UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
Form 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2005
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
---------------
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 if the registrant is a well-known seasoned issuer,
as defined in Rule 405 of the Securities Act of 1933. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes [ ] No [X]
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 a large accelerated filer,
an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of
the Securities Exchange Act of 1934). Large accelerated filer [X] Accelerated
filer [ ] Non-accelerated filer [ ]
1
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No [X]
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, 2005 was
approximately $6,814,320,626. As of January 31, 2006, the registrant had
157,012,776 Common Units outstanding.
2
KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
------
PART I
Items 1 Business and Properties....................................... 4
and 2.
General Development of Business............................ 4
Business Strategy........................................ 5
Recent Developments...................................... 6
Financial Information about Segments....................... 11
Narrative Description of Business.......................... 11
Products Pipelines....................................... 11
Natural Gas Pipelines.................................... 19
CO2...................................................... 25
Terminals................................................ 29
Major Customers............................................ 33
Regulation................................................. 33
Environmental Matters...................................... 36
Other...................................................... 39
Financial Information about Geographic Areas............... 39
Available Information...................................... 39
Item 1A. Risk Factors.................................................. 39
Item 1B. Unresolved Staff Comments..................................... 46
Item 3. Legal Proceedings............................................. 46
Item 4. Submission of Matters to a Vote of Security Holders........... 46
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer
Purchases of Equity Securities........................... 47
Item 6. Selected Financial Data....................................... 48
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................... 51
Critical Accounting Policies and Estimates............... 51
Results of Operations.................................... 53
Liquidity and Capital Resources.......................... 73
Recent Accounting Pronouncements......................... 83
Information Regarding Forward-Looking Statements......... 83
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.... 85
Energy Financial Instruments............................. 85
Interest Rate Risk....................................... 87
Item 8. Financial Statements and Supplementary Data................... 88
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure...................................... 88
Item 9A. Controls and Procedures....................................... 88
Item 9B. Other Information............................................. 89
PART III
Item 10. Directors and Executive Officers of the Registrant............ 90
Directors and Executive Officers of our General Partner
and its Delegate......................................... 90
Corporate Governance..................................... 92
Section 16(a) Beneficial Ownership Reporting Compliance.. 94
Item 11. Executive Compensation........................................ 94
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.................... 100
Item 13. Certain Relationships and Related Transactions................ 102
Item 14. Principal Accounting Fees and Services........................ 102
PART IV
Item 15. Exhibits and Financial Statement Schedules.................... 104
Index to Financial Statements................................. 107
Signatures................................................................. 201
3
PART I
Items 1 and 2. Business and Properties.
In this report, unless the context requires otherwise, references to "we,"
"us," "our," "KMP" or the "Partnership" are intended to mean Kinder Morgan
Energy Partners, L.P., a Delaware limited partnership, our operating limited
partnerships and their subsidiaries. Our common units, which represent limited
partner interests in us, trade on the New York Stock Exchange under the symbol
"KMP." 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. 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
Kinder Morgan Energy Partners, L.P. is one of the largest publicly-traded
pipeline limited partnerships in the United States in terms of market
capitalization and the owner and operator of the largest independent refined
petroleum products pipeline system in the United States in terms of volumes
delivered. We own or operate approximately 27,000 miles of pipelines and
approximately 145 terminals. Our pipelines transport more than two million
barrels per day of gasoline and other petroleum products and up to 8.4 billion
cubic feet per day of natural gas. Our terminals handle over 80 million tons of
coal and other dry-bulk materials annually and have a liquids storage capacity
of almost 70 million barrels for petroleum products and chemicals. We are also
the leading independent provider of carbon dioxide for enhanced oil recovery
projects in the United States.
As of December 31, 2005, Kinder Morgan, Inc. and its consolidated
subsidiaries, referred to in this report as KMI, owned, through its general and
limited partner interests, an approximate 15.2% interest in us. KMI trades on
the New York Stock Exchange under the symbol "KMI" and is one of the largest
energy transportation and storage companies in North America, operating or
owning an interest in, either for itself or on our behalf, approximately 43,000
miles of pipelines and approximately 150 terminals. KMI and its consolidated
subsidiaries also distribute natural gas to approximately 1.1 million customers.
In addition to the distributions it receives from its limited and general
partner interests, KMI also 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
our 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 2005
distribution level, KMI received approximately 51% of all quarterly
distributions from us, with approximately 42% and 9% of all quarterly
distributions from us attributable to KMI's general partner and limited partner
interests, respectively. The actual level of distributions KMI will receive in
the future will vary with the level of distributions to our limited partners
determined in accordance with our partnership agreement.
In February 2001, Kinder Morgan Management, LLC, a Delaware limited
liability company referred to in this report 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 has 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.
KMR's shares represent limited liability company interests and trade on the
New York Stock Exchange under the symbol "KMR." Since its inception, KMR has
used substantially all of the net proceeds received from the public offerings of
its shares to purchase i-units from us, thus becoming a limited partner in 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.
4
In general, our limited partner units, consisting of 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 interim
capital transactions to our common and Class B unitholders in cash, and we pay
our quarterly distributions to KMR in additional i-units rather than in cash. As
of December 31, 2005, KMR, through its ownership of our i-units, owned
approximately 26.3% of all of our outstanding limited partner units.
Business Strategy
The objective of our business strategy is to grow our portfolio of
businesses by:
* focusing on stable, fee-based energy transportation and storage assets
that are core to the energy infrastructure of growing markets within the
United States;
* increasing utilization of our existing assets while controlling costs,
operating safely, and employing environmentally sound operating
practices;
* l everaging economies of scale from incremental acquisitions and
expansions of assets that fit within our strategy and are accretive to
cash flow and earnings; and
* maximizing the benefits of our financial structure to create and return
value to our unitholders.
Primarily, our business model consists of owning and/or operating a solid
asset base designed to generate stable, fee-based income and distributable cash
flow that together provide overall long-term value to our unitholders. We own
and manage a diversified portfolio of energy transportation and storage assets.
Our operations are conducted through our operating limited partnerships and
their subsidiaries and are grouped into four reportable business segments. These
segments are as follows:
* Products Pipelines, which consists of over 10,000 miles of refined
petroleum products pipelines that deliver gasoline, diesel fuel, jet fuel
and natural gas liquids to various markets; plus over 60 associated
product terminals and petroleum pipeline transmix processing facilities
serving customers across the United States;
* Natural Gas Pipelines, which consists of approximately 15,000 miles of
natural gas transmission pipelines and gathering lines, plus natural gas
storage, treating and processing facilities, through which natural gas is
gathered, transported, stored, treated, processed and sold;
* CO2, which produces, transports through pipelines and markets carbon
dioxide, commonly called CO2, to oil fields that use carbon dioxide to
increase production of oil; owns interests in and/or operates seven oil
fields in West Texas; and owns and operates a crude oil pipeline system
in West Texas; and
* Terminals, which consists of approximately 85 owned or operated liquids
and bulk terminal facilities and more than 50 rail transloading and
materials handling facilities located throughout the United States, that
together transload, store and deliver a wide variety of bulk, petroleum,
petrochemical and other liquids products for customers across the United
States.
Generally, as utilization of our pipelines and terminals increases, our
fee-based revenues increase. We do not face significant risks relating directly
to short-term movements in commodity prices for two principal reasons. First, we
primarily transport and/or handle products for a fee and are not engaged in
significant unmatched purchases and resales of commodity products. Second, in
those areas of our business where we do face exposure to fluctuations in
commodity prices, primarily oil production in our CO2 business segment, we
engage in a hedging program to mitigate this exposure.
It is our intention to carry out the above business strategy, modified as
necessary to reflect changing economic conditions and other circumstances.
However, as discussed under Item 1A "Risk Factors" below, there are factors
that could affect our ability to carry out our strategy or affect its level of
success even if carried out.
5
Recent Developments
The following is a brief listing of significant developments since December
31, 2004. Additional information regarding most of these items may be found
elsewhere in this report.
* Effective January 31, 2005, we acquired an approximate 64.5% gross
working interest in the Claytonville oil field unit located in Fisher
County, Texas from Aethon I L.P. for an aggregate consideration of
approximately $6.5 million, consisting of $6.2 million in cash and the
assumption of $0.3 million of liabilities. The field is located nearly 30
miles east of the SACROC unit in the Permian Basin of West Texas.
Following our acquisition, we became the operator of the field, which at
the time of acquisition was producing approximately 200 barrels of oil
per day. As of our acquisition date, and depending on further studies as
to the technical and economic feasibility of carbon dioxide injection, we
expected to invest an additional $30 million in the field in order to
increase oil production and ultimate oil recovery;
* On February 24, 2005, we received the necessary permits and approvals
from the city of Carson, California, to construct new storage tanks as
part of a major expansion of our West Coast petroleum products storage
and transfer terminal located in Carson, California. Three new storage
tanks were placed into service in the fourth quarter of 2005 and one more
was completed in January 2006. Combined, the four tanks will add
approximately 320,000 barrels of storage capacity, all of which was
previously contracted under long-term agreements with customers;
* On March 15, 2005, we closed a public offering of $500 million in
principal amount of 5.80% senior notes and repaid $200 million of 8.0%
senior notes that matured on that date. The 5.80% senior notes are due
March 15, 2035. We received proceeds from the issuance of the notes,
after underwriting discounts and commissions, of approximately $494.4
million, and we used the proceeds remaining after repayment of the 8.0%
senior notes to reduce our commercial paper debt;
* On March 24, 2005, we announced that we had settled a lawsuit for $25
million. The lawsuit was filed shortly after we acquired our Kinder
Morgan Tejas Pipeline on January 31, 2002. The plaintiffs alleged that,
in connection with our acquisition of Kinder Morgan Tejas, we wrongfully
caused natural gas volumes to be shipped on our Kinder Morgan Texas
Pipeline system instead of our Kinder Morgan Tejas system, on which the
plaintiffs had a profits interest in certain contracts. We believe that
the natural gas was shipped appropriately at the request of a customer.
However, we agreed to settle the lawsuit in order to obtain a release
from any possible claims related to the case, and we made payment in
April 2005;
* Effective April 29, 2005, we acquired seven bulk terminal operations from
Trans-Global Solutions, Inc. for an aggregate consideration of
approximately $247.2 million, consisting of $186.0 million in cash, $46.2
million in common units, and an obligation to pay an additional $15
million on April 29, 2007, two years from closing. We will settle the $15
million obligation by issuing additional common units. All of the
acquired assets are located in the State of Texas, and include facilities
at the Port of Houston, the Port of Beaumont and the TGS Deepwater
Terminal located on the Houston Ship Channel. We combined the acquired
operations into a new terminal region called the Texas Petcoke region, as
certain of the terminals have contracts in place to provide petroleum
coke handling services for major Texas oil refineries;
* On July 11, 2005, we announced a combined $48 million investment for two
major terminal expansion projects. The first involves the construction of
600,000 barrels of new storage capacity for gasoline and distillates at
our Pasadena, Texas liquids terminal located on the Houston Ship Channel.
The incremental storage is supported by long-term customer contracts. The
second project entails a capital expansion at our Shipyard River bulk
terminal, located in Charleston, South Carolina. The Shipyard project is
expected to increase the terminal's throughput by more than 30% and
enhance our ability to handle the increasing supplies of imported coal
used to meet the growing demand for electricity in the Southeast. We have
executed a long-term contract with a third party to support the economics
of the expansion. At the time of the announcement, the Shipyard terminal
handled approximately 3.5 million tons of bulk products annually, mainly
consisting of coal, petroleum coke and cement;
6
* In July 2005, we acquired four terminal facilities in separate
transactions for an aggregate consideration of approximately $45.1
million, consisting of $38.2 million in cash, $3.4 million in common
units and $3.5 million in assumed liabilities. In addition, as of our
acquisition dates, we expected to invest approximately $14 million
subsequent to acquisition in order to enhance operational efficiencies.
Specifically, the acquisitions included the following:
* $23.9 million for the Kinder Morgan Staten Island terminal, a refined
petroleum products terminal located in New York Harbor, from
ExxonMobil Oil Corporation. The terminal had storage capacity at the
date of acquisition of 2.3 million barrels for gasoline, diesel and
fuel oil. As of our acquisition date, we expected to bring several
idle tanks back into service that would add another 550,000 barrels
of capacity. In addition, we planned to rebuild a ship berth with the
ability to accommodate tanker vessels. As part of the transaction,
ExxonMobil entered into a long-term storage capacity agreement with
us and will continue to utilize a portion of the terminal;
* $8.9 million for all of the partnership interests in General
Stevedores, L.P., which owns, operates and leases barge unloading
facilities located along the Houston, Texas ship channel. Its
operations primarily consist of receiving, storing and transferring
semi-finished steel products, including coils, pipe and billets;
* $7.3 million for a dry-bulk river terminal located along the Ohio
River in Hawesville, Kentucky. The terminal primarily handles wood
chips and finished paper products. As part of the transaction, we
assumed a long-term handling agreement with Weyerhauser Company, an
international forest products company, and we planned to expand the
terminal in order to increase utilization and provide storage
services for additional products; and
* $5 million for a liquids/dry-bulk facility located in Blytheville,
Arkansas, which included storage and supporting infrastructure for
40,000 tons of anhydrous ammonia, 9,500 tons of urea ammonium nitrate
solutions and 40,000 tons of urea. As part of the transaction, we
entered into a long-term agreement to sublease all of the existing
anhydrous ammonia and urea ammonium nitrate terminal assets to Terra
Nitrogen Company, L.P. The terminal is one of only two facilities in
the United States that can handle imported fertilizer and provide
shipment west on railcars;
* Effective August 1, 2005, we acquired a natural gas storage facility in
Liberty County, Texas, from Texas Genco LLC for an aggregate
consideration of approximately $109.4 million, consisting of $52.9
million in cash and $56.5 million in assumed debt. The facility, referred
to as our North Dayton storage facility, has approximately 6.3 billion
cubic feet of total capacity, consisting of 4.2 billion cubic feet of
working capacity and 2.1 billion cubic feet of pad (cushion) gas. The
acquisition positioned us to pursue expansions at the facility that will
provide needed services to utilities, the growing liquefied natural gas
industry along the Texas Gulf Coast, and other natural gas storage users.
Additionally, as part of the transaction, we entered into a long-term
storage capacity and transportation agreement with Texas Genco, one of
the largest wholesale electric power generating companies in the United
States;
* On August 4, 2005, we announced plans for a second expansion to our
Pacific operations' East Line pipeline. In addition to our approximate
$210 million East Line expansion initially proposed in October 2002 and
which is expected to be completed by May 1, 2006, this second expansion
consists of replacing approximately 140 miles of 12-inch diameter pipe
between El Paso, Texas and Tucson, Arizona with 16-inch diameter pipe.
The project also includes the construction of additional pump stations on
the East Line. The project is expected to cost approximately $145
million. We began the permitting process for this project in September
2005, we expect construction to begin in January 2007, and we expect to
complete the expansion project in the fourth quarter of 2007;
* On August 5, 2005, we increased our five-year unsecured revolving credit
facility from a total commitment of $1.25 billion to $1.6 billion and
extended the maturity by one year to August 18, 2010. On February 22,
2006, we entered into a second credit facility: a $250 million unsecured
nine month credit facility that matures November 21, 2006. Our credit
covenants remained substantially unchanged as compared to our previous
facility. The two credit facilities primarily serve as a backup to our
commercial paper program, which had $566.2 million outstanding as of
December 31, 2005;
7
* On August 15, 2005, we announced plans to expand our Texas intrastate
natural gas pipeline system into the Permian Basin by converting an
approximate 254-mile segment of a previously acquired 24-inch diameter
Texas crude oil pipeline from carrying crude oil to natural gas. The
initial project was completed at a cost of approximately $32 million and
service was commenced in early October 2005. The expansion accesses a
number of natural gas processing plants in West Texas and provides
transportation service from McCamey, Texas to just west of Austin, Texas.
The expansion complements our 2004 conversion of a 135-mile segment of
the same pipeline between Katy and Austin, Texas, that began natural gas
service in July 2004. Approximately 95% of the 150 million cubic feet per
day of new natural gas capacity being created by this conversion project
is already supported by customer contracts. We expect to complete the
final phase of the project in the first quarter of 2006, adding both
compression and additional pipeline interconnects. Total project costs
will be approximately $46 million;
* On August 16, 2005, we completed a public offering of 5,000,000 of our
common units at a price of $51.25 per unit, less commissions and
underwriting expenses. On September 9, 2005, we issued an additional
750,000 units upon the exercise by the underwriters of an over-allotment
option. We received net proceeds of $283.6 million for the issuance of
these 5,750,000 common units and used the proceeds to reduce the
borrowings under our commercial paper program;
* On August 17, 2005, we announced that we had entered into a memorandum of
understanding with Sempra Pipelines & Storage, a unit of Sempra Energy,
to pursue development of a proposed new natural gas pipeline that would
link producing areas in the Rocky Mountain region to the upper Midwest
and Eastern United States. The 1,323-mile, 42-inch diameter Rockies
Express Pipeline project will have a capacity of up to 1.8 billion cubic
feet per day of natural gas and total project costs are expected to
exceed $4 billion. The pipeline will originate at the Cheyenne Market Hub
in northeastern Colorado and extend to the Clarington Hub in Monroe
County in eastern Ohio. Under the memorandum of understanding with
Sempra, we will operate the pipeline, but we will share responsibility
for development activities with Sempra. Initially, we will own 66 2/3% of
the equity in the proposed pipeline and Sempra will own the remaining 33
1/3% interest. Further developments with regard to the Rockies Express
Pipeline included the following:
* In October 2005, we and Sempra announced that we had entered into a
memorandum of understanding with the Wyoming Natural Gas Pipeline
Authority with regard to our development of the Rockies Express
Pipeline. Pursuant to our memorandum of understanding with the WNGPA,
the WNGPA will contract for up to 200 million cubic feet per day of
firm capacity natural gas on the proposed pipeline and explore the use
of its $1 billion in bonding authority to provide debt financing for
the project;
* In December 2005, we and Sempra announced that conforming, binding
firm commitments totaling approximately 1.3 billion cubic feet per day
of natural gas were received during open seasons held to solicit
shipper support for the Rockies Express Pipeline project and the
expansion of the Entrega Pipeline, which is discussed below. The total
commitments included agreements for 500 million cubic feet per day
from a subsidiary of EnCana Corporation and 200 million cubic feet per
day from an affiliate of Sempra Pipelines & Storage; and
* On February 28, 2006, we and Sempra announced that conforming, binding
firm commitments for all of the pipeline capacity had been secured
from shippers, and that additional agreements had been reached that
will enable the Entrega and Overthrust pipelines to connect with and
extend the reach of Rockies Express. Discussions with shippers also
indicate there is an opportunity to extend the original scope of the
project further eastward, and we will begin working shortly to secure
such commitments. We and Sempra intend to file an application in May
2006 with the Federal Energy Regulatory Commission, referred to in
this report as the FERC, for regulatory approval for the first
710-mile pipeline segment, which will run from the Cheyenne Hub to an
interconnection with Panhandle Eastern Pipeline Company in Audrain
County, Missouri. The FERC will make the final decision on the
pipeline route. In addition, in exchange for shipper commitments to
the project, we and Sempra have granted options to
June 3, 2006, to acquire equity in the project, which, if fully
exercised, could result in us owning a minimum interest of 50% and
Sempra owning a minimum interest of 25% after the project is
completed. Pending regulatory approval, service on the first segment
of the project is expected to commence on January 1,
8
2008. The second segment of the project, which is planned to be in
service in January 2009, will continue to the Lebanon Hub in Ohio.
The third segment, continuing service to the Clarington Hub is
expected to be in operation no later than June 2009.
* On September 22, 2005, we announced the start of a binding open season
for our proposed Kinder Morgan Louisiana Pipeline. The pipeline would
provide approximately 3.2 billion cubic feet per day of take-away natural
gas capacity from the Cheniere Sabine Pass liquefied natural gas (LNG)
plant now under construction in Cameron Parish, Louisiana. We plan to
invest approximately $500 million to build this interstate natural gas
pipeline that will originate at the Sabine Pass LNG terminal and extend
into Evangeline Parish, Louisiana. The Kinder Morgan Louisiana Pipeline
will consist of two segments: (i) a 137-mile large diameter pipeline with
firm capacity of about 2.0 billion cubic feet per day of natural gas that
will connect to various interstate and intrastate pipelines within
Louisiana, and (ii) a 1-mile pipeline with firm capacity of about 1.2
billion cubic feet per day that will connect to KMI's Natural Gas
Pipeline Company of America's natural gas pipeline. In November 2005, we
announced that Total Gas & Power North America, Inc. and Chevron U.S.A.
had signed binding precedent agreements for 100% of the initial pipeline
capacity for a term of 20 years and were awarded all of the open season
capacity. Pending various shipper and regulatory approvals, the lateral
segment of the pipeline that will interconnect with KMI's pipeline is
projected to be in service by October 1, 2008;
* Effective November 4, 2005, we acquired a bulk terminal facility from
Allied Terminals, Inc. for an aggregate consideration of approximately
$13.3 million, consisting of $12.1 million in cash and $1.2 million in
assumed liabilities. The facility, located adjacent to our Shipyard River
bulk terminal in Charleston, South Carolina, primarily stores refined
petroleum products and chemicals, and also offers dock services to
accommodate a variety of barges and vessels. The acquired assets included
16 liquids storage tanks with a total capacity of 1.2 million barrels.
The acquisition complemented an ongoing capital expansion project at our
Shipyard River terminal. The Shipyard expansion will allow the terminal
to handle increasing supplies of imported coal and cement, and together
with the Allied acquisition, offers significant opportunities for future
expansion;
* On November 8, 2005, we completed a public offering of 2,600,000 of our
common units at a price of $51.75 per unit, less commissions and
underwriting expenses. We received net proceeds of $130.1 million for the
issuance of these common units and used the proceeds to reduce the
borrowings under our commercial paper program;
* On November 15, 2005, we announced that we and Sempra had entered into a
purchase and sale agreement with EnCana Corporation for its Entrega Gas
Pipeline. Effective February 23, 2006, Rockies Express Pipeline LLC
acquired Entrega Gas Pipeline LLC for $240.0 million in cash. We
contributed $160.0 million, which corresponded to our 66 2/3% ownership
interest in Rockies Express Pipeline LLC. Sempra Energy holds the
remaining 33 1/3% ownership interest and contributed $80.0 million. The
Entrega Gas Pipeline is an interstate natural gas pipeline that will
consist of two segments: (i) a 136-mile, 36-inch diameter pipeline that
extends from the Meeker Hub in Rio Blanco County, Colorado to the
Wamsutter Hub in Sweetwater County, Wyoming, and (ii) a 191-mile, 42-inch
diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub
in Weld County, Colorado, where it will ultimately connect with the
Rockies Express Pipeline (discussed above). In combination, the Entrega
and Rockies Express pipelines have the potential to create a major new
natural gas transmission pipeline that will provide seamless
transportation of natural gas from Rocky Mountain production areas to
Midwest and eastern Ohio markets. EnCana completed construction of the
first segment of the pipeline, and under the terms of the purchase and
sale agreement, we and Sempra will construct the second segment. It is
anticipated that the entire Entrega system will be placed into service by
January 1, 2007;
* On November 21, 2005, we announced that we, Sempra and Questar
Corporation had entered into a memorandum of understanding with
Overthrust Pipeline Company, a Questar subsidiary, to enter into a
long-term capacity lease for up to 1.5 billion cubic feet per day of
natural gas to support the extension and expansion of the
above-mentioned Entrega Gas Pipeline. As of February 28, 2006, we have
executed binding definitive agreements with Overthrust for a long-term
lease of 625 million cubic feet per day of natural gas capacity. The
proposed extension of the Entrega system would run approximately 140
miles west of the
9
Wamsutter Hub to the Opal Hub in Lincoln County, Wyoming. The expected
in-service date of the extension is January 1, 2008. Under the capacity
lease agreement, Overthrust will transport natural gas received from the
Opal Hub, various pipeline interconnects, and gas processing plants and
deliver it to the Entrega Pipeline at the Wamsutter Hub. Overthrust
plans to construct new pipeline interconnects to physically connect with
Entrega at Wamsutter and to add compression to handle the capacity lease
quantity. Approval from the FERC is required to construct these
facilities. The expected in service date of the new facilities and
effective date of the capacity lease will coincide with the anticipated
start of service on the first segment of the Rockies Express Pipeline,
discussed above;
* On December 13, 2005, we announced that we expect to declare cash
distributions of $3.28 per unit for 2006, a 5% increase over our cash
distributions of $3.13 per unit for 2005. This expectation includes
contributions from assets owned by us as of the announcement date and
does not include any potential benefits from unidentified acquisitions;
* On December 16, 2005, the FERC issued an order addressing two cases: (i)
the phase two initial decision, issued September 9, 2004, which would
establish the basis for prospective rates and the calculation of
reparations for complaining shippers with respect to our Pacific
operations' West Line and East Line pipelines, and (ii) certain cost of
service issues remanded to the FERC by the United States Court of Appeals
for the District of Columbia Circuit in its July 2004 BP West Coast
Products v. FERC opinion, including the level of income tax allowance
that our Pacific operations is entitled to include in its interstate
rates. In the order, the FERC reversed a number of findings of the
administrative law judge unfavorable to us on significant phase two cost
issues and, on the income tax allowance, the FERC ruled favorably on our
entitlement to a tax allowance, though additional procedural steps remain
ahead. We recognized a $105.0 million non-cash expense attributable to an
increase in our reserves related to our rate case liability. We filed a
request for rehearing of the December 16, 2005 order and certain shippers
have filed petitions for review of the order with the United States Court
of Appeals for the District of Columbia Circuit. On February 13, 2006,
the FERC ruled favorably on the majority of matters raised by us in our
rehearing request. The December 16, 2005 order did not address the FERC's
March 2004 phase one rulings on the grandfathered state of our Pacific
operations' rates that are currently pending on appeal before the
District of Columbia Circuit Court of Appeals. For additional
information, see Note 16 to our consolidated financial statements;
* During 2005, we spent $863.1 million for additions to our property, plant
and equipment, including both expansion ($722.3 million) and maintenance
projects ($140.8 million). Our capital expenditures included the
following:
* $302.1 million in our CO2 segment, mostly related to additional
infrastructure, including wells and injection and compression
facilities, to support the expanding carbon dioxide flooding
operations at the SACROC and Yates oil field units in West Texas;
* $271.5 million in our Products Pipelines segment, mostly related to
expansion work on our Pacific operations' East Line products pipeline
and to storage and expansion projects at our combined Carson/Los
Angeles Harbor terminal system;
* $186.6 million in our Terminals segment, largely related to expanding
the petroleum products storage capacity at our liquids terminal
facilities and to various expansion projects and improvements
undertaken at multiple bulk terminal facilities; and
* $102.9 million in our Natural Gas Pipelines segment, mostly related
to completing the conversion and start up of our McCamey to Austin,
Texas intrastate natural gas pipeline, an expansion on the northern
portion of our TransColorado Pipeline, and various natural gas
storage facility expansions and improvements; and
* On January 12, 2006, we announced a major expansion project that will
provide additional infrastructure to help meet the growing need for
terminal services in key markets along the East Coast. The investment of
approximately $45 million includes the construction of new liquids
storage tanks at our Perth Amboy, New Jersey liquids terminal located
along the Arthur Kill River in the New York Harbor area. The Perth
10
Amboy expansion will involve the construction of nine new storage tanks
with a capacity of 1.4 million barrels for gasoline, diesel and jet
fuel. The expansion was driven by continued strong demand for refined
products in the Northeast, much of which is being met by imported fuel
arriving via the New York Harbor. The new tanks are expected to be in
service during the first quarter of 2007.
(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 our refined petroleum products
and natural gas liquids pipelines and their associated terminals, our Southeast
terminals and our transmix processing facilities.
