital expansion projects at our liquids terminal
facilities, by expected increases in certain bulk tonnage transfer volumes, most
notably soda ash, petroleum coke, fertilizer and synfuel, and by the addition
of our Tampa, Florida bulk terminal facilities, purchased in December 2003.
Other
Items not attributable to any segment include general and administrative
expenses, interest income and expense and minority interest. Our general and
administrative expenses include such items as salaries and employee-related
expenses, payroll taxes, legal fees, insurance and office supplies and rentals.
Overall general and administrative expenses totaled $150.4 million in 2003,
compared to $122.2 million in 2002 and $113.5 million in 2001. The $28.2 million
(23%) increase in general and administrative expenses in 2003 compared to the
prior year was primarily due to higher legal expenses, employee benefit and
pension costs and overall corporate and worker-related insurance expenses. The
$8.7 million (8%) increase in general and administrative expenses in 2002
compared to 2001 was principally due to additional employee benefit,
compensation and reimbursement charges, higher insurance related expenses and
administrative expenses related to our Kinder Morgan Tejas acquisition. 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 $181.4 million in
2003, $176.5 million in 2002 and $171.5 million in 2001. The $4.9 million (3%)
increase in net interest items in 2003 compared to 2002 and the $5.0 million
(3%) increase in net interest items in 2002 compared to 2001each reflect higher
average borrowings since the end of the prior year, partially offset by
decreases in our average borrowing rates.
Minority interest, which includes the 1.0101% general partner interest in our
five operating limited partnerships, totaled $9.1 million in 2003, compared to
$9.6 million in 2002 and $11.4 million in 2001. Both the $0.5 million (5%)
decrease in 2003 compared to 2002, and the $1.8 million (16%) decrease in 2002
from 2001 resulted primarily from our May 2002 acquisition of the remaining 33
1/3% ownership interest in Trailblazer Pipeline Company that we did not already
own, thereby eliminating the minority interest related to Trailblazer.
Liquidity and Capital Resources
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 including i-units in the determination of cash
distributions per unit but paying quarterly distributions on i-units in
additional
61
i-units rather than cash), additional borrowings, the issuance
of additional common units or the issuance of additional i-units to KMR;
o interest payments with 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, although such 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. We are able to access this segment of the capital market through
KMR's purchases of i-units issued by us with the proceeds from the sale of KMR
shares to institutional investors.
The following table illustrates the sources of our invested capital. In
addition to our results of operations, these balances are affected by our
financing activities as discussed below (dollars in thousands):
December 31,
-----------------------------------------
2003 2002 2001
------------ ------------ ------------
Long-term debt, excluding market value of
interest rate swaps............................... $ 4,316,678 $ 3,659,533 $ 2,237,015
Minority interest.................................. 40,064 42,033 65,236
Partners' capital.................................. 3,510,927 3,415,929 3,159,034
------------ ------------ ------------
Total capitalization............................ 7,867,669 7,117,495 5,461,285
Short-term debt, less cash and cash equivalents.... (21,081) (41,088) 497,417
------------ ------------ ------------
Total invested capital........................... $ 7,846,588 $ 7,076,407 $ 5,958,702
============ ============ ============
Capitalization:
Long-term debt, excluding market value of
interest rate swaps............................... 54.9% 51.4% 41.0%
Minority interest................................ 0.5% 0.6% 1.2%
Partners' capital................................ 44.6% 48.0% 57.8%
------------ ------------ ------------
100.0% 100.0% 100.0%
============ ============ ============
Invested Capital:
Total debt, less cash and cash equivalents
and excluding market value of interest
rate swaps..................................... 54.7% 51.1% 45.9%
Partners' capital and minority interest.......... 45.3% 48.9% 54.1%
------------ ------------ ------------
100.0% 100.0% 100.0%
============ ============ ============
Short-term Liquidity
Our principal sources of short-term liquidity are our revolving bank credit
facilities, our $1.05 billion short-term commercial paper program (which is
supported by our revolving bank credit facilities, with the amount available for
borrowing under our credit facilities being reduced by our outstanding
commercial paper borrowings) and cash provided by operations. Our bank
facilities can be used for general corporate purposes and as a backup for our
commercial paper program. As of December 31, 2003, we had available a $570
million unsecured 364-day credit facility due October 12, 2004, and a $480
million unsecured three-year credit facility due October 15, 2005. There were no
borrowings under either credit facility as of December 31, 2003. After inclusion
of our outstanding commercial paper borrowings and letters of credit, the
remaining available borrowing capacity under our bank facilities was $572.0
million as of December 31, 2003.
As of December 31, 2003, we intend and have the ability to refinance $428.1
million of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amount has been classified as
long-term debt in our accompanying consolidated balance sheet. Currently, we
believe our liquidity to be adequate. For more information on our credit
facilities, see Note 9 to our Consolidated Financial Statements included
elsewhere in this report.
62
Long-term Financing Transactions
Debt Financing
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 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 November 21, 2003, we closed a public offering of $500 million in principal
amount of senior notes due December 15, 2013 at a price to the public of 99.363%
per note. In the offering, we received proceeds, net of underwriting discounts
and commissions, of approximately $493.6 million. We used the proceeds to reduce
our outstanding balance on our commercial paper borrowings. As of December 31,
2003, our total liability balance due on the various series of our senior notes
was approximately $3.7 billion. For more information on our senior notes, see
Note 9 to our Consolidated Financial Statements included elsewhere in this
report.
Equity Financing
In June 2003, we issued in a public offering, an additional 4,600,000 of our
common units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $173.3 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.
On February 3, 2004, we announced that we had priced the public offering of
an additional 5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We also granted to the underwriters an
option to purchase up to 795,000 additional common units to cover
over-allotments. On February 9, 2004, 5,300,000 common units were issued. We
received net proceeds of $237.8 million for the issuance of these common units
and we used the proceeds to reduce the borrowings under our commercial paper
program.
Capital Requirements for Recent Transactions
During 2003, our cash outlays for the acquisitions of assets and equity
investments totaled $359.9 million. We utilized our commercial paper program to
fund these acquisitions and then reduced our short-term borrowings with the
proceeds from our June 2003 issuance of common units and our November 2003
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 2004
through a combination of long-term debt, equity and the issuance of additional
commercial paper to replace maturing commercial paper borrowings. We are
committed to maintaining a cost effective capital structure and we intend to
finance new acquisitions using a mix of approximately 60% equity financing and
40% debt financing. We issued common units in February 2004 in a public offering
as discussed above.
In regard to acquisition expenditures, our primary capital requirements
during 2003 included the following:
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 $7.7 million in cash. We paid
$7.2 million in September 2002 and the remaining $0.5 million in September 2003.
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 the remaining $1.4 million in March
2003.
63
MKM Partners, L.P. Effective June 1, 2003, we acquired the MKM Partners,
L.P.'s 12.75% ownership interest in the SACROC oil field unit for approximately
$25.2 million in aggregate consideration, consisting of $23.3 million in cash
and $1.9 million in assumed liabilities.
Red Cedar Gas Gathering Company. Effective August 1, 2003, we acquired
reversionary interests in the Red Cedar Gas Gathering Company held by the
Southern Ute Indian Tribe. We paid $10.0 million in cash in September 2003.
Shell Products Terminals. Effective October 1, 2003, we acquired five refined
petroleum products terminals in the western United States from Shell Oil
Products U.S. for approximately $20.0 million in cash. We paid this amount in
October 2003.
Yates Field Unit and Carbon Dioxide Assets. Effective November 1, 2003, we
acquired from a subsidiary of Marathon Oil Corporation an approximate 42.5%
ownership interest in the Yates oil field unit, crude oil gathering facilities
surrounding the Yates field and Marathon Carbon Dioxide Transportation Company.
Marathon Carbon Dioxide Transportation Company owns a 65% ownership interest in
the Pecos Carbon Dioxide Pipeline Company. We paid Marathon approximately $259.0
million in aggregate consideration, consisting of $231.0 million in cash and
$28.0 million in assumed liabilities.
MidTex Gas Storage Company, LLP. Effective November 1, 2003, we acquired the
remaining approximate 32% of MidTex Gas Storage Company, LLP that we did not
already own for approximately $17.5 million in aggregate consideration. We paid
$15.8 million in cash and assumed $1.7 million in debt.
ConocoPhillips Products Terminals. Effective December 11, 2003, we acquired
seven refined petroleum products terminals in the southeastern United States
from ConocoPhillips and Phillips Pipe Line Company for approximately $14.0
million in cash and $1.1 million in assumed liabilities. We paid this amount in
December 2003.
Tampa, Florida Bulk Terminals. Effective December 10 and 23, 2003, we
acquired two bulk terminal facilities located in Tampa, Florida from Nitram,
Inc. and IMC Global, Inc., respectively. Our consideration consisted of
approximately $26.0 million in cash and $3.5 million in assumed liabilities. We
paid this amount in December 2003.
Summary of Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial
statements. Our obligations with respect to these investments, as well as our
obligations with respect to a letter of credit, are summarized below (in
millions):
Our
Our Remaining Total Total Contingent
Investment Ownership Interest(s) Entity Entity Share of
Entity Type Interest Ownership Assets(4) Debt Entity Debt(5)
- ---------------------------------- ---------- --------- ----------- --------- ------ --------------
General 50% (1) $132 $231 $116 (2)
Cortez Pipeline Company........ Partner
Common 51% Affiliate of $280 $179 $5
Shareholder, Exxon Mobil
Plantation Pipe Line Company... Operator Corporation
Red Cedar Gas Gathering General 49% Southern Ute $166 $55 $55
Company.................... Partner Indian Tribe
Nassau County, N/A N/A Nassau County, N/A N/A $28
Florida Ocean Highway Florida Ocean
and Port Authority (3)..... Highway and
Port Authority
- ---------
64
(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.
(3) Results from our Vopak terminal acquisition in July 2001. See Note 3 to the
Consolidated Financial Statements. 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 LLC, the operator of the port facilities. In July 2002, we
acquired Nassau Terminals LLC 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.
(4) Principally property, plant and equipment.
(5) Represents the portion of the entity's debt that we may be responsible for
if the entity cannot satisfy the obligation.
For the year ended December 31, 2003, our share of earnings, based on our
ownership percentage, before income taxes and amortization of excess investment
cost was $32.2 million from Cortez Pipeline Company, $28.0 million from
Plantation Pipe Line Company and $18.6 million from Red Cedar Gas Gathering
Company. Additional information regarding the nature and business purpose of
these investments is included in Notes 7 and 13 to our Consolidated Financial
Statements included elsewhere in this report.
Summary of Certain Contractual Obligations
Amount of Commitment Expiration per Period
---------------------------------------------------------------
1 Year After 5
Total or Less 2-3 Years 4-5 Years Years
---------- -------- -------- -------- ----------
(In thousands)
Commercial paper outstanding...... $ 426,130 $426,130 $ - $ - $ -
Other debt borrowings............. 3,892,796 4,218 248,252 257,857 3,382,469
Operating leases.................. 102,753 17,076 27,780 22,457 35,440
Postretirement welfare plans(a)... 1,800 300 600 600 300
Other obligations................. 3,600 600 1,200 1,200 600
---------- -------- -------- -------- ----------
Total............................. $4,427,079 $448,324 $277,832 $282,114 $3,418,809
========== ======== ======== ======== ==========
Other commercial commitments:
Capital expenditures.............. $ 54,918 $ 54,918 - - -
========== ======== ======== ======== ==========
- ----------
(a) Represents expected annual contributions of $0.3 million per year based on
calculations of independent Enrolled Actuary as of December 31, 2003.
Our budgeted expenditures for capital spending during 2004 are approximately
$115.9 million. This amount has been budgeted primarily for the purchase of
plant and equipment and is based on the payments we expect to make as part of
our 2004 sustaining capital expenditure plan. All of our capital expenditures,
with the exception of sustaining capital expenditures, are discretionary.
Operating Activities
Net cash provided by operating activities was $768.5 million in 2003, versus
$869.7 million in 2002. The $101.2 million (12%) decrease in 2003 compared to
2002 was primarily the result of an $87.9 million use of cash relative to net
changes in the collection on and payments of our accounts receivables and
payables in 2003 compared to a $111.5 million source of cash from these changes
in 2002. In addition to
65
timing differences, we made higher payments to settle related party payables at
the beginning of 2003, primarily for reimbursements to KMI for costs related to
the construction of our Mier-Monterrey natural gas pipeline and for general and
administrative services.
We also paid $44.9 million in 2003 for reparations and refunds under order
from the Federal Energy Regulatory Commission. The reparation and refund
payments were mandated by the FERC in a consolidated proceeding in FERC Docket
OR92-8-000 concerning rates charged by our Pacific operations on certain
interstate portions of their products pipelines. For more information on our
Pacific operations' regulatory proceedings, see Note 16 to our Consolidated
Financial Statements included elsewhere in this report.
The impact of these payments and the working capital timing differences were
partially offset by a $131.9 million increase in overall cash earnings,
reflecting the strong performance and growth that occurred across our business
portfolio during 2003. It also includes a $20.1 million increase in cash flows
related to higher payments made in 2002 under certain settlement agreements and
a $5.3 million increase related to higher distributions from equity investments
in 2003. The litigation settlements were primarily related to tariff-related
agreements between shippers and our Products Pipelines, and the increase in
distributions from equity investments in 2003 compared to 2002 mainly related to
higher returns from our 49% equity interest in the Red Cedar Gathering Company.
Investing Activities
Net cash used in investing activities was $943.1 million for the year ended
December 31, 2003, compared to $1,450.9 million for the prior year. The $507.8
million (35%) decrease in funds utilized in investing activities was mainly
attributable to higher expenditures made for strategic acquisitions in 2002.
Outlays for acquisition of assets, new businesses and investments totaled $910.3
million in 2002, versus $359.9 million in 2003. The $550.4 million (60%)
difference in acquisition expenditures was mainly due to our acquisition of
Kinder Morgan Tejas on January 31, 2002.
We continue to invest significantly in strategic acquisitions in order to
fuel future growth and increase unitholder value. These expenditures in 2003 are
detailed under "- Capital Requirements for Recent Transactions" above. Our
expenditures in 2002 included, (i) $721.6 million for Kinder Morgan Tejas, (ii)
$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, (iii) $29.9 million for certain bulk terminal assets previously
owned by M.J. Rudolph Corporation and (iv) $29.0 million for an additional 10%
ownership interest in the Cochin Pipeline system, which was made effective
December 31, 2001. For more information on our acquisitions, see Note 3 to our
Consolidated Financial Statements included elsewhere in this report.
The overall decline in funds used in investing activities in 2003 compared to
2002 includes a $34.7 million increase in funds used for capital expenditures
and an $11.8 million reduction in proceeds from sales and retirements of
property, plant and equipment. Including expansion and maintenance projects, our
capital expenditures were a record $577.0 million in 2003. We spent $542.2
million for capital expenditures in 2002. This $34.8 million (6%) increase was
principally due to higher 2003 capital investment in our CO2 and Products
Pipelines business segments. We continue to expand and grow our existing
businesses and have current projects in place that will, together with recent
acquisitions, significantly add production and throughput capacity to our oil
field and carbon dioxide flooding operations, and will add storage and transfer
capacity to our terminaling and natural gas businesses. Our sustaining capital
expenditures were $92.8 million for 2003, compared to $77.0 million for 2002.
Financing Activities
Net cash provided by financing activities amounted to $156.8 million in 2003,
compared to $559.5 million in 2002. This decrease of $402.7 million (72%) from
the prior year was chiefly due to both a $157.8 million decrease in cash flows
from overall debt financing activities and a $157.2 million decrease in cash
flows from partnership equity issuances. Both decreases were related to our
higher acquisition expenditures during 2002, as described above. During each of
the years 2003 and 2002, we purchased the pipeline and terminal businesses we
acquired primarily with borrowings under our commercial paper program. We
subsequently raised funds by completing public and private debt offerings of
senior notes and by issuing additional common units and i-units. We used the
proceeds from these debt and equity issuances to reduce our borrowings under our
commercial paper program.
66
In 2003, we closed a public offering of $500 million in principal amount of
senior notes, resulting in a net cash inflow of $493.6 million net of discounts
and issuing costs, and we borrowed an additional $206.1 million under our
commercial paper program. We used our commercial paper borrowings to fund our
asset acquisitions, capital expansion projects and other partnership activities,
and we used the proceeds from the senior note issuance to reduce commercial
paper borrowings. 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 in the fourth quarter of 2002 with substantially identical
notes that are registered under the Securities Act of 1933) and retired a
maturing amount of $200 million in principal amount of senior notes. We also
made payments of $55.0 million to retire the outstanding balance on our
Trailblazer Pipeline Company's two-year revolving credit facility and used
$370.5 million to reduce our commercial paper borrowings.
The year-to-year decrease in cash flows from partnership equity issuances
primarily relates to the difference in cash received from our June 2003 issuance
of common units and our August 2002 issuance of i-units. In June 2003, we issued
4,600,000 of our common units in a public offering at a price of $39.35 per
share, less commissions and underwriting expenses. After commissions and
underwriting expenses, we received net proceeds of $173.3 million for the
issuance of these common units. In August 2002, we issued 12,478,900 i-units to
KMR at a price of $27.50 per share, less commissions and underwriting expenses.
After commissions and underwriting expenses, we received net proceeds of $331.2
million for the issuance of these i-units. We used the proceeds from each of
these issuances to reduce the borrowings under our commercial paper program.
The overall decrease in funds provided by financing activities in 2003
compared to 2002 also resulted from a $97.2 million increase in distributions to
our partners in 2003 compared to the prior year. Cash distributions to all
partners, including KMI, increased to $679.3 million in 2003 compared to $582.1
million in 2002. The increase in distributions was due to increases in the per
unit cash distributions paid, the number of outstanding units and the resulting
increase in the general partner incentive distributions.
We paid distributions of $2.575 per unit in 2003 compared to $2.36 per unit
in 2002. The 9% increase in paid distributions per unit resulted from favorable
operating results in 2003. We also distributed 3,342,417 and 2,538,785 i-units
in quarterly distributions during 2003 and 2002, respectively, to KMR, our sole
i-unitholder. 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 2003 and 2002. For each outstanding i-unit that KMR held,
a fraction of an i-unit was issued. The fraction was determined by dividing the
cash amount distributed per common unit by 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 2003, 2002 and
2001, we distributed 100.4%, 97.6% and 100%, 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
changes in reserves.
67
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. The cash equivalent of distributions of
i-units is 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.
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. Our general partner's incentive distribution that
we declared for 2003 was $322.8 million, while the incentive distribution paid
to our general partner during 2003 was $309.4 million. The difference between
declared and paid distributions is due to the fact that our distributions for
the fourth quarter of each year are declared and paid in the first quarter of
the following year.
On February 13, 2004, we paid a quarterly distribution of $0.68 per unit for
the fourth quarter of 2003. This distribution was 9% greater than the $0.625
distribution per unit we paid for the fourth quarter of 2002 and 6% greater than
the $0.64 distribution per unit we paid for the first quarter of 2003. 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 $0.68 cash distribution per common unit.
Litigation and Environmental
As of December 31, 2003, we have recorded a total reserve for environmental
claims in the amount of $39.6 million. This reserve is primarily established to
address and clean up soil and ground water impacts from former releases to the
environment at facilities we have acquired. Reserves for each project are
generally established by reviewing existing documents, conducting interviews and
performing site inspections to determine the overall size and impact to the
environment. Reviews are made on a quarterly basis to determine the status of
the cleanup and the costs associated with the effort and to identify if the
reserve allocation is appropriately valued. In assessing environmental risks in
conjunction with proposed acquisitions, we review records relating to
environmental issues, conduct site inspections, interview employees, and, if
appropriate, collect soil and groundwater samples. After consideration of
reserves established, we believe that costs for environmental remediation and
ongoing compliance with environmental regulations will not have a material
adverse effect on our cash flows, financial position or results of operations or
diminish our ability to operate our businesses. However, there can be no
assurances that future events, such as changes in existing laws, the
promulgation of new laws, or the development or discovery of new or existing
facts or conditions will not cause us to incur significant unanticipated costs.
Please refer to Note 16 to our Consolidated Financial Statements included
elsewhere in this report for additional information on our pending environmental
and litigation matters, respectively. We believe we have established
68
adequate environmental and legal reserves such that the resolution of pending
environmental matters and litigation will not have a material adverse impact on
our business, cash flows, financial position or results of operations. However,
changing circumstances could cause these matters to have a material adverse
impact.
Regulation
On June 26, 2003, FERC issued an interim rule to be effective August 7, 2003,
under which regulated companies are required to document cash management
arrangements and transactions. The interim rule does not include a proposed rule
that would have required regulated companies, as a prerequisite to participation
in cash management programs, to maintain a proprietary capital ratio of 30% and
an investment grade credit rating. On October 22, 2003, the FERC issued its
final rule amending its regulations effective November 2003 which, among other
things, requires FERC-regulated entities to file their cash management
agreements with the FERC and to notify the FERC within 45 days after the end of
the quarter when their proprietary capital ratio drops below 30%, and when it
subsequently returns to or exceeds 30%. KMIGT and Trailblazer filed their cash
management agreements with the FERC on or before the deadline, which was
December 10, 2003.
On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate pipeline must
file a compliance plan by that date and must be in full compliance with the
Standards of Conduct by June 1, 2004. The primary change from existing
regulation is to make such standards applicable to an interstate pipeline's
interaction with many more affiliates (which are referred to as "energy
affiliates"), including intrastate/Hinshaw pipelines, processors and gatherers
and any company involved in natural gas or electric markets (including natural
gas marketers) even if they do not ship on the affiliated interstate pipeline.
Local distribution companies are excluded, however, if they do not make
off-system sales. The Standards of Conduct require, among other things, separate
staffing of interstate pipelines and their energy affiliates (but support
functions and senior management at the central corporate level may be shared)
and strict limitations on communications from the interstate pipeline to an
energy affiliate.
Kinder Morgan Interstate Gas Transmission LLC filed for clarification and
rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing,
Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw
pipeline affiliates not be included in the definition of energy affiliates. To
date the FERC has not acted on these hearing requests. On February 19, 2004,
Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company
filed exemption requests with the FERC. The pipelines seek a limited exemption
from the requirements of Order No. 2004 for the purpose of allowing their
affiliated Hinshaw and intrastate pipelines, which are subject to state
regulation and do not make any off-system sales, to be excluded from the rule's
definition of energy affiliate. We expect the one-time costs of compliance with
the Order, assuming the request to exempt intrastate pipeline affiliates is
granted, to range from $600,000 to $700,000, to be shared between us and KMI.
The Pipeline Safety Improvement Act of 2002 was signed into law on December
17, 2002, providing guidelines in the areas of testing, education, training and
communication. The Act requires pipeline companies to perform integrity tests on
natural gas transmission pipelines that exist in high population density areas
that are designated as High Consequence Areas. Pipeline companies are required
to perform the integrity tests within ten years of the date of enactment and
must perform subsequent integrity tests on a seven year cycle. At least 50% of
the highest risk segments must be tested within five years of the enactment
date. The 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. Testing will
consist of hydrostatic testing, internal electronic testing, or direct
assessment of the piping. 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. Department of
Transportation is responsible for providing. A similar integrity management rule
for refined petroleum products pipelines became effective May 29, 2001. All
baseline assessments for products pipelines must be completed by March 31, 2008.
At least half of the line pipe affecting High Consequence Areas must be assessed
by September 30, 2004. We have included all incremental expenditures estimated
to occur during 2004 associated with the Pipeline Safety Improvement Act of 2002
and the integrity management of our products pipelines in our 2004 capital
expenditure plan.
69
Please refer to Note 16 to our Consolidated Financial Statements included
elsewhere in this report for additional information regarding regulatory
matters.
New Accounting Pronouncements
Please refer to Note 17 to our Consolidated Financial Statements included
elsewhere in this report for information on New Accounting Pronouncements.
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;
o changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
o our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to make
expansions to our facilities;
o difficulties or delays experienced by railroads, barges, trucks, ships or
pipelines in delivering products to or from 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 our
services or provide services or products to us;
o changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that 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;
70
o acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
o capital markets conditions;
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 inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o foreign exchange fluctuations;
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 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. 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. For more information on our risk management
activities, see Note 14 to our Consolidated Financial Statements included
elsewhere in this report.
71
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 energy
financial instruments are as follows:
Credit Rating
-------------
J. Aron & Company / Goldman Sachs A+
Morgan Stanley.................. A+
Deutsche Bank................... AA-
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 (i) ceased to account for those
derivatives as hedges, (ii) entered into new derivative transactions on
substantially similar terms with other counterparties to replace our positions
with Enron, (iii) designated the replacement derivative positions as hedges of
the exposures that had been hedged with the Enron positions and (iv) 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.
Pursuant to our management's approved risk management policy, we are to
engage in these activities only as a hedging mechanism against price volatility
associated with:
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.
Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows. Accordingly, as of December 31, 2003, no financial
instruments were used to limit the effects of foreign exchange rate fluctuations
on our financial results. In February 2004, we entered into a single $17.0
million foreign currency call option that expires on December 31, 2004.
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 $155.8 million of deferred net loss being reported as
"Accumulated other comprehensive loss" in our accompanying Balance Sheet as of
December 31, 2003, and $45.3 million of deferred
72
net loss being reported as "Accumulated other comprehensive loss" in our
accompanying Balance Sheet as of December 31, 2002.
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, 2003 and
2002, Value-at-Risk reached a high of $12.8 million and $12.8 million,
respectively, and a low of $2.2 million and $11.6 million, respectively.
Value-at-Risk as of December 31, 2003, was $6.2 million and averaged $5.2
million for 2003. Value-at-Risk as of December 31, 2002, was $12.8 million and
averaged $11.9 million for 2002.
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 above, 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.
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, 2003 and 2002, the carrying values of our long-term fixed
rate debt were approximately $3,801.7 million and $3,346.1 million,
respectively, compared to fair values of $4,372.3 million and $4,161.6 million,
respectively. The increase in the excess of fair value over carrying value is
primarily due to the decrease in interest rates during 2003. 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 2003 and 2002, respectively, would result in changes of approximately $158.6
million and $195.1 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 $493.0 million as of December 31, 2003 and $293.4 million as of December 31,
2002. 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 $2.3 million and $1.6 million in our 2003 and 2002
annualized pre-tax earnings, respectively.
As of December 31, 2003, we were party to interest rate swap agreements with
a notional principal amount of $2.1 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt
73
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
2003 or 2002. 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, 2003, 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 91.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
Item 9A. Controls and Procedures.
As of December 31, 2003, our management, including our Chief Executive
Officer and Chief Financial Officer, has evaluated the effectiveness of the
design and operation of our disclosure controls and procedures pursuant to Rule
13a-15(b) under the Securities Exchange Act of 1934. There are inherent
limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or
overriding of the controls and procedures. Accordingly, even effective
disclosure controls and procedures can only provide reasonable assurance of
achieving their control objectives. Based upon and as of the date of the
evaluation, our Chief Executive Officer and our Chief Financial Officer
concluded that the design and operation of our disclosure controls and
procedures were effective in all material respects to provide reasonable
assurance that information required to be disclosed in the reports we file and
submit under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported as and when required. There has been no change in our
internal control over financial reporting during the fourth quarter of 2003 that
has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
74
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.
Position with our General Partner and the
Name Age Delegate
---------------------- ---- --------------------------------------------
Richard D. Kinder......... 59 Director, Chairman and Chief Executive
Officer
Michael C. Morgan......... 35 President
C. Park Shaper............ 35 Director, Vice President and Chief Financial
Officer
Edward O. Gaylord......... 72 Director
Gary L. Hultquist......... 60 Director
Perry M. Waughtal......... 68 Director
Thomas A. Bannigan........ 50 President, Products Pipelines
R. Tim Bradley............ 48 President, CO2
David D. Kinder........... 29 Vice President, Corporate Development
Joseph Listengart......... 35 Vice President, General Counsel and
Secretary
Deborah A. Macdonald...... 52 President, Natural Gas Pipelines
Jeffrey R. Armstrong...... 35 President, Terminals
James E. Street........... 47 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 and Chief Financial Officer of KMR
and Kinder Morgan G.P., Inc. and Vice President 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, and served as Treasurer of
KMR from February 2001 to January 2004. He has served as Treasurer of KMI from
April 2000 to January 2004 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, and served as
Treasurer of Kinder Morgan G.P., Inc. from January 2000 to January 2004. 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
75
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. 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.
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. He is also a
director of Prime Medical Services, Inc. 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. Mr. Bannigan received his Juris Doctor, cum
laude, from Loyola University in 1980 and received a Bachelors degree from the
State University of New York in Buffalo.
R. Tim Bradley is President, CO2 of KMR and of Kinder Morgan G.P., Inc. and
President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was elected President,
CO2 of KMR and Vice President (President, CO2) 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
76
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. 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. Ms. Macdonald served as President of Natural Gas Pipeline Company
of America from October 1999 to March 2003. 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.
Jeffrey R. Armstrong is President, Terminals of KMR and Kinder Morgan G.P.,
Inc. Mr. Armstrong became President of our Terminals Segment in July 2003. Prior
to that, he served as President, Kinder Morgan Liquids Terminals LLC from March
1, 2001, when the company was formed via the acquisition of GATX Terminals,
until July 2003. From 1994 to 2001, Mr. Armstrong worked for GATX Terminals,
where he was General Manager of their East Coast operations. He received his
bachelor's degree from the United States Merchant Marine Academy and a MBA from
the University of Notre Dame.
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.
Corporate Governance
Our limited partnership agreement provides for us to have a general partner
rather than a board of directors. 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. Through the
operation of that agreement and our partnership agreement, KMR manages and
controls our business and affairs, and the board of directors of KMR performs
the functions of and is the equivalent of a board of directors for us.
Similarly, the standing committees of KMR's board of directors function as
standing committees of our board. KMR's board of directors is comprised of the
same persons who comprise our general partner's board of directors. References
in this report to the board mean the board of KMR as the delegate of our general
partner, acting as our board of directors, and references to committees mean
committees of the board of KMR as the delegate of our general partner, acting as
committees of our board of directors.
The board has adopted governance guidelines for the board and charters for
the audit committee, nominating and governance committee and compensation
committee. The governance guidelines and the rules of the New York Stock
Exchange require that a majority of the directors be independent, as described
in those guidelines and rules respectively. To assist in making determinations
of independence, the board has determined that the following categories of
relationships are not material relationships that would cause the affected
director not to be independent:
o If the director was an employee, or had an immediate family member who was
an executive officer of KMR or us or any of its or our affiliates, but the
employment relationship ended more than three years prior to the date of
determination (or, in the case of employment of a director as an interim
chairman or interim chief executive officer, such employment relationship
ended by the date of determination);
77
o If within the period of three years prior to the determination the director
received no more than, and has no immediate family member that received
more than, $100,000 per year in direct compensation from us or our
affiliates, other than (i) director and committee fees and pension or other
forms of deferred compensation for prior service (provided such
compensation is not contingent in any way on continued service), (ii)
compensation received by a director for former service as an interim
chairman or interim chief executive officer, and (iii) compensation
received by an immediate family member for service as a non-executive
employee;
o If the director is at the date of determination an executive officer or an
employee, or has an immediate family member that is at the date of
determination an executive officer, of another company that, within the
last three full fiscal years prior to the date of determination made
payments to, or received payments from, us and our affiliates for property
or services in an amount which, in any single fiscal year, was less than
the greater of $1.0 million or 2% of such other company's annual
consolidated gross revenues. Charitable organizations are not considered
"companies" for purposes of this determination;
o If the director is also a director, but is not an employee or executive
officer, of our general partner or another affiliate or affiliates of KMR
or us, so long as such director is otherwise independent; and
o If the director beneficially owns less than 10% of each class of voting
securities of us, our general partner, KMR or Kinder Morgan, Inc.
The board has affirmatively determined that Messrs. Gaylord, Hultquist and
Waughtal, who constitute a majority of the directors, are independent as
described in our governance guidelines and the New York Stock Exchange rules.
Each of them meets the standards above and has no other relationship with us. In
conjunction with regular board meetings, these three non-management directors
also meet in executive session without members of management. Mr. Waughtal has
been elected for a one year term expiring in October 2004 to serve as lead
director to develop the agendas for and moderate these executive sessions of
independent directors.
We have a separately designated standing audit committee established in
accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934
comprised of Messrs. Gaylord, Hultquist and Waughtal. Mr. Gaylord is the
chairman of the audit committee and has been determined by the board to be an
"audit committee financial expert." The governance guidelines and our audit
committee charter, as well as the rules of the New York Stock Exchange and the
Securities and Exchange Commission, require that members of the audit committee
satisfy independence requirements in addition to those above. The board has
determined that all of the members of the audit committee are independent as
described under the relevant standards.
We have not, nor has our general partner nor KMR made, within the preceding
three years, contributions to any charitable organization in which any of our or
KMR's directors serves as an executive officer in any single fiscal year that
exceeded the greater of $1 million or 2% of such charitable organization's
consolidated gross revenues.
We make available free of charge within the "Investors" information section
of our Internet website, at www.kindermorgan.com and in print to any shareholder
who requests, the governance guidelines, the charters of the audit committee,
compensation committee and nominating and governance committee, and our code of
business conduct and ethics (which applies to senior financial and accounting
officers and the chief executive officer, among others). Requests for copies may
be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500
Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490. We
intend to disclose any amendments to our code of business conduct and ethics,
and any waiver from a provision of that code granted to our executive officers
or directors, on our Internet website within five business days following such
amendment or waiver. The information contained on or connected to our Internet
website is not incorporated by reference into this Form 10-K and should not be
considered part of this or any other report that we file with or furnish to the
SEC.
You may contact our lead director or the independent directors as a group by
mail to Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston,
Texas 77002, Attention: General Counsel, or by email within the "Contact Us"
section of our Internet website, at www.kindermorgan.com. Your communication
should specify the intended recipient.
78
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Securities Exchange Act of 1934 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 2003.
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.
Summary Compensation Table
Long-Term
Compensation Awards
Annual Compensation Restricted KMI Shares
Stock Underlying All Other
Name and Principal Position Year Salary Bonus(1) Awards(2) Options Compensation(3)
----------------------------------------------- ----------- ----------- ------------- ------------- ----------------
Richard D. Kinder............... 2003 $ 1 $ -- $ -- -- $ --
Director, Chairman and CEO 2002 1 -- -- -- --
2001 1 -- -- -- --
Michael C. Morgan............... 2003 200,000 875,000 5,380,000 -- 9,815
President 2002 200,000 950,000 -- -- 9,584
2001 200,000 350,000 569,900 -- 7,835
C. Park Shaper.................. 2003 200,000 875,000 5,918,000 -- 8,378
Director, Vice President and CFO 2002 200,000 950,000 -- 100,000(4) 8,336
2001 200,000 350,000 569,900 -- 7,186
Deborah A. Macdonald............ 2003 200,000 875,000 5,380,000 -- 8,966
President, 2002 200,000 950,000 -- 50,000(5) 8,966
Natural Gas Pipelines 2001 200,000 350,000 569,900 -- 32,816
Joseph Listengart............... 2003 200,000 825,000 3,766,000 -- 8,378
Vice President, 2002 200,000 950,000 -- -- 8,336
General Counsel and Secretary 2001 200,000 350,000 569,900 -- 7,186
- ----------
(1) Amounts earned in year shown and paid the following year.
(2) Represent shares of restricted KMI stock awarded in 2003 and 2001. The 2003
and 2001 awards were issued under a shareholder approved plan. For the 2003
awards, value computed as the number of shares awarded times the closing
price on date of grant ($53.80 at July 16, 2003). Twenty-five percent of
the shares in each grant vest on the third anniversary after the date of
grant and the remaining seventy-five percent of the shares in each grant
vest on the fifth anniversary after the date of grant. To vest, we and/or
KMI must also achieve one of the following performance hurdles during the
vesting period: (i) KMI must earn $3.70 per share in any fiscal year; (ii)
we must distribute $2.72 over four consecutive quarters; (iii) we and KMI
must fund at least one year's annual incentive program; or (iv) KMI's stock
price must average over $60.00 per share during any consecutive 30-day
period. One of these hurdles has already been met. The 2003 awards were
long-term equity compensation for our current senior management
79
through July 2008, and neither we nor KMI intend to make further restricted
stock awards to them before that date. The 2001 awards were granted in 2002
and relate to performance in 2001. Value for 2001 grants computed as the
number of shares awarded (10,000) times the closing price on date of grant
($56.99 at January 16, 2002). 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 2003 and 2002, amounts represent contributions to the Kinder Morgan
Savings Plan (a 401(k) plan), value of group-term life insurance exceeding
$50,000 and taxable parking subsidy. 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. Ms.
Macdonald's amounts include additions in 2001 resulting from relocation
expenses.
(4) 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.
(5) 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.
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 between one percent
and fifty 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 employer 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 2004, we will not make any
discretionary contributions to individual accounts for 2003. 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 authorized 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.
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, 2003, outstanding options to
purchase 129,050 common units had been granted to 43 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 twenty 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, 2003, outstanding options to
purchase 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s
80
three non-employee directors. Forty percent of all such options will vest on the
first anniversary of the date of grant and twenty 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 2003 to any of the
individuals named in the Summary Compensation Table above. The following table
sets forth certain information as of December 31, 2003 with respect to common
unit options previously granted to the individuals named in the Summary
Compensation Table above. Mr. Listengart is 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 2003 and 2003 Year-End Common Unit Option Values
Number of Units Value of Unexercised
Underlying Unexercised In-the-Money Options
Units Acquired Value Options at 2003 Year-End At 2003 Year-End(1)
--------------------------- -------------------------
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
------------------ -------------- --------- ------------- -------------- -------------- --------------
Joseph Listengart.... -- -- 10,000 -- $ 319,888 --
- ----------
(1) Calculated on the basis of the fair market value of the underlying common
units at year-end 2003, 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. During 2003, none of the persons named in
the Summary Compensation Table above were granted KMI stock options.
Aggregated KMI Stock Option Exercises in 2003 and 2003 Year-End KMI Stock Option Values
Number of Shares Value of Unexercised
Underlying Unexercised In-the-Money Options
Options at 2003 Year-End at 2003 Year-End(1)
Shares Acquired Value -------------------------- -----------------------------
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
-------------------- --------------- ---------- --------------------------- -------------- --------------
Michael C. Morgan........... 140,000 $4,242,350 197,500 - $5,572,406 -
C. Park Shaper.............. 30,000 $814,500 113,750 106,250 $2,473,188 $1,231,687
Deborah A. Macdonald........ 50,000 $1,194,249 62,500 37,500 $1,790,750 $ 79,125
Joseph Listengart........... 26,250 $691,264 106,300 - $3,586,868 -
- ----------
(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. No additional contributions were made for 2003 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.
81
The following table sets forth the estimated annual benefits payable as of
December 31, 2003, 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.
These benefits are subject to federal and state income taxes, where applicable,
but are not subject to deduction for social security or other offset amounts.
Estimated Current Estimated
Current Credited Yrs Compensation Annual Benefit
Credited Yrs of Service Age as of Covered by Payable Upon
Name Of Service at Age 65 Jan. 1, 2004 Plans Retirement (1)
---- -------------- -------------- ------------ -------------- --------------
Richard D. Kinder......... 3 8.8 59.2 $ 1 $ -
Michael C. Morgan......... 3 32.7 35.4 200,000 62,537
C. Park Shaper............ 3 32.7 35.4 200,000 62,537
Joseph Listengart......... 3 32.5 35.6 200,000 61,780
Deborah A. MacDonald...... 3 15.9 52.1 200,000 15,823
- ----------
(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 the executive officers of our general partner
and its delegate, KMR. Mr. Richard D. Kinder and Mr. James E. Street, 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 compensation for services to KMI, KMR and our
general partner.
Directors Fees. During 2003, each of the three non-employee members of the
boards of directors of KMR and our general partner received $10,000 in cash
compensation with respect to board service for the first quarter of 2003. In
addition, the director who served as chairman of KMR's audit committee was paid
an additional $2,500 for each quarter in 2003. In addition, directors are
reimbursed for reasonable expenses in connection with board meetings. In April
2003, we implemented the Directors' Unit Appreciation Rights Plan, as discussed
below, to serve as the sole compensation for non-employee directors for the
remainder of 2003. In October 2003, KMR appointed Mr. Perry M. Waughtal as Lead
Director, whose compensation is an additional $20,000 per year, paid $5,000 per
quarter, effective October 1, 2003.
Directors' Unit Appreciation Rights Plan. On April 1, 2003, KMR's
compensation committee established the Directors' Unit Appreciation Rights Plan.
Pursuant to this plan, each of KMR's three non-employee directors is eligible to
receive common unit appreciation rights. The primary purpose of this plan is to
promote the interests of our unitholders by aligning the compensation of the
non-employee members of the board of directors of KMR with unitholders'
interests. Secondly, since KMR's success is dependent on its operation and
management of our business and our resulting performance, the plan is expected
to align the compensation of the non-employee members of the board with the
interests of KMR's shareholders.
Upon the exercise of unit appreciation rights, we will pay, within thirty
days of the exercise date, the participant an amount of cash equal to the
excess, if any, of the aggregate fair market value of the unit appreciation
rights exercised as of the exercise date over the aggregate award price of the
rights exercised. The fair market value of one unit appreciation right as of the
exercise date will be equal to the closing price of one common unit on the New
York Stock Exchange on that date. The award price of one unit appreciation right
will be equal to the closing price of one common unit on the New York Stock
Exchange on the date of grant. Each unit appreciation right granted under the
plan will be exercisable only for cash and will be evidenced by a unit
appreciation rights agreement.
All unit appreciation rights granted vest on the six-month anniversary of the
date of grant. If a unit appreciation right is not exercised in the ten year
period following the date of grant, the unit appreciation right will expire and
not be exercisable after the end of such period. In addition, if a participant
ceases to serve on the board for any reason prior to the vesting date of a unit
appreciation right, such unit appreciation right will immediately expire on the
date of cessation of service and may not be exercised. The plan is administered
by
82
KMR's compensation committee. The total number of unit appreciation rights
authorized under the plan is 500,000. KMR's board has sole discretion to
terminate the plan at any time with respect to unit appreciation rights which
have not previously been granted to participants.
On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors were granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights shall be granted to each of KMR's three
non-employee directors during the first meeting of the board each January.
Accordingly, each non-employee director received an additional 10,000 unit
appreciation rights on January 21, 2004. As of December 31, 2003, 52,500 unit
appreciation rights had been granted. No unit appreciation rights were exercised
during 2003.
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. Mr. Morgan 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 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, Kinder Morgan G.P., Inc.
(our general partner) and its delegate, KMR. Pursuant to the terms of the
agreement, Mr. Shaper obtained a $5 million personal loan guaranteed by KMI and
us. Mr. Shaper was required to purchase and did purchase KMI common stock and
our common units in the open market with the loan proceeds. The Sarbanes-Oxley
Act of 2002 does not allow companies to issue or guarantee new loans to
executives, but it "grandfathers" loans that were in existence prior to the act.
Regardless, Mr. Shaper, KMI and we agreed that in today's business
environment it would be prudent for him to repay the loan. In conjunction with
this decision, Mr. Shaper sold 37,000 of KMI shares and 82,000 of our common
units. He used the proceeds to repay the $5 million personal loan guaranteed by
KMI and us, thereby eliminating KMI's and our guarantee of this loan. Mr. Shaper
instead participates in KMI's restricted stock plan with other senior
executives. The retention agreement was terminated accordingly.
Lines of Credit. As of December 31, 2002, we had agreed to guarantee
potential borrowings under lines of credit available from Wachovia Bank,
National Association, formerly known as First Union National Bank, to Messrs.
Thomas Bannigan, C. Park Shaper, Joseph Listengart, and James Street and Ms.
Deborah Macdonald. Each of these officers was primarily liable for any borrowing
on his or her line of credit, and if we made any payment with respect to an
outstanding loan, the officer on behalf of whom payment was made was required to
surrender a percentage of his or her options to purchase KMI common stock. Our
obligations under the guaranties, on an individual basis, generally did not
exceed $1.0 million and such obligations, in the aggregate, did not exceed $1.9
million. As of October 31, 2003, we had made no payments with respect to these
lines of credit and each line of credit was either terminated or refinanced
without a guarantee from us. We have no further guaranteed obligations with
respect to any borrowings by our officers.
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
The following table sets forth information as of January 31, 2004, 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 KMR, its delegate, by each of
the named executive officers and by 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.
83
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 Shares(4) of Class of Shares(5) of Class
----------- -------- ----------- -------- ------------ -------- ------------ --------
Richard D. Kinder(6)........... 316,079 * -- -- 34,901 * 23,995,415 19.40%
Michael C. Morgan(7)........... 6,000 * -- -- 4,053 * 427,503 *
C. Park Shaper(8).............. 4,000 * -- -- 2,368 * 301,002 *
Edward O. Gaylord.............. 33,000 * -- -- -- -- 2,000 *
Gary L. Hultquist(9)........... 12,000 * -- -- -- -- -- --
Perry M. Waughtal(10).......... 35,300 * -- -- 35,103 * 40,000 *
Joseph Listengart(11).......... 14,198 * -- -- -- -- 189,300 *
Deborah A. Macdonald(12)....... -- -- -- -- -- -- 195,568 *
Directors and Executive Officers
as a group (13 persons)(13). 437,236 * -- -- 79,096 * 25,629,120 20.72%
Kinder Morgan, Inc.(14)........ 12,955,735 9.62% 5,313,400 100.00% 12,702,852 25.93% -- --
Fayez Sarofim (15)............. 7,266,921 5.39% -- -- -- -- -- --
Capital Group -- -- -- -- 6,751,430 13.78% -- --
International,Inc.(16).........
OppenheimerFunds, Inc.(17)..... -- -- -- -- 4,433,727 9.05% -- --
- ----------
* 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, 2004, we had 134,735,758 common units issued and
outstanding.
(3) As of January 31, 2004, we had 5,313,400 Class B units issued and
outstanding.
(4) Represent the limited liability company shares of KMR. As of January 31,
2004, there were 48,996,465 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, 2004, KMI had a total of 123,711,341 shares of issued and
outstanding voting common stock, which excludes 8,892,884 shares held in
treasury.
(6) Includes (a) 7,979 common units owned by Mr. Kinder's spouse, (b) 5,173 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 197,500 KMI shares exercisable within 60 days
of January 31, 2004, and includes 107,500 shares of restricted KMI stock.
(8) Includes options to purchase 170,000 KMI shares exercisable within 60 days
of January 31, 2004, and includes 117,500 shares of restricted KMI stock.
(9) Includes options to purchase 10,000 common units exercisable within 60 days
of January 31, 2004.
(10) Includes options to purchase 8,000 common units exercisable within 60 days
of January 31, 2004.
(11) Includes options to purchase 10,000 common units and 106,300 KMI shares
exercisable within 60 days of January 31, 2004, and includes 77,500 shares
of restricted KMI stock.
(12) Includes options to purchase 75,000 KMI shares exercisable within 60 days
of January 31, 2004, and includes 107,500 shares of restricted KMI stock.
(13) Includes options to purchase 32,000 common units and 815,425 KMI shares
exercisable within 60 days of January 31, 2004, and includes 597,800 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 filed February 12, 2004 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 3,990,712 common
units, sole disposition power over 2,000,000 common units and shared
disposition power over 7,266,921 common units. Mr. Sarofim's address is
2907 Two Houston Center, Houston, Texas 77010.
84
(16) As reported on the Schedule 13G/A filed February 13, 2004 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 5,144,620 shares,
shared voting power over 0 shares, sole disposition power over 6,751,430
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 11, 2004 by
OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund.
OppenheimerFunds, 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 4,433,727
shares. Of these 4,433,727 KMR shares, Oppenheimer Capital Income Fund has
sole voting power over 2,742,501 shares, shared voting power over 0 shares,
sole disposition power over 0 shares and shared disposition power over
2,742,501 shares. OppenheimerFunds, Inc.'s address is 225 Liberty Street,
11th Floor, New York, New York 10281, and Oppenheimer Capital Income Fund's
address is 6803 Tucson Way, Centennial, Colorado 80112.
Equity Compensation Plan Information
The following table sets forth information regarding our equity compensation
plans as of January 31, 2004. Specifically, the table refers to information
regarding our Common Unit Option Plan described in Item 11. "Executive
Compensation" as of January 31, 2004.