Pacific Operations
Our Pacific operations include our SFPP, L.P. operations, our CALNEV
Pipeline operations and our West Coast terminals operations. The assets include
interstate common carrier pipelines regulated by the FERC, intrastate pipelines
in the State of California regulated by the California Public Utilities
Commission, and certain non rate-regulated operations and terminal facilities.
Our Pacific operations serve six western states with approximately 3,200
miles of refined petroleum products pipelines and related terminal facilities
that provide refined products to some of the fastest growing population centers
in the United States, including California; Las Vegas and Reno, Nevada; and the
Phoenix-Tucson, Arizona corridor. For 2005, the three main product types
transported were gasoline (59%), diesel fuel (23%) and jet fuel (18%).
Our Pacific operations' pipeline system consists of seven pipeline segments,
which include the following:
* the West Line, which consists of approximately 705 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. Products for the West Line also come through
the Los Angeles and Long Beach port complexes;
* the East Line, which is comprised of two parallel pipelines, 8-inch
diameter and 12-inch diameter, 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.
Products received by the East Line at El Paso come from a refinery in El
Paso. Additional products are received through inter-connections with
non-affiliated pipelines;
* the San Diego Line, which 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 CALNEV Line, which consists of two parallel 248-mile, 14-inch and
8-inch diameter pipelines that run from our facilities at Colton,
California to Las Vegas, Nevada. It also includes approximately 55 miles
of pipeline serving Edwards Air Force Base;
* the North Line, which consists of approximately 864 miles of trunk
pipeline in five segments that transport products from Richmond and
Concord, California to 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;
11
* the Bakersfield Line, which is a 100-mile, 8-inch diameter pipeline
serving Fresno, California; and
* the Oregon Line, which is a 114-mile pipeline transporting products to
Eugene, Oregon for 13 shippers from marine terminals in Portland, Oregon
and from the Olympic Pipeline.
We have embarked on two major expansions of the East Line. The first
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 project also includes
the construction of a major origin pump station and tank farm. The project is
estimated to cost $210 million and is scheduled to be completed by May 1, 2006.
The second expansion consists of replacing approximately 140 miles of 12-inch
diameter pipe between El Paso, Texas and Tucson, Arizona with 16-inch diameter
pipe, and also includes the construction of additional pump stations. The
project is expected to cost approximately $145 million and is scheduled to be
completed in the fourth quarter of 2007.
Our Pacific operation's West Coast terminals are fee-based terminals located
in several strategic locations along the west coast of the United States with a
combined total capacity of approximately 8.3 million barrels of storage for both
petroleum products and chemicals. The Carson terminal and the connected Los
Angeles Harbor terminal are 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.
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. We
also have two petroleum product terminals located in Portland, Oregon and one in
Seattle, Washington.
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 16
million barrels. The truck terminals provide services including short-term
product storage, truck loading, vapor handling, additive injection, dye
injection and oxygenate blending.
Markets. Combined, our Pacific operations' pipelines transport over 1.1
million barrels per day of refined petroleum products, providing pipeline
service to approximately 39 customer-owned terminals, 11 commercial airports and
14 military bases. Currently, our Pacific operations' pipelines serve
approximately 85 shippers in the refined petroleum products market; the largest
customers being major petroleum companies, independent refiners, and the United
States military.
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 one million
barrels per day. The Arizona gasoline market, which is served primarily by us,
is approximately 167,000 barrels per day. Nevada's gasoline market is
approximately 64,000 barrels per day and Oregon's is approximately 100,000
barrels per day. The diesel and jet fuel market is approximately 526,000 barrels
per day in California, 83,000 barrels per day in Arizona, 48,000 barrels per day
in Nevada and 52,000 barrels per day in Oregon.
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.
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 from waterborne terminals located near
these refining centers.
12
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 terminal and trucking arrangements within our market
areas. We believe that high capital costs, tariff regulation, and environmental
and right-of-way 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 individual
pipelines being constructed or expanded 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 continues to compete for
short haul movements by pipeline. The State of California mandated the
elimination of methyl tertiary-butyl ether, used as an additive in gasoline and
referred to in this report as MTBE, from gasoline by January 1, 2004. The
mandated elimination of MTBE and subsequent substitution of ethanol in
California gasoline has 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 began
transporting refined products from refineries on the Gulf Coast to El Paso and
other destinations in Texas in late 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, although this will change with the implementation of the
December 16, 2005 FERC order in our Pacific operations' rate case and the East
Line expansion. Our East Line is currently running at capacity and we have under
construction facilities to increase East Line capacity to meet market demand.
The planned capacity increase will require significant investment which may,
under the FERC cost of service methodology, result in a more balanced tariff
between our East and West Line pipelines, depending on volumes. Such shift of
supply sourcing has not had, and is not expected to have, a material effect on
our operating results.
Our Pacific operation's terminals compete with terminals owned by our
shippers and by third party terminal operators in Sacramento, San Jose,
Stockton, Colton, Orange County, Mission Valley, and San Diego, California,
Phoenix and Tucson, Arizona and Las Vegas, Nevada. Short haul trucking from the
refinery centers is also a competitive factor to terminals close to the
refineries. Competitors of our 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. Competition to our Richmond
terminal's chemical business comes primarily from IMTT. Competitors to our
Portland, Oregon terminals include ST Services, ChevronTexaco and Shell Oil
Products U.S. Competitors to our Seattle petroleum products terminal primarily
include BP and Shell.
Plantation Pipe Line Company
We own approximately 51% of Plantation Pipe Line Company, a 3,100-mile
refined petroleum products pipeline system serving the southeastern United
States. An affiliate of ExxonMobil owns the remaining 49% ownership interest.
ExxonMobil is the largest shipper on the Plantation system both in terms of
volumes and revenues. We operate the system 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 2005, Plantation delivered an average of 595,248 barrels per
day of refined petroleum products. These delivered volumes were comprised of
gasoline (65%), diesel/heating oil (22%) and jet fuel (13%). Average delivery
volumes for 2005 were 4% lower than the 620,363 barrels per day delivered during
2004. The decrease was predominantly driven by numerous refinery outages and
other supply disruptions related to hurricanes Dennis and Katrina.
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 five shippers
represent slightly over 79% of total system volumes.
13
The eight states in which Plantation operates represent a collective
pipeline demand of approximately two million barrels per day of refined
petroleum 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
another pipeline company. 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 decreased 4.3% in 2005 compared to 2004, due primarily to a 38%
decrease in shipments to Charlotte-Douglas International airport, which was
largely the result of air carriers realizing lower wholesale prices on jet fuel
transported by competing pipelines.
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.
Central Florida Pipeline
Our 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 Petroleum. The 10-inch diameter pipeline is connected to our Taft,
Florida terminal (located near Orlando) and is also the sole pipeline supplying
jet fuel to the Orlando International Airport in Orlando, Florida. In 2005, the
pipeline system transported approximately 112,000 barrels per day of refined
products, with the product mix being approximately 68% gasoline, 14% diesel
fuel, and 18% jet fuel.
We also own and operate liquids terminals in Tampa and Taft, Florida. The
Tampa terminal contains approximately 1.4 million barrels of storage capacity
and is connected to two ship dock facilities in the Port of Tampa. 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
railcar and loaded onto trucks through five truck-loading racks. The Taft
terminal contains approximately 0.7 million barrels of storage capacity,
providing storage for gasoline and diesel fuel for further movement into trucks
through 13 truck-loading racks.
Markets. The estimated total refined petroleum products demand in the State
of Florida is approximately 800,000 barrels per day. Gasoline is, by far, the
largest component of that demand at approximately 545,000 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
approximately 360,000 barrels per day, or 45% of the consumption of refined
products in the state. We distribute approximately 150,000 barrels of refined
petroleum products per day including the Tampa terminal truck loadings. 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 in March and April
during spring break and again in the summer vacation season, and is also heavily
influenced by tourism, with Disney World and other amusement parks located in
Orlando.
Supply. The vast majority of refined petroleum products consumed in Florida
is supplied 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 petroleum 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
14
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 Central Florida pipeline system, the most
significant competitors are trucking firms and marine transportation firms.
Trucking transportation is more competitive in serving markets close to the
marine terminals on the east and west coasts 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.
We believe it is unlikely that a new pipeline system comparable in size and
scope to our Central Florida Pipeline system will be constructed, due to the
high cost of pipeline construction, tariff regulation and environmental and
right-of-way permitting in Florida. However, the possibility of such a pipeline
or a smaller capacity pipeline being built is a continuing competitive factor.
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 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.
Federal regulation of marine vessels, including the requirement, under the
Jones Act, that United States-flagged vessels contain double-hulls, is a
significant factor influencing the availability of vessels that 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.
North System
Our North System consists of an approximate 1,600-mile interstate common
carrier pipeline system that delivers natural gas liquids and refined petroleum
products for approximately 50 shippers from south central Kansas 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, which requires us to pay approximately $2.3 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, Kansas. 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.
We also own a 50% ownership interest in the Heartland Pipeline Company,
which owns the Heartland pipeline system, a natural gas liquids pipeline that
ships refined petroleum products in the Midwest. We include our equity interest
in Heartland as part of our North System operations. ConocoPhillips owns the
remaining 50% interest in the Heartland Pipeline Company. The Heartland pipeline
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.
Heartland leases to ConocoPhillips 100% of the Heartland terminal capacity at
Des Moines 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 2006 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.
15
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 the 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.
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.
During 2005, utilizing line-fill acquired in 2004, the North System was able
to satisfy shippers' needs and avoid a decline in throughput volumes due to a
lack of product supplies, as experienced in previous years. In an effort to
obtain the greatest benefit from line-fill on a year round basis, the product
distribution was restructured in 2005, adding isobutane as a component of
line-fill, increasing the proportion of normal butane and reducing the
proportion of propane. We believe this restructured line-fill will help mitigate
the operational constraints that could result from shippers holding reduced
inventory levels at any point in the year.
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. With respect to the Chicago market, our
North System competes with other natural gas liquids pipelines that deliver into
the area and with railcar 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 products
carriers in the geographic market served. Heartland's principal competitor is
Magellan Midstream Partners, L.P.
Cochin Pipeline System
We own 49.8% of the Cochin pipeline system, a joint venture that operates an
approximate 1,900-mile, 12-inch diameter multi-product pipeline operating
between Fort Saskatchewan, Alberta and Sarnia, Ontario, including five
terminals. Effective October 1, 2004, we acquired our most recent ownership
interest (5%) from subsidiaries of ConocoPhillips. An affiliate of BP owns the
remaining 50.2% ownership interest and is the operator of the pipeline.
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. 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 FERC (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 BP, EnerPro or Dow
fractionation facilities at Fort Saskatchewan, Alberta; from Provident Energy
storage at five points within the provinces of Canada; or from the Enterprise
West Junction, in Minnesota.
16
Competition. The pipeline competes with railcars and Enbridge Energy
Partners for natural gas liquids long-haul 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 natural gas liquids
pipeline originating at storage facilities in Mont Belvieu, Texas and extending
104 miles east to a major petrochemical producer in 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 natural gas liquids from major producing areas in Texas, New Mexico,
Louisiana, Oklahoma and the Mid-Continent Region supply ethane and
ethane/propane mix to Mont Belvieu.
Competition. The pipeline's primary competition into the Lake Charles market
comes from Louisiana onshore and offshore natural gas liquids.
Southeast Terminals
Our Southeast terminal operations consist of Kinder Morgan Southeast
Terminals LLC and its consolidated affiliate, Guilford County Terminal Company,
LLC. Kinder Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred
to in this report 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.
Since December 2003, KMST has acquired 23 petroleum products terminals for
an aggregate consideration of approximately $141.4 million, consisting of
approximately $134.7 million in cash and $6.7 million in assumed liabilities.
The 23 terminals have a total storage capacity of approximately 7.6 million
barrels and together, transferred approximately 348,000 barrels of refined
products per day during 2005.
The 23 terminals consist of the following:
* seven petroleum products terminals acquired from ConocoPhillips and
Phillips Pipe Line Company in December 2003. 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. The terminals contain
approximately 1.2 million barrels of storage capacity. ConocoPhillips has
entered into a long-term contract with us to use the terminals. All seven
terminals are served by the Colonial Pipeline and three are also
connected to the Plantation Pipeline;
* seven petroleum products terminals acquired from Exxon Mobil Corporation
in March 2004. The terminals are located 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. All seven of these terminals are connected to products
pipelines owned by either Plantation Pipe Line Company or Colonial
Pipeline Company; and
17
* nine petroleum products terminals acquired from Charter Terminal Company
and Charter-Triad Terminals in November 2004. Three terminals are located
in Selma, North Carolina, and the remaining facilities are located in
Greensboro and Charlotte, North Carolina; Chesapeake and Richmond,
Virginia; Athens, Georgia; and North Augusta, South Carolina. The
terminals have a combined storage capacity of approximately 3.2 million
barrels for gasoline, jet fuel and diesel fuel. We fully own seven of the
terminals and jointly own the remaining two. All nine terminals are
connected to Plantation or Colonial pipelines.
During 2005, KMST expanded its terminal located in Collins, Mississippi,
adding an incremental 80,000 barrels of gasoline storage and one new truck
loading lane. The expansion project was completed and began service in January
2006.
Markets. KMST's acquisition and marketing activities are focused on the
Southeastern United States from Mississippi through Virginia, including
Tennessee. The primary function involves the receipt of petroleum products from
common carrier pipelines, short-term storage in terminal tankage, and subsequent
loading onto tank trucks. KMST has a physical presence in markets representing
almost 80% of the pipeline-supplied demand in the Southeast and offers a
competitive alternative to marketers seeking a relationship with a truly
independent truck terminal service provider.
Supply. Product supply is predominately from Plantation and/or Colonial
pipelines. To the maximum extent practicable, we endeavor to connect KMST
terminals to both Plantation and Colonial.
Competition. There are relatively few independent terminal operators in the
Southeast. Most of the refined petroleum products terminals in this region are
owned by large oil companies (BP, Motiva, Citgo, Marathon, 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 and TransMontaigne Product
Services represent the other independent terminal operators in this region.
Transmix Operations
Our Transmix operations include the processing of petroleum pipeline
transmix, a blend of dissimilar refined petroleum products that have become
co-mingled in the pipeline transportation process. During transportation,
different products are transported through the pipelines abutting each other,
and the volume of different mixed products is called transmix. At our transmix
processing facilities, we process and separate pipeline transmix into
pipeline-quality gasoline and light distillate products. We process transmix at
five separate processing facilities located in Colton, California; Richmond,
Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; and Wood River,
Illinois.
At our Dorsey Junction, Maryland facility, transmix processing is performed
for Colonial Pipeline Company on a "for fee" basis pursuant to a long-term
contract that expires in 2012. We process transmix on a "for fee" basis for
Shell Trading (U.S.) Company, referred to as Shell, according to the provisions
of a long-term contract that expires in 2011 at our transmix facilities located
in Richmond, Virginia; Indianola, Pennsylvania; and Wood River, Illinois. At
these locations, Shell procures transmix supply from pipelines and other
parties, pays a processing fee to us, and then sells the processed gasoline and
fuel oil through their marketing and distribution networks. The arrangement
includes a minimum annual processing volume and a per barrel fee to us, as well
as an opportunity to extend the processing agreement beyond 2011.
At our Colton, California facility, we process transmix on a "for fee" basis
for Duke Energy Merchants pursuant to a long-term contract that expires in 2010.
The Colton processing facility is located adjacent to our products terminal in
Colton, California, and it 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 of
transmix per day.
Our Richmond processing facility is supplied by the Colonial and Plantation
pipelines as well as deep-water barges (25 feet draft), transport truck and
rail. The facility can process approximately 7,500 barrels per day. Our Dorsey
Junction processing facility is located within Colonial's Dorsey Junction
terminal facility, near Baltimore, Maryland. The facility can process
approximately 5,000 barrels per day. Our Indianola processing facility is
18
located near Pittsburgh, Pennsylvania and is accessible by truck, barge and
pipeline. It primarily processes transmix from the Buckeye, Colonial, Sun and
Teppco pipelines. It has capacity to process 12,000 barrels of transmix per day.
Our Wood River processing facility is constructed on property owned by
ConocoPhillips and is accessible by truck, barge and pipeline. It primarily
processes transmix from both the Explorer and ConocoPhillips pipelines. It has
capacity to process 5,000 barrels of transmix per day.
Markets. The Gulf and East Coast refined petroleum products distribution
system, particularly the Mid-Atlantic region, is 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 Illinois and Pennsylvania assets,
respectively. Our West Coast transmix processing operations support the markets
served by our Pacific operations.
Supply. Transmix generated by Colonial, Plantation, Sun, Teppco, Explorer
and our Pacific operations provide the vast majority of the supply. These
suppliers are committed to the use of our transmix facilities under long-term
contracts. Individual shippers and terminal operators provide additional supply.
Duke Energy Merchants is responsible for acquiring transmix supply at Colton,
and Shell acquires transmix for processing at Indianola, Richmond and Wood
River. The Dorsey Junction facility is supplied by Colonial Pipeline Company.
Competition. Placid Refining is our main competitor in the Gulf Coast area.
There are various processors in the Mid-Continent area, primarily
ConocoPhillips, Gladieux Refining and Williams Energy Services, who compete with
our transmix facilities. 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 sales, transportation, storage,
gathering, processing and treating. Within this segment, we own approximately
15,000 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.
Texas Intrastate Natural Gas Pipeline Group
The group, which operates primarily along the Texas Gulf Coast, consists of
the following four natural gas pipeline systems:
* our Kinder Morgan Texas Pipeline;
* our Kinder Morgan Tejas Pipeline;
* our Mier-Monterrey Mexico Pipeline; and
* our Kinder Morgan North Texas Pipeline.
The two largest systems in the group are our Kinder Morgan Texas Pipeline,
acquired on December 31, 1999 from KMI, and our Kinder Morgan Tejas Pipeline,
acquired on January 31, 2002. These pipelines essentially operate as a single
pipeline system, providing customers and suppliers with improved flexibility and
reliability. The combined system includes approximately 6,000 miles of
intrastate natural gas pipelines with a peak transport and sales capacity of
approximately five billion cubic feet per day of natural gas and approximately
120 billion cubic feet of on system contracted 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).
In addition, the system, through owned assets and contractual arrangements with
third parties, has the capability to process 915 million cubic feet per day of
natural gas for liquids extraction and to treat approximately 250 million cubic
feet per day of natural gas for carbon dioxide removal.
19
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 and fuel costs.
Our Mier-Monterrey Pipeline, completed in March 2003, consists of a 95-mile,
30-inch diameter natural gas pipeline that stretches from south Texas to
Monterrey, Mexico and can transport up to 375 million cubic feet per day. 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.
Our North Texas Pipeline, completed in August 2002, 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 million cubic feet
per day of natural gas and is fully subscribed under a 30 year contract. In
2005, we completed an interconnection with the facilities of ETC and the
existing system was enhanced to be bi-directional in February 2006, so that
deliveries of additional supply coming out of the Barnett Shale area can be
delivered into NGPL's pipeline as well as power plants in the area.
We also own and operate 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 or third-party facilities. We own two processing
plants: our Texas City Plant in Galveston County, Texas and our Galveston Bay
Plant in Chambers County, Texas, which is currently idle. Combined, these plants
can process 115 million cubic feet per day of natural gas for liquids
extraction. In addition, we have contractual rights to process approximately 800
million cubic feet per day of natural gas at various third-party owned
facilities. We also own and operate three natural gas treating plants that offer
carbon dioxide and/or hydrogen sulfide removal. We can treat up to 155 million
cubic feet per day of natural gas for carbon dioxide removal at our Fandango
Complex in Zapata County, Texas, 50 million cubic feet per day of natural gas at
our Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic
feet per day of natural gas at our Thompsonville Facility located in Jim Hogg
County, Texas.
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 provide transportation service into and out of the facility.
In August 2005, we acquired our North Dayton natural gas storage facility
located in Liberty County, Texas from Texas Genco LLC for an aggregate
consideration of approximately $109.4 million, consisting of $52.9 million in
cash and $56.5 million in assumed debt. The North Dayton facility has
approximately 6.3 billion cubic feet of total capacity, consisting of 4.2
billion cubic feet of working capacity and 2.1 billion cubic feet of pad gas. As
part of the transaction, we entered into a long-term storage capacity and
transportation agreement with Texas Genco covering two billion cubic feet of
natural gas working capacity that expires in March 2017. We own in fee the land
at our Dayton facility, and there is an existing leaching system, which has been
idle, that can be used to develop additional capacity. Currently, we are
overhauling the leaching system back to operating mode and further expansion
options are being evaluated.
Additionally, we lease a salt dome storage facility located near Markham,
Texas. The facility consists of three salt dome caverns with approximately 12.8
billion cubic feet of total natural gas storage capacity, over 8.1 billion cubic
feet of working natural gas capacity and up to 750 million cubic feet per day of
peak deliverability. In April 2005, we put in service a third leased cavern
which increased working capacity by four billion cubic feet of natural gas, with
working capacity expected to be increased by two billion cubic feet of natural
gas in 2006. As part of the project, an additional 4,700 horsepower of
compression was added to increase injection capability by an average of
90 million cubic feet per day, and additional dehydration and other facilities
were added to increase natural gas deliverability from 500 million cubic feet
per day to 750 million cubic feet per day. We also lease salt dome caverns from
Dow Hydrocarbon & Resources, Inc. and BP America Production Company in Brazoria
County, Texas. The
20
salt dome caverns are referred to as the Stratton Ridge Facilities and have a
combined capacity of 11.2 billion cubic feet of natural gas, working natural gas
capacity of 6.7 billion cubic feet and a peak day deliverability of up to 400
million cubic feet per day.
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 certain of these new generation facilities to our pipeline
systems in order to maintain our share of natural gas supply for power
generation.
We serve the Mexico market through interconnection with the facilities of
Pemex at the United States-Mexico border near Arguellas, Mexico and Monterrey,
Mexico. In 2005, deliveries through the existing interconnection near Arguellas
fluctuated from zero to approximately 238 million cubic feet per day of natural
gas, and there were several days of exports to the United States which ranged up
to 250 million cubic feet per day. Deliveries to Monterrey also generally ranged
from zero to 330 million cubic feet per day. 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.
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 in this report as
KMIGT, along with our Trailblazer Pipeline Company and our TransColorado Gas
Transmission Company (both discussed following) comprise our three Rocky
Mountain interstate natural gas pipeline systems. As of December 31, 2005, the
combined peak transport capacity for our Rocky Mountain pipeline systems was
approximately 2.7 billion cubic feet per day of natural gas, and the combined
firm contracted storage capacity was approximately 10 billion cubic feet of
natural gas.
KMIGT owns approximately 5,100 miles of transmission lines in Wyoming,
Colorado, Kansas, Missouri and Nebraska. The pipeline system is powered by 28
transmission and storage compressor stations with approximately 160,000
horsepower. KMIGT also owns the Huntsman natural gas storage facility, located
in Cheyenne County, Nebraska, and which has approximately 10 billion cubic feet
of firm capacity commitments and provides for withdrawal of up to 169 million
cubic feet of natural gas per day.
Under transportation agreements and FERC tariff provisions, KMIGT offers its
customers firm and interruptible transportation and storage services, including
no-notice transportation and park and loan services. Under KMIGT's tariffs, firm
transportation and storage customers pay reservation fees each month plus a
commodity charge based on the actual transported or stored volumes. In contrast,
interruptible transportation and storage customers pay a commodity charge based
upon actual transported and/or stored volumes. 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. KMIGT also has the authority to make gas
purchases and sales, as needed for system operations, pursuant to its currently
effective FERC gas tariff.
21
On June 1, 2004, KMIGT implemented its Cheyenne Market Center service, which
provides nominated storage and transportation service between its Huntsman
storage field and multiple interconnecting pipelines at the Cheyenne Hub,
located in Weld County, Colorado. This service is fully subscribed for a period
of ten years and added an incremental withdrawal capacity of 60.9 million cubic
feet of natural gas per day and increased the working gas capacity by 3.5
billion cubic feet.
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 of 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 to power pumps for crop irrigation during the summer
from time-to-time exceeds heating season demand and provides KMIGT relatively
consistent volumes throughout the year. In addition, KMIGT has seen a
significant increase in demand from ethanol producers, and is actively seeking
ways to meet the demands from the ethanol producing community.
Supply. Approximately 12%, by volume, of KMIGT's firm contracts expire
within one year and 59% expire within one to five years. Our affiliates 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.
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
Our Trailblazer Pipeline Company owns a 436-mile natural gas pipeline system
that 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 it interconnects with Natural Gas
Pipeline Company of America's and Northern Natural Gas Company's pipeline
systems. Natural Gas Pipeline Company of America, a subsidiary of KMI, manages,
maintains and operates Trailblazer, for which it is reimbursed at cost.
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.
Trailblazer provides transportation services to third-party natural gas
producers, marketers, local distribution companies and other shippers. Pursuant
to transportation agreements and FERC tariff provisions, Trailblazer offers its
customers firm and interruptible transportation. Under Trailblazer's tariffs,
firm transportation customers pay reservation charges each month plus a
commodity charge based on actual volumes transported. Interruptible
transportation customers pay a commodity charge based upon actual volumes
transported.
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.
Supply. As of December 31, 2005, less than 1% of Trailblazer's firm
contracts, by volume, expire before one year and 36%, 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.
22
Competition. 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 addition,
Colorado Interstate Gas Company's Cheyenne Plains Pipeline can transport
approximately 560 million cubic feet per day of natural gas from Weld County,
Colorado to Greensburg, Kansas and competes with Trailblazer for natural gas
pipeline transportation demand from the Rocky Mountain area. Cheyenne Plains has
received approval from the FERC to expand its facilities to provide for an
additional 170 million cubic feet per day of capacity for a total capacity of
730 million cubic feet. The proposed expansion is anticipated to go into service
in early 2006. Additional competition could come from proposed pipeline projects
such as El Paso's Continental Connector and our own Rockies Express Pipeline. No
assurance can be given that additional competing pipelines will not be developed
in the future.
TransColorado Gas Transmission Company
Our TransColorado Gas Transmission Company owns a 300-mile interstate
natural gas pipeline that extends from approximately 20 miles southwest of
Meeker, Colorado to Bloomfield, New Mexico. It has 20 points of interconnection
with seven interstate pipelines, one intrastate pipeline, eight gathering
systems, and two local distribution companies. The pipeline system is powered by
five compressor stations in mainline service having an aggregate of
approximately 26,500 horsepower. KMI manages, maintains and operates
TransColorado, for which it is reimbursed at cost. We acquired all of the
ownership interests in TransColorado from KMI effective November 1, 2004.
TransColorado has the ability to flow gas south or north. Gas flowing south
through the pipeline moves onto the El Paso, Transwestern and Southern Trail
pipeline systems. TransColorado receives gas from two coal seam natural gas
treating plants located in the San Juan Basin of Colorado and from pipeline and
gathering system interconnections within the Paradox and Piceance Basins of
western Colorado. Gas moving north flows into our Entrega Pipeline at the Meeker
Hub and will ultimately be able to move to the Cheyenne Hub and into our Rockies
Express Pipeline. TransColorado provides transportation services to third-party
natural gas producers, marketers, gathering companies, local distribution
companies and other shippers. Pursuant to transportation agreements and FERC
tariff provisions, TransColorado offers its customers firm and interruptible
transportation and interruptible park and loan services. Under TransColorado's
tariffs, firm transportation customers pay reservation charges each month plus a
commodity charge based on actual volumes transported. Interruptible
transportation customers pay a commodity charge based upon actual volumes
transported. The underlying reservation and commodity charges are assessed
pursuant to a maximum recourse rate structure, which does not vary based on the
distance gas is transported. TransColorado has the authority to negotiate rates
with customers if it has first offered service to those customers under its
reservation and commodity charge rate structure.