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
warrants and rights warrants and rights in column (a))
Plan Category (a) (b) (c)
---------------------------------- -------------------------- ----------------------- -------------------------------
Equity compensation plans
approved by security holders - - -
Equity compensation plans
not approved by security holders 149,050 $17.88 55,400
------- ------
Total 149,050 55,400
======= ======
For information about our Common Unit Option Plan, see Item 11 "Executive
Compensation -- Common Unit Option Plan."
Item 13. Certain Relationships and Related Transactions.
Odessa Lateral
As previously reported in our Annual Report on Form 10-K for the year ended
December 31, 2002, we have purchased a certain 13-mile, 6-inch diameter carbon
dioxide pipeline lateral, referred to herein as the Odessa Lateral, from Morgan
Associates Proprietary, L.P. for $0.7 million. 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 owned and 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, prior to 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
85
ultimately sold to the South Cowden and Emmons projects. During 2002, KMCO2 was
selling carbon dioxide to ConocoPhillips for use 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 was obligated to pay 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 did 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 was approved by the Boards of Directors of our general
partner and KMR and the transaction closed 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.
Item 14. Principal Accounting Fees and Services
The following sets forth fees billed for the audit and other services
provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31,
2003, and December 31, 2002 (in dollars):
Year Ended December 31,
-----------------------------
2003 2002
------------- -------------
Audit fees(1)............$ 1,079,092 $ 983,546
Tax fees(2).............. 1,347,903 1,833,394
All other fees(3)......... - 10,000
------------- -------------
Total..................$ 2,426,995 $ 2,826,940
============= =============
- ----------
(1) Includes fees for audit of annual financial statements, reviews of the
related quarterly financial statements, and reviews of documents filed with
the Securities and Exchange Commission.
(2) Includes fees related to professional services for tax compliance, tax
advice and tax planning.
(3) Consists of fees for services other than services reported above. Includes
fees related to professional services for consultation on Environmental
Protection Agency report.
86
All services rendered by PricewaterhouseCoopers LLP are permissible
under applicable laws and regulations, and are pre-approved by the audit
committee of KMR and our general partner. Pursuant to the charter of the audit
committee of KMR, the delegate of our general partner, the committee's primary
purposes include the following:
o to select, appoint, engage, oversee, retain, evaluate and terminate our
external auditors;
o to pre-approve all audit and non-audit services, including tax services, to
be provided, consistent with all applicable laws, to us by our external
auditors; and
o to establish the fees and other compensation to be paid to our external
auditors.
Furthermore, the audit committee will review the external auditors' proposed
audit scope and approach as well as the performance of the external auditors. It
also has direct responsibility for and sole authority to resolve any
disagreements between our management and our external auditors regarding
financial reporting, will regularly review with the external auditors any
problems or difficulties the auditors encountered in the course of their audit
work, and will, at least annually, use its reasonable efforts to obtain and
review a report from the external auditors addressing the following (among other
items):
o the auditors' internal quality-control procedures;
o any material issues raised by the most recent internal quality-control
review, or peer review, of the external auditors;
o the independence of the external auditors; and
o the aggregate fees billed by our external auditors for each of the previous
two fiscal years.
87
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 91.
(a)(3) Exhibits
*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, File No. 1-11234 (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).
*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).
88
*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 (File 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
(File 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).
4.25-- Certificate of Vice President, Treasurer and Chief Financial Officer
and Vice President, General Counsel and Secretary of Kinder Morgan
Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder
Morgan Energy Partners, L.P. establishing the terms of the 5.00% Notes
due December 15, 2013.
4.26-- Specimen of 5.00% Notes due December 15, 2013 in book-entry form.
*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, File No. 1-11234).
*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, File No. 1-11234).
*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-- 364-day Credit Agreement dated as of October 14, 2003 among Kinder
Morgan Energy Partners, L.P., the lenders party thereto and Wachovia
Bank, National Association as Administrative Agent.
10.6-- Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation
Rights Plan.
10.7-- Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors' Unit
Appreciation Rights Plan.
11.1-- Statement re: computation of per share earnings.
21.1-- List of Subsidiaries.
23.1-- Consent of PricewaterhouseCoopers LLP.
31.1-- Certification by CEO pursuant to Rule 13A-14 or 15D of the Securities
Exchange Act of 1934, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2-- Certification by CFO pursuant to Rule 13A-14 or 15D of the Securities
Exchange Act of 1934, as adopted pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1-- Certification by CEO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
89
32.2-- Certification by CFO pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
- ----------
* 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 21, 2003 on Form 8-K was furnished on October
21, 2003, 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 discuss and answer
questions related to our carbon dioxide business in a live webcast. Interested
parties would be able to access the webcast by visiting:
http://www.firstcallevents.com/service/ ajwz391859932gf12.html. The webcast
began at 4:30 p.m. eastern daylight savings time on October 21, 2003, and is
archived at Kinder Morgan, Inc.'s website at: http://www.kindermorgan.com and
at: http://www.prnewswire.com.
Current report dated December 8, 2003 on Form 8-K was furnished on December
8, 2003, 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 on
December 9, 2003, at the Wachovia Securities Pipeline Conference, to discuss the
financials, business plans and objectives of us, Kinder Morgan, Inc. and Kinder
Morgan Management, LLC. Interested parties would be able to view the materials
presented at the conference by visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/investor/presentations.
Current report dated January 23, 2004 on Form 8-K was furnished on January
23, 2004, 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 on
January 23, 2004, at the Kinder Morgan 2004 Analyst Conference to address the
fiscal year 2003 results, the fiscal year 2004 outlook and other business
information about us, Kinder Morgan, Inc. and Kinder Morgan Management, LLC.
Interested parties would be able to view the materials presented at the
conference by visiting Kinder Morgan, Inc.'s website at:
http://www.kindermorgan.com/ investor/presentations. Interested parties would
also have access to the presentations by audio webcast, both live and on-demand.
The live presentation could be accessed at:
http://www.videonewswire.com/event.asp?id=19868. The conference began at 8:00
a.m. C.S.T. on January 23, 2004, and will be archived for 90 days on Kinder
Morgan, Inc.'s website at: http://www.kindermorgan.com.
Current report dated January 21, 2004 on Form 8-K was furnished on January
29, 2004, pursuant to Items 7 and 12 of that form. In Item 12, we provided
notice that on January 21, 2004, we issued a press release regarding our
financial results for the quarter and year ended December 31, 2003 and held a
webcast conference call on January 21, 2004 discussing those results. A copy of
the earnings press release and an unedited transcript of the webcast conference
call, prepared by an outside vendor, were filed pursuant to Item 7 as exhibits.
90
INDEX TO FINANCIAL STATEMENTS
Page
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Auditors........................................ 92
Consolidated Statements of Income for the years ended
December 31, 2003, 2002, and 2001..................................... 93
Consolidated Statements of Comprehensive Income for the
years ended December 31, 2003, 2002, and 2001......................... 94
Consolidated Balance Sheets as of December 31, 2003 and 2002.......... 95
Consolidated Statements of Cash Flows for the years
ended December 31, 2003, 2002, and 2001.............................. 96
Consolidated Statements of Partners' Capital for the
years ended December 31, 2003, 2002, and 2001......................... 97
Notes to Consolidated Financial Statements............................ 98
91
Report of Independent Auditors
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, 2003 and 2002, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2003 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 4 to the consolidated financial statements, the Partnership
changed its method of accounting for asset retirement obligations effective
January 1, 2003.
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.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 3, 2004
92
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
--------------------------------------
2003 2002 2001
---------- ---------- ----------
(In thousands except per unit amounts)
Revenues
Natural gas sales..................................... $4,889,235 $2,740,518 $1,627,037
Services.............................................. 1,377,745 1,272,640 1,161,643
Product sales and other............................... 357,342 223,899 157,996
---------- ---------- ----------
6,624,322 4,237,057 2,946,676
---------- ---------- ----------
Costs and Expenses
Gas purchases and other costs of sales................ 4,880,118 2,704,295 1,657,689
Operations and maintenance............................ 397,723 376,479 352,407
Fuel and power........................................ 108,112 86,413 73,188
Depreciation and amortization......................... 219,032 172,041 142,077
General and administrative............................ 150,435 122,205 113,540
Taxes, other than income taxes........................ 62,213 51,326 43,947
---------- ---------- ----------
5,817,633 3,512,759 2,382,848
---------- ---------- ----------
Operating Income........................................ 806,689 724,298 563,828
Other Income (Expense)
Earnings from equity investments...................... 92,199 89,258 84,834
Amortization of excess cost of
equity investments.................................. (5,575) (5,575) (9,011)
Interest, net......................................... (181,357) (176,460) (171,457)
Other, net............................................ 7,601 1,698 1,962
Minority Interest....................................... (9,054) (9,559) (11,440)
---------- ---------- ----------
Income Before Income Taxes and Cumulative
Effect of a Change in Accounting Principle............ 710,503 623,660 458,716
Income Taxes............................................ 16,631 15,283 16,373
---------- ---------- ----------
Income Before Cumulative Effect of a Change
in Accounting Principle................................. 693,872 608,377 442,343
Cumulative effect adjustment from change
in accounting for asset retirement
obligations........................................... 3,465 - -
---------- ---------- ----------
Net Income.............................................. $ 697,337 $ 608,377 $ 442,343
========== ========== ==========
Calculation of Limited Partners'
Interest in Net Income:
Income Before Cumulative Effect of a
Change in Accounting Principle........................ $ 693,872 $ 608,377 $ 442,343
Less: General Partner's interest........................ (326,489) (270,816) (202,095)
---------- ---------- ----------
Limited Partners' interest.............................. 367,383 337,561 240,248
Add: Limited Partners' interest in
Change in Accounting Principle........................ 3,430 - -
---------- ---------- ----------
Limited Partners' interest in Net Income................ $ 370,813 $ 337,561 $ 240,248
========== ========== ==========
Basic and Diluted Limited Partners'
Net Income per Unit:
Income Before Cumulative Effect of a
Change in Accounting Principle........................ $ 1.98 $ 1.96 $ 1.56
Cumulative effect adjustment from change
in accounting for asset retirement obligations........ 0.02 - -
----------- ---------- ----------
Net Income.............................................. $ 2.00 $ 1.96 $ 1.56
=========== ========== ==========
Weighted average number of units used in
computation of Limited Partners' Net
Income per Unit:
Basic................................................... 185,384 172,017 153,901
========== ========== ==========
Diluted................................................. 185,494 172,186 154,110
========== ========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
93
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
----------------------------------
2003 2002 2001
--------- --------- ---------
(In thousands)
Net Income.......................................... $ 697,337 $ 608,377 $ 442,343
Cumulative effect transition adjustment............. -- -- (22,797)
Change in fair value of derivatives
used for hedging purposes......................... (192,618) (116,560) 35,162
Reclassification of change in fair
value of derivatives to net income................ 82,065 7,477 51,461
--------- --------- ---------
Comprehensive Income................................ $ 586,784 $ 499,294 $ 506,169
========= ========= =========
The accompanying notes are an integral part of
these consolidated financial statements.
94
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
-----------------------
2003 2002
---------- ----------
ASSETS (Dollars in thousands)
Current Assets
Cash and cash equivalents......................... $ 23,329 $ 41,088
Accounts and notes receivable
Trade.......................................... 562,974 457,583
Related parties................................ 27,587 17,907
Inventories
Products....................................... 7,214 4,722
Materials and supplies......................... 10,783 7,094
Gas imbalances
Trade.......................................... 36,449 21,595
Related parties................................ 9,084 3,893
Gas in underground storage........................ 8,160 11,029
Other current assets.............................. 19,942 104,479
---------- ----------
705,522 669,390
Property, Plant and Equipment, net.................. 7,091,558 6,244,242
Investments......................................... 404,345 451,374
Notes receivable.................................... 2,422 3,823
Goodwill............................................ 729,510 716,610
Other intangibles, net.............................. 13,202 17,324
Deferred charges and other assets................... 192,623 250,813
---------- ----------
Total Assets........................................ $9,139,182 $8,353,576
========== ==========
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Trade.......................................... $ 477,783 $ 373,368
Related parties................................ - 43,742
Current portion of long-term debt................. 2,248 -
Accrued interest.................................. 52,356 52,500
Deferred revenues................................. 10,752 4,914
Gas imbalances.................................... 49,912 40,092
Accrued other liabilities......................... 211,328 298,711
---------- ----------
804,379 813,327
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding.................................... 4,316,678 3,659,533
Market value of interest rate swaps............ 121,464 166,956
---------- ----------
4,438,142 3,826,489
Deferred revenues................................. 20,975 25,740
Deferred income taxes............................. 38,106 30,262
Asset retirement obligations...................... 34,898 -
Other long-term liabilities and deferred credits.. 251,691 199,796
---------- ----------
4,783,812 4,082,287
Commitments and Contingencies (Notes 13 and 16)
Minority Interest................................... 40,064 42,033
---------- ----------
Partners' Capital
Common Units (134,729,258 and 129,943,218
units issued and outstanding as of
December 31, 2003 and 2002,
respectively)................................... 1,946,116 1,844,553
Class B Units (5,313,400 and 5,313,400
units issued and outstanding as of
December 31, 2003 and 2002,
respectively)................................... 120,582 123,635
i-Units (48,996,465 and 45,654,048
units issued and outstanding as
of December 31, 2003 and 2002,
respectively)................................... 1,515,659 1,420,898
General Partner................................... 84,380 72,100
Accumulated other comprehensive loss.............. (155,810) (45,257)
---------- ----------
3,510,927 3,415,929
---------- ----------
Total Liabilities and Partners' Capital............. $9,139,182 $8,353,576
========== ==========
The accompanying notes are an integral part of
these consolidated financial statements.
95
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
--------------------------------------
2003 2002 2001
----------- ----------- -----------
(In thousands)
Cash Flows From Operating Activities
Net income................................................................ $ 697,337 $ 608,377 $ 442,343
Adjustments to reconcile net income to net cash provided by operating
activities:
Cumulative effect adj. from change in accounting for asset retirement
obligations........................................................... (3,465) -- --
Depreciation, depletion and amortization................................ 219,032 172,041 142,077
Amortization of excess cost of equity investments....................... 5,575 5,575 9,011
Earnings from equity investments........................................ (92,199) (89,258) (84,834)
Distributions from equity investments..................................... 83,000 77,735 68,832
Changes in components of working capital:
Accounts receivable..................................................... (180,632) (177,240) 174,098
Other current assets.................................................... (1,858) (7,583) 22,033
Inventories............................................................. (2,945) (1,713) 22,535
Accounts payable........................................................ 92,702 288,712 (183,179)
Accrued liabilities..................................................... 9,740 26,132 (47,792)
Accrued taxes........................................................... (4,904) 2,379 8,679
FERC rate reparations and refunds......................................... (44,944) -- --
Other, net................................................................ (7,923) (35,462) 7,358
----------- ----------- -----------
Net Cash Provided by Operating Activities................................. 768,516 869,695 581,161
----------- ----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets.................................................... (349,867) (908,511) (1,523,454)
Additions to property, plant and equip. for expansion and maintenance
projects................................................................ (576,979) (542,235) (295,088)
Sale of investments, property, plant and equipment, net of removal costs.. 2,090 13,912 9,043
Acquisitions of investments............................................... (10,000) (1,785) --
Contributions to equity investments....................................... (14,052) (10,841) (2,797)
Other..................................................................... 5,747 (1,420) (6,597)
----------- ----------- -----------
Net Cash Used in Investing Activities..................................... (943,061) (1,450,880) (1,818,893)
----------- ----------- -----------
Cash Flows From Financing Activities
Issuance of debt.......................................................... 4,674,605 3,803,414 4,053,734
Payment of debt........................................................... (4,014,296) (2,985,322) (3,324,161)
Loans to related party.................................................... -- -- (17,100)
Debt issue costs.......................................................... (5,204) (17,006) (8,008)
Proceeds from issuance of common units.................................... 175,567 1,586 4,113
Proceeds from issuance of i-units......................................... -- 331,159 996,869
Contributions from General Partner........................................ 4,181 3,353 11,716
Distributions to partners:
Common units............................................................ (340,927) (306,590) (268,644)
Class B units........................................................... (13,682) (12,540) (8,501)
General Partner......................................................... (314,244) (253,344) (181,198)
Minority interest....................................................... (10,445) (9,668) (14,827)
Other, net................................................................ 1,231 4,429 (2,778)
----------- ----------- -----------
Net Cash Provided by Financing Activities................................. 156,786 559,471 1,241,215
----------- ----------- -----------
Increase (Decrease) in Cash and Cash Equivalents.......................... (17,759) (21,714) 3,483
Cash and Cash Equivalents, beginning of period............................ 41,088 62,802 59,319
----------- ----------- -----------
Cash and Cash Equivalents, end of period.................................. $ 23,329 $ 41,088 $ 62,802
=========== =========== ===========
Noncash Investing and Financing Activities:
Assets acquired by the issuance of units................................ $ 2,000 $ -- $ --
Assets acquired by the assumption of liabilities........................ 36,187 213,861 293,871
Supplemental disclosures of cash flow information:
Cash paid (received) during the year for
Interest (net of capitalized interest).................................. 183,908 161,840 165,357
Income taxes............................................................ (261) 1,464 2,168
The accompanying notes are an integral part of
these consolidated financial statements.
96
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
2003 2002 2001
------------------------- ------------------------ --------------------------
Units Amount Units Amount Units Amount
----------- ----------- ----------- ----------- ----------- -----------
(Dollars in thousands)
Common Units:
Beginning Balance.................. 129,943,218 $ 1,844,553 129,855,018 $ 1,894,677 129,716,218 $ 1,957,357
Net income......................... -- 265,423 -- 254,934 -- 203,559
Units issued as consideration in the
acquisition of assets............ 51,490 2,000 -- -- -- --
Units issued for cash.............. 4,734,550 175,067 88,200 1,532 138,800 2,405
Distributions...................... -- (340,927) -- (306,590) -- (268,644)
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance..................... 134,729,258 1,946,116 129,943,218 1,844,553 129,855,018 1,894,677
Class B Units:
Beginning Balance.................. 5,313,400 123,635 5,313,400 125,750 5,313,400 125,961
Net income......................... -- 10,629 -- 10,427 -- 8,335
Units issued for cash.............. -- -- -- (2) -- (44)
Distributions...................... -- (13,682) -- (12,540) -- (8,502)
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance..................... 5,313,400 120,582 5,313,400 123,635 5,313,400 125,750
i-Units:
Beginning Balance.................. 45,654,048 1,420,898 30,636,363 1,020,153 -- --
Net income......................... -- 94,761 -- 72,200 -- 28,354
Units issued for cash.............. -- -- 12,478,900 328,545 29,750,000 991,799
Distributions...................... 3,342,417 -- 2,538,785 -- 886,363 --
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance..................... 48,996,465 1,515,659 45,654,048 1,420,898 30,636,363 1,020,153
General Partner:
Beginning Balance.................. -- 72,100 -- 54,628 -- 33,749
Net income......................... -- 326,524 -- 270,816 -- 202,095
Units issued for cash.............. -- -- -- -- -- (18)
Distributions...................... -- (314,244) -- (253,344) -- (181,198)
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance..................... -- 84,380 -- 72,100 -- 54,628
Accumulated other comprehensive income:
Beginning Balance.................. -- (45,257) -- 63,826 -- --
Cumulative effect transition adj... -- -- -- -- -- (22,797)
Change in fair value of derivatives
used for hedging purposes........ -- (192,618) -- (116,560) -- 35,162
Reclassification of change in fair
value of derivatives to net
Income........................... -- 82,065 -- 7,477 -- 51,461
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance..................... -- (155,810) -- (45,257) -- 63,826
Total Partners' Capital.............. 189,039,123 $ 3,510,927 180,910,666 $ 3,415,929 165,804,781 $ 3,159,034
=========== =========== =========== =========== =========== ===========
The accompanying notes are an integral part of
these consolidated financial statements.
97
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
General
Kinder Morgan Energy Partners, L.P. is a Delaware limited partnership formed
in August 1992. Unless the context requires otherwise, references to "we," "us,"
"our" or the "Partnership" are intended to mean Kinder Morgan Energy Partners,
L.P. and its consolidated subsidiaries.
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 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. 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; 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 35,000 miles of natural gas and products
pipelines and approximately 80 terminals. At December 31, 2003, KMI and its
consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 19.0% interest in us.
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
98
affairs, except that KMR cannot take certain specified actions without the
approval of our general partner. Under 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. As
of December 31, 2003, KMR owned approximately 25.9% of our outstanding limited
partner units (which are in the form of i-units that are issued only to KMR).
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 by management, 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. These estimates and assumptions affect
the amounts we report for assets and liabilities and our disclosure of
contingent assets and liabilities at the date of the financial statements.
Therefore, the reported amounts of our assets and liabilities 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.
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, 2003, 2002 and 2001.
99
Valuation and Qualifying Accounts
(in thousands)
Balance at Additions Additions Balance at
beginning of charged to costs charged to other end of
Allowance for Doubtful Accounts Period and expenses accounts(1) Deductions(2) period
------------ ---------------- ------------------ -------------- -------------
Year ended December 31, 2003.... $8,092 $1,448 $ - $ (757) $8,783
Year ended December 31, 2002.... $7,556 $ 822 $ 4 $ (290) $8,092
Year ended December 31, 2001.... $4,151 $3,641 $1,362 $(1,598) $7,556
- ----------
(1) Amount for 2002 represents the allowance recognized when we acquired IC
Terminal Holdings Company and Consolidated Subsidiaries. Amount for 2001
represents 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.
In addition, the balances of "Accrued other current liabilities" in our
accompanying consolidated balance sheets include amounts related to customer
prepayments of approximately $8.2 million as of December 31, 2003 and $38.7
million as of December 31, 2002.
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.
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 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 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. 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.
Our oil and gas producing 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. In
addition, we engage in enhanced recovery techniques in which CO2 is injected
into certain producing oil reservoirs. The acquisition cost of this CO2 for the
SACROC unit is capitalized as part of our development costs when it is injected.
When CO2 is recovered in conjunction with oil production, it is extracted and
re-injected, and all of the associated costs are expensed as incurred. 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 units-of-production rate is determined by field.
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.
100
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. 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.
Equity Method of Accounting
We account for investments greater than 20% in 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, and less distributions received.
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 months, goodwill must be tested for impairment annually or
as changes in circumstances require. 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 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. We
have selected an impairment measurement test date of January 1 of each year and
we have determined that our goodwill was not impaired as of January 1, 2004.
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 but not consolidated, we reported amortization of excess cost of
investments as amortization of excess cost of equity investments in our
accompanying consolidated statements of income.
101
Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was approximately $729.5 million as of December 31, 2003
and $716.6 million as of December 31, 2002. Such amounts are reported as
"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 $150.3 million as of December 31,
2003, and approximately $140.3 million as of December 31, 2002. Pursuant to SFAS
No. 142, this amount, referred to as equity method goodwill, should continue to
be recognized in accordance with Accounting Principles Board Opinion No. 18,
"The Equity Method of Accounting for Investments in Common Stock." Accordingly,
we included this amount within "Investments" on our accompanying consolidated
balance sheets. In addition, approximately $189.7 million and $195.3 million
at December 31 2003 and 2002, respectively, representing the excess of the fair
market value of property, plant and equipment over its book value at the date of
acquisition was being amortized over a weighted average life of approximately
34 years.
In addition to our annual impairment test of goodwill, 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 APB Opinion No. 18. The impairment test under APB No. 18
considers whether the fair value of the equity investment as a whole, not the
underlying net assets, has declined and whether that decline is other than
temporary. As of December 31, 2003, 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 capitalized in 2003, 2002 and 2001 was $5.3
million, $5.8 million and $3.1 million, respectively.
Unit-Based Compensation
SFAS No. 123, "Accounting for Stock-Based Compensation," as amended by SFAS
No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure,"
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 APB 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. No compensation expense has been
recorded since the options were granted at exercise prices equal to the market
prices at the date of grant. 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. 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
102
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
canreasonably 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 potential
environmental issues that could impact our assets or operations, we recognized a
$0.3 million reduction in environmental expense and in our overall accrued
environmental liability, and we included this amount within "Other, net" in our
accompanying Consolidated Statement of Income for 2002. The $0.3 million income
item resulted from 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 from a $15.7 million loss in
our Products Pipelines business segment and a $16.0 million gain in our
Terminals business segment. For more information on our environmental
disclosures, see Note 16.