On February 27, 2006, we announced the beginning of a binding open season to
solicit shipper support for firm natural gas transportation capacity on a
proposed expansion of our TransColorado Pipeline. The expansion would link
TransColorado with several major interstate and intrastate pipelines, including
the Entrega Pipeline, thereby facilitating access to the Rockies Express
Pipeline. As designed, the project would increase northbound capacity on
TransColorado by approximately 250 million cubic feet of natural gas per day. A
prearranged shipper has executed a binding precedent agreement for capacity on
the project. The total expansion project is expected to cost approximately $48
million.
Markets. TransColorado acts principally as a feeder pipeline system from the
developing natural gas supply basins on the Western Slope of Colorado into the
interstate natural gas pipelines that lead away from the Blanco Hub area of New
Mexico and the interstate natural gas pipelines that lead away eastward from
northwestern Colorado and southwestern Wyoming. TransColorado is the largest
transporter of natural gas from the Western Slope supply basins of Colorado and
provides a competitively attractive outlet for that developing natural gas
resource. In 2005, TransColorado transported an average of approximately 670
million cubic feet per day of natural gas from these supply basins, an increase
of 29% over the previous year. This increase in throughput is further evidence
of TransColorado's strategic positioning to the underdeveloped gas supply
resources on the Western Slope of Colorado and the greater southwestern United
States marketplace.
Supply. During 2005, 87% of TransColorado's transport business was with
producers or their own marketing affiliates and 13% was with gathering
companies. Approximately 74% of TransColorado's transport business in
23
2005 was conducted with its two largest customers. All of TransColorado's
southbound pipeline capacity is committed under firm transportation contracts
that extend at least through year-end 2007. TransColorado's pipeline capacity is
79% subscribed during 2007 through 2011 and TransColorado is actively pursuing
contract extensions and or replacement contracts to increase firm subscription
levels beyond 2007. TransColorado's north system expansion project was completed
in 2005 and was in-service on January 1, 2006. The expansion provides for up to
300 million cubic feet per day of additional northbound transportation capacity.
The project was supported by a long-term contract with Williams that runs
through 2015 with an option for a five-year extension.
Competition. TransColorado competes with other transporters of natural gas
in each of the natural gas supply basins it serves. These competitors include
both interstate and intrastate natural gas pipelines and natural gas gathering
systems. TransColorado's shippers compete for market share with shippers drawing
upon gas production facilities within the New Mexico portion of the San Juan
Basin. TransColorado has phased its past construction and expansion efforts to
coincide with the ability of the interstate pipeline grid at Blanco, New Mexico
to accommodate greater natural gas volumes. TransColorado's transport
concurrently ramped up over that period such that TransColorado now enjoys a
growing share of the outlet from the San Juan Basin to the southwestern United
States marketplace.
Historically, the competition faced by TransColorado with respect to its
natural gas transportation services has generally been based upon the price
differential between the San Juan and Rocky Mountain basins. The Kern River Gas
Transmission expansion project, placed in service in May 2003, has had the
effect of reducing that price differential. However, given the increased number
of direct connections to production facilities in the Piceance and Paradox
basins and the gas supply development in each of those basins, we believe that
TransColorado's transport business will be less susceptible to changes in the
price differential in the future.
Casper and Douglas Natural Gas Gathering and Processing Systems
We own and operate our Casper and Douglas natural gas gathering systems,
which are comprised of over 1,500 miles of natural gas gathering pipelines and
two facilities in Wyoming capable of processing 210 million cubic feet of
natural gas per day. The Douglas gathering system is comprised of approximately
1,500 miles of 4-inch to 16-inch diameter pipe that gathers approximately 26
million cubic feet per day of natural gas from 650 active receipt points.
Douglas Gathering has an aggregate 20,650 horsepower of compression situated at
17 field compressor stations. Gathered volumes are processed at our Douglas
plant, located in Douglas, Wyoming. Residue gas is delivered into KMIGT and
recovered liquids are injected in ConocoPhillips Petroleum's natural gas liquids
pipeline for transport to Borger, Texas.
The Casper gathering system is comprised of approximately 32 miles of 4-inch
to 8-inch diameter pipeline gathering approximately four million cubic feet per
day of natural gas from four 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.
Markets. Casper and Douglas are processing plants servicing gas streams
flowing into KMIGT. 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.
Competition. Other regional facilities in the Greater Powder River Basin
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
Merit Energy. Casper and Douglas, however, are the only plants which provide
straddle processing of natural gas flowing into KMIGT.
Red Cedar Gathering Company
We own a 49% equity interest in the Red Cedar Gathering Company, a joint
venture organized in August 1994 and referred to in this report as Red Cedar.
The remaining 51% interest in Red Cedar is owned by the Southern Ute Indian
Tribe. 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.
24
Red Cedar's gas gathering system currently consists of over 1,100 miles of
gathering pipeline connecting more than 850 producing wells, 85,000 horsepower
of compression at 24 field compressor stations and two carbon dioxide treating
plants. A majority of the natural gas on the system moves through 8-inch to
16-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 in
this report as Coyote Gulch. Coyote Gulch is a joint venture that was organized
in December 1996. Enterprise Field Services LLC 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
in this report 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 of Wyoming. Throughput volumes include
both coal seam and conventional plant residue gas. Thunder Creek is
independently operated from offices located in Denver, Colorado with field
offices in Glenrock and Gillette, Wyoming.
Thunder Creek's operations are a combination of mainline and low pressure
gathering assets. The mainline assets include 125 miles of 24-inch diameter
mainline pipeline, 230 miles of 4-inch to 12-inch diameter high and low pressure
laterals, 23,000 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
47 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 191
miles of 4-inch to 14-inch diameter gathering pipeline and 35,400 horsepower of
field compression. Gas is gathered from 91 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 in this report 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. We also hold ownership interests in several
oil-producing fields and own a 450-mile crude oil pipeline, all located in the
Permian Basin region of West Texas.
25
Carbon Dioxide Reserves
We own approximately 45% of, and operate, the McElmo Dome unit, which
contains more than ten trillion cubic feet of 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 52
wells that produce at individual rates of up to 55 million cubic feet per day.
We also own approximately 11% of the Bravo Dome unit, which contains reserves of
approximately two trillion cubic feet of carbon dioxide. The Bravo Dome produces
approximately 303 million cubic feet per day, with production coming from more
than 350 wells in the Tubb Sandstone at 2,300 feet.
Markets. Our principal market for carbon dioxide is for injection into
mature oil fields in the Permian Basin, where industry demand is expected to
grow modestly for the next several years. We are exploring additional potential
markets, including enhanced oil recovery targets in California, Mexico, and
Canada, 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. 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
Our Central Basin pipeline consists of approximately 143 miles of 16-inch to
26-inch diameter pipe and 177 miles of 4-inch to 12-inch lateral supply lines
located in the Permian Basin between Denver City, Texas and McCamey, Texas with
a throughput capacity of 600 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 Trinity CO2, 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 300 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% equity interest in and operate the approximate 500-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 of carbon dioxide per day,
including approximately 95% 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 approximately 98% of the Canyon Reef Carriers pipeline
and approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline
extends 139 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. It has a capacity of approximately 120 million cubic feet per day
of carbon dioxide and makes deliveries to the Yates unit. The tariffs charged on
the Canyon Reef Carriers and Pecos pipelines are not regulated.
26
Markets. The principal market for transportation on our carbon dioxide
pipelines is to customers, including ourselves, using carbon dioxide for
enhanced recovery operations in mature oil fields in the Permian Basin, where
industry demand is expected to grow modestly for the next several years.
Competition. Our ownership interests in the Central Basin, Cortez and Bravo
pipelines are in direct competition with other carbon dioxide pipelines. We also
compete with other interest owners in McElmo Dome and Bravo Dome for
transportation of carbon dioxide to the Denver City, Texas market area.
Oil Reserves
KMCO2 also holds ownership 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 21% net profits interest in the H.T. Boyd unit, an
approximate 65% working interest in the Claytonville unit and lesser 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.
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 56,000 acres located in the Permian Basin in Scurry County, Texas.
SACROC was discovered in 1948 and has produced over 1.29 billion barrels of oil
since inception. It is estimated that SACROC originally held approximately 2.7
billion barrels of oil. We have expanded the development of the carbon dioxide
project initiated by the previous owners and increased production over the last
several years. We now own an approximate 97% ownership interest in the SACROC
field unit.
As of December 2005, the SACROC unit had 354 producing wells, and the
purchased carbon dioxide injection rate was 258 million cubic feet per day, down
from an average of 339 million cubic feet per day as of December 2004. The
average oil production rate for 2005 was approximately 32,000 barrels of oil per
day, up from an average of approximately 28,000 barrels of oil per day during
2004.
The Yates unit is also one of the largest oil fields ever discovered in the
United States. It is estimated that it originally held more than five billion
barrels of oil, of which about 28% has been produced. The field, discovered in
1926, is comprised of approximately 26,000 acres located about 90 miles south of
Midland, Texas. 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 also acquired the crude
oil gathering lines and equipment surrounding the Yates field. We now own a
nearly 50% ownership interest in the Yates field unit.
Our plan has been 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. We are implementing our plan and
as of December 2005, the Yates unit was producing about 24,000 barrels of oil
per day. As of December 2004, the Yates unit was producing approximately 22,000
barrels of oil per day. Unlike our operations at SACROC, where we use carbon
dioxide and water to drive oil to the producing wells, we are 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.
Effective January 31, 2005, we acquired an approximate 64.5% gross working
interest in the Claytonville oil field unit located in Fisher County, Texas from
Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in
the Permian Basin of West Texas. Our purchase price was approximately $6.5
million, consisting of $6.2 million in cash and the assumption of $0.3 million
of liabilities. Following our acquisition, we became the operator of the field,
which at the time of acquisition was producing approximately 200 barrels of oil
per day. As of December 31, 2005, pending further studies as to the technical
and economic feasibility of carbon dioxide injection, we may invest an
additional $30 million in the field in order to increase production and ultimate
oil recovery.
Oil Acreage and Wells
The following table sets forth productive wells, service wells and drilling
wells in the oil and gas fields in which we own interests as of December 31,
2005. When used with respect to acres or wells, gross refers to the total acres
27
or wells in which we have a working interest; net refers to gross acres or wells
multiplied, in each case, by the percentage working interest owned by us:
Productive Wells (a) Service Wells (b) Drilling Wells (c)
------------------------ --------------------- ---------------------
Gross Net Gross Net Gross Net
---------- --------- ------ -------- ------- ---------
Crude Oil............ 2,538 1,535 976 730 2 2
Natural Gas.......... 9 4 27 13 - -
---------- --------- ------ -------- ------- ---------
Total Wells........ 2,547 1,539 1,003 743 2 2
========== ========= ====== ======== ======= =========
- ----------
(a) Includes active wells and wells temporarily shut-in. As of December 31,
2005, we did not operate any gross wells with multiple completions.
(b) Consists of injection, water supply, disposal wells and service wells
temporarily shut-in. A disposal well is used for disposal of saltwater into
an underground formation; a service well is a well drilled in a known oil
field in order to inject liquids that enhance recovery or dispose of salt
water.
(c) Consists of development wells in the process of being drilled as of
December 31, 2005. A development well is a well drilled in an already
discovered oil field.
The oil and gas producing fields in which we own interests are located in
the Permian Basin area of West Texas. The following table reflects our net
productive and dry wells that were completed in each of the three years ended
December 31, 2005, 2004 and 2003:
2005 2004 2003
---------- --------- -------
Productive
Development............... 42 31 69
Exploratory............... - - -
Dry
Development............... - - -
Exploratory............... - - -
---------- --------- -------
Total Wells................. 42 31 69
========== ========= =======
- ----------
Notes: The above table includes wells that were completed during each year
regardless of the year in which drilling was initiated, and does not
include any wells where drilling operations were not completed as of the
end of the applicable year. Also, the table includes our previous 15%
equity interest in MKM Partners, L.P. MKM Partners, L.P was dissolved on
June 30, 2003. Development wells include wells drilled in the proved area
of an oil or gas resevoir.
The following table reflects the developed and undeveloped oil and gas
acreage that we held as of December 31, 2005:
Gross Net
-------------- --------------
Developed Acres............. 67,047 62,388
Undeveloped Acres........... 8,788 8,131
-------------- --------------
Total..................... 75,835 70,519
============== ==============
Operating Statistics
Operating statistics from our oil and gas producing activities for each of
the years 2005, 2004 and 2003 are shown in the following table:
Results of Operations for Oil and Gas Producing Activities - Unit Prices and Costs
Year Ended December 31,
---------------------------------------
Consolidated Companies(a) 2005 2004 2003
----------- ----------- -----------
Production costs per barrel of oil equivalent(b)(c)(d) $ 10.00 $ 9.71 $ 8.98
=========== =========== ===========
Crude oil production (MBbl/d)........................ 37.9 32.5 18.0
=========== =========== ===========
Natural Gas liquids production (MBbl/d)(d)........... 5.3 3.7 1.3
Natural gas liquids production from gas plants
(MBbl/d)(e)......................................... 4.1 4.0 2.4
----------- ----------- -----------
Total natural gas liquids production (MBbl/d)...... 9.4 7.7 3.7
=========== =========== ===========
Natural gas production (MMcf/d)(d)(f)................ 3.7 4.4 1.6
Natural gas production from gas plants(MMcf/d)(e)(f). 3.1 3.9 2.0
----------- ----------- -----------
Total natural gas production(MMcf/d)(f)............ 6.8 8.3 3.6
=========== =========== ===========
Average Sales prices including hedge gains/losses:
Crude oil price per Bbl............................ $ 27.36 $ 25.72 $ 23.73
=========== =========== ===========
Natural gas liquids price per Bbl.................. $ 38.79 $ 31.37 $ 22.49
=========== =========== ===========
Natural gas price per Mcf.......................... $ 5.84 $ 5.27 $ 4.40
=========== =========== ===========
Total natural gas liquids price per Bbl(e)......... $ 38.98 $ 31.33 $ 21.77
=========== =========== ===========
Total natural gas price per Mcf(e) $ 5.80 $ 5.24 $ 4.50
=========== =========== ===========
Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl............................ $ 54.45 $ 40.91 $ 31.26
=========== =========== ===========
Natural gas liquids price per Bbl.................. $ 38.79 $ 31.68 $ 24.70
=========== =========== ===========
Natural gas price per Mcf $ 5.84 $ 5.27 $ 4.40
=========== =========== ===========
----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) Computed using production costs, excluding transportation costs, as defined
by the Securities and Exchange Commission. Natural gas volumes were
converted to barrels of oil equivalent (BOE) using a conversion factor of
six mcf of natural gas to one barrel of oil.
(c) Production costs include labor, repairs and maintenance, materials,
supplies, fuel and power, property taxes, severance taxes, and general and
administrative expenses directly related to oil and gas producing
activities.
(d) Includes only production attributable to leasehold ownership.
(e) Includes production attributable to our ownership in processing plants and
third party processing agreements.
(f) Excludes natural gas production used as fuel.
See Note 20 to our consolidated financial statements included in this report
for additional information with respect to our oil and gas producing activities.
Gas Plant Interests
We operate and own an approximate 22% working interest plus 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. We became
the operator of the Diamond M gas plant on August 1, 2005. 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
28
Snyder plant to process gas. Production of natural gas liquids at the Snyder
gasoline plant as of December 2005 was approximately 15,000 barrels per day, up
from approximately 13,400 barrels per day as of December 2004.
Crude Oil Pipeline
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline,
L.P. The acquisition included a 450-mile crude oil pipeline system, consisting
of four mainline sections, numerous gathering systems and truck off-loading
stations. The mainline sections are all located within the State of Texas, and
the 20-inch diameter segment that runs from Wink to El Paso has a total capacity
of 115,000 barrels of crude oil per day. As part of the transaction, we entered
into a long-term throughput agreement with Western Refining Company, L.P. to
transport crude oil into Western's 107,000 barrel per day refinery in El Paso.
The acquisition allows us to better manage crude oil deliveries from our oil
field interests in West Texas. As of December 31, 2005, the 20-inch pipeline
segment transported approximately 107,000 barrels of oil per day. The Wink
Pipeline is regulated by the FERC.
Terminals
Our Terminals segment includes the operations of our petroleum and
petrochemical-related liquids terminal facilities (other than those included in
our Products Pipelines segment) as well as all of our coal and dry-bulk material
services, including all transload, engineering and other in-plant services.
Combined, the segment is composed of approximately 85 owned or operated liquids
and bulk terminal facilities, and more than 50 rail transloading and materials
handling facilities located throughout the United States. In 2005, the number of
customers from whom our Terminals segment received more than $0.1 million of
revenue was approximately 500.
Liquids Terminals
Our liquids terminal operations primarily store refined petroleum products,
petrochemicals, industrial chemicals, and vegetable oil products, in aboveground
storage tanks and transfer products to and from pipelines, tank trucks, tank
barges, and tank railcars. Combined, our liquids terminal facilities possess
liquids storage capacity of approximately 42.4 million barrels, and in 2005,
these terminals handled approximately 551.5 million barrels of clean petroleum,
petrochemical and vegetable oil products. Our major liquids terminal assets are
described below.
Our Houston, Texas terminal complex is located in Pasadena and Galena Park,
Texas, along the Houston Ship Channel. Recognized as a distribution hub for
Houston's refineries situated on or near the Houston Ship Channel, the Pasadena
and Galena Park terminals are the western Gulf Coast refining community's
central interchange point. The complex has approximately 18.9 million barrels of
capacity and is connected via pipeline to 14 refineries, four petrochemical
plants and ten major outbound pipelines. Since our acquisition of the terminal
complex in January 2001, we have added more than three million barrels of new
storage capacity, as refinery outputs along the Gulf Coast have continued to
increase. We have also upgraded our pipeline manifold connection with the
Colonial pipeline system, added pipeline connections to new refineries and
expanded our truck rack. In addition, the facilities have four ship docks and
seven barge docks for inbound and outbound movement of products. The terminals
are served by the Union Pacific railroad.
We own three liquids facilities in the New York Harbor area: one in
Carteret, New Jersey, one in Perth Amboy, New Jersey, and one on Staten Island,
New York. The Carteret facility is located along the Arthur Kill River just
south of New York City and has a capacity of approximately 7.7 million barrels
of petroleum and petrochemical products, of which 1.1 million barrels have been
added since our acquisition of the Carteret terminal in January 2001. In
addition, in October 2003, we completed the construction of a new 16-inch
diameter pipeline at Carteret that connects to the Buckeye pipeline system, a
major products pipeline serving the East Coast. Our Carteret facility has two
ship docks and four barge docks. It is connected to the Colonial, Buckeye, Sun
and Harbor pipeline systems, and the CSX and Norfolk Southern railroads service
the facility. The Perth Amboy facility is also located along the Arthur Kill
River and has a capacity of approximately 2.3 million barrels of petroleum and
petrochemical products. Tank sizes range from 2,000 barrels to 300,000 barrels.
The Perth Amboy terminal provides chemical and petroleum storage and handling,
as well as dry-bulk handling of salt and aggregates. In addition to providing
product movement via vessel, truck and rail, Perth Amboy has direct access to
the Buckeye and Colonial pipelines. The facility has one ship dock and one barge
dock, and is connected to the CSX and Norfolk Southern railroads.
29
Our two New Jersey facilities offer a viable alternative for moving
petroleum products between the refineries and terminals throughout the New York
Harbor and both are New York Mercantile Exchange delivery points for gasoline
and heating oil. Both facilities are connected to the Intra Harbor Transfer
Service, an operation that offers direct outbound pipeline connections that
allow product to be moved from over 20 Harbor delivery points to destinations
north and west of New York City.
In July 2005, we acquired the Kinder Morgan Staten Island terminal from
ExxonMobil Oil Corporation. Located on Staten Island, New York, the facility is
bounded to the north and west by the Arthur Kill River and covers approximately
200 acres, of which 120 acres are used for site operations. The terminal has a
storage capacity of approximately three million barrels for gasoline, diesel
fuel and fuel oil. The facility also maintains and operates an above ground
piping network to transfer petroleum products throughout the operating portion
of the site, and we are currently rebuilding a ship berth at the facility that
will accommodate tanker vessels.
We own two liquids terminal facilities in the Chicago area: one facility is
located in Argo, Illinois, approximately 14 miles southwest of downtown Chicago,
and the other is located in the Port of Chicago along the Calumet River. The
Argo facility is a large throughput fuel ethanol facility and a major break bulk
facility for large chemical manufacturers and distributors. It 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, and has a direct connection to Midway Airport. The Canadian
National railroad services this facility. The Port of Chicago facility handles a
wide variety of liquids chemicals with a working capacity of approximately
741,000 barrels in tanks ranging from 12,000 gallons to 55,000 barrels. The
facility provides access to a full slate of transportation options, including a
deep water barge/ship berth on Lake Calumet, and offers services including truck
loading and off-loading, iso-container handling and drumming. There are two ship
docks and four barge docks, and the facility is served by the Norfolk Southern
railroad.
Two of our other largest liquids facilities are located in South Louisiana:
our Port of New Orleans facility located in Harvey, Louisiana, and our St.
Gabriel terminal, located near a major petrochemical complex in Geismar,
Louisiana. The New Orleans facility handles a variety of liquids products such
as chemicals, vegetable oils, animal fats, alcohols and oil field products. It
has approximately three 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 can be accessed
by vessel, barge, tank truck, or rail, and also provides ancillary services
including drumming, packaging, warehousing, and cold storage services.
Our St. Gabriel facility is located approximately 75 miles north of the New
Orleans facility on the bank of the Mississippi River near the town of St.
Gabriel, Louisiana. The facility has approximately 340,000 barrels of tank
capacity and the tanks vary in sizes ranging from 1,500 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.
Competition. We are one of the largest independent operators of liquids
terminals in North America. Our primary competitors are Magellan, Kaneb, IMTT,
Vopak, Oil Tanking, TransMontaigne, and Savage Industries.
Bulk Terminals
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, railcar switching services, ship agency and miscellaneous marine
services. Combined, our dry-bulk and material transloading facilities handled
approximately 83.2 million tons of coal, petroleum coke and other dry-bulk
materials in 2005. We own or operate approximately 28 petroleum coke or coal
terminals in the United States. Our major bulk terminal assets are described
below.
In 2005, we handled approximately 12.3 million tons of petroleum coke.
Petroleum coke is a by-product of the crude oil refining process and has
characteristics similar to coal. It is used in domestic utility and industrial
steam generation facilities, and it is exported to foreign markets. It is also
used by the steel industry in the manufacture of ferro alloys, and for the
manufacture of carbon and graphite products. Petroleum coke supply in the United
States
30
has increased in the last several years due to an increasingly heavy crude oil
supply and to the increased use of coking units by domestic refineries. Most of
our customers are large integrated oil companies that choose to outsource the
storage and loading of petroleum coke for a fee.
In April 2005, we acquired certain petroleum coke terminal operations from
Trans-Global Solutions, Inc. for an aggregate consideration of approximately
$247.2 million, consisting of $186.0 million in cash, $46.2 million in common
units, and an obligation to pay an additional $15 million on April 29, 2007, two
years from closing. All of the acquired assets are located in the State of
Texas, and include facilities at the Port of Houston, the Port of Beaumont and
the TGS Deepwater Terminal located on the Houston Ship Channel. The facilities
also provide handling and storage services for a variety of other bulk
materials.
In 2005, we also handled approximately 28.6 million tons of coal. 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.
Our Cora terminal is a high-speed, rail-to-barge coal transfer and storage
facility. 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. It has a throughput capacity of about 10 million tons per year and is
currently 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. Our Cora terminal sits on the mainline of the
Union Pacific Railroad and is strategically positioned to receive coal shipments
from the western United States.
Our Grand Rivers terminal is a coal transloading and storage facility
located along the Tennessee River just above the Kentucky Dam. The terminal is
operated on land under easements with an initial expiration of July 2014 and has
current annual throughput capacity of approximately 12 million tons with a
storage capacity of approximately one million tons. 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.
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 two terminals will be primarily due to
increased use of western low sulfur coal originating in Wyoming, Colorado and
Utah.
Our Pier IX terminal is located in Newport News, Virginia. The terminal 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. For coal, the
terminal offers blending services and rail to storage or direct transfer to
ship; for other dry bulk products, the terminal offers ship to storage to rail
or truck. Our Pier IX Terminal exports coal to foreign markets, serves power
plants on the eastern seaboard of the United States, and imports cement pursuant
to a long-term contract. The terminal operates a cement facility which has the
capacity to transload over 400,000 tons of cement annually. Since early-2004,
Pier IX has also operated two synfuel plants on site, which together produced
3.3 million tons of synfuel in 2005. 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.
Our Shipyard River Terminal is located in Charleston, South Carolina.
Shipyard is able to unload, store and reload coal imported from various foreign
countries. The imported coal is often a cleaner-burning, low-sulfur coal and it
is used by local utilities to comply with the U.S. Clean Air Act. Shipyard River
Terminal has the capacity to handle approximately 2.5 million tons of coal and
petroleum coke per year and offers approximately 300,000 tons of total storage
of which 50,000 tons are under roof. We are currently expanding our Shipyard
River terminal in order to increase the terminal's throughput and to allow for
the handling of increasing supplies of imported coal. In November 2005, we
acquired additional land and terminal assets for use at our Shipyard River
facility from Allied Terminals, Inc. for an aggregate consideration of $13.3
million.
31
Our Kinder Morgan Tampaplex terminal, a marine terminal acquired in December
2003 and located in Tampa, Florida, 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 terminal also
includes an inland bulk storage warehouse facility used for overflow cargoes
from our Port Sutton import terminal, which is also located in Tampa. Port
Sutton sits on 16 acres of land and offers 200,000 tons of covered storage.
Primary products handled in 2005 included fertilizers, salt, ores, and liquid
chemicals. Also in the Tampa Bay area are our Port Manatee and Hartford Street
terminals. Port Manatee has four warehouses which can store 130,000 tons of bulk
products. Products handled at Port Manatee include fertilizers, ores and other
general cargo. At our Hartford Street terminal, anhydrous ammonia and
fertilizers are handled and stored in two warehouses with an aggregate capacity
of 23,000 net tons.
In December 2004, we acquired substantially all of the assets used to
operate the major port distribution facility located at the Fairless Industrial
Park in Bucks County, Pennsylvania. Located on the bend of the Delaware River
below Trenton, New Jersey, the terminal is referred to as our Kinder Morgan
Fairless Hills terminal. It is the largest port on the East Coast for the
handling of semi-finished steel slabs. The facility also handles other types of
specialized cargo that caters to the construction industry and service centers
that use steel sheet and plate. The port has four ship berths with a total
length of 2,200 feet and a maximum draft of 38.5 feet. It contains two mobile
harbor cranes and is served by connections to two Class I rail lines: CSX and
Norfolk Southern.
Our Pinney Dock terminal is located in Ashtabula, Ohio along Lake Erie. It
handles iron ore, titanium ore, magnetite and other aggregates. Pinney Dock has
six docks with 15,000 feet of vessel berthing space, 200 acres of outside
storage space, 400,000 feet of warehouse space and two 45-ton gantry cranes.
Our Chesapeake Bay bulk terminal facility is located at Sparrows Point,
Maryland. It offers stevedoring services, storage, and rail, ground, or water
transportation for products such as coal, petroleum coke, iron and steel slag,
and other mineral products. It offers both warehouse and approximately 100 acres
of open storage.
Our Milwaukee and Dakota dry-bulk commodity facilities are located in
Milwaukee, Wisconsin and St. Paul, Minnesota, respectively. The Milwaukee
terminal is located on 34 acres of property leased from the Port of Milwaukee.
Its major cargoes are coal and bulk de-icing salt. The Dakota terminal is on 55
acres in St. Paul and primarily handles salt and grain products. In the fourth
quarter of 2004, we completed the construction of a $19 million cement loading
facility at the Dakota terminal. The loading facility was built for unloading
cement from barges and railcars, conveying and storing product, and loading and
weighing trucks and railcars. It covers nearly nine acres and can handle
approximately 400,000 tons of cement each year.
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. 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. Our Cora and Grand
Rivers coal terminals compete with two third-party coal terminals that also
serve the Midwest United States. While our Cora and Grand Rivers terminals are
modern high capacity coal terminals, some volume is diverted to these
third-party terminals by the Tennessee Valley Authority in order to promote
increased competition. Our Pier IX terminal competes primarily with two modern
coal terminals located in the same Virginian port complex as our Pier IX
terminal.
Materials Services (rail transloading)
Our materials services operations primarily include the rail-transloading
operations owned by Kinder Morgan Materials Services LLC, referred to as KMMS.
KMMS operates approximately 50 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 these terminal
facilities. Approximately 50% of the products handled by KMMS are liquids,
including an entire spectrum of liquid chemicals, and 50% are dry bulk products.
Many of the facilities are equipped for bi-modal operation (rail-to-truck, and
truck-to-rail). KMMS also designs and builds transloading facilities, performs
inventory management services, and provides value-added services such as
blending, heating and sparging. In 2005, and our materials services region
handled approximately 73,000 railcars.
32
Major Customers
Our total operating revenues are derived from a wide customer base. For the
year ended December 31, 2005, no revenues from transactions with a single
external customer accounted for 10% or more of our total consolidated revenues.
For each of the years ended December 31, 2004 and 2003, only one customer
accounted for more than 10% of our total consolidated revenues. Total
transactions with CenterPoint Energy accounted for 14.3% of our total
consolidated revenues during 2004 and 16.8% of our total consolidated revenues
during 2003. The high percentage of our total revenues attributable to
CenterPoint Energy in both 2004 and 2003 related to the merchant activity of our
Texas intrastate natural gas pipeline group, which both buys and sells
significant volumes of natural gas within the State of Texas. As a result, both
our total consolidated revenues and our total consolidated purchases (cost of
sales) increase considerably due to the inclusion of the cost of gas in both
financial statement line items. However, these higher revenues and higher
purchased gas costs do not necessarily translate into increased margins in
comparison to those situations in which we charge a fee 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 Pipeline Rate Regulation
Some of our pipelines are interstate common carrier pipelines, subject to
regulation by the Federal Energy Regulatory Commission under the Interstate
Commerce Act, or ICA. 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. 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 Note 16
to our consolidated financial statements included elsewhere in this report.
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 from the previous
year. 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 rates as alternatives to the indexing approach
in certain specified circumstances.
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 former 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 filed for
indexed rate adjustments on a number of our petroleum products pipelines and
33
realized benefits from the new index beginning in the second quarter of 2003.
Rate adjustments pursuant to the revised index were made on a number of pipeline
systems in 2004 and 2005. The FERC is currently reviewing the existing indexing
methodology for use in 2007 and beyond.
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 of 1938 and, to a lesser extent, the Natural Gas Policy Act
of 1978. 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:
* Order No. 436 (1985) requiring open-access, nondiscriminatory
transportation of natural gas;
* Order No. 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
* Order No. 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:
* requiring the unbundling of sales services from other services;
* 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
* 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.
On November 25, 2003, the FERC issued Order No. 2004, adopting revised
Standards of Conduct that apply uniformly to interstate natural gas pipelines
and public utilities. In light of the changing structure of the energy industry,
these Standards of Conduct govern relationships between regulated interstate
natural gas pipelines and all of their energy affiliates. These new Standards of
Conduct were designed to eliminate the loophole in the previous regulations that
did not cover an interstate natural gas pipeline's relationship with energy
affiliates that are not marketers. The rule is designed to prevent interstate
natural gas pipelines from giving an undue preference to any of their energy
affiliates and to ensure that transmission is provided on a nondiscriminatory
basis. In addition, unlike the prior regulations, these requirements apply even
if the energy affiliate is not a customer of its affiliated interstate pipeline.
The effective date of Order No. 2004 was September 22, 2004. Our interstate
natural gas pipelines have implemented compliance with these Standards of
Conduct. Please refer to Note 17 to our consolidated financial statements
included elsewhere in this report for additional information regarding FERC
Order No. 2004 and other Standards of Conduct rulemaking.
On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The
Energy Policy Act, among other things, amended the Natural Gas Act to prohibit
market manipulation by any entity, directed the FERC to facilitate market
transparency in the market for sale or transportation of physical natural gas in
interstate commerce, and significantly increased the penalties for violations of
the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules,
regulations or orders thereunder.
34
California Public Utilities Commission Rate Regulation
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 Note 16 to our consolidated financial
statements.
Safety Regulation
Our interstate pipelines are subject to regulation by the United States
Department of Transportation and our intrastate pipelines and other operations
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 railcars. We believe that we are in substantial compliance with
U.S. DOT and comparable state regulations.
The Pipeline Safety Improvement Act of 2002 provides guidelines in the areas
of testing, education, training and communication. The Pipeline Safety 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 magnetic flux or ultrasonic 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, and the U.S. DOT has approved our qualification program.
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
internal Operator Qualification Program. 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. We
expect to meet the required deadlines for both our natural gas and refined
petroleum products pipelines.
Certain of our products pipelines and natural gas pipelines have been issued
orders and civil penalties by the U.S. DOT's Office of Pipeline Safety
concerning alleged violations of certain federal regulations concerning our
pipeline Integrity Management Program. However, we dispute some of the findings,
disagree that civil penalties are appropriate for them, and have requested an
administrative hearing on these matters according to the U.S. DOT regulations.
Information on these matters is more fully described in Note 16 to our
consolidated financial statements.
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.
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.
35
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 marketing, production, pricing, pollution, protection of the
environment, and 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 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
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 35 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 and safety or the environment.
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 change, 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 accrued an environmental reserve in the amount of $51.2 million as of
December 31, 2005. Our reserve estimates range in value from approximately $51.2
million to approximately $88.3 million, and we have recorded a liability equal
to the low end of the range. 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. Virtually all of these
properties were owned by others before us. 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. Virtually all 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 the facilities and have an adverse effect on soils and
36
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 non-hazardous 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 non-hazardous waste. Furthermore, it is possible that
some wastes that are currently classified as non-hazardous, 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
non-hazardous 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 or "CERCLA," and analogous state laws, impose
joint and several 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 natural resource damages, if any. Although "petroleum" is excluded from
CERCLA's definition of a "hazardous substance," in the course of our ordinary
operations, we have and will generate materials that may fall within the
definition of "hazardous substance." By operation of law, if we are determined
to be a potentially responsible person, we may be responsible under CERCLA for
all or part of the costs required to clean up sites at which such materials are
present, in addition to compensation for natural resource damages, if any.
Clean Air Act
Our operations are subject to the Clean Air Act and analogous 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. Depending on the nature of those
requirements and any additional 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 nature of the regulations, full development and
implementation of many Clean Air Act regulations by the U.S. EPA and/or various
state and local regulators have been delayed. Therefore, until such time as the
new Clean Air Act requirements are implemented, we are unable to fully 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 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 containment and similar structures to help prevent
contamination of
37
navigable waters in the event of an overflow or release. We believe we are in
substantial compliance with these laws.
EPA Fuel Specifications/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 portions of our liquids pipeline
systems, for example, 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.
That service continues, and we also provide transportation and storage of butane
from the Chicago area back to Bushton during the summer 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. A number of
other states are making moves to ban MTBE also. Although various drafts of The
Energy Policy Act of 2005 provided for the gradual phase out of the use of MTBE,
the final bill did not include that provision. Instead, the Act eliminates the
oxygenate requirement for reformulated gasoline but does not ban the use of
MTBE. So, it is likely that the use of MTBE will be phased out through state
bans and voluntary shifts to different formulations of gasoline by the refiners.
In California and other states, MTBE-blended gasoline has been banned from
use or may be replaced by an ethanol blend. However, due to the lack of
dedicated pipelines, ethanol cannot be shipped through pipelines and therefore,
we have realized some reduction in California gasoline volumes transported by
our Pacific operations' pipelines. However, the conversion from MTBE to ethanol
in California has resulted in an increase in ethanol blending services at many
of our refined petroleum product terminal facilities, and the fees we earn for
new ethanol-related services at our terminals more than offset the reduction in
pipeline transportation fees. Furthermore, we have aggressively pursued
additional ethanol opportunities in other states where MTBE has been banned or
where our customers have decided not to market MTBE gasoline.
Our role in conjunction with ethanol is proving beneficial to our various
business segments as follows:
* our Products Pipelines' terminals are blending ethanol because unlike
MTBE, it cannot flow through pipelines;
* 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
* 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.
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
38
Morgan, Inc. for the services of their employees. As of December 31, 2005, KMGP
Services Company, Inc. and Kinder Morgan, Inc. had, in the aggregate,
approximately 8,481 full-time employees. Approximately 2,144 full-time hourly
personnel at certain terminals and pipelines are represented by labor unions
under collective bargaining agreements that expire between 2006 and 2010. 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 our consolidated financial statements included
elsewhere in this report.
Substantially all of our pipelines are constructed on rights-of-way granted
by the apparent record owners of such property. In many instances, lands over
which rights-of-way have been obtained are subject to prior liens which have not
been subordinated to the right-of-way grants. In some cases, not all of the
apparent record owners have joined in the right-of-way grants, but in
substantially all such cases, signatures of the owners of majority interests
have been obtained. Permits have been obtained from public authorities to cross
over or under, or to lay facilities in or along, water courses, county roads,
municipal streets and state highways, and in some instances, such permits are
revocable at the election of the grantor, or, the pipeline may be required to
move its facilities at its own expense. Permits have also been obtained from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at the grantor's election. Some such permits require annual
or other periodic payments. In a few minor cases, property for pipeline purposes
was purchased in fee.
We believe 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 in those
properties 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. In addition, amounts we have spent during 2005, 2004 and 2003 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
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.
Item 1A. Risk Factors.
You should carefully consider the risks described below, in addition to the
other information contained in this document. Realization of any of the
following risks could have a material adverse effect on our business, financial
condition, cash flows and results of operations. There are also risks associated
with being an owner of common units in a partnership that are different than
being an owner of common stock in a corporation. Investors in our common units
must be aware that realizations of any of those risks could result in a decline
in the trading price of our common units, and they might lose all or part of
their investment.
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 with respect to 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 2006.
Currently, we do not believe that the increased cost associated with these
measures will have a material effect on our operating results.
39
Risks Related to our Business
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. Some shippers on our
pipelines have 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. We may face
challenges, similar to those described in Note 16 to our consolidated financial
statements included elsewhere in this report, to the rates we receive on our
pipelines in the future. Any successful challenge could adversely affect our
future earnings and cash flows.
Proposed rulemaking by the Federal Energy Regulatory Commission or other
regulatory agencies having jurisdiction over our operations could adversely
impact our income and operations. New laws or regulations or different
interpretations of existing laws or regulations applicable to our assets could
have a negative impact on our business, financial condition and results of
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. There are, for example, federal
legislation guidelines for the U.S. Department of Transportation and pipeline
companies in the areas of testing, education, training and communication.
Compliance with laws and regulations require significant expenditures. We have
increased and may need to further increase our capital expenditures to address
these matters. Additional laws and regulations that may be enacted in the future
or a new interpretation of existing laws and regulations 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 not 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:
* demands on management related to the increase in our size after an
acquisition;
* the diversion of our management's attention from the management of daily
operations;
* difficulties in implementing or unanticipated costs of accounting,
estimating, reporting and other systems;
* difficulties in the assimilation and retention of necessary employees;
and
* potential adverse effects on operating results.
We may not be able to maintain the levels of operating efficiency that
acquired companies have achieved or might achieve separately. Successful
integration of each of their operations will depend upon our ability to manage
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 and expansion programs require 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, 2005, we made a
significant number of acquisitions that increased our asset base over 39 times
and increased our net income over 68 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
40
strategy. We normally fund acquisitions with short term debt and repay such debt
through the issuance of equity and long-term debt. 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. Tax legislation, beginning with The Jobs and Growth Tax Relief
Reconciliation Act of 2003, has generally reduced the maximum tax rate on
dividends paid by corporations to individuals. The maximum federal income tax
rate on qualified dividends paid by corporations to individuals was 15% in 2005
and, for taxpayers in the 10% and 15% ordinary income tax brackets, 5% in 2005
through 2007 and zero in 2008. The maximum federal income tax rate on net long
term capital gains for individuals was 15% in 2005 and, for taxpayers in the 10%
and 15% ordinary income tax brackets, 5% in 2005 through 2007 and zero in 2008.
The differences in the tax rates 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,
and some foreign laws and regulations relating to environmental protection. For
example, if an accidental leak, release or spill of liquid petroleum products,
chemicals or other products occurs from our pipelines or at our storage
facilities, we may experience significant operational disruptions and we may
have to pay a significant amount to clean up the leak, release or spill or pay
for government penalties, address natural resource damage, compensate for human
exposure or property damage, or a combination of these measures. 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 U.S. EPA standards or future environmental
measures could increase our costs significantly if environmental laws and
regulations become stricter.
In addition, our oil and gas development and production activities are
subject to certain federal, state and local laws and regulations relating to
environmental quality and pollution control. These laws and regulations increase
the costs of these activities and may prevent or delay the commencement or
continuance of a given operation. Specifically, we are subject to laws and
regulations regarding the acquisition of permits before drilling, restrictions
on drilling activities in restricted areas, emissions into the environment,
water discharges, and storage and disposition of hazardous wastes. In addition,
legislation has been enacted which requires well and facility sites to be
abandoned and reclaimed to the satisfaction of state authorities. The costs of
environmental regulation are already significant, and additional or more
stringent regulation could increase these costs or could otherwise negatively
affect our business.
Our future success depends in part upon our ability to develop additional
oil and gas reserves that are economically recoverable. The rate of production
from oil and natural gas properties declines as reserves are depleted. Without
successful development activities, the reserves and revenues of our CO2 business
segment will decline. We may not be able to develop or acquire additional
reserves at an acceptable cost or have necessary financing for these activities
in the future.
The development of oil and gas properties involves risks that may result in
a total loss of investment. The business of developing and operating oil and gas
properties involves a high degree of business and financial risk that even a
combination of experience, knowledge and careful evaluation may not be able to
overcome. Acquisition and development decisions generally are based on
subjective judgments and assumptions that are speculative. It is impossible to
predict with certainty the production potential of a particular property or
well. Furthermore, a successful completion of a well does not ensure a
profitable return on the investment. A variety of geological, operational, or
market-related factors, including, but not limited to, unusual or unexpected
geological formations, pressures, equipment failures or accidents, fires,
explosions, blowouts, cratering, pollution and other environmental risks,
shortages or delays in the availability of drilling rigs and the delivery of
equipment, loss of circulation of drilling fluids or other conditions may
substantially delay or prevent completion of any well, or otherwise prevent a
property or well from being profitable. A productive well may become uneconomic
in the event water or other deleterious substances are encountered, which impair
or prevent the production of oil and/or gas from the well. In
41
addition, production from any well may be unmarketable if it is contaminated
with water or other deleterious substances.
The volatility of natural gas and oil prices could have a material adverse
effect on our business. The revenues, profitability and future growth of our CO2
business segment and the carrying value of our oil and natural gas properties
depend to a large degree on prevailing oil and gas prices. Prices for oil and
natural gas are subject to large fluctuations in response to relatively minor
changes in the supply and demand for oil and natural gas, uncertainties within
the market and a variety of other factors beyond our control. These factors
include, weather conditions and events such as hurricanes in the United States;
the condition of the United States economy; the activities of the Organization
of Petroleum Exporting Countries; governmental regulation; political stability
in the Middle East and elsewhere; the foreign supply of oil and natural gas; the
price of foreign imports; and the availability of alternative fuel sources.
A sharp decline in the price of natural gas or oil prices would result in a
commensurate reduction in our revenues, income and cash flows from the
production of oil and natural gas and could have a material adverse effect on
the carrying value of our proved reserves. In the event prices fall
substantially, we may not be able to realize a profit from our production and
would operate at a loss. In recent decades, there have been periods of both
worldwide overproduction and underproduction of hydrocarbons and periods of both
increased and relaxed energy conservation efforts. Such conditions have resulted
in periods of excess supply of, and reduced demand for, crude oil on a worldwide
basis and for natural gas on a domestic basis. These periods have been followed
by periods of short supply of, and increased demand for, crude oil and natural
gas. The excess or short supply of crude oil or natural gas has placed pressures
on prices and has resulted in dramatic price fluctuations even during relatively
short periods of seasonal market demand.
Our use of hedging arrangements could result in financial losses or reduce
our income. We currently engage in hedging arrangements to reduce our exposure
to fluctuations in the prices of oil and natural gas. These hedging arrangements
expose us to risk of financial loss in some circumstances, including when
production is less than expected, when the counter-party to the hedging contract
defaults on its contract obligations, or when there is a change in the expected
differential between the underlying price in the hedging agreement and the
actual prices received. In addition, these hedging arrangements may limit the
benefit we would otherwise receive from increases in prices for oil and natural
gas.
The accounting standards regarding hedge accounting are very complex, and
even when we engage in hedging transactions (for example, to mitigate our
exposure to fluctuations in commodity prices or to balance our exposure to fixed
and floating interest rates) that are effective economically, these transactions
may not be considered effective for accounting purposes. Accordingly, our
financial statements may reflect some volatility due to these hedges, even when
there is no underlying economic impact at that point. In addition, it is not
always possible for us to engage in a hedging transaction that completely
mitigates our exposure to commodity prices. Our financial statements may
reflect a gain or loss arising from an exposure to commodity prices for which we
are unable to enter into a completely effective hedge.
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 or
be required to relocate our pipelines, 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.
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
42
use or occupy the property on which our pipelines are located. For the year
ended December 31, 2005, all of our right-of-way related expenses totaled $14.1
million.
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:
* incurring additional debt;
* entering into mergers, consolidations and sales of assets;
* granting liens; and
* 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, 2005, we had approximately $2.8 billion of debt, excluding market
value of interest rate swaps, subject to variable interest rates. This amount
included $2.1 billion of long-term fixed rate debt converted to variable rate
debt through the use of interest rate swaps. Should interest rates increase
significantly, our earnings could be adversely affected.
Current or future distressed financial condition of 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, and other customers may experience severe financial problems in the
future. The bankruptcy of one or more of them, or some other similar proceeding
or liquidity constraint might make it unlikely that we would be able to collect
all or a significant portion of amounts owed by the distressed entity or
entities. In addition, such events might force such customers to reduce or
curtail their future use of our products and services, which could have a
material adverse effect on our results of operations and financial condition.
The interests of KMI may differ from our interests 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 interests 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.
Risks Related to Our Common Units
Common unitholders have limited voting rights and limited control. Holders
of common units have only limited voting rights on matters affecting us. Our
general partner manages partnership activities. Under a delegation of control
agreement, our general partner has delegated the management and control of our
and our subsidiaries' business and affairs to KMR. Holders of common units have
no right to elect the general partner on an annual or other ongoing basis. If
the general partner withdraws, however, its successor may be elected by the
holders of a majority of the outstanding common units (excluding units owned by
the departing general partner and its affiliates).
The limited partners may remove the general partner only if:
* the holders of at least 66 2/3% of the outstanding common units,
excluding common units owned by the departing general partner and its
affiliates, vote to remove the general partner;
43
* a successor general partner is approved by at least 66 2/3% of the
outstanding common units, excluding common units owned by the departing
general partner and its affiliates; and
* we receive an opinion of counsel opining that the removal would not
result in the loss of limited liability to any limited partner, or the
limited partner of an operating partnership, or cause us or the operating
partnership to be taxed other than as a partnership for federal income
tax purposes.
A person or group owning 20% or more of the common units cannot vote. Any
common units held by a person or group that owns 20% or more of the common units
cannot be voted. This limitation does not apply to the general partner and its
affiliates. This provision may:
* discourage a person or group from attempting to remove the general
partner or otherwise change management; and
* reduce the price at which the common units will trade under certain
circumstances. For example, a third party will probably not attempt to
take over our management by making a tender offer for the common units at
a price above their trading market price without removing the general
partner and substituting an affiliate of its own.
The general partner's liability to us and our unitholders may be limited.
Our partnership agreement contains language limiting the liability of the
general partner to us or the holders of common units. For example, our
partnership agreement provides that:
* the general partner does not breach any duty to us or the holders of
common units by borrowing funds or approving any borrowing. The general
partner is protected even if the purpose or effect of the borrowing is to
increase incentive distributions to the general partner;
* the general partner does not breach any duty to us or the holders of
common units by taking any actions consistent with the standards of
reasonable discretion outlined in the definitions of available cash and
cash from operations contained in our partnership agreement; and
* the general partner does not breach any standard of care or duty by
resolving conflicts of interest unless the general partner acts in bad
faith.
Unitholders may have liability to repay distributions. Unitholders will not
be liable for assessments in addition to their initial capital investment in the
common units. Under certain circumstances, however, holders of common units may
have to repay us amounts wrongfully returned or distributed to them. Under
Delaware law, we may not make a distribution to unitholders if the distribution
causes our liabilities to exceed the fair value of our assets. Liabilities to
partners on account of their partnership interests and non-recourse liabilities
are not counted for purposes of determining whether a distribution is permitted.
Delaware law provides that for a period of three years from the date of such a
distribution, a limited partner who receives the distribution and knew at the
time of the distribution that the distribution violated Delaware law will be
liable to the limited partnership for the distribution amount. Under Delaware
law, an assignee who becomes a substituted limited partner of a limited
partnership is liable for the obligations of the assignor to make contributions
to the partnership. However, such an assignee is not obligated for liabilities
unknown to the assignee at the time the assignee became a limited partner if the
liabilities could not be determined from the partnership agreement.
Unitholders may be liable if we have not complied with state partnership
law. We conduct our business in a number of states. In some of those states the
limitations on the liability of limited partners for the obligations of a
limited partnership have not been clearly established. The unitholders might be
held liable for the partnership's obligations as if they were a general partner
if:
* a court or government agency determined that we were conducting business
in the state but had not complied with the state's partnership statute;
or
44
* unitholders' rights to act together to remove or replace the general
partner or take other actions under our partnership agreement constitute
"control" of our business.
The general partner may buy out minority unitholders if it owns 80% of the
units. If at any time the general partner and its affiliates own 80% or more of
the issued and outstanding common units, the general partner will have the right
to purchase all, and only all, of the remaining common units. Because of this
right, a unitholder will have to sell its common units at a time or price that
may be undesirable. The purchase price for such a purchase will be the greater
of:
* the 20-day average trading price for the common units as of the date five
days prior to the date the notice of purchase is mailed; or
* the highest purchase price paid by the general partner or its affiliates
to acquire common units during the prior 90 days.
The general partner can assign this right to its affiliates or to the
partnership.
We may sell additional limited partner interests, diluting existing
interests of unitholders. Our partnership agreement allows the general partner
to cause us to issue additional common units and other equity securities. When
we issue additional equity securities, including additional i-units to KMR when
it issues additional shares, unitholders' proportionate partnership interest in
us will decrease. Such an issuance could negatively affect the amount of cash
distributed to unitholders and the market price of common units. Issuance of
additional common units will also diminish the relative voting strength of the
previously outstanding common units. Our partnership agreement does not limit
the total number of common units or other equity securities we may issue.
The general partner can protect itself against dilution. Whenever we issue
equity securities to any person other than the general partner and its
affiliates, the general partner has the right to purchase additional limited
partnership interests on the same terms.
This allows the general partner to maintain its proportionate partnership
interest in us. No other unitholder has a similar right. Therefore, only the
general partner may protect itself against dilution caused by issuance of
additional equity securities.
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.
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 our treatment 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.
45
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.
In addition, because of widespread state budget deficits, several states are
evaluating ways to subject partnerships to entity-level taxation through the
imposition of state income, franchise or other forms of taxation. If any state
were to impose a tax upon us as an entity, the cash available for distribution
to our unitholders would be reduced.
Risks Related to Ownership of Our Common Units if We or KMI Default on Debt
Unitholders may have negative tax consequences if we default on our debt or
sell assets. If we default on any of our debt, the lenders will have the right
to sue us for non-payment. Such an action could cause an investment loss and
cause negative tax consequences for unitholders through the realization of
taxable income by unitholders without a corresponding cash distribution.
Likewise, if we were to dispose of assets and realize a taxable gain while there
is substantial debt outstanding and proceeds of the sale were applied to the
debt, unitholders could have increased taxable income without a corresponding
cash distribution.
There is the potential for a change of control if KMI defaults on debt. KMI
owns all of the outstanding capital stock of the general partner. KMI has
significant operations which provide cash independent of dividends that KMI
receives from the general partner. Nevertheless, if KMI defaults on its debt,
its lenders could acquire control of the general partner.
Item 1B. Unresolved Staff Comments.
None.
Item 3. Legal Proceedings.
See Note 16 of the notes to our 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 2005.
46
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities.
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
------- ------- ------------- -------------
2005
First Quarter $ 47.55 $ 42.77 $ 0.7600 0.017482
Second Quarter 51.49 45.22 0.7800 0.016210
Third Quarter. 55.20 49.72 0.7900 0.016360
Fourth Quarter 53.56 47.21 0.8000 0.017217
2004
First Quarter $ 49.12 $ 43.50 $ 0.6900 0.017412
Second Quarter 45.39 37.65 0.7100 0.018039
Third Quarter. 46.85 40.60 0.7300 0.017892
Fourth Quarter 47.70 42.75 0.7400 0.017651
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, no assurance can be
given that we will be able to achieve this level of distribution, and our
expectation does not take into account any transportation rate reductions or
capital costs associated with financing the payment of reparations sought by
shippers on our Pacific operations' interstate pipelines.
As of February 3, 2006, there were approximately 187,000 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 sell any units that were not registered under the Securities Act
of 1933 during 2005, other than sales that were previously reported in a Form
10-Q or Form 8-K during 2005. We did not repurchase any units during the fourth
quarter of 2005.
47
Item 6. Selected Financial Data
The following tables set forth, for the periods and at the dates indicated,
our summary historical financial and operating data. 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,
----------------------------------------------------------------
2005(5) 2004(6) 2003(7) 2002(8) 2001(9)
------------ ----------- ----------- ----------- -----------
(In thousands, except per unit and ratio data)
Income and Cash Flow Data:
Revenues............................................ $ 9,787,128 $ 7,932,861 $ 6,624,322 $ 4,237,057 $ 2,946,676
Gas purchases and other costs of sales.............. 7,167,414 5,767,169 4,880,118 2,704,295 1,657,689
Operations and maintenance.......................... 747,363 499,714 397,723 376,479 352,407
Fuel and power...................................... 183,458 151,480 108,112 86,413 73,188
Depreciation, depletion and amortization............ 349,827 288,626 219,032 172,041 142,077
General and administrative.......................... 216,706 170,507 150,435 122,205 113,540
Taxes, other than income taxes...................... 108,838 81,369 62,213 51,326 43,947
------------ ----------- ----------- ----------- -----------
Operating income.................................. 1,013,522 973,996 806,689 724,298 563,828
Other income/(expense):
Earnings from equity investments.................... 91,660 83,190 92,199 89,258 84,834
Amortization of excess cost of equity investments... (5,644) (5,575) (5,575) (5,575) (9,011)
Interest, net....................................... (258,861) (192,882) (181,357) (176,460) (171,457)
Other, net.......................................... 3,273 2,254 7,601 1,698 1,962
Minority interest................................... (7,262) (9,679) (9,054) (9,559) (11,440)
Income tax provision................................ (24,461) (19,726) (16,631) (15,283) (16,373)
------------ ----------- ----------- ----------- -----------
Income before cumulative effect of a change in
accounting principle............................. 812,227 831,578 693,872 608,377 442,343
Cumulative effect of a change in accounting principle -- -- 3,465 -- --
------------ ----------- ----------- ----------- -----------
Net income........................................ $ 812,227 $ 831,578 $ 697,337 $ 608,377 $ 442,343
Less: General Partner's interest in net income.... (477,300) (395,092) (326,524) (270,816) (202,095)
------------ ----------- ----------- ----------- -----------
Limited Partners' interest in net income.......... $ 334,927 $ 436,486 $ 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).......................... $ 1.58 $ 2.22 $ 1.98 $ 1.96 $ 1.56
Cumulative effect of a change in accounting principle -- -- 0.02 -- --
------------ ----------- ----------- ----------- -----------
Net income.......................................... $ 1.58 $ 2.22 $ 2.00 $ 1.96 $ 1.56
============ =========== =========== =========== ===========
Per unit cash distribution declared(2).............. $ 3.13 $ 2.87 $ 2.63 $ 2.435 $ 2.15
Ratio of earnings to fixed charges(3)............... 3.76 4.91 4.77 4.37 3.56
Additions to property, plant and equipment.......... $ 863,056 $ 747,262 $ 576,979 $ 542,235 $ 295,088
Balance Sheet Data (at end of period):
Net property, plant and equipment.................. $ 8,864,584 $ 8,168,680 $ 7,091,558 $ 6,244,242 $ 5,082,612
Total assets........................................ $ 11,923,462 $10,552,942 $ 9,139,182 $ 8,353,576 $ 6,732,666
Long-term debt(4)................................... $ 5,220,887 $ 4,722,410 $ 4,316,678 $ 3,659,533 $ 2,237,015
Partners' capital................................... $ 3,613,740 $ 3,896,520 $ 3,510,927 $ 3,415,929 $ 3,159,034
- ----------
(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 maximum
potential dilution that could occur if units whose issuance depends on the
market price of the units at a future date were considered outstanding, or
if, by application of the treasury stock method, options to issue units were
exercised, both of which would result in the issuance of additional units
that would then share in our net income.