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. For more information on our legal disclosures, see Note 16.
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
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.
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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 either settled in cash or made up in-kind subject to
the pipelines' various terms.
Minority Interest
As of December 31, 2003, 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 33 1/3% interest in International Marine Terminals, a Louisiana
partnership owned 66 2/3% and controlled by Kinder Morgan Operating L.P.
"C"; and
o the approximate 31% interest in the Pecos Carbon Dioxide Company, a Texas
general partnership owned approximately 69% and controlled by Kinder Morgan
CO2 Company, L.P. and its consolidated subsidiaries.
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 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, 2003, 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.
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.
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Asset Retirement Obligations
As of January 1, 2003, we account for asset retirement obligations pursuant
to SFAS No. 143, "Accounting for Asset Retirement Obligations." For more
information on our asset retirement obligations, see Note 4.
Two-for-one Common Unit Split
On July 18, 2001, KMR, the delegate of our general partner, approved a
two-for-one 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 of 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 this
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 debt obligations.
Our derivatives are accounted for under 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 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 2001, 2002 and 2003, we completed or made adjustments for 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
preliminary allocation of assets and liabilities may be adjusted to reflect the
final determined amounts during a short period of time following the
acquisition. The results of operations from these acquisitions are included in
our consolidated financial statements from the acquisition date.
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Allocation of Purchase Price
-------------------------------------------------------------------
(in millions)
-------------------------------------------------------------------
Property Deferred
Purchase Current Plant & Charges Minority
Ref. Date Acquisition Price Assets Equipment & Other Goodwill Interest
----- ------ ------------------------------------------ ---------- -------- ---------- -------- -------- --------
(1) 1/01 GATX Domestic Pipelines and Terminals..... $1,233.4 $ 32.3 $928.7 $ 4.8 $267.6 -
(2) 3/01 Pinney Dock & Transport LLC............... 51.7 2.0 32.4 0.5 16.8 -
(3) 7/01 Bulk Terminals from Vopak................. 44.3 - 44.3 - - -
(4) 7/01 Kinder Morgan Texas Pipeline.............. 326.1 - 326.1 - - -
(5) 8/01 The Boswell Oil Company................... 22.4 1.6 13.9 - 6.9 -
(6) 11/01 Liquid Terminals from Stolt-Nielsen....... 70.8 - 70.7 - 0.1 -
(7) 11/01 Interests in Snyder and Diamond M Plants.. 20.9 - 20.9 - - -
(8) 1/02 Kinder Morgan Materials Services LLC...... 12.2 0.9 11.3 - - -
(9) 1/02 66 2/3% Interest in Intl. MarineTerminals. 40.5 6.6 31.8 0.1 - 2.0
(10) 1/02 Kinder Morgan Tejas....................... 881.5 56.5 674.1 - 150.9 -
(11) 5/02 Milwaukee Bagging Operations.............. 8.5 0.1 3.1 - 5.3 -
(12) 5/02 Trailblazer Pipeline Company.............. 80.1 - 41.7 - 15.0 23.4
(13) 9/02 Owensboro Gateway Terminal................ 7.7 0.0 4.3 0.1 3.3 -
(14) 9/02 IC Terminal Holdings Company.............. 17.7 0.1 14.3 3.3 - -
(15) 1/03 Bulk Terminals from M.J. Rudolph.......... 31.3 0.1 18.2 0.1 12.9 -
(16) 6/03 MKM Partners, L.P......................... 25.2 - 25.2 - - -
(17) 8/03 Red Cedar Gathering Company............... 10.0 - - 10.0 - -
(18) 10/03 Shell Products Terminals.................. 20.0 - 20.0 - - -
(19) 11/03 Yates Field Unit and Carbon Dioxide Assets 259.0 3.5 255.8 - - (0.3)
(20) 11/03 MidTex Gas Storage Company, LLP........... 17.5 - 11.9 - - 5.6
(21) 12/03 ConocoPhillips Products Terminals......... 15.1 - 15.1 - - -
(22) 12/03 Tampa, Florida Bulk Terminals............. $ 29.5 $- $ 29.5 $- $- $-
(1) 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.
After the acquisitions, Kinder Morgan Liquids Terminals LLC's assets included
12 terminals, located across the United States, with storage capacity of
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.
(2) Pinney Dock & Transport LLC
Effective March 1, 2001, we acquired all of the equity interests in Pinney
Dock & Transport LLC, formerly Pinney Dock & Transport Company, for
approximately $51.7 million. The acquisition included 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
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assumed liabilities. The $16.8 million of goodwill was assigned to our Terminals
business segment and the entire amount is expected to be deductible for tax
purposes.
(3) 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.
(4) 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 from a third-party
under an operating lease 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 were released from lease payments of $40 million
annually from 2002 through 2005 and $30 million annually from 2006 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.
(5) 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. 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.
(6) 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. 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.
(7) 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
107
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 business segment.
(8) Kinder Morgan Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of Kinder
Morgan Materials Services LLC for an aggregate consideration of $12.2 million,
consisting of approximately $8.9 million in cash 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.
(9) 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 eight 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.
(10) 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 expanded 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 combination of these
systems is part of our Texas intrastate natural gas pipeline group. Our
allocation to assets acquired and liabilities assumed was based on an appraisal
of fair market values. 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.
(11) 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 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. 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.
(12) 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 an
aggregate consideration of $80.1 million. We now own 100% of Trailblazer
Pipeline Company. In May 2002, we paid $68 million to an affiliate of Enron
Corp., and during the first quarter of 2002, we paid $12.1 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.
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Trailblazer Pipeline Company has a current certificated capacity of 846 million
cubic feet per day of natural gas. 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.
(13) Owensboro Gateway Terminal
Effective September 1, 2002, we acquired the Lanham River Terminal near
Owensboro, Kentucky and related equipment for $7.7 million. In September 2002,
we paid approximately $7.2 million and established a $0.5 million purchase price
retention liability to be paid at the later of: (i) one year following the
acquisition, or (ii) the day we received consent to the assignment of a contract
between the seller and the New York Mercantile Exchange, Inc. We paid the $0.5
million liability in September 2003. 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. We
refer to the acquired terminal as our Owensboro Gateway Terminal and we include
its operations in our Terminals business segment. 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.
(14) 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 $17.7 million, consisting of $17.4 million in cash and the
assumption of $0.3 million in liabilities. The total purchase price decreased
$0.2 million in the third quarter of 2003 primarily due to adjustments in the
amount of working capital items assumed on the acquisition date. The acquisition
included the former ICOM marine terminal in St. Gabriel, Louisiana. The St.
Gabriel facility has 400,000 barrels of liquids storage capacity and a related
pipeline network. The acquisition further expanded our terminal businesses along
the Mississippi River. The acquired terminal is referred to as the Kinder Morgan
St. Gabriel terminal, and we include its operations in our Terminals business
segment.
(15) Bulk Terminals from M.J. Rudolph
Effective January 1, 2003, we acquired long-term lease contracts from New
York-based M.J. Rudolph Corporation to operate four bulk terminal facilities at
major ports along the East Coast and in the southeastern United States. The
acquisition also included the purchase of certain assets that provide
stevedoring services at these locations. The aggregate cost of the acquisition
was approximately $31.3 million. On December 31, 2002, we paid $29.9 million for
the Rudolph acquisition and this amount was included with "Other current assets"
on our accompanying consolidated balance sheet. In the first quarter of 2003, we
paid the remaining $1.4 million and we allocated our aggregate purchase price to
the appropriate asset and liability accounts. 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 expanded our growing Terminals
business segment and complements certain of our existing terminal facilities. In
our final analysis, it was considered reasonable to allocate a portion of our
purchase price to goodwill given the substance of this transaction, including
expected benefits from integrating this acquisition with our existing assets,
and we include its operations in our Terminals business segment. The $12.9
million of goodwill was assigned to our Terminals business segment and the
entire amount is expected to be deductible for tax purposes.
(16) MKM Partners, L.P.
Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership
interest in the SACROC unit for an aggregate consideration of $25.2 million,
consisting of $23.3 million in cash and the assumption of $1.9 million of
liabilities. The SACROC unit is one of the largest and oldest oil fields in the
United States using carbon dioxide flooding technology. This transaction
increased our ownership interest in the SACROC unit to approximately 97%.
109
On June 20, 2003, we signed an agreement with subsidiaries of Marathon Oil
Corporation to dissolve MKM Partners, L.P., a joint venture we formed on January
1, 2001 with subsidiaries of Marathon Oil Company. The joint venture assets
consisted of a 12.75% interest in the SACROC oil field unit and a 49.9% interest
in the Yates Fieldunit, both of which are in the Permian Basin of West Texas.
The MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and
15% by Kinder Morgan CO2 Company, L.P. It was dissolved effective June 30, 2003,
and the net assets were distributed to partners in accordance with its
partnership agreement.
(17) Red Cedar Gas Gathering Company
Effective August 1, 2003, we acquired reversionary interests in the Red Cedar
Gas Gathering Company held by the Southern Ute Indian Tribe. Our purchase price
was $10.0 million. The 4% reversionary interests were scheduled to take effect
September 1, 2004 and September 1, 2009. With the elimination of these
reversions, our ownership interest in Red Cedar will be maintained at 49% in the
future.
(18) Shell Products Terminals
Effective October 1, 2003, we acquired five refined petroleum products
terminals in the western United States for approximately $20.0 million from
Shell Oil Products U.S. We plan to invest an additional $8.0 million in the
facilities. The terminals are located in Colton and Mission Valley, California;
Phoenix and Tucson, Arizona; and Reno, Nevada. Combined, the terminals have 28
storage tanks with total capacity of approximately 700,000 barrels for gasoline,
diesel fuel and jet fuel. As part of the transaction, Shell has entered into a
long-term contract to store products in the terminals. The acquisition enhances
our Pacific operations and complements our existing West Coast Terminals. The
acquired operations are included as part of our Pacific operations and our
Products Pipelines business segment.
(19) Yates Field Unit and Carbon Dioxide Assets
Effective November 1, 2003, we acquired certain assets in the Permian Basin
of West Texas from a subsidiary of Marathon Oil Corporation. Our purchase price
was approximately $259.0 million, consisting of $231.0 million in cash and the
assumption of $28.0 million of liabilities. The assets acquired consisted of the
following:
o Marathon's approximate 42.5% interest in the Yates oil field unit. We
previously owned a 7.5% ownership interest in the Yates field unit and we
now operate the field;
o Marathon's 100% interest in the crude oil gathering system surrounding the
Yates field; and
o Marathon Carbon Dioxide Transportation Company. Marathon Carbon Dioxide
Transportation Company owns a 65% ownership interest in the Pecos Carbon
Dioxide Pipeline Company, which owns a 25-mile carbon dioxide pipeline.
We previously owned a 4.27% ownership interest in the Pecos Carbon Dioxide
Pipeline Company and accounted for this investment under the cost method of
accounting. After the acquisition of our additional 65% interest in Pecos, its
financial results were included in our consolidated results and we recognized
the appropriate minority interest. The acquisition complemented our existing
carbon dioxide assets in the Permian Basin, increased our working interest in
the Yates field to nearly 50% and allowed us to become the operator of the
field. The acquired operations are included as part of our CO2 business segment.
Our allocation of the purchase price to assets acquired, liabilities assumed and
minority interest is preliminary, pending final purchase price adjustments that
we expect to make in the first quarter of 2004.
(20) MidTex Gas Storage Company, LLP
Effective November 1, 2003, we acquired the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP from an affiliate of
NiSource Inc. Our combined purchase price was approximately $17.5 million,
including the assumption of $1.7 million of debt. The debt represented a MidTex
note payable that was to be paid by the former partner. We now own 100% of
MidTex Gas Storage Company, LLP. MidTex Gas Storage Company, LLP is a Texas
limited liability partnership that owns two salt dome natural gas storage
facilities located
110
in Matagorda County, Texas. The acquisition eliminated the third-party interest
in the operations of MidTex. MidTex's operations are included as part of our
Natural Gas Pipelines business segment. Our allocation of the purchase price to
assets acquired, liabilities assumed and minority interest is preliminary,
pending final purchase price adjustments that we expect to make in the first
quarter of 2004.
(21) ConocoPhillips Products Terminals
Effective December 11, 2003, we acquired seven refined petroleum products
terminals in the southeastern United States from ConocoPhillips Company and
Phillips Pipe Line Company. Our purchase price was approximately $15.1 million,
consisting of approximately $14.1 million in cash and $1.0 million in assumed
liabilities. The terminals are located in Charlotte and Selma, North Carolina;
Augusta and Spartanburg, South Carolina; Albany and Doraville, Georgia; and
Birmingham, Alabama. We will fully own and operate all of the terminals except
for the Doraville, Georgia facility, which is operated and owned 70% by Citgo.
We plan to invest an additional $1.3 million in the facilities. Combined, the
terminals have 35 storage tanks with total capacity of approximately 1.15
million barrels for gasoline, diesel fuel and jet fuel. As part of the
transaction, ConocoPhillips entered into a long-term contract to use the
terminals. The acquisition broadens our refined petroleum products operations in
the southeastern United States as three of the terminals are connected to the
Plantation pipeline system, which is operated and owned 51% by us. The acquired
operations are included as part of our Products Pipelines business segment. Our
allocation of the purchase price to assets acquired and liabilities assumed is
preliminary, pending final purchase price adjustments that we expect to make in
the first quarter of 2004.
(22) Tampa, Florida Bulk Terminals
In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.5 million, consisting of
$26.0 million in cash (including closing and related costs of approximately $1.1
million) and $3.5 million in assumed liabilities. We plan to invest an
additional $16.9 million in the facilities. The principal purchased asset was a
marine terminal acquired from a subsidiary of IMC Global, Inc. We also entered
into a long-term agreement with IMC to enable it to be the primary user of the
facility, which we will operate and refer to as the Kinder Morgan Tampaplex
terminal. The terminal sits on a 114-acre site, and serves as a storage and
receipt point for imported ammonia, as well as an export location for dry bulk
products, including fertilizer and animal feed. We closed on the Tampaplex
portion of this transaction on December 23, 2003. The second facility includes
assets from the former Nitram, Inc. bulk terminal, which we plan to use as an
inland bulk storage warehouse facility for overflow cargoes from our Port Sutton
import terminal. We closed on the Nitram portion of this transaction on December
10, 2003. The acquired operations are included as part of our Terminals business
segment and complement our existing business in the Tampa area by generating
additional fee-based income. Our allocation of the purchase price to assets
acquired and liabilities assumed is preliminary, pending final purchase price
adjustments that we expect to make in the first quarter of 2004.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the years ended December 31, 2003 and 2002, assumes that all of
the 2003 and 2002 acquisitions and joint ventures we have made since January 1,
2002, including the ones listed above, had occurred as of January 1, 2002. 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 2003 and 2002
acquisitions and joint ventures as of January 1, 2002 or the results that will
be attained in the future. Amounts presented below are in thousands, except for
the per unit amounts:
Pro Forma Year Ended
December 31,
2003 2002
------------ ------------
(Unaudited)
Revenues................................................ $ 6,709,834 $ 4,608,979
Operating Income........................................ 857,762 802,373
Income Before Cumulative Effect of a Change in
Accounting Principle................................... 736,598 673,766
Net Income.............................................. $ 740,063 $ 673,766
Basic and Diluted Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a
Change in Accounting Principle..................... $ 2.21 $ 2.19
Net Income............................................ $ 2.23 $ 2.19
111
4. Change in Accounting for Asset Retirement Obligations
In August 2001, the Financial Accounting Standards Board issued SFAS No. 143,
"Accounting for Asset Retirement Obligations." SFAS No. 143 provides accounting
and reporting guidance for legal obligations associated with the retirement of
long-lived assets that result from the acquisition, construction or normal
operation of a long-lived asset. The provisions of this Statement are effective
for fiscal years beginning after June 15, 2002. We adopted SFAS No. 143 on
January 1, 2003.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. Its primary impact on
us will be to change the method of accruing for oil production site restoration
costs related to our CO2 business segment. Prior to January 1, 2003, we
accounted for asset retirement obligations in accordance with SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies." Under
SFAS No. 143, the fair value of asset retirement obligations are recorded as
liabilities on a discounted basis when they are incurred, which is typically at
the time the assets are installed or acquired. Amounts recorded for the related
assets are increased by the amount of these obligations. Over time, the
liabilities will be accreted for the change in their present value and the
initial capitalized costs will be depreciated over the useful lives of the
related assets. The liabilities are eventually extinguished when the asset is
taken out of service. Specifically, upon adoption of this Statement, an entity
must recognize the following items in its balance sheet:
o a liability for any existing asset retirement obligations adjusted for
cumulative accretion to the date of adoption;
o an asset retirement cost capitalized as an increase to the carrying amount
of the associated long-lived asset; and
o accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement are measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost is measured as of the date the
asset retirement obligation was incurred. Cumulative accretion and accumulated
depreciation are measured for the time period from the date the liability would
have been recognized had the provisions of this Statement been in effect to the
date of adoption of this Statement.
The cumulative effect adjustment for this change in accounting principle
resulted in income of $3.5 million in the first quarter of 2003. Furthermore, as
required by SFAS No. 143, we recognized the cumulative effect of initially
applying SFAS No. 143 as a change in accounting principle as described in
Accounting Principles Board Opinion 20, "Accounting Changes." The cumulative
effect adjustment resulted from the difference between the amounts recognized in
our consolidated balance sheet prior to the application of SFAS No. 143 and the
net amount recognized in our consolidated balance sheet pursuant to SFAS No.
143.
In our CO2 business segment, we are required to plug and abandon oil wells
that have been removed from service and to remove our surface wellhead equipment
and compressors. As of December 31, 2003, we have recognized asset retirement
obligations in the aggregate amount of $32.7 million relating to these
requirements at existing sites within our CO2 segment.
In our Natural Gas Pipelines business segment, if we were to cease providing
utility services, we would be required to remove surface facilities from land
belonging to our customers and others. Our Texas intrastate natural gas pipeline
group has various condensate drip tanks and separators located throughout its
natural gas pipeline systems, as well as inactive gas processing plants,
laterals and gathering systems which are no longer integral to the overall
mainline transmission systems, and asbestos-coated underground pipe which is
being abandoned and retired. Our Kinder Morgan Interstate Gas Transmission
system has compressor stations which are no longer active and other
miscellaneous facilities, all of which have been officially abandoned. We
believe we can reasonably estimate both the time and costs associated with the
retirement of these facilities. As of December 31, 2003, we have recognized
asset retirement obligations in the aggregate amount of $3.0 million relating to
the businesses within our Natural Gas Pipelines segment.
We have included $0.8 million of our total $35.7 million asset retirement
obligations as of December 31, 2003 with "Accrued other current liabilities" in
our accompanying consolidated balance sheet. The remaining $34.9
112
million obligation is reported separately as a non-current liability. No assets
are legally restricted for purposes of settling our asset retirement
obligations. A reconciliation of the beginning and ending aggregate carrying
amount of our asset retirement obligations for the twelve months ended December
31, 2003 is as follows (in thousands):
Balance as of December 31, 2002............ $ -
Initial ARO balance upon adoption.......... 14,125
Liabilities incurred....................... 12,911
Liabilities settled........................ (1,056)
Accretion expense.......................... 1,028
Revisions in estimated cash flows.......... 8,700
-----------
Balance as of December 31, 2003............ $ 35,708
===========
Pro Forma Information
Had the provisions of SFAS No. 143 been in effect prior to January 1, 2003,
our net income and associated per unit amounts, and the amount of our liability
for asset retirement obligations, would have been as follows (in thousands,
except per unit amounts):
Pro Forma Year Ended
December 31,
-------------------------------------
2003 2002 2001
----------- ----------- -----------
(Unaudited)
Reported income before cumulative effect of a change in
accounting principle................................... $ 693,872 $ 608,377 $ 442,343
Adjustments from change in accounting for asset
retirement obligations................................. -- (1,161) (980)
----------- ----------- -----------
Adjusted income before cumulative effect of a change in
accounting principle................................... $ 693,872 $ 607,216 $ 441,363
=========== =========== ===========
Reported income before cumulative effect of a change in
accounting principle per unit (fully diluted).......... $ 1.98 $ 1.96 $ 1.56
=========== =========== ===========
Adjusted income before cumulative effect of a change in
accounting principle per unit (fully diluted).......... $ 1.98 $ 1.95 $ 1.55
=========== =========== ===========
Dec. 31, Dec. 31,
2002 2001
------- -------
Liability for asset retirement obligations............. $14,125 $14,345
======= =======
5. Income Taxes
Components of the income tax provision applicable to continuing operations
for federal, foreign and state taxes are as follows (in thousands):
Year Ended December 31,
-------------------------------
2003 2002 2001
-------- -------- --------
Taxes currently payable:
Federal.............. $ 437 $ 15,855 $ 9,058
State................ 1,131 3,116 1,192
Foreign.............. 25 147 -
-------- -------- --------
Total................ 1,593 19,118 10,250
Taxes deferred:
Federal.............. 11,650 (3,280) 5,366
State................ 1,939 (555) 757
Foreign.............. 1,449 - -
-------- -------- --------
Total................ 15,038 (3,835) 6,123
-------- -------- --------
Total tax provision.... $ 16,631 $ 15,283 $ 16,373
======== ======== ========
Effective tax rate..... 2.3% 2.4% 3.5%
The difference between the statutory federal income tax rate and our
effective income tax rate is summarized as follows:
113
Year Ended December 31,
2003 2002 2001
--------- --------- -------
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.......... 0.5% 0.6% 1.3%
Income tax expense attributable to corporate equity 1.5% 1.6% 1.8%
earnings................................................
Income tax expense attributable to foreign corporate 0.2% - -
earnings................................................
State taxes........................................... 0.1% 0.2% 0.4%
-------- -------- --------
Effective tax rate...................................... 2.3% 2.4% 3.5%
======== ======== ========
Deferred tax assets and liabilities result from the following (in thousands):
December 31,
-----------------
2003 2002
------- --------
Deferred tax assets:
Book accruals.................................... $ 1,424 $ 97
Net Operating Loss/Alternative minimum tax credits 10,797 3,556
------- --------
Total deferred tax assets.......................... 12,221 3,653
Deferred tax liabilities:
Property, plant and equipment.................... 50,327 33,915
------- --------
Total deferred tax liabilities..................... 50,327 33,915
------- --------
Net deferred tax liabilities....................... $38,106 $ 30,262
======= ========
We had available, at December 31, 2003, approximately $0.3 million of
alternative minimum tax credit carryforwards, which are available indefinitely,
and $10.5 million of net operating loss carryforwards, which will expire between
the years 2004 and 2023. 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,
2003 2002
Natural gas, liquids and carbon dioxide pipelines........... $ 3,458,736 $ 2,544,987
Natural gas, liquids and carbon dioxide pipeline
station equipment.......................................... 2,908,273 2,801,729
Coal and bulk tonnage transfer, storage and services........ 359,088 281,713
Natural gas and transmix processing......................... 100,778 98,094
Other....................................................... 330,982 292,881
Accumulated depreciation and depletion...................... (641,914) (452,408)
----------- -----------
6,515,943 5,566,996
Land and land right-of-way.................................. 339,579 340,507
Construction work in process................................ 236,036 336,739
----------- -----------
$ 7,091,558 $ 6,244,242
=========== ===========
Depreciation and depletion expense charged against property, plant and
equipment consists of the following (in thousands):
2003 2002 2001
--------- --------- ------
Depreciation and depletion expense.. $ 217,401 $171,461 $126,641
7. Investments
Our significant equity investments at December 31, 2003 consisted of:
o Plantation Pipe Line Company (51%);
o Red Cedar Gathering Company (49%);
o Thunder Creek Gas Services, LLC (25%);
114
o Coyote Gas Treating, LLC (Coyote Gulch) (50%);
o Cortez Pipeline Company (50%); and
o Heartland Pipeline Company (50%).