(2) Represents the amount of cash distributions declared with respect to that
year. Amounts have been adjusted for the two-for-one split of common units
that occurred on August 31, 2001.
(3) For the purpose of computing the ratio of earnings to fixed charges,
earnings are defined as income before income taxes and cumulative effect of
a change in accounting principle, and before minority interest in
consolidated subsidiaries, equity earnings (including amortization of excess
cost of equity investments) and unamortized capitalized interest, plus fixed
48
charges and distributed income of equity investees. Fixed charges are
defined as the sum of interest on all indebtedness (excluding capitalized
interest), amortization of debt issuance costs and that portion of rental
expense which we believe to be representative of an interest factor.
(4) Excludes market value of interest rate swaps. Increases (Decreases) to
Long-term debt for market value of interest rate swaps totaled $98,469 as of
December 31, 2005, $130,153 as of December 31, 2004, $121,464 as of December
31, 2003, $166,956 as of December 31, 2002, and ($5,441) as of December 31,
2004.
(5) Includes results of operations for the 64.5% interest in the Claytonville
unit, the seven bulk terminal operations acquired from Trans-Global
Solutions, Inc., the Kinder Morgan Staten Island terminal, the terminal
facilities located in Hawesville, Kentucky and Blytheville, Arkansas,
General Stevedores, L.P., the North Dayton natural gas storage facility, the
Kinder Morgan Blackhawk terminal, the terminal repair shop acquired from
Trans-Global Solutions, Inc., and the terminal assets acquired from Allied
Terminals, Inc. since effective dates of acquisition. We acquired the 64.5%
interest in the Claytonville unit effective January 31, 2005. We acquired
the seven bulk terminal operations from Trans-Global Solutions, Inc.
effective April 29, 2005. The Kinder Morgan Staten Island terminal, the
Hawesville, Kentucky terminal and the Blytheville, Arkansas terminal were
each acquired separately in July 2005. We acquired all of the partnership
interests in General Stevedores, L.P. effective July 31, 2005. We acquired
the North Dayton natural gas storage facility effective August 1, 2005. We
acquired the Kinder Morgan Blackhawk terminal in August 2005 and the
terminal repair shop in September 2005. We acquired the terminal assets from
Allied Terminals, Inc. effective November 4, 2005.
(6) Includes results of operations for the seven refined petroleum products
terminals acquired from ExxonMobil, Kinder Morgan Wink Pipeline, L.P., an
additional 5% interest in the Cochin Pipeline System, Kinder Morgan River
Terminals LLC and its consolidated subsidiaries, TransColorado Gas
Transmission Company, interests in nine refined petroleum products terminals
acquired from Charter Terminal Company and Charter-Triad Terminals, LLC, and
the Kinder Morgan Fairless Hills terminal since effective dates of
acquisition. We acquired the seven refined petroleum products terminals from
ExxonMobil effective March 9, 2004. We acquired Kinder Morgan Wink Pipeline,
L.P. effective August 31, 2004. The additional interest in Cochin was
acquired effective October 1, 2004. We acquired Kinder Morgan River
Terminals LLC and its consolidated subsidiaries effective October 6, 2004.
We acquired TransColorado effective November 1, 2004, the interests in the
nine Charter Terminal Company and Charter-Triad Terminals, LLC refined
petroleum products terminals effective November 5, 2004, and the Kinder
Morgan Fairless Hills terminal effective December 1, 2004.
(7) 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 effective January 1, 2003. The
additional 12.75% interest in SACROC was acquired effective June 1, 2003.
The five refined petroleum products terminals were acquired effective
October 1, 2003. The additional 42.5% interest in the Yates field unit, the
Yates gathering system and the additional 65% interest in Pecos Carbon
Dioxide Company were acquired effective 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
effective December 10 and 23, 2003.
(8) 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 its consolidated subsidiaries
since dates of acquisitions. The additional interest in Cochin was acquired
effective December 31, 2001. Kinder Morgan Materials Services LLC was
acquired effective January 1, 2002. We acquired a 33 1/3% interest in
International Marine Terminals effective January 1, 2002 and an additional
33 1/3% interest effective February 1, 2002. Tejas Gas, LLC was acquired
effective January 31, 2002. The Milwaukee Bagging Operations were acquired
effective May 1, 2002. The remaining interest in Trailblazer was acquired
effective May 6, 2002. The Owensboro Gateway Terminal and IC Terminal
Holdings Company and its subsidiaries were acquired effective September 1,
2002.
(9) 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 effective December 31, 2000. Central Florida and Kinder Morgan
49
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 effective June
20, 2001. Vopak terminal LLCs were acquired July 10, 2001. Boswell terminals
were acquired August 31, 2001. Stolt-Nielsen terminals were acquired
effective November 8 and 29, 2001, and our additional interests in the
Snyder Gasoline Plant and the Diamond M Gas Plant were acquired effective
November 14, 2001.
50
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
The following discussion and analysis of our financial condition and results
of operations provides you with a narrative on our financial results. It
contains a discussion and analysis of the results of operations for each segment
of our business, followed by a discussion and analysis of our financial
condition. The following discussion and analysis is based on our consolidated
financial statements, which are included elsewhere in this report and 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.
Additional sections in this report which should be helpful to your reading
of our discussion and analysis include the following:
* a description of our business strategy found in Items 1 and 2 "Business
and Properties - Business Strategy";
* a description of developments during 2005, found in Items 1 and 2
"Business and Properties - Recent Developments"; and
* a description of risk factors affecting us and our business, found in
Item 1A "Risk Factors."
We begin with a discussion of our Critical Accounting Polices and Estimates,
those areas that are both very important to the portrayal of our financial
condition and results and which require our management's most difficult,
subjective or complex judgments, often as a result of the need to make estimates
about the effect of matters that are inherently uncertain.
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 our financial statements. We routinely evaluate these estimates, 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 consolidated 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
consolidated financial statement preparation process than others, which policies
are discussed following.
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. We routinely conduct
reviews of potential environmental issues and claims that could impact our
assets or operations. 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 2005, after a thorough review of any potential environmental
issues that could impact our assets or operations and of our need to correctly
record all related environmental contingencies, we recognized a $23.3 million
increase in environmental expense associated with environmental liability
adjustments. The $23.3 million expense item resulted from the necessity of
properly adjusting our environmental expenses and accrued liabilities between
our reportable business segments, primarily affecting our Products Pipelines and
our Terminals business segments. The $23.3 million increase in environmental
expense resulted in a $19.6 million increase in expense to
51
our Products Pipelines business segment, a $3.5 million increase in expense to
our Terminals business segment, a $0.3 million increase in expense to our CO2
business segment, and a $0.1 million decrease in expense to our Natural Gas
Pipelines business segment. The adjustment included an $8.7 million increase in
our estimated environmental receivables and reimbursables and a $32.0 million
increase in our overall accrued environmental and related claim liabilities. We
included the additional $23.3 million expense within "Operations and
maintenance" in our accompanying consolidated statement of income for 2005.
Similarly, in December 2004, we recognized a $0.2 million increase in
environmental expenses and an associated $0.1 million increase in deferred
income tax expense resulting from changes to previous estimates. The $0.3
million expense item, including taxes, resulted from the necessity of properly
adjusting our environmental expenses, liabilities and receivables between our
four reportable business segments. It is the net impact of a $30.6 million
increase in expense in our Products Pipelines business segment, a $7.6 million
decrease in expense in our Natural Gas Pipelines business segment, a $4.1
million decrease in expense in our CO2 business segment, and an $18.6 million
decrease in expense in our Terminals business segment. The adjustment included
an $18.9 million increase in our estimated environmental receivables and
reimbursables and a $19.1 million increase in our overall accrued environmental
and related claim liabilities. We included the additional $0.2 million
environmental expense within "Other, net" in our accompanying consolidated
statement of income for 2004. For more information on our environmental
disclosures, see Note 16 to our consolidated financial statements included
elsewhere in this report.
Legal Matters
We are subject to litigation and regulatory proceedings as a 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. We expense legal costs as incurred,
and all recorded legal liabilities are revised as better information becomes
available.
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations' pipelines, excluding CALNEV Pipe Line LLC. Tariffs charged by our
Pacific operations' pipeline systems 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.
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 and could, therefore owe
reparations and/or refunds to complainants as mandated by FERC or the United
States' judicial system.
We recorded an accrual of $105.0 million for an expense attributable to an
increase in our reserves related to our rate case liability, and we included
this amount within "Operations and maintenance" in our accompanying consolidated
statement of income for 2005. The factors we considered when making this
additional accrual included: (i) the opinions and views of our legal counsel;
(ii) our experience with reparations and refunds previously paid to complainants
and other shippers as required by FERC (in 2003, we paid transportation rate
reparation and refund payments in the amount of $44.9 million as mandated by the
FERC); and (iii) the decision of our management as to how we intend to respond
to the complaints, which includes the compliance filing we submitted to the FERC
on March 7, 2006.
We estimated, as of December 31, 2003, that shippers' claims for reparations
totaled approximately $154 million and that prospective rate reductions would
have an aggregate average annual impact of approximately $45 million, with the
reparations amount and interest increasing as the timing for implementation of
rate reductions and the payment of reparations has extended (estimated at a
quarterly increase of approximately $9 million). Based on the December 16, 2005
order, rate reductions will be implemented on May 1, 2006. We now assume that
reparations and accrued interest thereon will be paid no earlier than the first
quarter of 2007; however, the timing, and nature, of any rate reductions and
reparations that may be ordered will likely be affected by the final disposition
of the application of the FERC's new policy statement on income tax allowances
to our Pacific operations in the FERC Docket Nos. OR92-8 and OR96-2 proceedings.
As discussed in the preceding paragraph, we recorded an accrual of $105.0
million for an expense attributable to an increase in our reserves related to
our rate case liability. We had previously estimated the combined annual impact
of the rate reductions and the payment of reparations sought by
52
shippers would be approximately 15 cents of distributable cash flow per unit.
Based on our review of the FERC's December 16 order and the FERC's February 13
order on rehearing, and subject to the ultimate resolution of these issues in
our compliance filings and subsequent judicial appeals, we now expect the total
annual impact will be less than 15 cents per unit. The actual, partial year
impact on 2006 distributable cash flow per unit will likely be closer to 5 cents
per unit. For more information on our Pacific operations' regulatory
proceedings, see Note 16 to our consolidated financial statements included
elsewhere in this report.
Intangible Assets
Intangible assets are those assets which provide future economic benefit but
have no physical substance. We account for our intangible assets according to
the provisions of 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 provided that all identifiable
intangible assets having indefinite useful economic lives, including goodwill,
will not be subject to regular periodic amortization. Such assets are not to be
amortized until their lives are determined to be finite. Instead, the carrying
amount of a recognized intangible asset with an indefinite useful life must 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 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,
2006. As of January 1, 2006, our goodwill was $799.0 million.
Our remaining intangible assets, excluding goodwill, include lease value,
contracts, customer relationships and agreements. These intangible assets have
definite lives, are being amortized on a straight-line basis over their
estimated useful lives, and are reported separately as "Other intangibles, net"
in our accompanying consolidated balance sheets. As of December 31, 2005 and
2004, these intangibles totaled $217.0 million and $15.3 million, respectively.
Estimated Net Recoverable Quantities of Oil and Gas
We use the successful efforts method of accounting for our oil and gas
producing activities. The successful efforts method inherently relies on the
estimation of proved reserves, both developed and undeveloped. The existence and
the estimated amount of proved reserves affect, among other things, whether
certain costs are capitalized or expensed, the amount and timing of costs
depleted or amortized into income and the presentation of supplemental
information on oil and gas producing activities. The expected future cash flows
to be generated by oil and gas producing properties used in testing for
impairment of such properties also rely in part on estimates of net recoverable
quantities of oil and gas.
Our estimation of net recoverable quantities of oil and gas is a highly
technical process performed primarily by in-house reservoir engineers and
geoscience professionals. Independent oil and gas consultants have reviewed the
estimates of proved reserves of crude oil, natural gas and natural gas liquids
that we have attributed to our net interest in oil and gas properties as of
December 31, 2005.
Proved reserves are the estimated quantities of oil and gas that geologic
and engineering data demonstrates with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either positively and
negatively, as additional information becomes available and as contractual,
economic and political conditions change.
Hedging Activities
We engage in a hedging program to mitigate our exposure to fluctuations in
commodity prices and to balance our exposure to fixed and floating interest
rates, and we believe that these hedges are generally effective in realizing
these objectives. However, the accounting standards regarding hedge
accounting are very complex, and even when we engage in hedging transactions
that are effective economically, these transactions may not be considered
effective for accounting purposes. Accordingly, our financial statements may
reflect some volatility due to these hedges, even when there is no underlying
economic impact at that point. Generally, the financial statement volatility
arises from an accounting requirement to recognize changes in values of
financial instruments while not concurrently recognizing the values of the
underlying transactions being hedged.
In addition, it is not always possible for us to engage in a hedging
transaction that completely mitigates our exposure to commodity prices. For
example, when we purchase a commodity at one location and sell it at another,
we may be unable to hedge completely our exposure to a differential in the price
of the product between these two locations. Even when we cannot enter into a
completely effective hedge, we often enter into hedges that are not completely
effective in those instances where we believe to do so would be better than not
hedging at all. Our financial statements may reflect a gain or loss arising
from an exposure to commodity prices for which we are unable to enter into a
completely effective hedge.
Results of Operations
Our business model is built to support two principal components: helping
customers by providing energy, bulk commodity and liquid products
transportation, storage and distribution; and creating long-term value for our
unitholders. To achieve these objectives, we focus on providing fee-based
services to customers from a business portfolio consisting of energy-related
pipelines, bulk and liquids terminal facilities, and carbon dioxide and
petroleum reserves. Our reportable business segments are based on the way our
management organizes our enterprise, and each of our four segments represents a
component of our enterprise that engages in a separate business activity and for
which discrete financial information is available.
53
Consolidated
Year Ended December 31,
----------------------------------------------
2005 2004 2003
------------- ------------- -------------
(In thousands)
Earnings before depreciation, depletion and amortization
expense and
amortization of excess cost of equity investments
Products Pipelines........................................... $ 370,052 $ 444,865 $ 441,600
Natural Gas Pipelines........................................ 500,324 418,261 373,350
CO2.......................................................... 470,887 357,636 203,599
Terminals.................................................... 314,606 281,738 240,776
------------- ------------- -------------
Segment earnings before depreciation, depletion and
amortization of excess cost of equity investments(a)..... 1,655,869 1,502,500 1,259,325
Depreciation, depletion and amortization expense............. (349,827) (288,626) (219,032)
Amortization of excess cost of investments................... (5,644) (5,575) (5,575)
Interest and corporate administrative expenses(b)............ (488,171) (376,721) (337,381)
------------- ------------- -------------
Net income................................................. $ 812,227 $ 831,578 $ 697,337
============= ============= =============
- ----------
(a) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses. 2005
Products Pipelines business segment amount includes a rate case liability
adjustment resulting in a $105,000 expense, and a North System liquids
inventory reconciliation adjustment resulting in a $13,691 expense. 2005
amounts also include environmental liability adjustments resulting in a
$19,600 expense to our Products Pipelines business segment, an $89
reduction in expense to our Natural Gas Pipelines business segment, a $298
increase in expense to our CO2 business segment and a $3,535 increase in
expense to our Terminals business segment. 2004 amounts include
environmental liability adjustments resulting in a $30,611increase in
expense to our Products Pipelines business segment, a $7,602 reduction in
expense to our Natural Gas Pipelines business segment, a $4,126 reduction
in expense to our CO2 business segment and an $18,571 reduction in expense
to our Terminals business segment.
(b) Includes unallocated interest income, interest and debt expense, general
and administrative expenses (including unallocated litigation and
environmental expenses), minority interest expense, loss from early
extinguishment of debt (2004 only) and cumulative effect adjustment from a
change in accounting principle (2003 only).
In 2005, we earned net income of $812.2 million ($1.58 per diluted unit) on
revenues of $9,787.1 million, compared to net income of $831.6 million ($2.22
per diluted unit) on revenues of $7,932.9 million in 2004, and net income of
$697.3 million ($2.00 per diluted unit) on revenues of $6,624.3 million in 2003.
Because our partnership agreement requires us to distribute 100% of our
available cash to our partners on a quarterly basis (available cash consists
primarily of all our cash receipts, less cash disbursements and changes in
reserves), we consider each period's earnings before all non-cash depreciation,
depletion and amortization expenses, including amortization of excess cost of
equity investments, to be an important measure of our success in maximizing
returns to our partners. We also use this measure of profit and loss internally
for evaluating segment performance and deciding how to allocate resources to our
business segments. Our total segment earnings before depreciation, depletion and
amortization totaled $1,655.9 million in 2005, $1,502.5 million in 2004, and
$1,259.3 million in 2003.
As noted in the table above, our 2005 segment earnings before depreciation,
depletion and amortization included charges of $105.0 million attributable to an
increase in our reserves related to our rate case liability, $23.3 million from
the adjustment of our environmental liabilities, and $13.7 million related to a
natural gas liquids inventory reconciliation on our North System; our 2004
segment earnings before depreciation, depletion and amortization included
charges of $0.3 million from the adjustment of our environmental liabilities.
Excluding these charges, segment earnings before depreciation, depletion and
amortization for our four business segments totaled $1,797.9 million in 2005 and
$1,502.8 million in 2004.
Both the $295.1 million (20%) increase in segment earnings before
depreciation, depletion, and amortization, and the environmental, rate case and
inventory charges discussed above, in 2005 compared to 2004, and the $243.5
million (19%) increase in 2004 compared to 2003, consisted of year-to-year
increases from all four of our business segments, with the strongest growth
coming from our CO2 (carbon dioxide) and Natural Gas Pipelines business
segments. The year-over-year increases in earnings were attributable both to
internal growth and to contributions from acquired assets; more specifically:
54
* higher earnings from our CO2 segment, where we benefited from higher
crude oil and natural gas processing plant liquids production volumes,
higher industry price levels for both crude oil and natural gas
processing plant liquids products, higher third party carbon dioxide
sales, and acquisitions of additional oil reserve interests and related
assets;
* higher earnings from our Natural Gas Pipelines segment, largely due to
improved gross margins on natural gas sales activities and higher
revenues from natural gas transportation and storage services;
* higher earnings from our Terminals segment, primarily due to higher
revenues earned from transporting and storing petroleum,
petrochemical-related liquids, and dry-bulk material products, and to the
favorable impact of completed internal expansion projects and acquired
terminal operations since the end of 2003; and
* higher earnings from our Products Pipelines segment, mainly due to higher
revenues from deliveries of refined petroleum products and natural gas
liquids, higher revenues from refined product terminal operations, and
the acquisition of our Southeast terminal operations, which consist of 23
refined petroleum products terminals that were acquired since December
2003.
We declared a cash distribution of $0.80 per unit for the fourth quarter of
2005 (an annualized rate of $3.20). This distribution was 8% higher than the
$0.74 per unit distribution we made for the fourth quarter of 2004, and 18%
higher than the $0.68 per unit distribution we made for the fourth quarter of
2003. We expect to declare cash distributions of at least $3.28 per unit for
2006. However, no assurance can be given that we will be able to achieve this
level of distribution, and our expectation does not take into account any
transportation rate reductions or capital costs associated with financing the
payment of reparations sought by shippers on our Pacific operations' interstate
pipelines. 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.
Products Pipelines
Year Ended December 31,
---------------------------------------
2005 2004 2003
----------- ----------- -----------
(In thousands, except operating statistics)
Revenues.................................................. $ 711,886 $ 645,249 $ 585,376
Operating expenses (including adjustments)(a)............. (366,048) (222,036) (169,526)
Earnings from equity investments.......................... 28,446 29,050 30,948
Interest income and Other, net- income (expense).......... 6,111 4,677 6,471
Income taxes.............................................. (10,343) (12,075) (11,669)
----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 370,052 444,865 441,600
investments.................................................
Depreciation, depletion and amortization expense.......... (79,199) (71,263) (67,345)
Amortization of excess cost of equity investments......... (3,350) (3,281) (3,281)
----------- ----------- -----------
Segment earnings........................................ $ 287,503 $ 370,321 $ 370,974
=========== =========== ===========
Gasoline (MMBbl).......................................... 457.8 459.1 451.0
Diesel fuel (MMBbl)....................................... 166.0 161.7 161.4
Jet fuel (MMBbl).......................................... 118.1 117.8 111.3
----------- ----------- -----------
Total refined product volumes (MMBbl)................... 741.9 738.6 723.7
Natural gas liquids (MMBbl)............................... 37.3 43.9 42.2
----------- ----------- -----------
Total delivery volumes (MMBbl)(b)....................... 779.2 782.5 765.9
=========== =========== ===========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes. Also, 2005 amount
includes expense of $19,600 associated with environmental liability
adjustments, expense of $105,000 associated with a rate case liability
adjustment, and expense of $13,691 associated with a North System liquids
inventory reconciliation adjustment. 2004 amount includes expense of
$30,611 associated with environmental expense adjustments.
(b) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
55
Our Products Pipelines segment's primary businesses include transporting
refined petroleum products and natural gas liquids through pipelines and
operating liquid petroleum products terminals and petroleum pipeline transmix
processing facilities. The segment reported earnings before depreciation,
depletion and amortization of $370.1 million on revenues of $711.9 million in
2005. This compared to earnings before depreciation, depletion and amortization
of $444.9 million on revenues of $645.2 million in 2004 and earnings before
depreciation, depletion and amortization of $441.6 million on revenues of $585.4
million in 2003.
As noted in the table above, and referred to above in "Critical Accounting
Policies and Estimates--Environmental Matters," the segment's 2005 and 2004
earnings include charges of $19.6 million and $30.6 million, respectively, from
the adjustment of our environmental liabilities. As noted in the table and
referred to above in "Critical Accounting Policies and Estimates--Legal
Matters," the segment's 2005 earnings also includes a charge of $105.0 million
attributable to an increase in our reserves related to our rate case liability.
Finally, as noted in the table above, the segment's 2005 earnings includes a
charge of $13.7 million to account for differences between physical and book
natural gas liquids inventory on our North System. This charge was based on an
inventory reconciliation of our North System's liquids inventory that was
completed in the fourth quarter of 2005. Excluding these adjustments, segment
earnings before depreciation, depletion and amortization totaled $508.4 million
in 2005 and $475.5 million in 2004.
The segment's overall $32.9 million (7%) increase in earnings before
depreciation, depletion and amortization in 2005 versus 2004 (excluding the
above adjustments) included an $18.6 million increase from our Southeast product
terminal operations. Our Southeast terminal operations consist of 23 refined
products terminals located in the southeastern United States that we acquired in
December 2003, March 2004, and November 2004. The overall $18.6 million
year-to-year increase in earnings before depreciation, depletion and
amortization from our Southeast terminals included incremental earnings of $9.9
million from the nine refined product terminal operations we acquired in
November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC;
the remaining $8.7 million (73%) increase was primarily due to higher product
throughput revenues and to the inclusion of a full year of operations from the
seven refined product terminal operations we acquired in March 2004 from Exxon
Mobil Corporation.
Other increases to the segment's earnings before depreciation, depletion and
amortization in 2005 compared to the prior year included a $17.5 million (7%)
increase from our Pacific operations, a $3.3 million (8%) increase from our
CALNEV Pipeline, a $1.9 million (6%) increase from our approximate 51% ownership
interest in Plantation Pipe Line Company, and a $1.3 million (4%) increase from
our Central Florida Pipeline.
The increases from our combined Pacific and CALNEV operations were primarily
revenue driven; revenues from refined petroleum product deliveries increased
$24.1 million (9%) and terminal service revenues increased $7.5 million (8%).
The increase in earnings before depreciation, depletion and amortization
attributable to Plantation was mainly due to the recognition, in 2005, of
incremental interest income of $2.5 million on our long-term note receivable
from Plantation. In July 2004, we loaned $97.2 million to Plantation to allow it
to pay all of its outstanding credit facility and commercial paper borrowings
and in exchange for this funding, we received a seven year note receivable
bearing interest at the rate of 4.72% per annum. The increase in earnings from
our Central Florida Pipeline was mainly due to higher product delivery revenues,
resulting from an 8% increase in throughput delivery volumes.
Offsetting the overall increase in segment earnings before depreciation,
depletion and amortization in 2005 compared to 2004 were decreases in earnings
of $3.4 million (15%) from our 49.8% proportionate interest in the Cochin
pipeline system, $2.6 million (6%) from our West Coast product terminals, $2.0
million (9%) from our petroleum transmix processing operations, and a combined
$1.7 million (6%) from our North System and Cypress natural gas liquids
pipelines.
The decrease from Cochin resulted from both lower transportation revenues,
due to a drop in delivery volumes caused by extended pipeline testing and repair
activities and warmer winter weather, and higher operating expenses, due
principally to higher pipeline repair, maintenance and testing costs. The
decrease from our West Coast terminals was largely due to higher property tax
expenses in 2005, due to expense reversals taken in the second quarter of 2004
pursuant to favorable property reassessments, and to lower product revenues
resulting from the fourth quarter 2004 closure of our Gaffey Street product
terminal located in San Pedro, California. The year-to-year
56
decrease in earnings from our transmix operations was due to both lower revenues
and lower other income. The decrease in revenues was due to a nearly 6% decrease
in processing volumes, largely resulting from the disallowance, beginning in
July 2004, of methyl tertiary-butyl ether (MTBE) blended transmix in the State
of Illinois. The decrease in other income was due to a $0.9 million benefit
taken from the reversal of certain short-term liabilities in the second quarter
of 2004. The decrease in earnings from our North System was mainly due to higher
product storage expenses, which was related to a new storage contract agreement
entered into in April 2004 and to higher levels of year-end inventory in 2005.
Cypress' decrease was driven by lower revenues, the result of a 17% decrease in
throughput volumes that was largely due to the third quarter 2005
hurricane-related closure of a petrochemical plant in Lake Charles, Louisiana
that is served by the pipeline.