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 a 15% ownership
interest in MKM Partners, L.P., a joint venture with Marathon Oil Company. The
MKM joint venture was owned 85% by subsidiaries of Marathon Oil Company and 15%
by Kinder Morgan CO2 Company, L.P. The joint venture assets consisted of a
12.75% interest in the SACROC oil field unit and a 49.9% interest in the Yates
field unit, both of which are in the Permian Basin of West Texas. We accounted
for our 15% investment in the joint venture under the equity method of
accounting because our ownership interest included 50% of the joint venture's
general partner interest, and the ownership of this general partner interest
gave us the ability to exercise significant influence over the operating and
financial policies of the joint venture. Effective June 1, 2003, we acquired the
MKM joint venture's 12.75% ownership interest in the SACROC unit for $23.3
million and the assumption of $1.9 million of liabilities. On June 20, 2003, we
signed an agreement with subsidiaries of Marathon Oil Corporation to dissolve
MKM Partners, L.P. The partnership's dissolution was effective June 30, 2003,
and the net assets were distributed to partners in accordance with its
partnership agreement. Our interests in the SACROC unit and the Yates field
unit, including the incremental interest acquired in November 2003, are
accounted for using the proportional method of consolidation for oil and gas
operations.
Finally, in September 2003, we paid $10.0 million to acquire reversionary
interests in the Red Cedar Gas Gathering Company. The 4% reversionary interests
were held by the Southern Ute Indian Tribe and were scheduled to take effect
September 1, 2004 and September 1, 2009. With the elimination of these
reversions, our ownership interest in Red Cedar will be maintained at 49% in the
future. For more information on our acquisitions, see Note 3.
Our total investments consisted of the following (in thousands):
December 31,
-------------------
2003 2002
-------- --------
Plantation Pipe Line Company..................... $219,349 $212,300
Red Cedar Gathering Company...................... 114,176 106,422
Thunder Creek Gas Services, LLC.................. 37,245 36,921
Coyote Gas Treating, LLC......................... 13,502 14,435
Cortez Pipeline Company.......................... 12,591 10,486
Heartland Pipeline Company....................... 5,109 5,459
MKM Partners, L.P................................ - 60,795
All Others....................................... 2,373 4,556
-------- --------
Total Equity Investments......................... $404,345 $451,374
======== ========
Our earnings from equity investments were as follows (in thousands):
115
Year Ended December 31,
-------------------------------
2003 2002 2001
-------- -------- --------
Plantation Pipe Line Company........ $ 27,983 $ 26,426 $ 25,314
Cortez Pipeline Company............. 32,198 28,154 25,694
Red Cedar Gathering Company......... 18,571 19,082 18,814
MKM Partners, L.P................... 5,000 8,174 8,304
Coyote Gas Treating, LLC............ 2,608 2,651 2,115
Thunder Creek Gas Services, LLC..... 2,833 2,154 1,629
Heartland Pipeline Company.......... 973 998 882
All Others.......................... 2,033 1,619 2,082
-------- -------- --------
Total............................... $ 92,199 $ 89,258 $ 84,834
======== ======== ========
Amortization of excess costs........ $ (5,575) $ (5,575) $ (9,011)
======== ======== ========
Summarized combined unaudited financial information for our significant
equity investments (listed above) is reported below (in thousands; amounts
represent 100% of investee financial information):
Year Ended December 31,
---------------------------------
Income Statement 2003 2002 2001
------------------------------- --------- --------- ---------
Revenues.......................................... $ 467,871 $ 505,602 $ 449,259
Costs and expenses................................. 295,931 309,291 280,100
--------- --------- ---------
Earnings before extraordinary items and
cumulative effect of a change in accounting
principle........................................ 171,940 196,311 169,159
========= ========= =========
Net income......................................... $ 168,167 $ 196,311 $ 169,159
========= ========= =========
December 31,
Balance Sheet 2003 2002
--------------------- ----------- --------
Current assets............ $ 93,709 $ 83,410
Non-current assets........ 684,754 1,101,057
Current liabilities....... 377,535 243,636
Non-current liabilities... 209,468 374,132
Partners'/owners' equity.. $ 191,460 $ 566,699
8. Intangibles
Under ABP No. 18, any premium paid by an investor, which is analogous to
goodwill, must be identified. Under prior rules, excess cost over underlying
fair value of net assets accounted for under the equity method, referred to as
equity method goodwill, would have been amortized, however, under SFAS No. 142,
equity method goodwill is not subject to amortization but rather to impairment
testing pursuant to ABP No. 18. The impairment test under APB No. 18 considers
whether the fair value of the equity investment as a whole, not the underlying
net assets, has declined and whether that decline is other than temporary. This
test requires equity method investors to continue to assess impairment of
investments in investees by considering whether declines in the fair values of
those investments, versus carrying values, may be other than temporary in
nature. The caption "Investments" in our accompanying consolidated balance
sheets includes $150.3 million and $140.3 million of equity method goodwill at
December 31, 2003 and 2002, respectively.
Our intangible assets include goodwill, lease value, contracts and
agreements. All of our intangible assets having definite lives are being
amortized on a straight-line basis over their estimated useful lives. Following
is information related to our intangible assets still subject to amortization
and our goodwill (in thousands):
December 31,
---------------------
2003 2002
--------- ---------
Goodwill
Gross carrying amount...... $ 743,652 $ 730,752
Accumulated amortization... (14,142) (14,142)
--------- ---------
Net carrying amount........ 729,510 716,610
--------- ---------
Lease value
Gross carrying amount...... 6,592 6,592
Accumulated amortization... (888) (748)
--------- ---------
Net carrying amount........ 5,704 5,844
--------- ---------
116
December 31,
---------------------
2003 2002
--------- ---------
Contracts and other
Gross carrying amount...... 7,801 11,719
Accumulated amortization... (303) (239)
--------- ---------
Net carrying amount........ 7,498 11,480
--------- ---------
Total intangibles, net..... $ 742,712 $ 733,934
========= =========
Changes in the carrying amount of goodwill for each of the two years ended
December 31, 2002 and 2003 are summarized as follows (in thousands):
Products Natural Gas CO2
Pipelines Pipelines Pipelines Terminals Total
----------- ----------- ----------- ----------- -----------
Balance as of Dec. 31, 2001 $ 262,765 $ 87,452 $ 46,101 $ 150,416 $ 546,734
Goodwill acquired 417 165,906 - 3,553 169,876
Impairment losses - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of Dec. 31, 2002 $ 263,182 $ 253,358 $ 46,101 $ 153,969 $ 716,610
=========== =========== =========== =========== ===========
Goodwill acquired - - - 12,900 12,900
Impairment losses - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of Dec. 31, 2003 $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510
=========== =========== =========== =========== ===========
Amortization expense on intangibles consists of the following (in thousands):
Year Ended December 31,
2003 2002 2001
-------- -------- ------
Goodwill................. $ - $ - $13,416
Lease value.............. 140 140 4,999
Contracts and other...... 64 40 60
-------- -------- -------
Total amortization....... $ 204 $ 180 $18,475
======== ======== =======
As of December 31, 2003, our weighted average amortization period for our
intangible assets is approximately 40 years. Our estimated amortization expense
for these assets for each of the next five fiscal years is approximately $0.2
million.
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,
------------------------------------
2003 2002 2001
--------- --------- ---------
Reported limited partners' interest in net income $ 370,813 $ 337,561 $ 240,248
Add: limited partners' interest in goodwill amortization -- -- 13,280
--------- --------- ---------
Adjusted limited partners' interest in net income $ 370,813 $ 337,561 $ 253,528
========= ========= =========
Basic limited partners' net income per unit:
Reported net income $ 2.00 $ 1.96 $ 1.56
Goodwill amortization -- -- 0.09
--------- --------- ---------
Adjusted net income $ 2.00 $ 1.96 $ 1.65
========= ========= =========
Diluted limited partners' net income per unit:
Reported net income $ 2.00 $ 1.96 $ 1.56
Goodwill amortization -- -- 0.09
--------- --------- ---------
Adjusted net income $ 2.00 $ 1.96 $ 1.65
========= ========= =========
9. Debt
Our debt and credit facilities as of December 31, 2003, consisted primarily
of:
o a $570 million unsecured 364-day credit facility due October 12, 2004;
o a $480 million unsecured three-year credit facility due October 15, 2005;
117
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 $25 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 $500 million of 5.00% Senior Notes due December 15, 2013;
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 $1.05 billion 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 as of December 31, 2003 was $430.3 million.
The balance consisted of:
o $426.1 million of commercial paper borrowings;
o $5 million under the Central Florida Pipeline LLC Notes; and
o an offset of $0.8 million (which represents the net of other borrowings and
the accretion of discounts on our senior note issuances).
As of December 31, 2003, we intend and have the ability to refinance $428.1
million of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amount has been classified as
long-term debt in our accompanying consolidated balance sheet. Currently, we
believe our liquidity to be adequate.
118
The weighted average interest rate on allof our borrowings was approximately
4.4924% during 2003 and 5.015%during 2002.
Credit Facilities
On February 21, 2002, we obtained an 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 Kinder Morgan Tejas. 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.
The two credit facilities consisted of a $530 million unsecured 364-day credit
facility due October 14, 2003, and a $445 million unsecured three-year credit
facility due October 15, 2005. There were no borrowings under either credit
facility as of December 31, 2002.
On May 5, 2003, we increased the borrowings available under our two credit
facilities by $75 million as follows:
o our $530 million unsecured 364-day credit facility was increased to $570
million; and
o our $445 million unsecured three-year credit facility was increased to
$480 million.
Our $570 million unsecured 364-day credit facility expired October 14, 2003.
On that date, we obtained a new $570 million unsecured 364-day credit facility
due October 12, 2004. As of December 31, 2003, we had two credit facilities:
o a $570 million unsecured 364-day credit facility due October 12, 2004; and
o a $480 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. There were no borrowings under either credit facility at
December 31, 2003. 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.
The amount available for borrowing under our credit facilities at December
31, 2003 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);
o a $0.2 million letter of credit entered into on June 4, 2002 that supports
a workers' compensation insurance policy; and
o our outstanding commercial paper borrowings.
In addition to our letters of credit outstanding as of December 31, 2003, in
early 2004 we issued a $50 million letter of credit to Morgan Stanley in support
of our hedging activities.
119
Our three-year credit facility also permits us to obtain bids for fixed-rate
loans from members of the lending syndicate.
Our credit facilities included the following restrictive covenants as of
December 31, 2003:
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 $2.1 billion; 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.
Senior Notes
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% senior notes and $248.3 million for the 5.35% senior 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.
On November 21, 2003, we closed a public offering of $500 million in
principal amount of 5% senior notes due December 15, 2013 at a price to the
public of 99.363% per note. In the offering, we received proceeds, net of
underwriting discounts and commissions, of approximately $493.6 million. We used
the proceeds to reduce our outstanding balance on our commercial paper
borrowings.
As of December 31, 2003, our liability balance due on the various series of
our senior notes was as follows (in millions):
8.00% senior notes due March 15, 2005...... $ 199.9
5.35% senior notes due August 15, 2007..... 249.9
6.30% senior notes due February 1, 2009.... 249.6
7.50% senior notes due November 1, 2010.... 248.9
6.75% senior notes due March 15, 2011...... 698.5
7.125% senior notes due March 15, 2012..... 448.3
5.00% senior notes due December 15, 2013... 496.8
120
7.40% senior notes due March 15, 2031...... 299.3
7.75% senior notes due March 15, 2032...... 298.6
7.30% senior notes due August 15, 2033..... 499.0
---------
Total.................................... $ 3,688.8
=========
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, 2003, we have entered into interest rate swap agreements with a
notional principal amount of $2.1 billion for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.
These 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. 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. For more information on our interest rate swaps, see Note 14.
Commercial Paper Program
On February 21, 2002, we increased our commercial paper program to provide
for the issuance of up to $1.8 billion. 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. As of December 31,
2002, we had $220.0 million of commercial paper outstanding with an average
interest rate of 1.58%. On May 5, 2003, we increased the program to allow for
the borrowing of up to $1.05 billion of commercial paper. As of December 31,
2003, we had $426.1 million of commercial paper outstanding with an average
interest rate of 1.1803%.
The borrowings under our commercial paper program were used to finance
acquisitions made during 2002 and 2003. The borrowings under our commercial
paper program reduce the borrowings allowed under our credit facilities.
SFPP, L.P. Debt
In December 2003, SFPP, L.P. prepaid the $37.1 million balance outstanding
under the Series F notes, plus $2.0 million for interest, as a result of its
taking advantage of certain optional prepayment provisions without penalty in
1999 and 2000.
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 was
10.70%, the maturity was December 2004, and interest was payable semiannually in
June and December. We had 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 were collateralized by mortgages on substantially all of the
properties of SFPP, L.P. and contained 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.
121
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, 2003, the
interest rate was 0.9606%. 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 (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. As of December 31, 2002, Central Florida's
outstanding balance under the senior notes was $30.0 million. In July 2003, we
made an annual repayment of $5.0 million and as of December 31, 2003, Central
Florida's outstanding balance under the senior notes was $25.0 million.
Trailblazer Pipeline Company Debt
As of December 31, 2001, Trailblazer Pipeline Company had a two-year
unsecured revolving credit facility with a bank syndicate. The facility 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. As of December 31, 2001, the outstanding balance
under Trailblazer's two-year revolving credit facility was $55.0 million, with a
weighted average interest rate of 2.875%, which reflected 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.
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 2003, the weighted-average interest
rate on these bonds was 1.05% per annum, and at December 31, 2003, the interest
rate was 1.20%. 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.
122
International Marine Terminals Debt
Since February 1, 2002, we have 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, as of December 31, 2003, are summarized as follows (in
thousands):
2004........ $ 430,348
2005........ 204,349
2006........ 43,903
2007........ 253,917
2008........ 3,940
Thereafter.. 3,382,469
----------
Total....... $4,318,926
==========
Of the $430.3 million scheduled to mature in 2004, we intend and have the
ability to refinance $428.1 million on a long-term basis under our unsecured
long-term credit facility. Accordingly, this amount has been classified as
long-term debt in our accompanying consolidated balance sheet as of December 31,
2003.
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 as
of December 31, 2003 and December 31, 2002 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, 2003 December 31, 2002
------------------------- -------------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
----------- ----------- ----------- -----------
(In thousands)
Total Debt $ 4,318,926 $ 4,889,478 $ 3,659,533 $ 4,475,058
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 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. SFPP's
post-retirement benefit plan is frozen and no additional participants may join
the plan.
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.
123
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.
Net periodic benefit costs and weighted-average assumptions for these plans
include the following components (in thousands):
Other Post-retirement Benefits
-------------------------------
2003 2002 2001
------ ------ ------
Net periodic benefit cost
Service cost...................... $ 41 $ 165 $ 120
Interest cost..................... 807 906 804
Expected return on plan assets.... -- -- --
Amortization of prior service cost (622) (545) (545)
Actuarial gain.................... - - (27)
------ ------ ------
Net periodic benefit cost......... $ 226 $ 526 $ 352
====== ====== ======
Additional amounts recognized
Curtailment (gain) loss......... $ -- $ -- $ --
Weighted-average assumptions as of
December 31:
Discount rate..................... 6.00% 6.50% 7.00%
Expected return on plan assets.... -- -- --
Rate of compensation increase..... 3.9% 3.9% --
Information concerning benefit obligations, plan assets, funded status and
recorded values for these plans follows (in thousands):
Other Post-retirement
Benefits
--------------------------
2003 2002
-------- --------
Change in benefit obligation
Benefit obligation at Jan. 1........ $ 13,275 $ 13,368
Service cost........................ 41 165
Interest cost....................... 807 906
Participant contributions........... 144 143
Amendments.......................... (190) (493)
Actuarial (gain) loss............... (7,456) (264)
Benefits paid from plan assets...... (445) (550)
-------- --------
Benefit obligation at Dec. 31....... $ 6,176 $ 13,275
======== ========
Change in plan assets
Fair value of plan assets at Jan. 1. $ -- $ --
Actual return on plan assets........ -- --
Employer contributions.............. 301 407
Participant contributions........... 144 143
Benefits paid from plan assets...... (445) (550)
-------- --------
Fair value of plan assets at Dec. 31 $ -- $ --
======== ========
Other Post-retirement
Benefits
--------------------------
2003 2002
-------- --------
Funded status....................... $ (6,176) $(13,275)
Unrecognized net actuarial (gain)
loss................................ (6,728) 729
Unrecognized prior service (benefit) (627) (1,059)
Adj. for 4th qtr. Employer
contributions....................... 72 105
-------- --------
Accrued benefit cost................ $(13,459) $(13,500)
======== ========
The unrecognized prior service credit is amortized on a straight-line basis
over the average future lifetime until full eligibility for benefits. For
measurement purposes, an 11% annual rate of increase in the per capita cost of
covered health care benefits was assumed for 2004. The rate was assumed to
decrease gradually to 5% by 2010 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 (in thousands):
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1-Percentage 1-Percentage
Point Increase Point Decrease
-------------- --------------
Effect on total of service and
interest cost components......... $ 78 $ (66)
Effect on postretirement benefit
obligation....................... $ 689 $ (575)
Amounts recognized in our consolidated balance sheets consist of (in
thousands):
As of December 31,
2003 2002
------------ ------------
Prepaid benefit cost...................... - -
Accrued benefit liability................. (13,459) (13,500)
Intangible asset.......................... - -
Accumulated other comprehensive income.... - -
------------ ------------
Net amount recognized as of Dec. 31..... (13,459) (13,500)
============ ============
We expect to contribute approximately $0.3 million to our post-retirement
benefit plans in 2004. The following benefit payments, which reflect expected
future service, as appropriate, are expected to be paid (in thousands):
Other Post-retirement Benefits
-------------------------------
2004........ $ 445
2005........ 445
2006........ 445
2007........ 445
2008........ 445
2009-2013... 2,225
-----------
Total....... $ 4,450
===========
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 $4.9 million for the year ended
2003 and $1.3 million for the year ended 2002.
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 between 1% and 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 employer
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 2004, no discretionary
contributions were made to individual accounts for 2003. The total amount
charged to expense for our Savings Plan was $5.9 million during 2003 and $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 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 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 3% of eligible
compensation every pay period. In addition, discretionary contributions are made
to the plan based on our and KMI's performance. No additional contributions were
made for 2003 performance. Interest will be credited to the personal
125
retirement accounts at the 30-year U.S. Treasury bond rate, or an approved
substitute, 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
As of December 31, 2003, our partners' capital consisted of:
o 134,729,258 common units;
o 5,313,400 Class B units; and
o 48,996,465 i-units.
Together, these 189,039,123 units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights. As of December 31, 2003, our
common unit total consisted of 121,773,523 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.
As of 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.
Our total common units outstanding at December 31, 2002, 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.
In June 2003, we issued in a public offering an additional 4,600,000 of our
common units, including 600,000 units upon exercise by the underwriters of an
over-allotment option, at a price of $39.35 per share, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $173.3 million for the issuance of these common units. We used
the proceeds to reduce the borrowings under our commercial paper program.
On February 3, 2004, we announced that we had priced the public offering of
an additional 5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We also granted to the underwriters an
option to purchase up to 795,000 additional common units to cover
over-allotments. On February 9, 2004, 5,300,000 common units were issued. We
received net proceeds of $237.8 million for the issuance of these common units
and we used the proceeds to reduce the borrowings under our commercial paper
program.
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 us,
our operating limited partnerships and their 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
126
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 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 cashwe 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 cash to the holders of our i-units
but will retain the cash for use 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 811,625 i-units on November 14, 2003.
These additional i-units distributed were based on the $0.66 per unit
distributed to our common unitholders on that date. During the year ended
December 31, 2003, KMR received distributions of 3,342,417 i-units. These
additional i-units distributed were based on the $2.575 per unit distributed to
our common unitholders during 2003.
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, 2003, 2002 and 2001, we declared
distributions of $2.63, $2.435 and $2.15 per unit, respectively. Our
distributions to unitholders for 2003, 2002 and 2001 required incentive
distributions to our general partner in the amount of $322.8 million, $267.4
million and $199.7 million, respectively. The increased incentive distributions
paid for 2003 over 2002 and 2002 over 2001 reflect the increase in amounts
distributed per unit as well as the issuance of additional units.
On January 21, 2004, we declared a cash distribution of $0.68 per unit for
the quarterly period ended December 31, 2003. This distribution was paid on
February 13, 2004, to unitholders of record as of January 30, 2004. 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 $0.68
distribution per common unit. The number of i-units distributed was 778,309. For
each outstanding i-unit that KMR held, a fraction of an i-unit (0.015885) was
issued. The fraction was determined by dividing:
o $0.68, the cash amount distributed per common unit
by
o $42.807, the average of KMR's limited liability shares' closing market
prices from January 13-27, 2004, 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 13, 2004 distribution required an incentive distribution to our
general partner in the amount of $85.8 million. Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2003 balance sheet as a Distribution Payable.
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12. Related Party Transactions
General and Administrative Expenses
KMGP Services Company, Inc., a subsidiary of our general partner, provides
employees and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR,
provides centralized payroll and employee benefits services to us, our operating
partnerships 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 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. Additionally,
we reimburse KMR with respect to costs incurred or allocated to KMR in
accordance with our limited partnership agreement, the delegation of control
agreement among our general partner, KMR, us and others, and KMR's limited
liability company agreement.
The named executive officers of our general partner and KMR and 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. 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 us, and a direct 1.0101% ownership interest in each of our five
operating partnerships. Collectively, our general partner owns an effective 2%
interest in our operating partnerships, excluding incentive distributions rights
as follows:
o its 1.0101% direct general partner ownership interest (accounted for as
minority interest in our consolidated financial statements); and
o its 0.9899% ownership interest indirectly owned via its 1% ownership
interest in us.
As of December 31, 2003, our general partner owned 1,724,000 common units,
representing approximately 0.91% 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.
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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.
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. Our general partner's declared incentive
distributions for the years ended December 31, 2003, 2002 and 2001 were $322.8
million, $267.4 million and $199.7 million, respectively.
Kinder Morgan, Inc.
KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the sole
stockholder of our general partner. As of December 31, 2003, KMI directly owned
8,838,095 common units and 5,313,400 Class B units, indirectly owned 4,117,640
common units owned by its consolidated affiliates, including our general partner
and owned 14,531,495 KMR shares, representing an indirect ownership interest of
14,531,495 i-units. Together, these units represent approximately 17.4% of our
outstanding limited partner units. Including both its general and limited
partner interests in us, at the 2003 distribution level, KMI received
approximately 51% of all quarterly distributions from us, of which approximately
41% is attributable to its general partner interest and 10% 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
As of December 31, 2003, KMR, our general partner's delegate, remains the
sole owner of our 48,996,465 i-units.
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Asset Acquisitions
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 have developed 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 as the Monterrey pipeline. The Monterrey pipeline 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 pipeline to explore the feasibility of and to
obtain permits for the Mexican portion of the pipeline. Following 1998, the
Monterrey pipeline 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 pipeline,
the Monterrey pipeline 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 pipeline
and determined that the Monterrey pipeline was an economically feasible pipeline
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 pipeline between 1996 and 1998.
KMI Asset Contributions
In conjunction with our acquisition of Natural Gas Pipelines assets from KMI
on December 31, 1999 and 2000, KMI became a guarantor of approximately $522.7
million of our debt. This amount has not changed as of December 31, 2003. KMI
would be obligated to perform under this guarantee only if we and/or our assets
were unable to satisfy our obligations.
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 other agreements between KMI and us. 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. On January
1, 2003, KMI began operating additional pipeline assets, including our North
System and Cypress pipeline, which are part of our Products Pipelines business
segment. The amounts paid to KMI for corporate general and administrative costs,
including amounts related to Trailblazer Pipeline Company, were $8.7 million of
fixed costs and $10.8 million of actual costs incurred for 2003, and $13.3
million of fixed costs and $2.8 million of actual costs incurred for 2002. We
estimate the total reimbursement for corporate general and administrative costs
to be paid to KMI in respect of all pipeline assets operated by KMI and its
subsidiaries for us for 2004 will be approximately $19.8 million, which includes
$8.7 million of fixed costs (adjusted for inflation) and $11.1 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 fixed amounts that were agreed upon at
the time the contracts were entered into were reasonable estimates of the
corporate general and administrative expenses to be
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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.
Retention Agreement
Effective January 17, 2002, KMI entered into a retention agreement with Mr.
C. Park Shaper, an officer of KMI, Kinder Morgan G.P., Inc. (our general
partner) and its delegate, KMR. Pursuant to the terms of the agreement, Mr.