The segment's overall $33.9 million (8%) increase in earnings before
depreciation, depletion and amortization in 2004 compared to 2003 (excluding the
2004 environmental charge) included incremental earnings of $14.0 million from
the addition of our Southeast terminal operations, and a year-to-year increase
in earnings of $9.5 million (4%) from our Pacific operations. For our Pacific
operations, the increase was primarily due to incremental fees earned from
ethanol-related blending services, higher refined product delivery revenues, and
incremental revenues related to the refined products terminal operations we
acquired from Shell Oil Products in October 2003. Due to environmental and
health concerns, the State of California began transitioning from MTBE-blended
gasoline to ethanol-blended gasoline in 2003, and mandated the elimination of
MTBE from gasoline by January 1, 2004. Ethanol is an alcohol-based alternative
fuel produced by fermenting and distilling starch crops and can be used to
increase octane and improve the emissions quality of gasoline. However, due to
the lack of dedicated pipelines, ethanol cannot be shipped through pipelines but
must instead be blended at terminals. We have, therefore, since 2003, realized
some reduction in California gasoline volumes transported by our Pacific and
CALNEV pipelines but the conversion from MTBE to ethanol in California has
resulted in an increase in ethanol blending services at many of our Pacific,
CALNEV and West Coast refined petroleum product terminal facilities, and the
fees we have earned for ethanol-related services at our terminals have more than
offset the reduction in pipeline transportation fees.
We also reported, in 2004, increases in earnings before depreciation,
depletion and amortization of $8.9 million (64%) from our proportionate
ownership interest in the Cochin pipeline system, $2.8 million (7%) from our
West Coast terminal operations, and $1.4 million (32%) from our Cypress
Pipeline. For our proportionate interest in Cochin, the increase in earnings
before depreciation, depletion and amortization was driven by higher revenues
from pipeline throughput deliveries and by an additional ownership interest
acquired since the end of 2003. Effective October 1, 2004, we acquired an
additional undivided 5% interest in the Cochin pipeline system for approximately
$10.9 million, bringing our total interest to 49.8%. For our West Coast
terminals, the increase in earnings was largely attributable to higher fees from
ethanol blending services and from revenue increases across all service
activities performed at our Carson, California and our connected Los Angeles
Harbor product terminals. The increase in Cypress' earnings in 2004 versus 2003
was primarily due to a 26% increase in throughput delivery volumes in 2004, due
to improved demand for natural gas liquids driven by higher petrochemical profit
margins.
The overall increase in segment earnings before depreciation, depletion and
amortization in 2004 compared to 2003 were partly offset by decreases in
earnings of $2.4 million (5%) from our CALNEV Pipeline and $2.1 million (8%)
from our North System. For CALNEV, the decrease was driven by higher 2004 fuel
and power expenses, higher operating expenses, and lower other income items. For
the North System, the decrease was primarily due to higher 2004 leased storage
expenses, due to higher lease fees, and lower transport revenues, related to a
6% decrease in 2004 throughput delivery volumes. The decline in North System
delivery volumes was primarily due to a lack of propane supplies in February
through April of 2004, caused by shippers reducing line-fill and storage volumes
to lower levels than 2003. In April 2004, we filed a plan with the Federal
Energy Regulatory Commission to provide a line-fill service, which has helped
mitigate the supply problems we experienced on our North System in the first
half of 2004. Pursuant to this plan, we purchased $23.0 million of line-fill
during 2004.
Revenues for the segment increased $66.7 million (10%) in 2005 compared to
2004. The 10% increase primarily consisted of:
* a $33.1 million increase from incremental revenues earned by our
Southeast terminal operations, including $23.7 million attributable to
the Charter terminals we acquired in November 2004, and $8.4 million
attributable to the ExxonMobil terminals we acquired in March 2004;
57
* a $26.5 million (8%) increase from our Pacific operations;
* a $5.1 million (9%) increase from our CALNEV Pipeline;
* a $2.8 million (8%) increase from our Central Florida Pipeline; and
* a $1.8 million (5%) decrease from our investment in the Cochin
Pipeline, as described above.
Our Pacific operations' $26.5 million increase in revenues in 2005 relative
to 2004 included increases of $21.2 million (9%) from mainline refined product
delivery revenues and $5.4 million (6%) from incremental terminal revenues. The
increase from product delivery revenues was driven by a 2% increase in delivery
volumes and by increases in average tariff rates. The higher tariff rates
included FERC approved annual indexed interstate tariff increases in July of
2004 and 2005 (producer price index-finished goods adjustments), and a filed
rate increase on our completed North Line expansion with the California Public
Utility Commission. In November 2004, we filed an application with the CPUC
requesting a $9 million increase in existing California intrastate
transportation rates to reflect the in-service date of our $95 million North
Line expansion project. Pursuant to CPUC regulations, this increase
automatically became effective as of December 22, 2004, but is being collected
subject to refund, pending resolution of protests to the application by certain
shippers. The year-to-year increase in revenues from terminal operations was
primarily due to increased terminaling and ethanol blending services, as a
result of the increase in throughput, and to incremental revenues from diesel
lubricity-additive injection services that we began offering in May 2005.
For our CALNEV Pipeline, the $5.1 million increase in revenues in 2005
versus 2004 consisted of a $2.9 million (7%) increase from refined product
delivery revenues, primarily due to volume growth, and a $2.2 million (19%)
increase from terminal operations, due to higher product storage, injection and
ethanol blending services. The year-to-year increase in Central Florida's
revenues in 2005 compared to 2004 was due to an 8% increase in transport
volumes, partly due to hurricane-related pipeline delivery disruptions in the
State of Florida during the third quarter of 2004.
Including all of the segment's operations, total delivery volumes of refined
products, consisting of gasoline, diesel fuel and jet fuel, were up 0.4% in 2005
compared to 2004, with increases on Pacific, Central Florida and CALNEV offset
by a decrease on Plantation. Excluding Plantation, which was impacted by Gulf
Coast hurricanes and post-hurricane refinery disruptions in 2005, refined
products delivery volumes increased 2.5% in 2005 compared to 2004; by product,
deliveries of gasoline, diesel fuel and jet fuel increased 1.6%, 5.0% and 2.6%,
respectively, in 2005 compared to 2004. Year-to-year deliveries of natural gas
liquids were down 15% in 2005 versus 2004. The decrease was due to low demand
for propane on both the North System, primarily due to a minimal grain drying
season and warmer weather in 2005, and the Cypress Pipeline, due to the
hurricane-related closure of a petrochemical plant in Lake Charles, Louisiana.
The $59.8 million (10%) increase in segment revenues in 2004 compared to
2003 primarily consisted of the following:
* a $23.2 million increase attributable to the acquisition of our
Southeast terminals;
* a $16.6 million (5%) increase from our Pacific operations;
* a $13.1 million (53%) increase from our proportionate share of Cochin;
* a $2.7 million (8%) increase from our Central Florida Pipeline; and
* a $2.0 million (4%) increase from our West Coast terminals
Our Pacific operations' year-over-year increase was due to both the higher
terminal revenues, discussed above, and higher transport revenues, due largely
to an almost 2% increase in mainline delivery volumes. Cochin's increase was
mainly due to a 30% increase in delivery volumes and to higher average tariff
rates in 2004 versus 2003. The increase in delivery volumes was due to two
reasons. First, lower product inventory levels in western
58
Canada in the first half of 2003, caused by a drop in propane production due to
lower profit margins from the extraction and sale of natural gas liquids, and
secondly, a pipeline rupture and fire in July 2003 that led to the shutdown of
the system for 29 days during the third quarter of 2003. For our Central Florida
Pipeline, the 8% increase in revenues in 2004 compared to 2003 reflected an
almost 8% increase in product delivery volumes, and for our West Coast
terminals, the revenue growth in 2004 related to increased terminal services, as
described above.
Combining all of the segment's operations, total throughput delivery of
refined petroleum products increased 2% in 2004 compared to 2003. Jet fuel
delivery volumes, boosted by strong military and solid commercial demand, were
up nearly 6% in 2004 compared to 2003, and gasoline delivery volumes increased
2%. Deliveries of diesel fuel were essentially flat across both 2004 and 2003,
but both gasoline and diesel volumes were impacted in the fourth quarter of 2004
by the shut-down of a refinery connected to the Plantation Pipeline following
Hurricane Ivan.
Excluding the effects attributable to the 2005 and 2004 environmental
liability adjustments, the 2005 Pacific operations' pipeline rate case liability
adjustment and the North System's inventory reconciliation adjustment, the
segment's operating expenses increased $36.3 million (19%) in 2005 compared to
2004. The overall increase included incremental expenses of $14.5 million from
our Southeast terminals, including $13.7 million from the terminals we acquired
in November 2004. The overall increase in segment operating expenses also
included an increase of $11.7 million (13%) from our combined Pacific and CALNEV
Pipeline operations. The increase was mainly due to higher labor and operating
expenses, including incremental power expenses, associated with increased
transportation volumes and terminal operations, as well as higher maintenance,
inspection, and pipeline integrity expenses incurred during 2005 as a result of
environmental issues, repairs, clean-up, and pipeline repairs associated with
wash-outs that were caused by flooding in the State of California in the first
quarter of 2005. We also reported, in 2005, operating expense increases of $2.9
million from both our North System and our interest in Cochin, and $1.6 million
(9%) from our West Coast terminal operations. The 16% increase in our North
System's expenses was primarily due to higher liquids storage expenses in 2005,
as discussed above. The 22% increase in Cochin's expenses was primarily due to
higher labor and outside services associated with pipeline maintenance and
testing costs; incremental health, safety, and security work; and the full
year's inclusion of our additional 5% ownership interest, acquired on October 1,
2004. The increase from our West Coast terminals was due to higher property tax
expenses, described above, and higher cost of sales related to incremental
terminal services.
The segment's operating expenses increased $21.9 million (13%) in 2004
compared to 2003. The increase was mainly due to incremental expenses of $9.3
million from our Southeast terminals and to a $3.8 million (5%) increase in
expenses from our Pacific operations, largely the result of higher 2004 fuel and
power expenses associated with higher utility rates and higher delivery volumes.
The segment also reported a $1.6 million year-over-year increase in expenses in
2004 from each of the following four businesses: Cochin Pipeline, North System,
CALNEV Pipeline and Plantation Pipeline. Cochin's increase was related to higher
expenses associated with increased delivery volumes and our additional ownership
interest. The North System's increase was primarily due to higher natural gas
liquids storage expenses. CALNEV's increase was mostly due to higher fuel and
power expenses, due to favorable credit adjustments to electricity access and
surcharge reserves taken in the first nine months of 2003. Plantation's increase
was primarily related to higher 2004 labor, testing and maintenance expenses.
Earnings from our Products Pipelines' equity investments were $28.4 million
in 2005, $29.1 million in 2004 and $30.9 million in 2003. Earnings from equity
investments consist primarily of earnings from our approximate 51% ownership
interest in Plantation Pipe Line Company (which exclude interest income earned
on loans to Plantation) and our 50% ownership interest in Heartland Pipeline
Company, both accounted for under the equity method of accounting. The $0.7
million (2%) decrease in equity earnings in 2005 compared to 2004 included a
$1.3 million (5%) decrease related to our investment in Plantation and a $0.8
million (55%) increase related to our investment in Heartland. For our
investment in Plantation, the decrease in 2005 was due to lower overall net
income earned by Plantation, due to, among other things, higher operating
expenses and higher interest expenses. For our investment in Heartland, the
increase in 2005 was primarily due to higher pipeline delivery volumes in 2005
versus 2004. The $1.8 million (6%) decrease in equity earnings in 2004 compared
to 2003 was mainly due to a $2.4 million (8%) decrease in equity earnings from
our investment in Plantation. In the first quarter of 2004, we recorded a $3.2
million expense for our share of an environmental litigation settlement reached
between Plantation and various plaintiffs.
59
The segment's income from allocable interest income and other income and
expense items increased $1.4 million in 2005 compared to 2004, and decreased
$1.8 million in 2004 compared to 2003. For 2005, the increase primarily related
to incremental interest income of $2.5 million on our long-term note receivable
from Plantation, as discussed above; for 2004, the decrease was largely due to
higher gains realized from sales of property, plant and equipment by our Pacific
operations during 2003. Income tax expense was essentially flat across 2004 and
2003, but decreased $1.7 million (14%) in 2005 compared to 2004. The decrease
was mainly due to lower income tax on Cochin, largely due to the decrease in
Canadian operating results in 2005.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of investments, were $82.5 million, $74.5 million
and $70.6 million in each of the years ended December 31, 2005, 2004 and 2003,
respectively. The year-over-year increases in both 2005 and 2004 were primarily
due to incremental depreciation charges related to the acquisition of our
Southeast terminals and to higher depreciation expenses from our Pacific
operations, related to the capital investment we have made since the end of 2003
in order to strengthen and enhance our business operations on the West Coast.
For 2006, we currently expect that our Products Pipelines segment will
report earnings before depreciation, depletion and amortization expense of
approximately $581.7 million, a 14% increase over 2005, excluding the effects
from the environmental, rate case, and inventory expense adjustments discussed
above. The earnings increase is expected to be driven by continued improvement
in refined petroleum product delivery volumes and planned capital improvements
and expansions.
Natural Gas Pipelines
Year Ended December 31,
------------------------------------------
2005 2004 2003
------------ ------------ ------------
(In thousands, except operating statistics)
Revenues.................................................. $ 7,718,384 $ 6,252,921 $ 5,316,853
Operating expenses (including environmental adjustments)(a) (7,254,979) (5,854,557) (4,967,531)
Earnings from equity investments.......................... 36,812 19,960 24,012
Interest income and Other, net - income (expense)......... 2,729 1,832 1,082
Income taxes.............................................. (2,622) (1,895) (1,066)
------------ ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 500,324 418,261 373,350
Depreciation, depletion and amortization expense.......... (61,661) (53,112) (53,785)
Amortization of excess cost of equity investments......... (277) (277) (277)
------------ ------------ ------------
Segment earnings........................................ $ 438,386 $ 364,872 $ 319,288
============ ============ ============
Natural gas transport volumes (Trillion Btus)(b) 1,317.9 1,353.1 1,364.1
============ ============ ============
Natural gas sales volumes (Trillion Btus)(c)... 925.8 992.4 906.0
============ ============ ============
- ----------
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes. Also, includes decreases in expense of $89 in 2005 and $7,602 in
2004 associated with environmental liability adjustments.
(b) Includes Kinder Morgan Interstate Gas Transmission, Texas intrastate
natural gas pipeline group, Trailblazer and TransColorado pipeline volumes.
TransColorado annual volumes are included for all three years (acquisition
date November 1, 2004).
(c) Represents Texas intrastate natural gas pipeline group.
Our Natural Gas Pipelines segment's primary businesses involve transporting,
storing, marketing, gathering and processing natural gas through both intrastate
and interstate pipeline systems and related facilities. In 2005, the segment
reported earnings before depreciation, depletion and amortization of $500.3
million on revenues of $7,718.4 million. This compared to earnings before
depreciation, depletion and amortization of $418.3 million on revenues of
$6,252.9 million in 2004 and earnings before depreciation, depletion and
amortization of $373.4 million on revenues of $5,316.9 million in 2003.
As noted in the table above, the segment's earnings in 2005 and 2004
included increases of $0.1 million and $7.6 million, respectively, from the
adjustments of our environmental liabilities referred to in "Critical Accounting
60
Policies and Estimates--Environmental Matters." Excluding the environmental
adjustments, segment earnings before depreciation, depletion and amortization
totaled $500.2 million in 2005 and $410.7 million in 2004. Both the $89.5
million (22%) increase in segment earnings before depreciation, depletion and
amortization in 2005 compared to 2004 and the $37.3 million (10%) increase in
2004 compared to 2003 were primarily driven by:
* improved margins on recurring natural gas sales business and higher
storage and service revenues from our Texas intrastate natural gas
pipeline group, which includes the operations of the following four
natural gas pipeline systems: Kinder Morgan Tejas, Kinder Morgan Texas
Pipeline, Kinder Morgan North Texas Pipeline and the Mier-Monterrey
Mexico Pipeline; and
* incremental contributions from the inclusion of our TransColorado
Pipeline, a 300-mile interstate natural gas pipeline system that extends
from the Western Slope of Colorado to the Blanco natural gas hub in
northwestern New Mexico. We acquired the TransColorado Pipeline from KMI
effective November 1, 2004.
The segment's overall $89.5 million (22%) increase in earnings before
depreciation, depletion and amortization in 2005 versus 2004 (excluding
environmental adjustments) included increases of $33.4 million from the
inclusion of TransColorado, $30.1 million (13%) from our Texas intrastate
natural gas pipeline group, $17.3 million (119%) from our 49% equity investment
in the Red Cedar Gathering Company, $10.9 million (28%) from our Trailblazer
Pipeline, $2.4 million (2%) from our Kinder Morgan Interstate Gas Transmission
system, referred to as KMIGT, and $0.6 million (24%) from our 50% equity
investment in Coyote Gas Treating, LLC.
The segment's overall increase in earnings before depreciation, depletion
and amortization in 2005 compared to 2004 was offset by a $5.2 million (35%)
decrease in earnings from our Casper Douglas natural gas gathering system. The
decrease was primarily due to higher cost of sales, caused by higher natural gas
purchase costs as a result of higher average gas prices, and to higher commodity
hedging costs, due to unfavorable changes in settlement prices.
The increase in 2005 compared to 2004 from Red Cedar related to higher
year-over-year net income that was largely driven by incremental revenues from
sales of excess fuel gas, the result of both higher natural gas prices in 2005
and reductions in the amount of natural gas lost and used within the system
during gathering operations, which increased volumes available for sale. The
increase from our Trailblazer Pipeline, a 436-mile natural gas pipeline system
that transports gas from near Rockport, Colorado to Beatrice, Nebraska, was
mainly due to timing differences on the favorable settlements of pipeline
transportation imbalances in 2005 versus 2004. These pipeline imbalances were
caused by differences between the volumes nominated and volumes delivered at an
inter-connecting point by the pipeline. The increase from KMIGT was mainly due
to lower operating expenses and higher revenues in 2005, compared to the prior
year. The higher revenues were mainly due to favorable fuel recovery volumes and
pricing and imbalance valuation adjustments, partially offset by lower
operational sales margins and reduced cushion gas volumes sold in 2005 versus
2004. The decrease in operating expenses was primarily due to KMIGT's expensing,
in the fourth quarter of 2004, certain capitalized project costs that no longer
held realizable economic benefits.
The segment's overall $37.3 million (10%) increase in earnings before
depreciation, depletion and amortization in 2004 compared to 2003 (excluding the
2004 environmental adjustment) included increases of $44.6 million (23%) from
our Texas intrastate natural gas pipeline group and $5.8 million from the
inclusion of TransColorado. Partially offsetting the overall increase in
earnings before depreciation, depletion and amortization were decreases of $10.6
million (21%) from our Trailblazer Pipeline and $3.9 million (21%) from our
investment in Red Cedar. The decrease from Trailblazer was mainly due to lower
revenues; the decrease from our investment in Red Cedar was due to lower equity
earnings as a result of overall lower net income. The drop in Trailblazer's
revenues in 2004 compared to 2003 was the result of both timing differences on
imbalance cashouts and lower transportation revenues. The decrease in
transportation revenues was due to lower gas transmission tariffs that became
effective January 1, 2004, pursuant to a rate case settlement.
The year-over-year increases in earnings before depreciation, depletion and
amortization in both 2005 and 2004 from our Texas intrastate natural gas
pipeline group were mainly due to improved margins from natural gas sales
activities, returns from capital investments and acquisitions made since the end
of 2003, and incremental earnings from natural gas transmission, storage, and
other services. The group has increased its gas transportation and
61
storage revenues by both increasing services performed under existing agreements
and by entering into additional service contracts.
Our Texas intrastate pipeline group has continued to grow internally and
through acquisitions by constructing and acquiring new natural gas assets and by
further refining the management of risk associated with the purchase and sale of
natural gas. Effective August 1, 2005, we acquired our North Dayton natural gas
storage facility, located in Liberty County, Texas, for an aggregate
consideration of approximately $109.4 million, consisting of $52.9 million in
cash and $56.5 million in assumed debt. The North Dayton facility includes 4.2
billion cubic feet of natural gas working capacity and since its acquisition,
the facility has allowed us to provide or offer needed services to utilities,
the growing liquefied natural gas industry along the Texas Gulf Coast, and other
natural gas storage users. Internally, we benefited from incremental
transportation revenues in both 2005 and 2004 from a 135-mile intrastate natural
gas pipeline providing transportation service between Katy and Austin, Texas.
The line, acquired in December 2003, was converted from carrying crude oil to
natural gas and was placed into service in July 2004. In 2005, we spent
approximately $32 million to convert and expand an additional 254-mile segment
of the line into the Permian Basin area of West Texas. The expansion accesses a
number of natural gas processing plants in West Texas and provides
transportation service from McCamey, Texas to just west of Austin. This segment
commenced service in October 2005. The project is being phased in through the
first quarter of 2006, and the total project costs are expected to be
approximately $46 million.
In each of the years 2005 and 2004, the segment reported significant
increases in both revenues and operating expenses when compared to the
year-earlier period. Revenues earned by our Natural Gas Pipelines segment
increased $1,465.5 million (23%) in 2005 versus 2004, and $936.0 million (18%)
in 2004 versus 2003. Excluding the effects attributable to the 2005 and 2004
environmental liability adjustments, the segment's operating expenses, including
natural gas purchase costs, increased $1,392.9 million (24%) in 2005 compared to
2004, and $894.6 million (18%) in 2004 compared to 2003. The increases in
revenues and operating expenses in both years were largely due to higher natural
gas sales revenues and higher natural gas cost of sales, due mainly to higher
commodity prices. Our Texas intrastate pipeline group both purchases and sells
significant volumes of natural gas, which is often stored and/or transported on
its pipelines. The group's purchase and sale activities result in considerably
higher revenues and operating expenses compared to the interstate operations of
our Rocky Mountain pipelines, which include our KMIGT, Trailblazer and
TransColorado pipelines. All three pipelines charge a transportation fee for gas
transmission service and have the authority to initiate natural gas sales
primarily for operational purposes, but none engage in significant gas purchases
for resale.
For the Texas intrastate group combined, revenues from the sales of natural
gas increased $1,405.8 million (25%) in 2005 compared to 2004, and $912.2
million (19%) in 2004 compared to 2003. Similarly, costs of sales, including
natural gas purchase costs, increased $1,393.8 million (25%) in 2005 compared to
2004, and $871.0 million (18%) in 2004 compared to 2003. In 2005, the inclusion
of our TransColorado Pipeline accounted for incremental revenues and expenses of
$37.6 million and $4.1 million, respectively, and in the two months of 2004 that
we owned TransColorado, it reported revenues of $6.7 million and operating
expenses of $1.1 million.
Due to the fact that our Texas intrastate group sells natural gas in the
same price environment in which it is purchased, the increases in its gas
purchase costs are largely offset by corresponding increases in its sales
revenues. Our objective is to match purchases and sales in the aggregate, thus
locking-in an acceptable margin that is the equivalent of a transportation
and/or storage fee. Margin is defined as the difference between the prices at
which we buy gas in our supply areas and the prices at which we sell gas in our
market areas, less the cost of fuel to transport. We manage remaining price risk
by the use of energy financial instruments, such as over-the-counter forward
contracts and both fixed price and basis swaps to help lock-in favorable margins
from our natural gas purchase and sales activities, thereby generating more
stable earnings during periods of fluctuating natural gas prices.
Total natural gas sales volumes decreased nearly 7% in 2005 compared to
2004, largely due to lower electric generation demand and to our efforts to
reduce sales to lower margin customers. In 2004, the group benefited from both
higher average gas prices and higher sales volumes when compared to 2003.
We account for the segment's investments in Red Cedar Gathering Company,
Coyote Gas Treating, LLC and Thunder Creek Gas Services, LLC under the equity
method of accounting. In 2005, equity earnings from these three investees
increased $16.9 million (84%) when compared to the prior year. The increase was
due to the higher net
62
income earned by Red Cedar during 2005, as described above. Earnings from equity
investments decreased $4.1 million (17%) in 2004 compared to 2003. The decrease
was chiefly due to lower earnings from our investment in Red Cedar, mainly due
to higher operational sales of natural gas by Red Cedar in 2003.
The segment's non-cash depreciation, depletion and amortization charges,
including amortization of excess cost of investments increased $8.5 million
(16%) in 2005 compared to 2004. The increase was largely due to the inclusion of
incremental depreciation expense on the acquired TransColorado Pipeline and to
higher depreciation expenses on the assets of our Texas intrastate natural gas
pipeline group, due to additional capital investments made since the end of
2004. Depreciation, depletion and amortization charges decreased a slight $0.7
million (1%) in 2004 compared to 2003, primarily due to lower year-to-year
depreciation expense on our Trailblazer Pipeline. The decrease was due to a
Trailblazer rate case settlement which became effective January 1, 2004.
For 2006, we currently expect that our Natural Gas Pipelines segment will
report earnings before depreciation, depletion and amortization expense of
approximately $501.2 million, essentially the same as the $500.2 million in
earnings reported in 2005, excluding the effect from our environmental liability
adjustments. The 2006 earnings is expected to be driven by the continuing the
sale of natural gas at favorable margins and by continuing to pursue expansion
and extension projects off our existing asset base.
CO2
Year Ended December 31,
---------------------------------------------
2005 2004 2003
------------- ------------- -------------
(In thousands, except operating statistics)
Revenues.................................................. $ 657,594 $ 492,834 $ 248,535
Operating expenses (including environmental adjustments)(a) (212,636) (169,256) (82,055)
Earnings from equity investments.......................... 26,319 34,179 37,198
Other, net - income (expense)............................. (5) 26 (40)
Income taxes.............................................. (385) (147) (39)
------------- ------------- -------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity
investments............................................ 470,887 357,636 203,599
Depreciation, depletion and amortization expense(b)....... (149,890) (121,361) (60,827)
Amortization of excess cost of equity investments......... (2,017) (2,017) (2,017)
------------- ------------- -------------
Segment earnings........................................ $ 318,980 $ 234,258 $ 140,755
============= ============= =============
Carbon dioxide delivery volumes (Bcf)(c)................... 649.3 640.8 504.7
============= ============= =============
SACROC oil production (gross)(MBbl/d)(d)................... 32.1 28.3 20.2
============= ============= =============
SACROC oil production (net)(MBbl/d)(e)..................... 26.7 23.6 15.9
============= ============= =============
Yates oil production (gross)(MBbl/d)(d).................... 24.2 19.5 18.9
============= ============= =============
Yates oil production (net)(MBbl/d)(f)...................... 10.8 8.6 1.8
============= ============= =============
Natural gas liquids sales volumes (net)(MBbl/d)(e)......... 9.4 7.7 3.7
============= ============= =============
Realized weighted average oil price per Bbl(g)(h).......... $ 27.36 $ 25.72 $ 23.73
============= ============= =============
Realized weighted average natural gas liquids price per
Bbl(h)(i).................................................. $ 38.98 $ 31.33 $ 21.77
============= ============= =============
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes. Also, includes expense
of $298 in 2005 and a decrease in expense of $4,126 in 2004 associated with
environmental liability adjustments.
(b) Includes depreciation, depletion and amortization expense associated with
oil and gas producing and gas processing activities in the amount of
$132,286 for 2005, $105,890 for 2004, and $49,039 for 2003. Includes
depreciation, depletion and amortization expense associated with sales and
transportation services activities in the amount of $17,604 for 2005,
$15,471 for 2004, and $11,788 for 2003.
(c) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(d) Represents 100% of the production from the field. We own an approximate 97%
working interest in the SACROC unit and an approximate 50% working interest
in the Yates unit.
(e) Net to Kinder Morgan.
(f) Net to Kinder Morgan. In 2003, we owned an approximate 7% working interest
in the Yates unit for four months and an approximate 50% working interest
for two months.
(g) Includes all Kinder Morgan crude oil production properties.
(h) Hedge gains/losses for oil and natural gas liquids are included with crude
oil.
(i) Includes production attributable to leasehold ownership and production
attributable to our ownership in processing plants and third party
processing agreements.