Shaper obtained a $5 million personal loan guaranteed by KMI and us. Mr. Shaper
was required to purchase and did purchase KMI common stock and our common units
in the open market with the loan proceeds. The Sarbanes-Oxley Act of 2002 does
not allow companies to issue or guarantee new loans to executives, but it
"grandfathers" loans that were in existence prior to the act. Regardless, Mr.
Shaper, KMI and we agreed that in today's business environment it would be
prudent for him to repay the loan. In conjunction with this decision, Mr. Shaper
sold 37,000 of KMI shares and 82,000 of our common units. He used the proceeds
to repay the $5 million personal loan guaranteed by KMI and us, thereby
eliminating KMI's and our guarantee of this loan. Mr. Shaper instead
participates in KMI's restricted stock plan with other senior executives. The
retention agreement was terminated accordingly.
Lines of Credit
As of December 31, 2002, we had agreed to guarantee potential borrowings
under lines of credit available from Wachovia Bank, National Association,
formerly known as First Union National Bank, to Messrs. Thomas Bannigan, C. Park
Shaper, Joseph Listengart and James Street and Ms. Deborah Macdonald. Each of
these officers was primarily liable for any borrowing on his or her line of
credit, and if we made any payment with respect to an outstanding loan, the
officer on behalf of whom payment was made was required to surrender a
percentage of his or her options to purchase KMI common stock. Our obligations
under the guaranties, on an individual basis, generally did not exceed $1.0
million and such obligations, in the aggregate, did not exceed $1.9 million. As
of October 31, 2003, we had made no payments with respect to these lines of
credit and each line of credit was either terminated or refinanced without a
guarantee from us. We have no further guaranteed obligations with respect to any
borrowings by our officers.
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, 2003, Coyote's balance sheet has current notes
payable to each partner in the amount of $17.1 million. These notes are due on
June 30, 2004. At that time, the partners can either renew the notes or make
capital contributions which will 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 our 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.
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13. Leases and Commitments
Operating Leases
Including probable elections to exercise renewal options, the remaining terms
on our operating leases range from one to 39 years. Future commitments related
to these leases as of December 31, 2003 are as follows (in thousands):
2004...................... $ 17,076
2005...................... 14,955
2006...................... 12,825
2007...................... 11,623
2008...................... 10,834
Thereafter................ 35,440
---------
Total minimum payments.... $ 102,753
=========
We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $1.1 million. Total lease and rental expenses,
including related variable charges were $25.3 million for 2003, $21.6 million
for 2002 and $41.1 million for 2001.
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 authorized
under the option plan is 500,000. The option plan terminates in March 2008. 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.
As of December 31, 2002, outstanding options for 263,600 common units had
been granted at an average exercise price of $17.25 per unit. Outstanding
options for 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s three non-employee directors at an average exercise price of $20.58 per
unit. As of December 31, 2003, outstanding options for 129,050 common units had
been granted at an average exercise price of $17.46 per unit. Outstanding
options for 20,000 common units had been granted to two of Kinder Morgan G.P.,
Inc.'s three non-employee directors at an average exercise price of $20.58 per
unit.
During 2002, 88,200 common unit options were exercised at an average price of
$17.77 per unit. The common units underlying these options had an average fair
market value of $34.24 per unit. During 2003, 134,550 common unit options were
exercised at an average price of $17.06 per unit. The common units underlying
these options had an average fair market value of $38.85 per unit.
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, we record
expense for our common unit option plan equal to the excess of the market price
of the underlying common units at the date of grant over the exercise price of
the common unit award, if any. Such excess is commonly referred to as the
intrinsic value. All of our common unit options were issued with the exercise
price equal to the market price of the underlying common units at the grant date
and therefore, no compensation expense has been recorded. Pro forma information
regarding changes in net income and per unit data, if the accounting prescribed
by Statement of Financial Accounting Standards No. 123 "Accounting for Stock
Based Compensation," had been applied, is not material.
Directors' Unit Appreciation Rights Plan
On April 1, 2003, KMR's compensation committee established the Directors'
Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR's three
non-employee directors is eligible to receive common unit appreciation rights.
The primary purpose of this plan is to promote the interests of our unitholders
by aligning the compensation of the non-employee members of the board of
directors of KMR with unitholders' interests. Secondly, since KMR's
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success is dependent on its operation and management of our business and our
resulting performance, the plan is expected to align the compensation of the
non-employee members of the board with the interests of KMR's shareholders.
Upon the exercise of unit appreciation rights, we will pay, within thirty
days of the exercise date, the participant an amount of cash equal to the
excess, if any, of the aggregate fair market value of the unit appreciation
rights exercised as of the exercise date over the aggregate award price of the
rights exercised. The fair market value of one unit appreciation right as of the
exercise date will be equal to the closing price of one common unit on the New
York Stock Exchange on that date. The award price of one unit appreciation right
will be equal to the closing price of one common unit on the New York Stock
Exchange on the date of grant. Each unit appreciation right granted under the
plan will be exercisable only for cash and will be evidenced by a unit
appreciation rights agreement.
All unit appreciation rights granted vest on the six-month anniversary of the
date of grant. If a unit appreciation right is not exercised in the ten year
period following the date of grant, the unit appreciation right will expire and
not be exercisable after the end of such period. In addition, if a participant
ceases to serve on the board for any reason prior to the vesting date of a unit
appreciation right, such unit appreciation right will immediately expire on the
date of cessation of service and may not be exercised. The plan is administered
by KMR's compensation committee. The total number of unit appreciation rights
authorized under the plan is 500,000. KMR's board has sole discretion to
terminate the plan at any time with respect to unit appreciation rights which
have not previously been granted to participants.
On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors were granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights will be granted to each of KMR's three
non-employee directors during the first meeting of the board each January.
Accordingly, each non-employee director received an additional 10,000 unit
appreciation rights on January 21, 2004. As of December 31, 2003, 52,500 unit
appreciation rights had been granted. No unit appreciation rights were exercised
during 2003.
Contingent Debt
We apply the disclosure provisions of FASB Interpretation (FIN) No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" to our agreements that contain
guarantee or indemnification clauses. These disclosure provisions expand those
required by FASB No. 5, "Accounting for Contingencies," by requiring a guarantor
to disclose certain types of guarantees, even if the likelihood of requiring the
guarantor's performance is remote. The following is a description of our
contingent debt agreements.
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.
As of December 31, 2003, the debt facilities of Cortez Capital Corporation
consisted of:
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o $95 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 22, 2004
(to support the above-mentioned $175 million commercial paper program).
As of December 31, 2003, Cortez Capital Corporation had $135.7 million of
commercial paper outstanding with an interest rate of 1.12%, the average
interest rate on the Series D notes was 7.04% and there were no borrowings
under the credit facility.
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 as of December 31, 2003.
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 collateralized 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 under joint and several liability. The principal is
to be repaid in seven equal installments beginning on October 31, 2004 and
ending on October 31, 2010. The $55 million is outstanding as of December 31,
2003.
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 LLC, the operator of the
port facilities. In July 2002, we acquired Nassau Terminals LLC 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, including: commodity futures and
options contracts, fixed-price swaps, and basis swaps.
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Pursuant to our management's approved policy, we are to engage in these
activities only as a hedging mechanism against price volatility associated with:
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.
Certain of our business activities expose us to foreign currency
fluctuations. However, due to the limited size of this exposure, we do not
believe the risks associated with changes in foreign currency will have a
material adverse effect on our business, financial position, results of
operations or cash flows. Accordingly, as of December 31, 2003, no financial
instruments were used to limit the effects of foreign exchange rate fluctuations
on our financial results. In February 2004, we entered into a single $17.0
million foreign currency call option that expires on December 31, 2004.
Our derivatives hedge our commodity price risks involving our normal business
activities, which include the sale of natural gas, natural gas liquids, oil and
carbon dioxide, and these derivatives have been designated by us as cash flow
hedges as defined by SFAS No. 133. SFAS No. 133 designates derivatives that
hedge 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 is reclassified into earnings when the forecasted transaction
affects earnings. To be considered effective, changes in the value of the
derivative or its resulting cash flows must substantially offset changes in the
value or cash flows of the item being hedged. The ineffective portion of the
gain or loss is reported in earnings immediately.
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
(loss)" in the accompanying consolidated balance sheets are reclassified into
earnings as the hedged sales and purchases take place. Approximately $65.4
million of the Accumulated other comprehensive loss balance of $155.8 million
representing unrecognized net losses on derivative activities as of December 31,
2003 is expected to be reclassified into earnings during the next twelve months.
During the twelve months ended December 31, 2003, we reclassified $82.1 million
of Accumulated other comprehensive income into earnings. This amount includes
the balance of $45.3 million representing unrecognized net losses on derivative
activities as of December 31, 2002. For each of the years ended December 31,
2003, 2002 and 2001, no gains or losses were reclassified 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 $10.3 million as of
December 31, 2003 and $1.9 million as of December 31, 2002. Our margin deposits
associated with over-the-counter swap partners were $7.7 million as of December
31, 2003 and $0.0 million as of December 31, 2002.
135
We recognized a gain of $0.5 million during 2003, a gain of $0.7 million
during 2002 and a loss of $1.3 million during 2001 as a result of ineffective
hedges. All of these amounts are reported within the captions "Gas purchases and
other costs of sales" or "Operations and maintenance" in our accompanying
Consolidated Statements of Income. For each of the years ended December 31,
2003, 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 included within
"Other current assets", "Accrued other current liabilities", "Deferred charges
and other assets" and "Other long-term liabilities and deferred credits" in our
accompanying consolidated balance sheets. As of December 31, 2003, the balance
in "Other current assets" on our consolidated balance sheet included $18.2
million related to risk management hedging activities, and the balance in
"Accrued other current liabilities" included $90.4 million related to risk
management hedging activities. As of December 31, 2002, the balance in "Other
current assets" on our consolidated balance sheet included $57.9 million related
to risk management hedging activities, and the balance in "Accrued other current
liabilities" included $101.3 million related to risk management hedging
activities. As of December 31, 2003, the balance in "Deferred charges and other
assets" included $2.7 million related to risk management hedging activities, and
the balance in "Other long-term liabilities and deferred credits" included
$101.5 million related to risk management hedging activities. As of December 31,
2002, the balance in "Deferred charges and other assets" included $5.7 million
related to risk management hedging activities, and the balance in "Other
long-term liabilities and deferred credits" included $8.5 million related to
risk management hedging activities.
Given our portfolio of businesses as of December 31, 2003, our principal uses
of derivative energy 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, 2003, 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 2009.
As of December 31, 2003, 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........................ $ 5,261 $(178,480) $ (173,219)
Contract Amounts-- Gross........................ $ 68,934 $ 954,313 $1,023,247
Contract Amounts-- Net.......................... $ (3,687) $(890,105) $ (893,792)
(Number of contracts(1))
Natural Gas
Notional Volumetric Positions: Long........... 663 588 1,251
Notional Volumetric Positions: Short.......... (670) (2,369) (3,039)
Net Notional Totals to Occur in 2004.......... (7) (1,756) (1,763)
Net Notional Totals to Occur in 2005 and Beyond -- (25) (25)
Crude Oil
Notional Volumetric Positions: Long........... -- 336 336
Notional Volumetric Positions: Short.......... -- (37,418) (37,418)
Net Notional Totals to Occur in 2004.......... -- (10,854) (10,854)
Net Notional Totals to Occur in 2005 and Beyond -- (26,228) (26,228)
Natural Gas Liquids
Notional Volumetric Positions: Long........... -- -- --
Notional Volumetric Positions: Short.......... -- (460) (460)
Net Notional Totals to Occur in 2004.......... -- (336) (336)
Net Notional Totals to Occur in 2005 and Beyond -- (124) (124)
- ----------
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(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, who
principally have investment grade credit ratings. We both owe money and are owed
money under these financial instruments; however, as of December 31, 2003 we had
virtually no amounts owed to us from other parties. 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. While we enter into derivative transactions
principally 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 in the future.
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 our 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.
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, 2003 and December 31, 2002, we were a party to interest rate swap
agreements with a notional principal amount of $2.1 billion and $1.95 billion,
respectively, for the purpose of hedging the interest rate risk associated with
our fixed and variable rate debt obligations.
As of December 31, 2003, a notional principal amount of $2.0 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 $250 million principal amount of our 5.0% senior notes due December 15,
2013;
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.
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These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of December 31, 2003,
the maximum length of time over which we have hedged a portion of 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% 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, 2003, we also had swap agreements that effectively convert
the interest expense associated with $100 million of our variable rate debt to
fixed rate debt. Half of these agreements, converting $50 million of our
variable rate debt to fixed rate debt, mature on August 1, 2005, and the
remaining half mature on September 1, 2005. Prior to March 2002, this swap was
designated a hedge of our $200 million Floating Rate Senior Notes, which were
retired (repaid) 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 $100 million of our portfolio of commercial paper.
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. As of December 31, 2003, we
recognized an asset of $129.6 million and a liability of $8.1 million for the
$121.5 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 our 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 our accompanying balance sheet. As of 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 our 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 our
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 primarily 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;
138
o CO2; 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
principally 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 and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the transmission, storage,
gathering and sale of natural gas. Our CO2 segment derives its revenues
primarily from the transportation and marketing of carbon dioxide used as a
flooding medium for recovering crude oil from mature oil fields, and from the
production and sale 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):
2003 2002 2001
---------- ----------- ----------
Revenues
Products Pipelines............. $ 585,376 $ 576,542 $ 605,392
Natural Gas Pipelines.......... 5,316,853 3,086,187 1,869,315
CO2............................ 248,535 146,280 122,094
Terminals...................... 473,558 428,048 349,875
---------- ----------- ----------
Total consolidated revenues.... $6,624,322 $4,237,057 $2,946,676
========== ========== ==========
Operating expenses(a)
Products Pipelines................ $ 169,526 $ 169,782 $ 240,537
Natural Gas Pipelines............. 4,967,531 2,784,278 1,665,852
CO2............................... 82,055 50,524 44,973
Terminals......................... 229,054 213,929 175,869
---------- ---------- ----------
Total consolidated operating
expenses......................... $5,448,166 $3,218,513 $2,127,231
========== ========== ==========
(a)Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes.
Earnings from equity investments
Products Pipelines............... $ 30,948 $ 28,998 $ 28,278
Natural Gas Pipelines............ 24,012 23,887 22,558
CO2.............................. 37,198 36,328 33,998
Terminals........................ 41 45 --
---------- ---------- ----------
Total consolidated equity
earnings....................... $ 92,199 $ 89,258 $ 84,834
========== ========== ==========
Amortization of excess cost of equity investments
Products Pipelines............. $ 3,281 $ 3,281 $ 5,592
Natural Gas Pipelines.......... 277 277 1,402
CO2............................ 2,017 2,017 2,017
Terminals...................... -- -- --
---------- ---------- ----------
Total consol. amortization of $ 5,575 $ 5,575 $ 9,011
========== ========== ==========
excess cost of invests...........
Other, net-income (expense)(a)
Products Pipelines............... $ 6,471 $ (14,000) $ 440
Natural Gas Pipelines............ 1,082 36 749
CO2.............................. (40) 112 547
Terminals........................ 88 15,550 226
---------- ---------- ----------
Total consolidated Other,
net-income (expense)............ $ 7,601 $ 1,698 $ 1,962
========== ========== ==========
(a) 2002 amounts include 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.
139
Income tax benefit (expense)
Products Pipelines................. $ (11,669)$ (10,154) $ (9,653)
Natural Gas Pipelines.............. (1,066) (378) --
CO2................................ (39) -- --
Terminals.......................... (3,857) (4,751) (6,720)
---------- ---------- ----------
Total consolidated income tax
benefit (expense)................. $ (16,631)$ (15,283) $ (16,373)
========== ========== ==========
Segment earnings before
depreciation, depletion,
amortization and amortization of
excess cost of equity investments
Products Pipelines................. $ 441600 $ 411,604 $ 383,920
Natural Gas Pipelines.............. 373,350 325,454 226,770
CO2................................ 203,599 132,196 111,666
Terminals.......................... 240,776 224,963 167,512
---------- ---------- ----------
Total segment earnings before
DD&A(a)........................... 1,259,325 1,094,217 889,868
Consolidated depreciation and
amortization...................... (219,032) (172,041) (142,077)
Consolidated amortization of
excess cost of invests............ (5,575) (5,575) (9,011)
Interest and corporate
administrative expenses(b)........ (337,381) (308,224) (296,437)
---------- ---------- ----------
Total consolidated net income...... $ 697,337 $ 608,377 $ 442,343
========== ========== ==========
(a) Includes revenues, earnings from equity investments, income taxes and
other, net, less operating expenses.
(b) Includes interest and debt expense, general and administrative expenses,
minority interest expense and cumulative effect adjustment from a change in
accounting principle (2003 only).
Segment earnings
Products Pipelines............................. $ 370,974 $ 343,935 $ 312,464
Natural Gas Pipelines.......................... 319,288 276,766 193,804
CO2............................................ 140,755 100,983 92,087
Terminals...................................... 203,701 194,917 140,425
------------- ------------- -------------
Total segment earnings......................... 1,034,718 916,601 738,780
Interest and corporate administrative expenses. (337,381) (308,224) (296,437)
------------- ------------- -------------
Total consolidated net income.................. $ 697,337 $ 608,377 $ 442,343
============= ============= =============
Assets at December 31
Products Pipelines.......................... $ 3,198,107 $ 3,088,799 $ 3,095,899
Natural Gas Pipelines....................... 3,253,792 3,121,674 2,058,836
CO2......................................... 1,177,645 613,980 503,565
Terminals................................... 1,368,279 1,165,096 990,760
------------- ------------ -------------
Total segment assets........................ 8,997,823 7,989,549 6,649,060
Corporate assets(a)......................... 141,359 364,027 83,606
------------- ------------ -------------
Total consolidated assets................... $ 9,139,182 $ 8,353,576 $ 6,732,666
============= ============= =============
(a) Includes cash, cash equivalents and certain unallocable deferred charges.
Depreciation, depletion and amortization
Products Pipelines........................... $ 67,345 $ 64,388 $ 65,864
Natural Gas Pipelines........................ 53,785 48,411 31,564
CO2.......................................... 60,827 29,196 17,562
Terminals.................................... 37,075 30,046 27,087
------------- ------------- -------------
Total consol. depreciation, depletion and
amortiz..................................... $ 219,032 $ 172,041 $ 142,077
============= ============= =============
Investments at December 31
Products Pipelines........................... $ 226,680 $ 220,203 $ 225,561
Natural Gas Pipelines........................ 164,924 157,778 146,566
CO2.......................................... 12,591 71,283 68,232
Terminals.................................... 150 2,110 159
------------- ------------- -------------
Total consolidated investments............... $ 404,345 $ 451,374 $ 440,518
============= ============= =============
Capital expenditures
Products Pipelines........................... $ 94,727 $ 62,199 $ 84,709
Natural Gas Pipelines........................ 101,679 194,485 86,124
CO2.......................................... 272,177 163,183 65,778
Terminals.................................... 108,396 122,368 58,477
------------- ------------- -------------
Total consolidated capital expenditures...... $ 576,979 $ 542,235 $ 295,088
============= ============= =============
140
We do not attribute interest income or interest expense to any of our
reportable business segments. For each of the years ended December 31, 2003,
2002 and 2001, we reported (in thousands) total consolidated interest revenue of
$1,420, $1,819 and $4,473, respectively. For each of the years ended December
31, 2003, 2002 and 2001, we reported (in thousands) total consolidated interest
expense of $182,777, $178,279 and $175,930, respectively.
Our total operating revenues are derived from a wide customer base. For each
of the years ended December 31, 2003, 2002 and 2001, one customer accounted for
more than 10% of our total consolidated revenues. Total transactions within our
Natural Gas Pipelines segment in 2003 and 2002 with CenterPoint Energy accounted
for 16.84% and 15.6% of our total consolidated revenues during 2003 and 2002,
respectively. 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.
16. Litigation and Other Contingencies
The tariffs we charge for transportation on our interstate common carrier
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, 2003, 2002 and 2001, the application of the indexing methodology
did not significantly affect tariff rates on our interstate petroleum products
pipelines.
SFPP, L.P.
Federal Energy Regulatory Commission Proceedings
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 in the proceedings before the FERC 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." If SFPP rates previously "grandfathered"
under the Energy Policy Act lose their "grandfathered" status and are found to
be unjust and unreasonable, shippers may be entitled to prospective rate
reductions and complainants may be entitled to reparations for periods from the
date of their respective complaint to the date of the implementation of the new
rates.
On June 24, 2003, a non-binding, phase one initial decision was issued by an
administrative law judge hearing a FERC case on the rates charged by SFPP on the
interstate portion of its pipelines (see OR96-2 section below for further
discussion). In his phase one initial decision, the administrative law judge
recommended that the FERC "ungrandfather" SFPP's interstate rates and found most
of SFPP's rates at issue to be unjust and unreasonable. The administrative law
judge has indicated that a phase two initial decision will address prospective
rates and whether reparations are necessary.
141
Initial decisions have no force or effect and must be reviewed by the FERC.
The FERC is not obliged to follow any of the administrative law judge's findings
and can accept or reject this initial decision in whole or in part. In addition,
as stated above, the facts are complex, the rules and regulations in this area
are vague and little precedent exists. The FERC is now considering the phase one
initial decision and will consider the phase two initial decision when it is
issued and briefed by the parties. If the FERC ultimately finds, after reviewing
both initial decisions, that these rates should be "ungrandfathered" and are
unjust and unreasonable, they could be lowered prospectively and complaining
shippers could be entitled to reparations for prior periods. We do not expect
any impact on our rates relating to this matter before early 2005.
We currently believe that these FERC complaints seek approximately $154
million in tariff reparations and prospective annual tariff reductions, the
aggregate average annual impact of which would be approximately $45 million. As
the length of time from the filing of the complaints increases, the amounts
sought by complainants in tariff reparations will likewise increase until a
determination of reparations owed is made by the FERC. 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. The
administrative law judge's initial decision does not change our estimate of what
the complainants seek. Furthermore, 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, results of operations or cash flows.
OR92-8, et al. proceedings. FERC Docket No. OR92-8-000 et al., is a
consolidated proceeding that began in September 1992 and includes a number of
shipper complaints against certain rates and practices on SFPP's East Line (from
El Paso, Texas to Phoenix, Arizona) and West Line (from Los Angeles, California
to Tucson, Arizona), as well as SFPP's gathering enhancement fee at Watson
Station in Carson, California. The complainants in the case are El Paso
Refinery, L.P. (which settled with SFPP in 1996), Chevron Products Company,
Navajo Refining Company (now Navajo Refining Company, L.P.), ARCO Products
Company (now part of BP West Coast Products, LLC), Texaco Refining and Marketing
Inc., Refinery Holding Company LP (now named Western Refining Company, L.P.),
Mobil Oil Corporation (now part of ExxonMobil Oil Corporation) and Tosco
Corporation (now part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in those proceedings.
A FERC administrative law judge held hearings in 1996, and issued an initial
decision in September 1997. The initial decision held that all but one of SFPP's
West Line rates were "grandfathered" under the Energy Policy Act of 1992 and
therefore deemed to be just and reasonable; it further held that complainants
had failed to prove "changed circumstances" with respect to those rates and that
they therefore could not be challenged in the Docket No. OR92-8 et al.
proceedings, either for the past or prospectively. However, the initial decision
also made rulings generally adverse to SFPP on certain cost of service issues
relating to the evaluation of East Line rates, which are not "grandfathered"
under the Energy Policy Act. Those issues included the capital structure to be
used in computing SFPP's "starting rate base," the level of income tax allowance
SFPP may include in rates and the recovery of civil and regulatory litigation
expenses and certain pipeline reconditioning costs incurred by SFPP. The initial
decision also held SFPP's Watson Station gathering enhancement service was
subject to FERC jurisdiction and ordered SFPP to file a tariff for that service.
The FERC subsequently reviewed the initial decision, and issued a series of
orders in which it adopted certain rulings made by the administrative law judge,
changed others and modified a number of its own rulings on rehearing. Those
orders began in January 1999, with FERC Opinion No. 435, and continued through
June 2003.
The FERC affirmed that all but one of SFPP's West Line rates are
"grandfathered" and that complainants had failed to satisfy the threshold burden
of demonstrating "changed circumstances" necessary to challenge those rates. The
FERC further held that the one West Line rate that was not grandfathered did not
need to be reduced. The FERC consequently dismissed all complaints against the
West Line rates in Docket Nos. OR92-8 et al. without any requirement that SFPP
reduce, or pay any reparations for, any West Line rate.