63
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. The segment's primary businesses involve the
production, transportation and marketing of carbon dioxide, commonly called CO2,
and the production and marketing of crude oil and natural gas from ownership
interests in field units located in the Permian Basin area of West Texas. In
2005, our CO2 segment reported earnings before depreciation, depletion and
amortization of $470.9 million on revenues of $657.6 million. This compared to
earnings before depreciation, depletion and amortization of $357.6 million on
revenues of $492.8 million in 2004 and earnings before depreciation, depletion
and amortization of $203.6 million on revenues of $248.5 million in 2003.
As noted in the table above, the segment's 2005 earnings included a $0.3
million decrease and its 2004 earnings included a $4.1 million increase from the
adjustments of our environmental liabilities referred to in "Critical Accounting
Policies and Estimates--Environmental Matters." Excluding the environmental
adjustments, segment earnings before depreciation, depletion and amortization
totaled $471.2 million in 2005 and $353.5 million in 2004. Both the $117.7
million (33%) increase in segment earnings before depreciation, depletion and
amortization in 2005 compared to 2004 and the $149.9 million (74%) increase in
2004 compared to 2003 were primarily driven by:
* higher earnings from the segment's oil and gas producing activities,
which include the operations associated with our ownership interests in
oil-producing fields and gas processing plants;
* improved performance from carbon dioxide sales; and
* incremental contributions from strategic acquisitions, which included
additional working interests in crude oil field units in both 2003 and
2005, and the Kinder Morgan Wink Pipeline in August 2004.
Our CO2 segment's oil and gas producing and gas processing activities
reported earnings before depreciation, depletion and amortization of $304.5
million in 2005, $220.4 million in 2004 and $103.6 million in 2003. These
operations include all construction, drilling and production activities
necessary to produce oil and gas from its natural reservoirs, and all of the
activities where natural gas is processed to extract liquid hydrocarbons, called
natural gas liquids or commonly referred to as gas plant products. Both the
$84.1 million (38%) increase in earnings before depreciation, depletion and
amortization in 2005 compared to 2004 and the $116.8 million (113%) increase in
2004 compared to 2003 were primarily driven by increased crude oil and natural
gas processing plant liquids production volumes and higher realized weighted
average sale prices for crude oil and gas plant products. The increase in 2004
compared to 2003 was also partly attributable to acquisitions of additional
ownership interests in oil producing properties since the beginning of 2003.
These acquisitions included the following:
* 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 in cash and the
assumption of $1.9 million of liabilities. This transaction increased our
ownership interest in the SACROC unit to approximately 97%; and
* effective November 1, 2003, we acquired certain assets in the Permian
Basin of West Texas from a subsidiary of Marathon Oil Corporation for
$230.2 million in cash and the assumption of $29.7 million of
liabilities. The assets acquired included Marathon's approximate 42.5%
interest in the Yates oil field unit, 100% interest in the crude oil
gathering system surrounding the Yates field unit, and Marathon's 65%
ownership interest in the Pecos Carbon Dioxide Pipeline Company. This
transaction increased our ownership interest in the Yates oil field unit
to nearly 50% and allowed us to become operator of the field.
Excluding the earnings effects attributable to the 2005 and 2004
environmental liability adjustments, our CO2 segment's carbon dioxide sales and
carbon dioxide and crude oil transportation activities reported earnings before
depreciation, depletion and amortization of $166.7 million in 2005, $133.1
million in 2004 and $100.0 million in 2003. The year-over-year increases were
driven by higher revenues from carbon dioxide sales, due to both higher average
carbon dioxide sale prices and higher volumes, and higher carbon dioxide
transportation volumes, related to infrastructure expansions at the SACROC and
Yates oil field units. We do not recognize profits on carbon dioxide sales to
ourselves.
In 2004 and 2005, we also benefited from the acquisition of the Kinder
Morgan Wink Pipeline, a 450-mile crude oil pipeline system originating in the
Permian Basin of West Texas and providing throughput to a crude oil refinery
located in El Paso, Texas. Effective August 31, 2004, we acquired all of the
partnership interests in Kinder Morgan
64
Wink Pipeline, L.P. for $89.9 million in cash and the assumption of $10.4
million in liabilities. The acquisition of the pipeline and associated storage
facilities has allowed us to better manage crude oil deliveries from our oil
field interests in West Texas. The Kinder Morgan Wink Pipeline accounted for
incremental earnings before depreciation, depletion and amortization of $13.7
million, revenues of $17.4 million and operating expenses of $3.7 million,
respectively, in 2005 compared to 2004. The pipeline contributed incremental
earnings before depreciation, depletion and amortization of $6.0 million,
revenues of $7.8 million and operating expenses of $1.8 million during the last
four months of 2004.
We also benefited, in 2004, from incremental contributions from our $28.5
million Centerline carbon dioxide pipeline, which was completed and began
operations in May 2003. In 2004, the Centerline Pipeline contributed incremental
earnings before depreciation, depletion and amortization of $3.4 million,
revenues of $4.1 million and operating expenses of $0.7 million, respectively.
Revenues earned by our CO2 business segment increased $164.8 million (33%)
in 2005 compared to 2004, and $244.3 million (98%) in 2004 compared to 2003. The
increase in 2005 versus 2004 was mainly due to higher crude oil, gas plant
product and carbon dioxide sales revenues, and higher crude oil transportation
revenues. Additionally, effective January 31, 2005, we spent $6.2 million in
cash and assumed $0.3 million in liabilities to acquire an approximate 64.5%
gross working interest in the Claytonville oil field unit, also located in the
Permian Basin. In 2005, Claytonville contributed incremental revenues of $2.6
million. The increase in 2004 versus 2003 was mainly due to higher crude oil and
gas plant product sales revenues, driven by higher production volumes, higher
average crude oil and gas plant product prices, and the additional working
interest in the Yates oil field that we acquired in November 2003. Combined, the
assets we acquired on November 1, 2003 contributed incremental revenues of
approximately $96.3 million in 2004.
Combined daily oil production from the two largest oil field units in which
we hold ownership interests increased 18% in 2005 compared to 2004, and 22% in
2004 compared to 2003. The two oil field interests include our approximate 97%
working interest in the SACROC unit, located in Scurry County, Texas, and our
approximate 50% working interest in the Yates oil field unit, located south of
Midland, Texas. Similarly, natural gas plant liquids product sales volumes
increased 22% in 2005 compared to 2004, and 108% in 2004 compared to 2003. The
year-over-year increases in oil production and gas plant product sales volumes
were primarily due to the capital expenditures we have made since the end of
2003.
We have made significant capital investments to increase the capacity and
deliverability of carbon dioxide and crude oil in and around the Permian Basin.
In 2005, capital expenditures for our CO2 business segment totaled $302.1
million, essentially the same as the $302.9 million of capital expenditures we
made during 2004, but 11% higher than the $272.2 million of expenditures made in
2003. The year-over-year increases largely represented incremental spending for
new well and injection compression facilities at the SACROC and, to a lesser
extent, Yates oil field units in order to enhance oil recovery from carbon
dioxide injection.
We also benefited from increases in our realized weighted average price of
oil and natural gas liquids per barrel of 6% and 24%, respectively, in 2005
compared to 2004, and increases of 8% and 44%, respectively, in 2004 compared to
2003. As a result of our carbon dioxide and oil reserve ownership interests, we
are exposed to commodity price risk associated with physical crude oil, gas
plant product and carbon dioxide sales that have pricing tied to crude oil
prices, but the risk is mitigated by our long-term hedging strategy that is
intended to generate more stable realized prices. Our hedging strategy involves
the use of financial derivative commodity instruments to manage this price risk
on certain activities, including firm commitments and anticipated transactions
for the sale of crude oil, natural gas liquids and carbon dioxide. Our strategy,
as it relates to our oil production business, primarily involves entering into a
forward sale or, in some cases, buying a put option in order to establish a
known price level. In this way, we use derivatives to lock in an acceptable
margin between our production costs and our selling price, in an attempt to
protect ourselves against the risk of adverse price changes and to maintain a
more stable and predictable earnings stream. All of our hedge gains and losses
for crude oil and natural gas liquids are included in our realized average price
for oil, none are allocated to natural gas liquids. For more information on our
hedging activities, see Note 14 to our consolidated financial statements,
included elsewhere in this report.
Additionally, in both 2005 and 2004, we realized higher revenues from both
carbon dioxide sales and carbon dioxide transportation services, driven by
continued strong demand for carbon dioxide throughout the Permian
65
Basin. The increase in sales revenues was due to higher volumes and higher
average prices; the increase in transportation services was mainly due to higher
carbon dioxide transportation volumes. Combined deliveries of carbon dioxide on
our Central Basin Pipeline, our majority-owned Canyon Reef Carriers and Pecos
Pipelines, our Centerline Pipeline, and our 50% owned Cortez Pipeline, which is
accounted for under the equity method of accounting, increased 1% in 2005 and
27% in 2004.
As discussed in Note 2 to our consolidated financial statements included
elsewhere in this report, in some cases, the cost of carbon dioxide that is
associated with enhanced oil recovery is capitalized as part of our development
costs when it is injected. The carbon dioxide costs incurred and capitalized as
development costs for our CO2 segment were $74.7 million, $70.6 million and
$45.9 million for the years ended December 31, 2005, 2004 and 2003,
respectively. We estimate that such costs will be approximately $79.2 million,
$73.9 million and $52.0 million in 2006, 2007 and 2008, respectively. In
addition, as of December 31, 2005, our projected expenditures for developing our
proved undeveloped reserves will be approximately $264.5 million in 2006, $165.6
million in 2007, and $172.3 million in 2008.
Excluding the effects attributable to the 2005 and 2004 environmental
liability adjustments, our CO2 segment's combined operating expenses increased
$39.0 million (22%) in 2005 compared to 2004, and $91.3 million (111%) in 2004
compared to 2003. The increases were primarily the result of higher property and
production taxes, higher fuel and power costs, and higher operating and
maintenance expenses. The increases in taxes were due to the year-over-year
increases in capitalized assets and oil production volumes. The increases in
fuel and power costs were due to increased carbon dioxide compression and
equipment utilization, as well as higher rates paid to electricity providers.
The increases in operating and maintenance expenses were mainly due to
additional labor and field expenses related to higher production volumes. Since
mid-2005, we have, however, benefited from the completion of a power plant we
constructed at the SACROC oil field unit. Construction began in mid-2004, and
the project was completed at a cost of approximately $76 million. The power
plant is being operated by KMI and is providing the majority of SACROC's current
electricity needs.
Earnings from equity investments decreased $7.9 million (23%) in 2005
compared to 2004. The earnings in both years represent our 50% interest in the
net income of the Cortez Pipeline Company, which owns and operates an
approximate 500-mile pipeline that carries carbon dioxide from the McElmo Dome
source reservoir to the Denver City , Texas carbon dioxide hub. The decrease in
equity earnings in 2005 was due to lower overall net income earned by Cortez,
mainly as a result of lower carbon dioxide transportation revenues due to
previously agreed lower tariff rates. Earnings from equity investments decreased
$3.0 million (8%) in 2004 compared to 2003. The decrease resulted from the
absence of equity earnings, in 2004, from our previous 15% ownership interest in
MKM Partners, L.P. Following our June 1, 2003 acquisition of its 12.75% interest
in the SACROC unit, MKM Partners was dissolved effective June 30, 2003, and the
lack of equity earnings in 2004 more than offset a $2.0 million (6%) increase in
equity earnings from our 50% investment in Cortez. The increase in equity
earnings from Cortez was mainly due to higher carbon dioxide delivery volumes in
2004 versus 2003.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, were up $28.5 million (23%)
in 2005 compared to 2004 and $60.5 million (96%) in 2004 compared to 2003. The
increases were primarily due to higher depreciable costs, related to incremental
capital spending since the end of 2003, and higher depletion charges, related to
year-over-year increases in crude oil production volumes.
For 2006, we currently expect that our CO2 segment will report earnings
before depreciation, depletion and amortization expense of approximately $547.4
million, a 16% increase over the $471.2 million in earnings reported in 2005,
excluding the effect from environmental liability adjustments. The earnings
increase is expected to be driven by the continuing development of the SACROC
and Yates oil field units and the initiation of gas processing enhancements.
66
Terminals
Year Ended December 31,
---------------------------------------
2005 2004 2003
----------- ----------- -----------
(In thousands, except operating
statistics)
Revenues.................................................. $ 699,264 $ 541,857 $ 473,558
Operating expenses (including environmental adjustments)(a) (373,410) (254,115) (229,054)
Earnings from equity investments.......................... 83 1 41
Other, net - income (expense)............................. (220) (396) 88
Income taxes(b)........................................... (11,111) (5,609) (3,857)
----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity 314,606 281,738 240,776
investments.................................................
Depreciation, depletion and amortization expense.......... (59,077) (42,890) (37,075)
Amortization of excess cost of equity investments......... - - -
----------- ----------- -----------
Segment earnings........................................ $ 255,529 $ 238,848 $ 203,701
=========== =========== ===========
Bulk transload tonnage (MMtons)(c)............. 83.2 84.1 61.2
=========== =========== ===========
Liquids leaseable capacity (MMBbl)............. 42.4 36.8 36.2
=========== =========== ===========
Liquids utilization %.......................... 95.4% 96.0% 96.0%
=========== =========== ===========
- ----------
(a) Includes costs of sales, operations and maintenance expenses, fuel and
power expenses and taxes, other than income taxes. Also, includes expense
of $3,535 in 2005 and income of $18,651 in 2004 associated with
environmental liability adjustments.
(b) Includes expense of $80 in 2004 associated with environmental liability
adjustments. (c) 2005 and 2004 volumes include all acquired terminals.
Our Terminals segment includes the operations of our coal, petroleum coke,
steel and other dry-bulk material terminals, as well as all the operations of
our petroleum and petrochemical-related liquids terminal facilities. The segment
reported earnings before depreciation, depletion and amortization of $314.6
million on revenues of $699.3 million in 2005. This compared to earnings before
depreciation, depletion and amortization of $281.7 million on revenues of $541.9
million in 2004 and earnings before depreciation, depletion and amortization of
$240.8 million on revenues of $473.6 million in 2003.
As noted in the table above, the segment's 2005 earnings included a $3.5
million decrease and its 2004 earnings included an $18.6 million increase from
the adjustments of our environmental liabilities referred to in "Critical
Accounting Policies and Estimates--Environmental Matters." Excluding the
environmental adjustments, segment earnings before depreciation, depletion and
amortization totaled $318.1 million in 2005 and $263.1 million in 2004.
Terminal operations acquired since the end of the third quarter of 2004
accounted for incremental amounts of earnings before depreciation, depletion and
amortization of $48.6 million, revenues of $113.3 million and operating expenses
of $64.1 million, respectively, in 2005. Since the end of the third quarter of
2004, we invested approximately $285.5 million in cash and $49.6 million in
common units to acquire assets and business operations included as part of our
Terminals segment. The acquisitions were made in order to gain access to larger
markets and to benefit from the economies of scale resulting from increases in
storage, handling and throughput capacity. The acquisitions helped increase
segment earnings before depreciation, depletion and amortization in both 2004
and 2005, and the most significant of these additions included the following:
* the river terminals and rail transloading facilities owned and operated
by Kinder Morgan River Terminals LLC and its consolidated subsidiaries,
acquired effective October 6, 2004;
* our Kinder Morgan Fairless Hills terminal located along the Delaware
River in Bucks County, Pennsylvania, acquired effective December 1, 2004;
* our Texas petroleum coke terminals, located in and around the Ports of
Houston and Beaumont, Texas, acquired effective April 29, 2005; and
67
* three terminals acquired separately in July 2005: our Kinder Morgan
Staten Island terminal, a dry-bulk terminal located in Hawesville,
Kentucky and a liquids/dry-bulk facility located in Blytheville,
Arkansas.
For more information in regard to our terminal acquisitions, see Note 3 to
our consolidated financial statements included elsewhere in this report.
For all other terminal operations (those owned during both years), earnings
before depreciation, depletion and amortization increased $6.4 million (2%) in
2005 compared to 2004 (excluding the environmental adjustments). We believe that
overall financial results would have been stronger in 2005 without the effects
of two hurricanes. In the third quarter of 2005, Hurricane Katrina struck the
Louisiana-Mississippi Gulf Coast, and Hurricane Rita struck the Texas-Louisiana
Gulf Coast, causing wide-spread damage to both residential and commercial
property. The assets we operate that were impacted by the storm included several
bulk and liquids terminal facilities located in the States of Louisiana,
Mississippi and Texas. Most of our owned terminal sites were minimally impacted
and suffered no significant structural damage. Terminals that were shutdown by
the storms experienced relatively short-term interruptions; however, throughput
at both the liquids terminals and bulk handling facilities decreased in the
fourth quarter of 2005 compared to the same period in 2004 due to post-hurricane
production issues at a number of Gulf Coast refineries. Presently, all of the
terminals have either resumed service or will do so in coordination with the
start up of associated refineries, businesses and other infrastructure located
along the Gulf Coast.
Our Terminals segment recognized, in 2005, essentially all of our losses
related to both hurricanes, and in total, the segment recognized $2.6 million in
expense in 2005 in order to meet its insurance deductible for Hurricane Katrina
and another $0.8 million to repair damaged facilities following Hurricane Rita.
We expect that the total costs incurred as a result of the two hurricanes will
be less than $10 million, including lost business at our terminal sites, but
estimates are difficult because of insurance complexities and the extended
recovery time involved. We do not believe that the resolution of any remaining
matters will have a material adverse effect on our business, financial position,
results of operations or cash flows.
The overall $6.4 million increase in segment earnings before depreciation,
depletion and amortization from terminals owned during both 2004 and 2005,
included a $13.7 million (22%) increase in earnings before depreciation,
depletion and amortization from our two large Gulf Coast liquids terminal
facilities located along the Houston Ship Channel in Pasadena and Galena Park,
Texas. The two terminals serve as a distribution hub for Houston's crude oil
refineries, and their combined year-to-year increase in earnings was largely due
to higher revenues, driven by higher sales of petroleum transmix, new customer
agreements, and escalations in annual contract provisions. Since the end of
2003, we have continued to invest in expansion projects at these two terminals;
resulting in additional storage tanks that have increased leaseable capacity for
refined petroleum product throughput.
For our entire liquids terminals combined, we have increased our liquids
leaseable capacity by 5.6 million barrels (15%) since the end of 2004. We
accomplished this through a combination of business acquisitions and internal
capital spending. At the same time, we maintained an overall capacity
utilization rate of over 95%. Our liquids terminals utilization rate is the
ratio of our actual output to our estimated potential output. Potential output
is generally derived from measures of total capacity, taking into account
periodic changes to terminal facilities due to additions, disposals,
obsolescence, or other factors.
Other contributions to the growth in earnings before depreciation, depletion
and amortization in 2005 versus 2004 included increases of $4.4 million (11%)
from terminals in our Midwest region, and $2.9 million (130%) from engineering
and other terminal services. For our Midwest terminal region, the increase
included higher earnings from our Dakota bulk terminal, located along the
Mississippi River near St. Paul, Minnesota; our Argo, Illinois liquids terminal,
situated along the Chicago sanitary and ship channel; and our Milwaukee,
Wisconsin bulk commodity terminal. The increase in earnings from Dakota was
primarily due to higher revenues generated by a cement unloading and storage
facility, which began operations in late 2004. The increase from our Argo
terminal was mainly due to new customer contracts and higher ethanol handling
revenues. The increase from our Milwaukee bulk terminal was mainly due to an
increase in coal handling revenues related to higher coal truckage within the
State of Wisconsin.
The overall increase in segment earnings before depreciation, depletion and
amortization in 2005 compared to 2004 from terminals owned during both periods
was partially offset by decreases of $10.4 million (30%) from
68
terminals in the Lower Mississippi River (Louisiana) region, and $4.3 million
(13%) from terminals in the Mid-Atlantic region. The decrease from the Louisiana
region terminals was largely related to the negative effects of the two Gulf
Coast hurricanes in 2005, resulting in both lower revenues and higher fuel and
power costs. Primarily affected was our International Marine Terminals facility,
a Louisiana partnership owned 66 2/3% by us. IMT is a multi-purpose bulk
commodity transfer terminal facility located in Port Sulphur, Louisiana. Its
overall earnings before depreciation, depletion and amortization decreased $6.5
million in 2005 compared to 2004, largely the result of property damage and a
general loss of business due to the effects of Hurricane Katrina.
The year-to-year decrease from our Mid-Atlantic terminals included a $2.1
million decrease in earnings from our Pier IX bulk terminal, located in Newport
News, Virginia, and a $2.0 million decrease in earnings from our Chesapeake Bay,
Maryland bulk terminal. The decrease from Pier IX was primarily due to higher
operating expenses in 2005 compared to 2004, due to incremental expenses
associated with a new synfuel maintenance program and to higher demurrage
expenses associated with increased cement imports. The decrease from our
Chesapeake terminal was mainly due to higher operating expenses associated with
higher movements of petroleum coke.
The $22.3 million (9%) increase in earnings before depreciation, depletion
and amortization in 2004 over 2003 (excluding the 2004 environmental adjustment)
was driven by higher revenues from both our bulk and liquids terminal
businesses, mainly due to the following:
* higher transfer volumes of bulk products;
* higher demand for storage and distribution services offered for petroleum
and liquid chemical products; and
* additional storage and throughput capacity due to both terminal
acquisitions and the completion of capital projects since the end of
2003.
For all bulk terminal facilities owned during both years, total transloaded
bulk tonnage volumes increased almost 11% in 2004, as compared to 2003. We also
completed, in 2004, capital expansion and betterment projects at certain of our
liquids terminal facilities that included the construction of additional
petroleum products storage tanks. The construction increased our liquids storage
capacity by approximately 600,000 barrels (2%), and at the same time, we
maintained a liquids utilization capacity rate of 96%.
Approximately half of the $22.3 million increase in earnings before
depreciation, depletion and amortization in 2004 over 2003 was attributable to
contributions from the bulk and liquids terminal businesses we acquired since
the end of the third quarter of 2003. In addition to the 2004 acquisitions
referred to above, these acquisitions included, among others, our Kinder Morgan
Tampaplex marine terminal and inland bulk storage warehouse facility, both
located in Tampa, Florida and acquired in December 2003. Combined, terminal
operations acquired since the end of the third quarter of 2003 accounted for
incremental amounts of earnings before depreciation, depletion and amortization
of $10.0 million, revenues of $27.0 million and operating expenses of $15.7
million, respectively, in 2004.
For terminal operations owned during both 2004 and 2003, earnings before
depreciation, depletion and amortization charges increased $12.3 million (5%)
and revenues increased $41.3 million (9%) in 2004, when compared to the prior
year. Both increases were primarily attributable to record throughput at our
Gulf Coast liquids terminals, and to higher coal, bulk and synfuel volumes from
certain of our Mid-Atlantic terminals, which include our Chesapeake Bay bulk
terminal and our Pier IX bulk terminal. Our two Gulf Coast liquids terminals
located on the Houston, Texas Ship Channel, reported a combined $3.8 million
increase in earnings before depreciation, depletion and amortization in 2004
compared to 2003. The increase was driven by a $7.1 million increase in revenues
resulting from higher throughput volumes, contract price escalations, additional
service contracts and new pipeline connections.
Our Chesapeake Bay facility reported a $2.7 million increase in earnings
before depreciation, depletion and amortization in 2004 compared to 2003. The
increase was driven by a $7.5 million increase in revenues, earned by providing
additional stevedoring services and storage and transportation for products such
as coal, petroleum coke, pig iron and steel slag. Our Pier IX terminal, which
transloads both coal and cement and operates a synfuel plant on
69
site, reported a $4.0 million increase in earnings before depreciation,
depletion and amortization in 2004 compared to 2003. The increase was driven by
a $6.3 million increase in revenues resulting from higher synfuel revenues and
coal activity. In February 2004, Pier IX began to operate a second synfuel plant
on site.
Segment revenues for all terminals owned during both 2005 and 2004 increased
$44.1 million (8%) in 2005, when compared to the prior year. The increase was
primarily due to the following:
* a $16.7 million (19%) increase from our Pasadena and Galena Park Gulf
Coast liquids terminals, due primarily to higher petroleum transmix
sales and to additional customer contracts and tankage capacity;
* a $12.7 million (15%) increase from our Midwest region, due primarily
to higher cement handling revenues at our Dakota terminal, increased
tonnage at our Milwaukee terminal, and higher marine fuel sales at our
Dravosburg, Pennsylvania terminal;
* a $5.8 million (10%) increase from our Mid-Atlantic region, due
primarily to higher coal volumes and higher dockage revenues at our
Shipyard River terminal, located in Charleston, South Carolina, higher
cement, iron ore, and dockage revenues at our Pier IX bulk terminal,
and incremental revenues from our North Charleston liquids/bulk
terminal, located just north of our Shipyard facility and acquired
effective April 30, 2004; and
* a $4.2 million (40%) increase from our engineering and terminal design
services, due to increased fee revenues discussed above.
Segment revenues for all terminals owned during both 2004 and 2003 increased
$41.3 million (9%) in 2004 compared to 2003. The increase was primarily due to
the following:
* a $15.0 million (23%) increase from our Mid-Atlantic region, due
primarily to higher petroleum coke, coal, and iron volumes at our
Chesapeake Bay facility, located in Sparrows Point, Maryland, and to
higher synfuel and coal tonnage at our Pier IX bulk terminal;
* an $8.3 million (9%) increase from our Lower Mississippi (Louisiana)
region, due primarily to higher tonnage and dockage revenue at our IMT
facility, partly offset by lower revenues at our Harvey, Louisiana
liquids facility due to higher customer tankage release in 2004;
* an $8.0 million (11%) increase from our Northeast region, due primarily
to higher throughput and additional tankage at our Carteret, New Jersey
liquids facility, and to higher volumes of salt, Belgian block and
scrap iron handled at our Port Newark terminal; and
* a $7.1 million (9%) increase from our Pasadena and Galena Park Gulf
Coast liquids facilities, largely attributable to internal growth,
resulting from both additional customer contracts and completed
expansion projects undertaken to increase leaseable liquids capacity.
Excluding the effects attributable to the 2005 and 2004 environmental
liability adjustments, our Terminal segment's combined operating expenses
increased $97.1 million (36%) in 2005 compared to 2004, and $43.7 million (19%)
in 2004 compared to 2003. In addition to the incremental expenses related to our
terminal acquisitions described above, the overall increases in segment expenses
included year-over-year increases of $33.0 million (13%) in 2005 from terminals
owned during both 2005 and 2004, and $28.0 million (12%) in 2004 from terminals
owned during both 2004 and 2003.
The increase in expenses from terminals owned in both 2005 and 2004 was
mainly due to higher expenses from our Mid-Atlantic, Midwest, Louisiana and Gulf
Coast terminals. The Mid-Atlantic increase was largely due to higher operating,
maintenance and labor expenses at our Pier IX and Chesapeake Bay facilities,
discussed above, and to higher general and equipment maintenance and labor
expenses at our Shipyard River terminal, due to higher bulk tonnage volumes. The
increase in operating expenses from our Midwest terminals included higher
expenses at our Milwaukee terminal, due to increased trucking and maintenance
expenses associated with the increase in coal volumes; higher cost of sales
expense at our Dravosburg terminal, due to marine oil purchasing costs and
inventory
70
maintenance; and higher expenses at our Dakota terminal, due to higher repair
and labor expenses associated with higher cement volumes, and lower capitalized
overhead in 2005, due to the completion of its cement unloading and storage
facility in late 2004. The increase in expenses from the terminals in our
Louisiana region was largely due to property damage related to the two Gulf
Coast hurricanes in the third quarter of 2005. Since the affected properties
were insured, our expenses were limited to the amount of the deductible under
our insurance policies. The year-to-year increase in expenses from our Gulf
Coast terminals was chiefly due to higher labor, fuel and power expenses.
The increase in expenses from terminals owned in both 2004 and 2003 was
largely due to higher bulk tonnage transfer volumes and increased liquids
throughput and storage capacity in 2004. The increases were primarily reflected
as higher operating, maintenance, fuel and electricity expenses, including
payroll, trucking, equipment rental and docking expenses, all related to
increased dry-bulk and liquids product transfers and ship conveyance activities.