The FERC initially modified the initial decision's ruling regarding the
capital structure to be used in computing SFPP's "starting rate base" to be more
favorable to SFPP, but later reversed that ruling. The FERC also made
142
certain modifications to the calculation of the income tax allowance and other
cost of service components, generally to SFPP's disadvantage.
On multiple occasions, the FERC required SFPP to file revised East Line rates
based on rulings made in the FERC's various orders. SFPP was also directed to
submit compliance filings showing the calculation of the revised rates, the
potential reparations for each complainant and in some cases potential refunds
to shippers. SFPP filed such revised East Line rates and compliance filings in
March 1999, July 2000, November 2001 (revised December 2001), October 2002 and
February 2003 (revised March 2003). Most of those filings were protested by
particular SFPP shippers. The FERC has held that certain of the rates SFPP filed
at the FERC's directive should be reduced retroactively and/or be subject to
refund; SFPP has challenged the FERC's authority to impose such requirements in
this context.
While the FERC initially permitted SFPP to recover certain of its litigation,
pipeline reconditioning and environmental costs, either through a surcharge on
prospective rates or as an offset to potential reparations, it ultimately
limited recovery in such a way that SFPP was not able to make any such surcharge
or take any such offset. Similarly, the FERC initially ruled that SFPP would not
owe reparations to any complainant for any period prior to the date on which
that party's complaint was filed, but ultimately held that each complainant
could recover reparations for a period extending two years prior to the filing
of its complaint (except for Navajo, which was limited to one month of
pre-complaint reparations under a settlement agreement with SFPP's predecessor).
The FERC also ultimately held that SFPP was not required to pay reparations or
refunds for Watson Station gathering enhancement fees charged prior to filing a
FERC tariff for that service.
In April 2003, SFPP paid complainants and other shippers reparations and/or
refunds as required by FERC's orders. In August 2003, SFPP paid shippers an
additional refund as required by FERC's most recent order in the Docket No.
OR92-8 et al. proceedings. We made payments of $44.9 million in 2003 for
reparations and refunds under order from the FERC.
Beginning in 1999, SFPP, the complainants and intervenor Ultramar Diamond
Shamrock Corporation (now part of Valero Energy Corporation) filed petitions for
review of FERC's Docket OR92-8 et al. orders in the United States Court of
Appeals for the District of Columbia Circuit. Certain of those petitions were
dismissed by the Court of Appeals as premature, and the remaining petitions were
held in abeyance pending completion of agency action. However, in December 2002,
the Court of Appeals returned to its active docket all petitions to review the
FERC's orders in the case through November 2001 and severed petitions regarding
later FERC orders. The severed orders were held in abeyance for later
consideration.
Briefing in the Court of Appeals was completed in August 2003, and oral
argument took place on November 12, 2003. The Court of Appeals is expected to
issue its decision in the first or second quarter of 2004.
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 claimed that the
rate for that service was unlawful. Several other West Line shippers filed
similar complaints and/or motions to intervene.
Following a hearing in March 1997, a FERC administrative law 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 pre-existing
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 set a hearing to determine
whether SFPP possessed market power in the origin market.
Following a hearing, on December 21, 2000, an administrative law judge found
that SFPP possessed market power over the Sepulveda origin market. On February
28, 2003, the FERC issued an order upholding that decision. SFPP filed a request
for rehearing of that order on March 31, 2003. The FERC denied SFPP's request
for rehearing on July 9, 2003.
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As part of its February 28, 2003 order denying SFPP's application for
market-based ratemaking authority, the FERC remanded to the ongoing litigation
in Docket No. OR96-2, et al. the question of whether SFPP's current rate for
service on the Sepulveda line is just and reasonable. That issue is currently
pending before the administrative law judge in the Docket No. OR96-2, et al.
proceeding. The procedural schedule in this remanded matter is currently
suspended pending issuance of the phase two initial decision in the Docket No.
OR96-2, et al. proceeding (see below).
OR96-2; 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. The FERC accepted the complaints and consolidated them into
one proceeding (Docket No. OR96-2, et al.), but held 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.
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. These complaints were
consolidated with the ongoing proceeding in Docket No. OR96-2, et al.
A hearing in this consolidated proceeding was held from October 2001 to March
2002. A FERC administrative law judge issued his initial decision on June 24,
2003. The initial decision found that, for the years at issue, the complainants
had shown substantially changed circumstances for rates on SFPP's West, North
and Oregon Lines and for SFPP's fee for gathering enhancement service at Watson
Station and thus found that those rates should not be "grandfathered" under the
Energy Policy Act of 1992. The initial decision also found that most of SFPP's
rates at issue were unjust and unreasonable. The initial decision indicated that
a phase two initial decision will address prospective rates and whether
reparations are necessary. Issuance of the phase two initial decision is
expected sometime in the first quarter of 2004.
SFPP has filed a brief on exceptions to the FERC that contests the findings
in the initial decision. SFPP's opponents have responded to SFPP's brief. The
FERC is now considering the phase one initial decision and will consider the
phase two initial decision when it is issued and briefed by the parties. If the
FERC ultimately finds, after reviewing both initial decisions, that these rates
should be "ungrandfathered" and are unjust and unreasonable, they could be
lowered prospectively and complaining shippers could be entitled to reparations
for prior periods. We do not expect any impact on our rates relating to this
matter before early 2005.
OR02-4 proceedings. On February 11, 2002, Chevron, an intervenor in the
Docket No. OR96-2, et al. proceeding, filed a complaint against SFPP in Docket
No. OR02-4 along with a motion to consolidate the complaint with the Docket No.
OR96-2, et al. proceeding. On May 21, 2002, the FERC dismissed Chevron's
complaint and motion to consolidate. Chevron filed a request for rehearing,
which the FERC dismissed on September 25, 2002. In October 2002, Chevron filed a
request for rehearing of the FERC's September 25, 2002 Order, which the FERC
denied on May 23, 2003. On July 1, 2003, Chevron filed a petition for review of
this denial at the U.S. Court of Appeals for the District of Columbia Circuit.
On August 18, 2003, SFPP filed a motion to dismiss Chevron's petition on the
basis that Chevron lacks standing to bring its appeal and that the case is not
ripe for review. Chevron answered on September 10, 2003. SFPP's motion was
pending, when the Court of Appeals, on December 8, 2003, granted Chevron's
motion to hold the case in abeyance pending the outcome of the appeal of the
Docket No. OR92-8, et al. proceeding. On January 8, 2004, the Court of Appeals
granted Chevron's motion to have its appeal of the
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FERC's decision in Docket No. OR03-5 (see below) consolidated with Chevron's
appeal of the FERC's decision in the Docket No. OR02-4 proceeding. Chevron
continues to participate in the Docket No. OR96-2 et al. proceeding as an
intervenor.
OR03-5 proceedings. On June 30, 2003, Chevron filed another complaint against
SFPP - substantially similar to its previous complaint - and moved to
consolidate the complaint with the Docket No. OR96-2, et al. proceeding. This
complaint was docketed as Docket No. OR03-5. Chevron requested that this new
complaint be treated as if it were an amendment to its complaint in Docket No.
OR02-4, which was previously dismissed by the FERC. By this request, Chevron
sought to, in effect, back-date its complaint, and claim for reparations, to
February 2002. SFPP answered Chevron's complaint on July 22, 2003, opposing
Chevron's requests for consolidation and for the back-dating of its complaint.
On October 28, 2003 , the FERC accepted Chevron's complaint, but held it in
abeyance pending the outcome of the Docket No. OR96-2, et al. proceeding. The
FERC denied Chevron's request for consolidation and for back-dating. On November
21, 2003, Chevron filed a petition for review of the FERC's October 28, 2003
Order at the Court of Appeals for the District of Columbia Circuit. On January
8, 2004, the Court of Appeals granted Chevron's motion to have its appeal
consolidated with Chevron's appeal of the FERC's decision in the Docket No.
OR02-4 proceeding and to have the two appeals held in abeyance pending outcome
of the appeal of the Docket No. OR92-8, et al. proceeding.
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 sought 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
resolution of these submitted matters is anticipated within the third quarter of
2004.
The CPUC subsequently 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 required SFPP to submit cost data for
2001, 2002, and 2003, and 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. On February 21, 2003, SFPP submitted the cost data
required by the CPUC, which submittal was protested by Valero Marketing and
Supply Company, Ultramar Inc., BP West Coast Products LLC, Exxon Mobil Oil
Corporation and Chevron Products Company. Issues raised by the protest,
including the reasonableness of SFPP's existing intrastate transportation rates,
were the subject of evidentiary hearings conducted in December 2003 and are
expected to be resolved by the CPUC by the third quarter of 2004.
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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. There is no
way to quantify the potential extent to which the CPUC could determine that
SFPP's existing California rates are unreasonable. With regard to 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, such refunds could
total about $6 million per year from October 2002 to the anticipated date of a
CPUC decision during the third quarter of 2004.
SFPP believes the submission of the required, representative cost data
required by the CPUC indicates 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, results of operations or
cash flows.
Trailblazer Pipeline Company
As required by its last rate case settlement, Trailblazer Pipeline Company
made a general rate case filing at the 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 sought rehearing of the FERC order with respect to the refund
condition on the rate decrease. On April 15, 2003, the FERC granted
Trailblazer's rehearing request to remove the refund condition that had been
imposed in the December 31, 2002 Order. Certain intervenors have sought
rehearing as to the FERC's acceptance of certain non-rate tariff provisions. A
prehearing conference on the rate issues was held on January 16, 2003, where a
procedural schedule was established.
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.
Comments on these issues as discussed at the technical conference were filed
by parties in March 2003. On May 23, 2003, FERC issued an order deciding
non-rate tariff issues and denying rehearing of its prior order. In the May 23,
2003 order, FERC:
o accepted Trailblazer's proposed capacity award procedures with very limited
changes;
o accepted Trailblazer's credit procedures subject to very extensive changes,
consistent with numerous recent orders involving other pipelines;
o accepted a compromise agreed to by Trailblazer and the active parties under
which existing shippers must match competing bids in the right of first
refusal process for up to 10 years (in lieu of the current 5 years); and
o accepted Trailblazer's withdrawal of daily imbalance charges.
The referenced order did the following:
o allowed shortened notice periods for suspension of service, but required at
least 30 days notice for service termination;
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o limited prepayments and any other assurance of future performance, such as
a letter of credit, to three months of service charges except for new
facilities;
o required the pipeline to pay interest on prepayments or allow those funds
to go into an interest-bearing escrow account; and
o required much more specificity about credit criteria and procedures in
tariff provisions.
Certain shippers and Trailblazer have sought rehearing of the May 23, 2003
order. Trailblazer made its compliance filing on June 20, 2003. Under the May
23, 2003 order, these tariff changes are effective as of May 23, 2003, except
that Trailblazer has filed to make the revised credit procedures effective
August 15, 2003.
With respect to the on-going rate review phase of the case, direct testimony
was filed by FERC Staff and Indicated Shippers on May 22, 2003 and
cross-answering testimony was filed by Indicated Shippers on June 19, 2003.
Trailblazer's answering testimony was filed on July 29, 2003.
On September 22, 2003, Trailblazer filed an offer of settlement with the
FERC. Under the settlement, if approved by the FERC, Trailblazer's rate would be
reduced effective January 1, 2004, from about $0.12 to $0.09 per dekatherm of
natural gas, and Trailblazer would file a new rate case to be effective January
1, 2010.
On January 23, 2004, the FERC issued an order approving, with modification,
the settlement that was filed on September 22, 2003. The FERC modified the
settlement to expand the scope of severance of contesting parties to present and
future direct interests, including capacity release agreements. The settlement
had provided the scope of the severance to be limited to present direct
interests. On February 20, 2004, Trailblazer filed a letter with the FERC
accepting the modifications to the settlement. As of March 1, 2004, all members
of the Indicated Shippers group opposing the settlement had filed to withdraw
their opposition. We do not expect the settlement to have a material effect on
our consolidated revenues in 2004 or in subsequent periods.
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 the 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 the 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 the 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 the 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.
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On May 22, 2003, KMIGT received an Order on Rehearing and Compliance Filing
(May 2003 Order) from the FERC, addressing KMIGT's November 19, 2001 filed
request for rehearing and filing to comply with the directives of the October
19, 2001 Order. The May 2003 Order granted in part and denied in part KMIGT's
request for rehearing, and directed KMIGT to file certain revised tariff sheets
consistent with the May 2003 Order's directives. On June 20, 2003, KMIGT
submitted its compliance filing reflecting revised tariff sheets in accordance
with the FERC's directives. Consistent with the May 2003 Order, KMIGT's
compliance filing reflected tariff sheets with proposed effective dates of June
1, 2003 and December 1, 2003. Those sheets with a proposed effective date of
December 1, 2003 concern tariff provisions necessitating computer system
modifications.
On November 21, 2003, KMIGT received a Letter Order (November 21 Order) from
the FERC accepting the tariff sheets submitted in the June 20, 2003 compliance
filing. In accordance with the November 21 Order, KMIGT commenced full
implementation of Order No. 637 on December 1, 2003. KMIGT's actual operating
experience under the full requirements of Order No. 637 is limited. However, we
believe that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
Separately, numerous petitioners, including KMIGT, have filed appeals in
respect 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 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.
On December 23, 2002, KMIGT filed revised tariff provisions (in a separate
docket) in compliance with the October 31, 2002 Order concerning the elimination
of the right of first refusal five-year term matching cap. In an order issued
January 22, 2003, the FERC approved such revised tariff provisions to be
effective January 23, 2003.
Trailblazer Pipeline Company
On August 15, 2000, Trailblazer Pipeline Company made a filing to comply with
the 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;
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o operational flow orders;
o penalty revenue crediting; and
o right of first refusal language.
On October 15, 2001, the FERC issued its order on Trailblazer's Order No. 637
compliance filing. The FERC approved Trailblazer's proposed language regarding
operational flow orders and rights 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 and also filed for rehearing of the October 15,
2001 order. On April 16, 2003, the FERC issued its order on Trailblazer's
compliance filing and rehearing order. The FERC denied Trailblazer's requests
for rehearing and approved the compliance filing subject to modifications that
must be made within 30 days of the order.
Trailblazer made those modifications in a further compliance filing on May
16, 2003. Certain shippers have filed a limited protest regarding that
compliance filing. That filing is pending FERC action. Under the FERC orders,
limited aspects of Trailblazer's plan (revenue crediting) were effective as of
May 1, 2003. The entire plan went into effective on December 1, 2003.
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, the 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 Kinder Morgan Interstate Gas Transmission LLC,
Trailblazer and their respective affiliates. In addition, the Notice could be
read to require separate staffing of Kinder Morgan Interstate Gas Transmission
LLC and its affiliates, and Trailblazer and its affiliates. Comments on the
Notice of Proposed Rulemaking were due December 20, 2001. Numerous parties,
including Kinder Morgan Interstate Gas Transmission LLC, have filed comment on
the Proposed Standards of Conduct Rulemaking. On May 21, 2002, the FERC held a
technical conference dealing with the FERC's proposed changes in the Standard of
Conduct Rulemaking. On June 28, 2002, Kinder Morgan Interstate Gas Transmission
LLC and numerous other parties filed additional written comments under a
procedure adopted at the technical conference.
On July 25, 2003, the FERC issued a Modification to Policy Statement stating
that FERC regulated natural gas pipelines will, on a prospective basis, no
longer be permitted to use gas basis differentials to price negotiated rate
transactions. Effectively, we will no longer be permitted to use commodity price
indices to structure transactions on our FERC regulated natural gas pipelines.
Negotiated rates based on commodity price indices in existing contracts will be
permitted to remain in effect until the end of the contract period for which
such rates were negotiated. Price indexed contracts currently constitute an
insignificant portion of our contracts on our FERC regulated natural gas
pipelines; consequently, we do not believe that this Modification to Policy
Statement will have a material impact on our operations, financial results or
cash flows.
On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate pipeline must
file a compliance plan by that date and must be in full compliance with the
Standards of Conduct by June 1, 2004. The primary change from existing
regulation is to make such standards applicable to an interstate pipeline's
interaction with many more affiliates (referred to as "energy affiliates"),
including intrastate/Hinshaw pipelines, processors and gatherers and any company
involved in natural gas or electric markets (including natural gas marketers)
even if they do not ship on the affiliated interstate pipeline. Local
distribution companies are excluded, however, if they do not make off-system
sales. The Standards of Conduct require, among other things, separate staffing
of interstate pipelines and their energy affiliates (but support functions and
senior management at the central corporate level may be shared) and strict
limitations on communications from the interstate pipeline to an energy
affiliate.
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Kinder Morgan Interstate Gas Transmission LLC filed for clarification and
rehearing of Order No. 2004 on December 29, 2003. In the request for rehearing,
Kinder Morgan Interstate Gas Transmission LLC asked that intrastate/Hinshaw
pipeline affiliates not be included in the definition of energy affiliates. To
date the FERC has not acted on these hearing requests. On February 19, 2004,
Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline Company
filed exemption requests with the FERC. The pipelines seek a limited exemption
from the requirements of Order No. 2004 for the purpose of allowing their
affiliated Hinshaw and intrastate pipelines, which are subject to state
regulation and do not make any off-system sales, to be excluded from the rule's
definition of energy affiliate. We expect the one-time costs of compliance with
the Order, assuming the request to exempt intrastate pipeline affiliates is
granted, to range from $600,000 to $700,000, to be shared between us and KMI.
On February 11, 2004, the FERC approved a final rule in Docket No. RM03-8-000
requiring jurisdictional entities to file quarterly financial reports with the
FERC. Electric utilities, natural gas companies, and licensees will file Form
3-Q, while oil pipeline companies will submit Form 6-Q. The final rule also
adopts some minimal changes to the annual financial reports filed with the FERC.
The final rule modifies the Notice of Proposed Rulemaking by eliminating the
management discussion and analysis section from both the quarterly and annual
reports, and eliminating the use of fourth quarter data in the annual report. In
addition, the final rule eliminates the cash management notification requirement
adopted in FERC Order No. 634-A. The FERC said it will also use the quarterly
financial information when reviewing the adequacy of traditional cost-based
rates. The first quarterly reports for major public utilities, licensees, and
natural gas companies will be due on July 9, 2004. The first quarterly reports
for non-major public utilities, licensees, natural gas companies, and all oil
pipeline companies will be due on July 23, 2004. After the transition period,
major public utilities, licensees and natural gas companies will file quarterly
reports 60 days after the end of the quarter; non-major public utilities,
licensees, natural gas companies, and all oil pipeline companies will file 70
days after the end of the quarter.
Cash Management
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. On June 26, 2003, FERC
issued an interim rule to be effective August 7, 2003, under which regulated
companies are required to document cash management arrangements and
transactions. The interim rule does not include a proposed rule that would have
required regulated companies, as a prerequisite to participation in cash
management programs, to maintain a proprietary capital ratio of 30% and an
investment grade credit rating. On October 22, 2003, the FERC issued its final
rule amending its regulations effective November 2003 which, among other things,
requires FERC-regulated entities to file their cash management agreements with
the FERC and to notify the FERC within 45 days after the end of the quarter when
their proprietary capital ratio drops below 30%, and when it subsequently
returns to or exceeds 30%. KMIGT and Trailblazer filed their cash management
agreements with the FERC on or before the deadline, which was December 10, 2003.
We believe that these matters, as finally adopted, will not have a material
adverse effect on our business, financial position, results of operations or
cash flows.
Other Regulatory
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, results of
operations or cash flows.
Southern Pacific Transportation Company Easements
SFPP, L.P. 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
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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). In the second quarter
of 2003, the trial court set the rent at approximately $5.0 million per year as
of January 1, 1994. SPTC has appealed the matter to the California Court of
Appeals.
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, has been
named as a defendant with several others in a series of lawsuits in the United
States District Court in Denver, Colorado and certain state courts in Colorado
and Texas. The plaintiffs include several private royalty, overriding royalty
and working interest owners at the McElmo Dome (Leadville) Unit in southwestern
Colorado. Plaintiffs in the Colorado state court action also are overriding
royalty interest owners in the Doe Canyon Unit. Plaintiffs seek to also
represent classes of claimants composed of all private and governmental royalty,
overriding royalty and working interest owners, and governmental taxing
authorities who have an interest in the carbon dioxide produced at the McElmo
Dome Unit. Plaintiffs claim they and the members of any classes that might be
certified have been damaged because the defendants have maintained a low price
for carbon dioxide in the enhanced oil recovery market in the Permian Basin and
maintained a high cost of pipeline transportation from the McElmo Dome Unit to
the Permian Basin. Plaintiffs claim breaches of contractual and potential
fiduciary duties owed by defendants and also allege other theories of liability
including:
o common law fraud;
o fraudulent concealment; and
o negligent misrepresentation.
In addition to actual or compensatory damages, certain plaintiffs are seeking
punitive or trebled damages as well as declaratory judgment for various forms of
relief, including the imposition of a constructive trust over the defendants'
interests in the Cortez Pipeline and the Partnership. 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); 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, and
Ainsworth 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. On March 24, 2003, the plaintiffs' counsel in the Shores
matter filed a Petition for Writ of Certiorari in the United States Supreme
Court seeking to have the Court review and overturn the decision of the 10th
Circuit Court of Appeals. On June 9, 2003, the United States Supreme Court
denied the Writ of Certiorari. On July 16, 2003, the settlement in the CO2
Claims Coalition, LLC, Rutter & Wilbanks, Watson, and Ainsworth cases became
final. 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 of those matters. 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
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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. On June 12, 2003, plaintiff served
discovery requests on certain defendants. On July 11, 2003, defendants moved to
stay any responses to such discovery.
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. 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 pending. 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 April 10, 2003, the court issued its decision
denying plaintiffs' motion for class certification. On July 8, 2003, a hearing
was held on the motion to amend the complaint. On July 28, 2003, the Court
granted leave to amend the complaint. The amended complaint does not list us or
any of our affiliates as defendants. Additionally, a new complaint was filed and
that complaint does not list us or any of our affiliates as defendants. We will
continue to monitor these matters.
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
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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 Claims Act. On May 7, 2003, Grynberg
sought leave to file a Third Amended Complaint, which adds allegations of
undermeasurement related to CO2 production. Defendants have filed briefs
opposing leave to amend.
Mel R. Sweatman and Paz Gas Corporation v. 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 tortious 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 to receive 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 not renew the underlying Entex contracts belonging to the Tejas/Paz joint
venture. Moreover, new and distinct allegations of breach of fiduciary and
bribery of a fiduciary are also raised in this amended petition for the first
time.
The parties have engaged in some discovery and depositions. At this stage of
discovery, we believe that our actions were justified and defensible under
applicable Texas law and that the decision not to renew the underlying gas sales
agreements was made unilaterally by persons acting on behalf of Entex. The
plaintiffs have moved for summary judgment asking the court to declare that a
fiduciary relationship existed for purposes of Sweatman's claims. We have moved
for summary judgment on the grounds that:
o there is no cause-in-fact of the gas sales nonrenewals attributable to us;
and
o the defense of legal justification applies to the claims for tortuous
interference.
In September 2003 and then again in November 2003, Sweatman and Paz filed
their third and fourth amended petitions, respectively, asserting all of the
claims for relief described above. In addition, the plaintiffs asked that the
court impose a constructive trust on (i) the proceeds of the sale of Tejas and
(ii) any monies received by any Kinder Morgan entity for sales of gas to any
Entex/Reliant entity following June 30, 2002 that replaced volumes of gas
previously sold under contracts to which Sweatman and Paz had a participating
interest pursuant to the joint venture agreement between Tejas, Sweatman and
Paz. In October 2003, the court granted, and then rescinded its order after a
motion to reconsider heard on February 13, 2004, a motion for partial summary
judgment on the issue of the existence of a fiduciary duty. We believe this suit
is without merit and we intend to defend the case 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
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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."
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"); 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
I"); Frankie Sue Galaz, et al v. City of Fallon, Exxon Mobil Corporation,;
Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc., Kinder Morgan Las
Vegas, LLC, Kinder Morgan Operating Limited Partnership "D", Kinder Morgan
Services LLC, Berry Hinkley and Does I-X, No. CV03-03613 (Second Judicial
District Court, State of Nevada, County of Washoe) ("Galaz II); Frankie Sue
Galaz, et al v. The United States of America, the City of Fallon, Exxon Mobil
Corporation,; Kinder Morgan Energy Partners, L.P., Kinder Morgan G.P., Inc.,
Kinder Morgan Las Vegas, LLC, Kinder Morgan Operating Limited Partnership "D",
Kinder Morgan Services LLC, Berry Hinkley and Does I-X, No.CVN03-0298-DWH-VPC
(United States District Court, District of Nevada)("Galaz III)
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.
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On December 3, 2002, plaintiffs filed an additional Complaint for Class
Action in the Galaz I 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 I Complaint on the grounds that it also fails to state a claim upon which
relief can be granted. This motion to dismiss was granted as to all defendants
on April 3, 2003. Plaintiffs have filed a Notice of Appeal to the United States
Court of Appeals for the 9th Circuit. On November 17, 2003, the 9th Circuit
dismissed the appeal, upholding the District Court's dismissal of the case.
On June 20, 2003, plaintiffs filed an additional Complaint for Class Action
(the "Galaz II" matter) asserting the same claims in Nevada State trial court on
behalf of the same purported class against virtually the same defendants,
including us (and excluding the United States Department of the Navy). On
September 30, 2003, the Kinder Morgan defendants filed a Motion to Dismiss the
Galaz II Complaint along with a Motion for Sanctions. On October 4, 2003,
plaintiffs' counsel agreed in writing to dismiss the Galaz II matter, but has
since withdrawn his agreement without explanation. The Kinder Morgan defendants'
Motion to Dismiss and Motion for Sanctions are currently pending.
Also on June 20, 2003, the plaintiffs in the Galaz matters filed yet another
Complaint for Class Action in the United States District Court for the District
of Nevada (the "Galaz III" matter) asserting the same claims in United States
District Court for the District of Nevada on behalf of the same purported class
against virtually the same defendants, including us. The Kinder Morgan
defendants filed a Motion to Dismiss the Galaz III matter on August 15, 2003. On
October 3, 2003, the plaintiffs filed a Motion for Withdrawal of Class Action,
which voluntarily drops the class action allegations from the matter and seeks
to have the case proceed on behalf of the Galaz family only. On December 5,
2003, the District Court granted the Kinder Morgan defendants' Motion to
Dismiss, but granted plaintiff leave to file a second Amended Complaint.
Plaintiff filed a Second Amended Complaint on December 13, 2003, and a Third
Amended Complaint on January 5, 2004. The Kinder Morgan defendants filed a
Motion to Dismiss the Third Amended Complaint on January 13, 2003, which Motion
is currently pending.
Richard Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482
(Second Judicial District Court, State of Nevada, County of Washoe) ("Jernee").
On May 30, 2003, a separate group of plaintiffs, individually and on behalf
of Adam Jernee, filed a civil action in the Nevada State trial court against us
and several Kinder Morgan related entities and individuals and additional
unrelated defendants ("Jernee"). Plaintiffs in the Jernee matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing "harmful
substances and emissions and gases" to damage "the environment and health of
human beings." Plaintiffs claim that "Adam Jernee's death was caused by leukemia
that, in turn, is believed to be due to exposure to industrial chemicals and
toxins." Plaintiffs purport to assert claims for wrongful death, premises
liability, negligence, negligence per se, intentional infliction of emotional
distress, negligent infliction of emotional distress, assault and battery,
nuisance, fraud, strict liability, and aiding and abetting, and seek unspecified
special, general and punitive damages. The Kinder Morgan defendants filed
Motions to Dismiss the complaint on November 20, 2003, which Motions are
currently pending.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the
counsel for the plaintiffs in the Jernee matter, individually and on behalf of
Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court
against us and several Kinder Morgan related entities and individuals and
additional unrelated defendants ("Sands"). Plaintiffs in the Sands matter claim
that defendants negligently and intentionally failed to inspect, repair and
replace unidentified segments of their pipeline and facilities, allowing
"harmful substances and emissions and gases" to damage "the environment and
health of human beings." Plaintiffs claim that Stephanie Suzanne Sands' death
was caused by leukemia that, in turn, is believed to be due to exposure to
industrial chemicals and toxins. Plaintiffs purport to assert claims for
wrongful death, premises liability, negligence, negligence per se, intentional
infliction of emotional distress, negligent infliction of emotional distress,
assault and battery, nuisance, fraud, strict liability, and aiding and abetting,
and seek unspecified special, general and punitive damages. The Kinder Morgan
defendants
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were served with the Complaint on January 10, 2004, and are planning to file a
Motion to Dismiss on February 26, 2004.
Based on the information available to date, our own preliminary
investigation, and the positive results of investigations conducted by State and
Federal agencies, we believe that the claims against us in the Snyder matter,
the three Galaz matters, the Jernee matter and the Sands matter are without
merit and intend to defend against them vigorously.
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.
A settlement has been reached between most of the plaintiffs and Plantation.
It is anticipated that all of the proceedings to complete the settlement will be
completed by the end of the first quarter of 2004. We believe that the ultimate
resolution of these Marion County, Mississippi cases will not have a material
effect on our business, financial position, results of operations or cash flows.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals,
Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed the Complaint in the
Superior Court of New Jersey, Gloucester County. We filed our answer to the
Complaint on June 27, 2003, in which we denied ExxonMobil's claims and
allegations as well as included counterclaims against ExxonMobil. The lawsuit
relates to environmental remediation obligations at a Paulsboro, New Jersey
liquids terminal owned by ExxonMobil from the mid-1950s through November 1989,
by GATX Terminals Corp. from 1989 through September 2000, and owned currently by
ST Services, Inc. Prior to selling the terminal to GATX Terminals, ExxonMobil
performed an environmental site assessment of the terminal required prior to
sale pursuant to state law. During the site assessment, ExxonMobil discovered
items that required remediation and the New Jersey Department of Environmental
Protection issued an order that required ExxonMobil to perform various
remediation activities to remove hydrocarbon contamination at the terminal.
ExxonMobil, we understand, is still remediating the site and has not been
removed as a responsible party from the state's cleanup order; however,
ExxonMobil claims that the remediation continues because of GATX Terminals'
storage of a fuel additive, MTBE, at the terminal during GATX Terminals'
ownership of the terminal. When GATX Terminals sold the terminal to ST Services,
the parties indemnified one another for certain environmental matters. When GATX
Terminals was sold to us, GATX Terminals' indemnification obligations, if any,
to ST Services may have passed to us. Consequently, at issue is any
indemnification obligations we may owe to ST Services in respect to
environmental remediation of MTBE at the terminal. The Complaint seeks any and
all damages related to remediating MTBE at the terminal, and, according to the
New Jersey Spill Compensation and Control Act, treble damages may be available
for actual dollars incorrectly spent by the successful party in the lawsuit for
remediating MTBE at the terminal. The parties are currently involved in
discovery.
Exxon Mobil Corporation v. Enron Gas Processing Co., Enron Corp., as party in
interest for Enron Helium Company, a division of Enron Corp., Enron Liquids
Pipeline Co., Enron Liquids Pipeline Operating Limited Partnership, Kinder
Morgan Operating L.P. "A," and Kinder Morgan, Inc., No. 2000-45252 (189th
Judicial District Court, Harris County, Texas)
On September 1, 2000, Plaintiff Exxon Mobil Corporation filed its Original
Petition and Application for Declaratory Relief against Kinder Morgan Operating
L.P. "A," Enron Liquids Pipeline Operating Limited Partnership n/k/a Kinder
Morgan Operating L.P. "A," Enron Liquids Pipeline Co. n/k/a Kinder Morgan G.P.,
Inc., Enron Gas Processing Co. n/k/a ONEOK Bushton Processing, Inc., and Enron
Helium Company. Plaintiff added Enron Corp. as party in interest for Enron
Helium Company in its First Amended Petition and added Kinder Morgan, Inc. as a
Defendant. The claims against Enron Corp. were severed into a separate cause of
action. Plaintiff's claims are based on a Gas Processing Agreement entered into
on September 23, 1987 between Mobil Oil Corp. and Enron Gas Processing Company
relating to gas produced in the Hugoton Field in Kansas and processed at
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the Bushton Plant, a natural gas processing facility located in Kansas.
Plaintiff also asserts claims relating to the Helium Extraction Agreement
entered between Enron Helium Company (a division of Enron Corp.) and Mobil Oil
Corporation dated March 14, 1988. Plaintiff alleges that Defendants failed to
deliver propane and to allocate plant products to Plaintiff as required by the
Gas Processing Agreement and originally sought damages of approximately $5.9
million.
Plaintiff filed its Third Amended Petition on February 25, 2003. In its Third
Amended Petition, Plaintiff alleges claims for breach of the Gas Processing
Agreement and the Helium Extraction Agreement, requests a declaratory judgment
and asserts claims for fraud by silence/bad faith, fraudulent inducement of the
1997 Amendment to the Gas Processing Agreement, civil conspiracy, fraud, breach
of a duty of good faith and fair dealing, negligent misrepresentation and
conversion. As of April 7, 2003, Plaintiff alleged economic damages for the
period November 1987 through March 1997 in the amount of $30.7 million. On May
2, 2003, Plaintiff added claims for the period April 1997 through February 2003
in the amount of $12.9 million. On June 23, 2003, plaintiff filed a Fourth
Amended Petition that reduced its total claim for economic damages to $30.0
million. On October 5, 2003, plaintiff filed a Fifth Amended Petition that
purported to add a cause of action for embezzlement. On February 10, 2004,
plaintiff filed its Eleventh Supplemental Responses to Requests for Disclosure
that restated its alleged economic damages for the period of November 1987
through December 2003 as approximately $37.4 million. The parties have completed
discovery and the matter is scheduled for trial on April 26, 2004. Based on the
information available to date in our investigation, the Kinder Morgan Defendants
believe that the claims against them 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
liability, and that these matters will not have a material adverse effect on our
business, financial position, results of operations or cash flows.
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,
terminal and carbon dioxide field and oil field 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;
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.
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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, results of operations or
cash flows. As of December 31, 2003, we have recorded a total reserve for
environmental claims in the amount of $39.6 million. However, 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, results of
operations or cash flows.
17. New Accounting Pronouncements
FIN 46 (revised December 2003)
In December 2003, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 46 (revised December 2003), "Consolidation of Variable
Interest Entities." This interpretation of Accounting Research Bulletin No. 51,
"Consolidated Financial Statements", addresses consolidation by business
enterprises of variable interest entities, which have one or more of the
following characteristics:
o the equity investment at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support
provided by any parties, including the equity holders;
o the equity investors lack one or more of the following essential
characteristics of a controlling financial interest:
o the direct or indirect ability to make decisions about the entity's
activities thorough voting rights or similar rights;
o the obligation to absorb the expected losses of the entity; and
o the right to receive the expected residual returns of the entity; and
o the equity investors have voting rights that are not proportionate to their
economic interests, and the activities of the entity involve or are
conducted on behalf of an investor with a disproportionately small voting
interest.
The objective of this Interpretation is not to restrict the use of variable
interest entities but to improve financial reporting by enterprises involved
with variable interest entities. The FASB believe that if a business enterprise
has a controlling financial interest in a variable interest entity, the assets,
liabilities, and results of the activities of the variable interest entity
should be included in consolidated financial statements with those of the
business enterprise.
This Interpretation explains how to identify variable interest entities and
how an enterprise assesses its interests in a variable interest entity to decide
whether to consolidate that entity. It requires existing unconsolidated variable
interest entities to be consolidated by their primary beneficiaries if the
entities do not effectively disperse risks
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among parties involved. Variable interest entities that effectively disperse
risks will not be consolidated unless a single party holds an interest or
combination of interests that effectively recombines risks that were previously
dispersed.
An enterprise that consolidates a variable interest entity is the primary
beneficiary of the variable interest entity. The primary beneficiary of a
variable interest entity is the party that absorbs a majority of the entity's
expected losses, receives a majority of its expected residual returns, or both,
as a result of holding variable interests, which are the ownership, contractual,
or other monetary interests in an entity that change with changes in the fair
value of the entity's net assets excluding variable interests. The primary
beneficiary of a variable interest entity is required to disclose:
o the nature, purpose, size and activities of the variable interest entity;
o the carrying amount and classification of consolidated assets that are
collateral for the variable interest entity's obligations; and
o any lack of recourse by creditors (or beneficial interest holders) of a
consolidated variable interest entity to the general credit of the primary
beneficiary.
In addition, an enterprise that holds significant variable interests in a
variable interest entity but is not the primary beneficiary is required to
disclose:
o the nature, purpose, size and activities of the variable interest entity;
o its exposure to loss as a result of the variable interest holder's
involvement with the entity; and
o the nature of its involvement with the entity and date when the involvement
began
Application of this Interpretation is required in financial statements of
public entities that have interests in variable interest entities or potential
variable interest entities commonly referred to as special-purpose entities for
periods ending after December 15, 2003. Application by public entities (other
than small business issuers) for all other types of entities is required in
financial statements for periods ending after March 15, 2004. We continue to
evaluate the effect from the adoption of this Statement on our consolidated
financial statements.
SFAS No. 132 (revised 2003)
In December 2003, the Financial Accounting Standards Board issued SFAS No.
132 (revised 2003), "Employers' Disclosures about Pensions and Other
Postretirement Benefits." The Statement revises and improves employers'
financial statement disclosures about defined benefit pension plans and other
postretirement benefit plans. The Statement does not change the measurement or
recognition of those plans and retains the disclosures required by the original
SFAS No. 132, which standardized the disclosure requirements for pensions and
other postretirement benefits to the extent practicable and required additional
information on changes in the benefit obligations and fair values of plans
assets.
The revised Statement requires additional disclosures to those in the
original SFAS No. 132 about the assets, obligations, cash flows, and net
periodic benefit cost of defined benefit pension plans and other defined benefit
postretirement plans. The additional disclosures have been added in response to
concerns expressed by users of financial statements; those disclosures include
information describing the types of plan assets, investment strategy,
measurement date(s), plan obligations, cash flows, and components of net
periodic benefit cost recognized during annual and interim periods.
Specifically, the additional requirements improve disclosures of relevant
accounting information by providing more information about the plan assets
available to finance benefit payments, the obligations to pay benefits, and an
entity's obligation to fund the plan, thus improving the information's
predictive value. Due to certain similarities between defined benefit pension
arrangements and arrangements for other postretirement benefits, the revised
Statement requires similar disclosures about postretirement benefits other than
pensions.
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Some of the required disclosures include the following:
o plan assets by category (i.e., debt, equity, real estate);
o investment policies and strategies;
o target allocation percentages or target ranges for plan asset categories;
o projections of future benefit payments;
o estimates of future contributions to fund pension and other postretirement
benefit plans; and
o interim disclosures of items such as (1) net periodic benefit cost
recognized during the period, including service cost, interest cost,
expected return on plan assets, prior service cost, and gain/loss due to
settlement or curtailment and (2) employer contributions paid and expected
to be paid, if significantly revised from the amounts previously disclosed.
This revised statement is effective for financial statements with fiscal
years ending after December 15, 2003. The interim period disclosures required by
this Statement are effective for interim periods beginning after December 15,
2003. Disclosure of estimated future benefit payments required by portions of
this revised Statement is effective for fiscal years ending after June 15, 2004.
The disclosures for earlier annual periods presented for comparative purposes
should be restated for:
o the percentages of each major category of plan assets held;
o the accumulated benefit obligation; and
o the assumptions used in the accounting for the plans.
However, if obtaining this information relating to earlier periods in not
practicable, the notes to the financial statements should include all available
information and identify the information not available. We do not expect the
adoption of this Statement to have any immediate effect on our consolidated
financial statements.
SFAS No. 149
In April 2003, the Financial Accounting Standards Board issued SFAS No. 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging Activities."
This Statement amends and clarifies accounting for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133.
The new guidance amends SFAS No. 133 for decisions made:
o as part of the Derivatives Implementation Group process that effectively
required amendments to SFAS No. 133;
o in connection with other Board projects dealing with financial instruments;
and
o regarding implementation issues raised in relation to the application of
the definition of a derivative, particularly regarding the meaning of an
"underlying" and the characteristics of a derivative that contains
financing components.
The amendments set forth in SFAS No. 149 are intended to improve financial
reporting by requiring that contracts with comparable characteristics be
accounted for similarly. In particular, this Statement clarifies under what
circumstances a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133. In addition, it
clarifies when a derivative contains a financing component that warrants special
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reporting in the statement of cash flows. SFAS No. 149 amends certain other
existing pronouncements. These changes are intended to result in more consistent
reporting of contracts that are derivatives in their entirety or that contain
embedded derivatives that warrant separate accounting.
This Statement is effective for contracts entered into or modified after June
30, 2003, except as stated below and for hedging relationships designated after
June 30, 2003. We will apply this guidance prospectively. We do not expect the
adoption of this Statement to have any immediate effect on our consolidated
financial statements.
We will continue to apply the provisions of this Statement that relate to
SFAS No. 133 Implementation Issues that have been effective for fiscal quarters
that began prior to June 15, 2003, in accordance with their respective effective
dates. In addition, certain provisions relating to forward purchases or sales of
"when-issued" securities or other securities that do not yet exist, will be
applied to existing contracts as well as new contracts entered into after June
30, 2003.
SFAS No. 150
In May 2003, the Financial Accounting Standards Board issued SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity." This Statement establishes standards for how an issuer
classifies and measures certain financial instruments with characteristics of
both liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as equity.
SFAS No. 150 requires an issuer to classify the following instruments as
liabilities (or assets in some circumstances):
o a financial instrument issued in the form of shares that is mandatorily
redeemable - that embodies an unconditional obligation requiring the issuer
to redeem it by transferring its assets at a specified or determinable date
(or dates) or upon an event that is certain to occur;
o a financial instrument, other than an outstanding share, that, at
inception, embodies an obligation to repurchase the issuer's equity shares,
or is indexed to such an obligation, and that requires or may require the
issuer to settle the obligation by transferring assets (for example, a
forward purchase contract or written put option on the issuer's equity
shares that is to be physically settled or net cash settled); and
o a financial instrument that embodies an unconditional obligation, or a
financial instrument other than an outstanding share that embodies a
conditional obligation, that the issuer must or may settle by issuing a
variable number of its equity shares, if, at inception, the monetary value
of the obligation is based solely or predominantly on any of the following:
o a fixed monetary amount known at inception, for example, a payable
settleable with a variable number of the issuer's equity shares;
o variations in something other than the fair value of the issuer's equity
shares, for example, a financial instrument indexed to the Standard &
Poor 500 and settleable with a variable number of the issuer's equity
shares; or
o variations inversely related to changes in the fair value of the
issuer's equity shares, for example, a written put option that could be
net share settled.
The requirements of this Statement apply to issuers' classification and
measurement of freestanding financial instruments, including those that comprise
more than one option or forward contract. This Statement does not apply to
features that are embedded in a financial instrument that is not a derivative in
its entirety. It also does not affect the classification or measurement of
convertible bonds, puttable stock, or other outstanding shares that are
conditionally redeemable. This Statement also does not address certain financial
instruments indexed partly to the issuer's equity shares and partly, but not
predominantly, to something else.
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This Statement is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of the
first interim period beginning after June 15, 2003, except for mandatorily
redeemable financial instruments of nonpublic entities. It is to be implemented
by reporting the cumulative effect of a change in accounting principle for
financial instruments created before the issuance date of the Statement and
still existing at the beginning of the interim period of adoption. Restatement
is not permitted. We will apply this guidance prospectively. We do not expect
the adoption of this Statement to have any immediate effect on our consolidated
financial statements.
SAB No. 104
On December 17, 2003, the staff of the Securities and Exchange Commission
issued Staff Accounting Bulletin No. 104, "Revenue Recognition," which
supersedes SAB No. 101, "Revenue Recognition in Financial Statements." SAB No.
104's primary purpose is to rescind the accounting guidance contained in SAB No.
101 related to multiple-element revenue arrangements that was superseded as a
result of the issuance of Emerging Issues Task Force Issues No. 00-21,
"Accounting for Revenue Arrangements with Multiple Deliverables." Additionally,
SAB No. 104 rescinds the SEC's related "Revenue Recognition in Financial
Statements Frequently Asked Questions and Answers" issued with SAB No. 101 that
had been codified in SEC Topic 13, "Revenue Recognition." While the wording of
SAB No. 104 has changed to reflect the issuance of EITF No. 00-21, the revenue
recognition principles of SAB No. 101 remain largely unchanged by the issuance
of SAB No. 104, which was effective upon issuance. The adoption of SAB No. 104
did not have a material effect on our financial position or results of
operations.
Other
In October 2003, the FASB voted to begin in 2005 requiring companies to
charge stock option costs against earnings. The new standard would mandate
expensing stock option awards just like any other form of compensation. A final
rule is expected to be formally issued in the second half of 2004. Besides the
effective date of the new rule, the FASB also decided to require companies to
use one method for making a transition toward expensing options. The transition
method decided on calls for companies to expense all at once previously granted
options as well as options issued in the year companies make the accounting
switch. In the proposed standard, companies would have the option to restate
prior results to reflect option expense. A reason for restatement would be a
company's desire for a fair year-to-year earnings comparison. If a company
chooses not to restate, it would have to recognize the cost of previously issued
but unvested options in 2005. At the current time, the FASB has not decided on
specific disclosure requirements.
18. Subsequent Events
On February 3, 2004, we announced that we had priced the public offering of
an additional 5,300,000 of our common units at a price of $46.80 per unit, less
commissions and underwriting expenses. We also granted to the underwriters an
option to purchase up to 795,000 additional common units to cover
over-allotments. On February 9, 2004, 5,300,000 common units were issued. We
received net proceeds of $237.8 million for the issuance of these common units
and we used the proceeds to reduce the borrowings under our commercial paper
program.
On February 4, 2004, we announced that we had reached an agreement with Exxon
Mobil Corporation to purchase seven refined petroleum products terminals in the
southeastern United States. The terminals are located in Collins, Mississippi,
Knoxville, Tennessee, Charlotte and Greensboro North Carolina, and Richmond,
Roanoke and Newington, Virginia. Combined, the terminals have a total storage
capacity of approximately 3.2 million barrels for gasoline, diesel fuel and jet
fuel. As part of the transaction, Exxon Mobil has entered into a long-term
contract to store products in the terminals. The acquisition enhances our
terminal operations in the Southeast and complements our December 2003
acquisition of seven products terminals from ConocoPhillips Company and Phillips
Pipe Line Company. The acquired operations will be included as part of our
Products Pipelines business segment.
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19. 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)
2003
First Quarter(a).. $1,788,838 $ 195,152 $ 170,478 $ 0.52 $ 0.52
Second Quarter.... 1,664,447 199,562 168,957 0.48 0.48
Third Quarter..... 1,650,842 204,965 174,176 0.49 0.49
Fourth Quarter.... 1,520,195 207,010 183,726 0.51 0.51
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
- ----------
(a) 2003 first quarter includes a benefit of $3,465 due to a cumulative effect
adjustment related to a change in accounting for asset retirement
obligations. Net income before cumulative effect of a change in accounting
principle was $167,013 and basic and diluted net income before cumulative
effect of a change in accounting principle was $0.50.
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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: March 5, 2004
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 March 5, 2004
--------------------- Executive Officer of Kinder
Richard D. Kinder Morgan Management, LLC, Delegate
of Kinder Morgan G.P., Inc.
/s/ EDWARD O. GAYLORD Director of Kinder Morgan March 5, 2004
--------------------- Management, LLC, Delegate of
Edward O. Gaylord Kinder Morgan G.P., Inc.
/s/ GARY L. HULTQUIST Director of Kinder Morgan March 5, 2004
--------------------- Management, LLC, Delegate of
Gary L. Hultquist Kinder Morgan G.P., Inc.
/s/ PERRY M. WAUGHTAL Director of Kinder Morgan March 5, 2004
--------------------- Management, LLC, Delegate of
Perry M. Waughtal Kinder Morgan G.P., Inc.
/s/ C. PARK SHAPER Director, Vice President and March 5, 2004
------------------ Chief Financial Officer of
C. Park Shaper Kinder Morgan Management, LLC,
Delegate of Kinder Morgan
G.P., Inc. (principal
financial officer and principal
accounting officer)
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