Income tax expenses totaled $11.1 million in 2005, $5.5 million in 2004
(excluding the $0.1 million tax expense on earnings attributable to adjustments
to the environmental liabilities recorded by taxable entities) and $3.9 million
in 2003. The $5.6 million (102%) increase in 2005 compared to 2004 was mainly
attributable to higher taxable income and to certain permanent differences
between taxable income and financial income, both related to Kinder Morgan Bulk
Terminals, Inc. and its consolidated subsidiaries. Kinder Morgan Bulk Terminals,
Inc. is the tax-paying entity that owns many of our bulk terminal businesses
which handle non-qualifying products. The $1.6 million (41%) increase in income
tax expense in 2004 compared to 2003 was primarily due to incremental expense
related to the taxable income of Kinder Morgan River Terminals LLC and its
consolidated subsidiaries.
Non-cash depreciation, depletion and amortization charges increased $16.2
million (38%) in 2005 compared to 2004 and $5.8 million (16%) in 2004 compared
to 2003. The increase in 2005 versus 2004 was mainly due to incremental
depreciation charges related to the terminal acquisitions we have made since the
end of the third quarter of 2004. Collectively, these acquisitions accounted for
incremental depreciation expenses of $13.7 million in 2005; the remaining
increase was associated with capital spending. The increase in 2004 versus 2003
was primarily due to property acquisitions and capital spending, and to
adjustments made to the estimated remaining useful lives of depreciable property
since the end of 2003.
For 2006, we currently expect that our Terminals segment will report
earnings before depreciation, depletion and amortization expense of
approximately $377.3 million, a 19% increase over the $318.1 million in earnings
reported in 2005, excluding the effect from environmental liability adjustments.
The earnings increase is expected to be driven by on-going capital expansion
projects, expected increases in bulk tonnage and liquids transfer volumes, and
by incremental earnings from the inclusion of a full year of operations from the
terminal operations we acquired during 2005.
Other
Year Ended December 31,
-------------------------------------
2005 2004 2003
---------- ---------- ----------
(In thousands - income/(expense))
General and administrative expenses.......................... $ (216,706) $ (170,507) $ (150,435)
Unallocable interest, net.................................... (264,203) (194,973) (181,357)
Minority interest............................................ (7,262) (9,679) (9,054)
Loss from early extinguishment of debt....................... - (1,562) -
Cumulative effect adjustment from change in accounting
principle.................................................... - - 3,465
---------- ---------- ----------
Interest and corporate administrative expenses............. $ (488,171) $ (376,721) $ (337,381)
========== ========== ==========
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
We also included both the $1.6 million loss from our early extinguishment of
debt in 2004 and the $3.4 million benefit from the cumulative effect adjustment
of a change in accounting for asset retirement obligations as of January 1, 2003
as items not attributable to any business segment.
The loss from the early extinguishment of debt represented the excess of the
price we paid to repurchase and retire the principal amount of $87.9 million of
tax-exempt industrial revenue bonds over the bonds' carrying value. Pursuant to
certain provisions that gave us the right to call and retire the bonds prior to
maturity, we took advantage
71
of the opportunity to refinance at lower rates, and we included the $1.6 million
loss under the caption "Other, net" in our accompanying consolidated statement
of income. For more information on this early extinguishment of debt, see Note 9
to our consolidated financial statements, included elsewhere in this report.
The cumulative benefit from our change in accounting for asset retirement
obligations was accounted for as a change in accounting principal 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.
Our general and administrative expenses include such items as salaries and
employee-related expenses, payroll taxes, legal fees, unallocated litigation and
environmental accruals, insurance and office supplies and rentals. Overall
general and administrative expenses totaled $216.7 million in 2005, compared to
$170.5 million in 2004 and $150.4 million in 2003. We continue to aggressively
manage our infrastructure expense and to focus on our productivity and expense
controls.
The $46.2 million (27%) increase in general and administrative expenses in
2005 compared to 2004 included incremental litigation and environmental
settlement expenses of $33.4 million. The additional expenses were associated
with higher negotiated settlement costs in 2005 versus 2004, including a $25
million expense for a settlement reached in the first quarter between us and a
shipper on our Kinder Morgan Tejas natural gas pipeline system, and an $8.4
million expense related to settlements of environmental matters at certain of
our operating sites located in the State of California. For more information on
our litigation matters, see Note 16 to our consolidated financial statements,
included elsewhere in this report.
The remaining increase in general and administrative expenses reflected
higher expenses incurred from KMI's operation of our natural gas pipeline
assets, associated with higher actual costs in 2005 versus lower negotiated
costs in 2004; higher insurance expenses, largely due to higher workers
compensation claims; and higher legal, benefits, and corporate secretary
services. The $20.1 million (13%) increase in general and administrative
expenses in 2004 compared to 2003 was principally due to higher employee bonus
and benefit expenses, higher corporate and employee-related insurance expenses,
and higher corporate service expenses, including legal, internal audit and human
resources.
Interest expense, net of unallocable interest income, totaled $264.2 million
in 2005, $195.0 million in 2004 and $181.4 million in 2003. The $69.2 million
(35%) increase in net interest charges in 2005 versus 2004 was due to both
higher average debt borrowings and higher effective interest rates. Our average
debt balance (excluding the market value of interest rate swaps) increased 10%
in 2005 compared to 2004, largely due to incremental borrowings made in
connection with both internal capital spending and external acquisitions.
Additionally, we issued a net $300 million in principal amount of senior notes
on March 15, 2005, when we both closed a public offering of $500 million in
principal amount of senior notes and retired a principal amount of $200 million.
The weighted average interest rate on all of our borrowings increased 13% in
2005 compared to 2004, reflecting a general rise in interest rates since the end
of 2004.
Although our average borrowing rates were essentially flat across both 2003
and 2004, we incurred a $13.6 million (7%) increase in net interest charges in
2004 as a result of higher average debt levels. Our average borrowings increased
13% in 2004 compared to 2003, primarily due to both higher capital spending,
related to internal expansions and improvements, and to incremental borrowings
made in connection with acquisition expenditures. For more information on our
capital expansion and acquisition expenditures, see "Liquidity and Capital
Resources - Investing Activities".
We use interest rate swap agreements to help manage our interest rate risk.
The swaps are contractual agreements we enter into in order to transform a
portion of the underlying cash flows related to our long-term fixed rate debt
securities into variable rate debt in order to achieve our desired mix of fixed
and variable rate debt. However, in a period of rising interest rates, these
swaps will result in period-to-period increases in our interest expense. For
more information on our interest rate swaps, see Note 14 to our consolidated
financial statements, included elsewhere in this report.
72
Minority interest, representing the deduction in our consolidated net income
attributable to all outstanding ownership interests in our five operating
limited partnerships and their consolidated subsidiaries that are not held by
us, totaled $7.3 million in 2005, compared to $9.7 million in 2004 and $9.1
million in 2003. The $2.4 million (25%) decrease in 2005 compared to 2004 was
chiefly due to lower net income allocated to the 33 1/3% minority interest in
the IMT Partnership in 2005, due to business interruption caused by Hurricane
Katrina. The $0.6 million (7%) increase in 2004 versus 2003 resulted mainly from
higher overall partnership income, partly offset by our November 2003
acquisition of the remaining approximate 32% ownership interest in MidTex Gas
Storage Company, LLP that we did not already own, thereby eliminating the
associated minority interest.
Liquidity and Capital Resources
We attempt to maintain a conservative overall capital structure, with a
long-term target mix of approximately 60% equity and 40% debt. The following
table illustrates the sources of our invested capital (dollars in thousands). In
addition to our results of operations, these balances are affected by our
financing activities as discussed below:
December 31,
-----------------------------------------
2005 2004 2003
------------ ------------ ------------
Long-term debt, excluding market value of interest rate swaps.... $ 5,220,887 $ 4,722,410 $ 4,316,678
Minority interest................................................ 42,331 45,646 40,064
Partners' capital, excluding accumulated other comprehensive loss 4,693,414 4,353,863 3,666,737
------------ ------------ ------------
Total capitalization........................................... 9,956,632 9,121,919 8,023,479
Short-term debt, less cash and cash equivalents.................. (12,108) - (21,081)
------------- ------------ ------------
Total invested capital......................................... $ 9,944,524 $ 9,121,919 $ 8,002,398
============ ============ ============
Capitalization:
Long-term debt, excluding market value of interest rate swaps.. 52.4% 51.8% 53.8%
Minority interest.............................................. 0.4% 0.5% 0.5%
Partners' capital, excluding accumulated other comprehensive
loss........................................................... 47.2% 47.7% 45.7%
------------ ------------ ------------
100.0% 100.0% 100.0%
============ ============ ============
Invested Capital:
Total debt, less cash and cash equivalents and excluding
market value of interest rate swaps.......................... 52.4% 51.8% 53.7%
Partners' capital and minority interest, excluding
accumulated other comprehensive loss ........................ 47.6% 48.2% 46.3%
------------ ------------ ------------
100.0% 100.0% 100.0%
============ ============ ============
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 facility, issuing short-term commercial paper, long-term notes or
additional common units or the proceeds from purchases of additional i-units by
KMR with the proceeds from issuances of KMR shares.
In general, we expect to fund:
* cash distributions and sustaining capital expenditures with existing cash
and cash flows from operating activities;
* expansion capital expenditures and working capital deficits with retained
cash (resulting from including i-units in the determination of cash
distributions per unit but paying quarterly distributions on i-units in
additional i-units rather than cash), additional borrowings, the issuance
of additional common units or the proceeds from purchases of additional
i-units by KMR;
* interest payments with cash flows from operating activities; and
* 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.
73
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 that some 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.
Short-term Liquidity
We employ a centralized cash management program that essentially
concentrates the cash assets of our operating partnerships and their
subsidiaries in joint accounts for the purpose of providing financial
flexibility and lowering the cost of borrowing. Our centralized cash management
program provides that funds in excess of the daily needs of our operating
partnerships and their subsidiaries are concentrated, consolidated, or otherwise
made available for use by other entities within our consolidated group. We place
no restrictions on the ability to move cash between entities, payment of
inter-company balances or the ability to upstream dividends to parent companies
other than restrictions that may be contained in agreements governing the
indebtedness of those entities.
Furthermore, certain of our operating subsidiaries are subject to Federal
Energy Regulatory Commission enacted reporting requirements for oil and natural
gas pipeline companies that participate in cash management programs.
FERC-regulated entities subject to these rules must, among other things, place
their cash management agreements in writing, maintain current copies of the
documents authorizing and supporting their cash management agreements, and file
documentation establishing the cash management program with the FERC.
Our principal sources of short-term liquidity are our revolving bank credit
facility, our $1.6 billion short-term commercial paper program (which is
supported by our revolving bank credit facility, with the amount available for
borrowing under our credit facility being reduced by our outstanding commercial
paper borrowings) and cash provided by operations. In August 2005, we replaced
our previous five-year credit facility that had a borrowing capacity of $1.25
billion with a five-year senior unsecured revolving credit facility that has a
borrowing capacity of $1.6 billion, and we increased our commercial paper
program by $350 million to provide for the issuance of up to $1.6 billion. Our
five-year bank facility is due August 18, 2010, and can be used for general
corporate purposes and as a backup for our commercial paper program. There were
no borrowings under our credit facility as of December 31, 2005. After inclusion
of our outstanding commercial paper borrowings and letters of credit, the
remaining available borrowing capacity under our bank facility was $434.5
million as of December 31, 2005.
In addition, on February 22, 2006, we entered into a second credit facility:
a $250 million unsecured nine month credit facility that matures November 21,
2006. This new credit facility includes covenants and requires payment of
facility fees that are similar in nature to the covenants and facility fees
required by our five-year credit facility.
For the year ended December 31, 2005, we continued to generate strong cash
flow from operations, and we provided for additional liquidity by maintaining a
sizable amount of excess borrowing capacity related to our commercial paper
program and long-term revolving credit facility. As of December 31, 2005, our
outstanding short-term debt was $575.6 million. We intended and had the ability
to refinance all of our short-term debt on a long-term basis under our unsecured
long-term credit facility. Accordingly, such amounts have been classified as
long-term debt in our accompanying consolidated balance sheet. Currently, we
believe our liquidity to be adequate. For more information on our credit
facility, see Note 9 to our consolidated financial statements included elsewhere
in this report.
On August 2, 2005, following KMI's announcement of its proposed acquisition
of Terasen Inc., Standard & Poor's Rating Services placed our debt credit
ratings, as well as KMI's ratings, on CreditWatch with negative implications. On
December 5, 2005, S&P affirmed our debt credit ratings, as well as KMI's
ratings, with a negative outlook and removed them from CreditWatch. As of
February 28, 2006, there was no change in our S&P credit rating. On February 23,
2006, Moody's Investors Service, which also publishes credit ratings on
commercial entities, affirmed our debt credit ratings and changed its rating
outlook from negative to stable. As of February 28, 2006, there was no change in
our Moody's credit rating.
Some of our customers are experiencing, or may experience in the future,
severe financial problems that have had or may have a significant impact on
their creditworthiness. We are working to implement, to the extent
74
allowable under applicable contracts, tariffs and regulations, prepayments and
other security requirements, such as letters of credit, to enhance our credit
position relating to amounts owed from these customers. We cannot 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.
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 facility or those issued by our subsidiaries and operating partnerships,
generally have the same terms except for interest rates, maturity dates and
prepayment premiums. All of our outstanding debt securities are unsecured
obligations that rank equally with all of our other senior debt obligations;
however, a modest amount of secured debt has been incurred by some of our
operating partnerships and subsidiaries. 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 March 15, 2005, we paid $200 million to retire the principal amount of
our 8.0% senior notes that matured on that date. Also on March 15, 2005, we
closed a public offering of $500 million in principal amount of 5.80% senior
notes due March 15, 2035 at a price to the public of 99.746% per note. In the
offering, we received proceeds, net of underwriting discounts and commissions,
of approximately $494.4 million. We used the proceeds remaining after repayment
of the 8.0% senior notes to reduce our commercial paper debt.
As of December 31, 2005, our total liability balance due on the various
series of our senior notes was $4,489.5 million. For more information on our
senior notes, see Note 9 to our consolidated financial statements included
elsewhere in this report. As of December 31, 2005, the total liability balance
due on the borrowings of our operating partnerships and subsidiaries was $165.2
million.
Equity Financing
On August 16, 2005, we issued, in a public offering, 5,000,000 of our common
units at a price of $51.25 per unit, less commissions and underwriting expenses.
At the time of the offering, we granted the underwriters a 30-day option to
purchase up to an additional 750,000 common units from us on the same terms and
conditions, and we issued an additional 750,000 common units on September 9,
2005 upon the underwriters' exercise of this option. After commissions and
underwriting expenses, we received net proceeds of $283.6 million for the
issuance of these 5,750,000 common units.
On November 8, 2005, we issued, in a public offering, 2,600,000 of our
common units at a price of $51.75 per unit, less commissions and underwriting
expenses. After commissions and underwriting expenses, we received net proceeds
of $130.1 million for the issuance of these common units.
We used the proceeds from both offerings to reduce the borrowings under our
commercial paper program.
Capital Requirements for Recent Transactions
During 2005, our cash outlays for the acquisition of assets totaled $307.8
million. With the exception of our acquisitions of the bulk terminal operations
from Trans-Global Solutions, Inc. and the ownership interests in General
Stevedores, L.P. from its previous partners, both of which were partially
acquired by the issuance of additional common units, we utilized our commercial
paper program to fund our 2005 acquisitions. We then reduced our short-term
borrowings with the proceeds from our March 2005 issuance of long-term senior
notes and our August and November 2005 issuances of common units. We intend to
refinance the remainder of our current short-term debt and any additional
short-term debt incurred during 2006 through a combination of long-term debt,
equity and the issuance of additional commercial paper to replace maturing
commercial paper borrowings.
75
In February 2005, a shelf registration statement became effective allowing
us to issue up to a total of $2 billion in debt and/or equity securities. As of
December 31, 2005, we had approximately $1.5 billion of availability remaining
on this shelf registration statement. 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. For more
information on our capital requirements during 2005 in regard to our acquisition
expenditures, see Note 3 to our consolidated financial statements included
elsewhere in this report.
Summary of Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial
statements. As of December 31, 2005, 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
Cortez Pipeline Company........ Partner 50% (1) $88.0 $166.6 $83.3 (2)
Red Cedar Gathering General Southern Ute
Company.................... Partner 49% Indian Tribe $207.6 $39.3 $39.3
Nassau County,
Nassau County, Florida Ocean
Florida Ocean Highway Highway and
and Port Authority (3)..... N/A N/A Port Authority N/A N/A $24.9
- ---------
(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 partners 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 partners 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. The partners' respective parent or other companies
further severally guarantee the obligations of the Cortez Pipeline owners
under this agreement.
(3) Arose from our Vopak terminal acquisition in July 2001. 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. As of December 31, 2005, the
value of this letter of credit outstanding under our credit facility was
$24.9 million. Principal payments on the bonds are made on the first of
December each year and reductions are made to the letter of credit.
(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.
We account for our investments in the Red Cedar Gathering Company and Cortez
Pipeline Company under the equity method of accounting. For the year ended
December 31, 2005, our share of earnings, based on our ownership percentage and
before amortization of excess investment cost was $26.3 million from Cortez
Pipeline Company, and $32.0 million from Red Cedar Gathering Company. Additional
information regarding the nature and business
76
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)
Contractual Obligations:
Commercial paper outstanding............... $ 566,200 $566,200 $ -- $ -- $ --
Other debt borrowings-principal payments... 4,654,687 9,401 269,767 516,635 3,858,884
Interest payments(a)....................... 4,152,111 319,732 570,079 526,072 2,736,228
Lease obligations(b)....................... 150,678 29,626 47,785 28,527 44,740
Post-retirement welfare plans(c)........... 3,359 337 667 683 1,672
Other obligations(d)....................... 97,494 13,646 40,290 21,538 22,020
---------- -------- -------- ---------- ----------
Total...................................... $9,624,529 $938,942 $928,588 $1,093,455 $6,663,544
========== ======== ======== ========== ==========
Other commercial commitments:
Standby letters of credit(e)............... $ 660,380 $659,890 $ -- $ 490 $ --
========== ======== ======== ========== ==========
Capital expenditures(f).................... $ 51,862 $ 51,862 -- -- --
========== ======== ======== ========== ==========
- ----------
(a) Interest payment obligations exclude adjustments for interest rate swap
agreements.
(b) Represents commitments for capital leases, including interest, and
operating leases.
(c) Represents expected contributions to post-retirement welfare plans based on
calculations of independent enrolled actuary as of December 31, 2005.
(d) Consist of payments due under carbon dioxide take-or-pay contracts, carbon
dioxide removal contracts, natural gas liquids joint tariff agreements and,
for the 2-3 Years column only, our purchase and sale agreement with
Trans-Global Solutions, Inc. for the acquisition of our Texas Petcoke
terminal assets.
(e) The $660.4 million in letters of credit outstanding as of December 31 2005
consisted of the following: (i) a combined $534 million in five letters of
credit supporting our hedging of commodity price risks; (ii) our $30.3
million guarantee under letters of credit supporting our International
Marine Terminals Partnership Plaquemines, Louisiana Port, Harbor, and
Terminal Revenue Bonds; (iii) a $25.4 million letter of credit supporting
our Kinder Morgan Liquids Terminals LLC New Jersey Economic Development
Revenue Bonds; (iv) a $24.9 million letter of credit supporting Nassau
County, Florida Ocean Highway and Port Authority tax-exempt bonds; (v) a
$24.1 million letter of credit supporting our Kinder Morgan Operating L.P.
"B" tax-exempt bonds; (vi) a $5.4 million letter of credit supporting our
Arrow Terminals, L.P. Illinois Development Revenue Bonds; and (vii) a
combined $16.3 million in six letters of credit supporting environmental
and other obligations of us and our subsidiaries.
(f) Represents commitments for the purchase of plant, property and equipment as
of December 31, 2005.
In our 2006 sustaining capital expenditure plan, we have budgeted $170.0
million, primarily for the purchase of plant and equipment. Sustaining capital
expenditures are defined as capital expenditures which do not increase the
capacity of an asset. All of our capital expenditures, with the exception of
sustaining capital expenditures, are discretionary.
Operating Activities
Net cash provided by operating activities was $1,289.4 million in 2005,
versus $1,155.1 million in 2004. The year-to-year overall increase of $134.3
million (12%) in cash flow from operations in 2005 compared to 2004 consisted of
the following:
* a $166.1 million increase in cash from overall higher partnership income
in 2005, net of non-cash items such as depreciation, depletion and
amortization charges, undistributed earnings from equity investments, and
non-cash operating expense adjustments that included the $105.0 million
expense attributable to an increase in our
77
reserves related to our rate case liability, and the $23.3 million
expense attributable to an increase in our environmental reserves;
* a $22.4 million decrease in cash inflows relative to net changes in non-
current assets and liabilities;
* a $7.2 million decrease relative to net changes in working capital items;
and
* a $2.2 million decrease related to lower distributions received from
equity investments.
The higher partnership income reflects the increase in cash earnings from
our four reportable business segments in 2005, as discussed above in "-Results
of Operations." The decrease in cash inflows relative to net changes in
non-current assets and liabilities related to, among other things, higher
payments made in 2005 to reduce long-term liabilities and reserves for items
such as natural gas imbalances, pipeline rate case liabilities, and other third
party claims. The decrease in cash inflows from working capital accounts was
primarily due to higher income tax payments in 2005 compared to 2004, as
increases in accounts receivables, inventories, and other current assets were
largely offset by increases in accounts payables and other current liabilities.
The decrease in cash inflows from our equity investees was primarily due to
lower distributions received from Cortez Pipeline, due to lower overall
partnership net income in 2005 versus 2004. The decrease from Cortez more than
offset a $5.2 million increase in distributions received from Red Cedar as a
result of higher year-over-year cash earnings.
Investing Activities
Net cash used in investing activities was $1,181.1 million for the year
ended December 31, 2005, compared to $1,250.5 million for the prior year. The
$69.4 million (6%) overall decrease in funds utilized in investing activities
was mainly attributable to:
* a $172.1 million decrease due to lower expenditures made for strategic
business acquisitions;
* an $8.8 million decrease due to higher net proceeds received from the
sale of investments, property, plant and equipment;
* a $5.8 million decrease related to lower contributions to equity
investments; and
* a $115.8 million increase due to higher capital expenditures.
We continue to make significant investments in strategic acquisitions. For
2005, our acquisition outlays totaled $307.8 million, including cash outflows of
$188.4 million for the acquisition of our Texas petroleum coke bulk terminal
assets, $52.9 million for our North Dayton, Texas natural gas storage facility,
and $23.9 million for the acquisition of our Kinder Morgan Staten Island liquids
terminal. For 2004, our acquisitions totaled $479.9 million, including cash
outflows of $211.2 million for the acquisition of our TransColorado Pipeline
from KMI, $120.6 million for the acquisition of additional refined petroleum
products terminals included in our Southeast terminal operations, and $89.9
million for the acquisition of our Kinder Morgan Wink Pipeline. Both our 2005
and 2004 acquisition expenditures are discussed more fully in Note 3 to our
consolidated financial statements included elsewhere in this report.
The period-to-period decrease in cash used in investing activities as a
result of higher proceeds received from the sale of property, plant and
equipment was largely due to the 2005 sales of certain surplus pumping units
previously used in our CO2 business segment. The decrease in cash used relative
to lower contributions paid to equity investees was mainly due to lower
contributions to Red Cedar, largely due to its higher net income in 2005
compared to 2004. Since the summer of 2004, Red Cedar has increased it expansion
capital spending and has funded a large portion of the expenditures with
retained cash.
The $115.8 million (15%) increase in cash used due to higher capital
expenditures was driven by higher internal capital spending in our Terminals and
Products Pipelines business segments, as we continued to expand and grow our
existing asset infrastructure through capital projects that further increase
storage and throughput across our
78
pipeline and terminal networks. Including expansion and maintenance projects,
our capital expenditures were $863.1 million in 2005, compared to $747.3 million
in 2004.
During 2005, we continued construction work related to our previously
announced $210 million expansion of our Pacific operations' East Line Pipeline,
which is expected to be completed in April 2006. When completed, the expansion
will increase capacity on our El Paso, Texas to Tucson, Arizona pipeline by
approximately 56%, and on our Tucson to Phoenix, Arizona pipeline by
approximately 80%. In August 2005, we announced plans for a second expansion to
our East Line Pipeline. This second expansion consists of replacing
approximately 140 miles of 12-inch diameter pipe between El Paso and Tucson with
16-inch diameter pipe. The project also includes the construction of additional
pump stations on the East Line. The project is expected to cost approximately
$145 million. We began the permitting process for this project in September
2005, we expect construction to begin in January 2007, and we expect to complete
the expansion project in the fourth quarter of 2007.
Expansion projects that contributed to internal growth in our Terminals
segment included adding storage tanks to increase leaseable capacity for refined
petroleum products at our liquids terminals located on the Houston Ship Channel
and in the New York Harbor area, along with expanding dock and handling
capabilities at our Kinder Morgan Tampaplex bulk terminal located in Tampa,
Florida. Furthermore, in January 2006, we announced a $45 million expansion
project at our Perth Amboy, New Jersey liquids terminal located along the Arthur
Kill River in the New York Harbor. The investment will involve the construction
of nine new storage tanks with a capacity of 1.4 million barrels for gasoline,
diesel and jet fuel. The new tanks are expected to be in service during the
first quarter of 2007.
In addition, during 2005 we announced the planned construction of our
Rockies Express and Kinder Morgan Louisiana pipelines. The Rockies Express
Pipeline is a 1,323-mile pipeline that will transport up to 1.8 billion cubic
feet per day of natural gas from the Rocky Mountains to eastern Ohio and will
cost over $4 billion to complete. We will operate the pipeline and initially
hold a 66 2/3% ownership interest. Sempra Energy will hold the remaining 33 1/3%
ownership interest. In addition, in exchange for shipper commitments to the
project, we and Sempra have granted options to June 3, 2006, to acquire equity
in the project, which, if fully exercised, could result in us owning a minimum
interest of 50% and Sempra owning a minimum interest of 25% after the project is
completed. We will build and hold sole ownership interest in the Kinder Morgan
Louisiana Pipeline, a 138-mile pipeline that will cost approximately $500
million. The pipeline will provide takeaway capacity from the Cheniere liquefied
natural gas facility in Louisiana and will deliver natural gas into the
country's pipeline network. We intend to finance these two projects with 50%
equity and 50% debt. We will issue equity for these projects in tranches to
coincide with construction and in-service dates. The permanent debt for the
Rockies Express Pipeline, a joint venture, will likely be non-recourse to us.
Our sustaining capital expenditures were $140.8 million in 2005, compared to
$119.2 million in 2004. Sustaining capital expenditures are defined as capital
expenditures which do not increase the capacity of an asset. All of our capital
expenditures, with the exception of sustaining capital expenditures, are
discretionary.
Financing Activities
Net cash used in financing activities was $96.0 million in 2005; while in
the prior year, our financing activities provided net cash of $72.1 million. The
$168.1 million overall decrease in cash inflows provided by financing activities
was primarily due to:
* a $158.9 million decrease from higher partnership distributions;
* a $158.5 million decrease from overall equity issuances; and
* a $29.3 million decrease from lower cash book overdrafts; and
* a $176.8 million increase from overall debt financing activities.
The $158.9 million (20%) year-to-year decrease from higher partnership
distributions in 2005 versus 2004 was due to an increase in the per unit cash
distributions paid, an increase in the number of units outstanding and an
79
increase in our general partner incentive distributions. We paid distributions
of $3.07 per unit in 2005 compared to $2.81 per unit in 2004. The 9% increase in
distributions paid per unit principally resulted from favorable operating
results in 2005. The increase in our general partner incentive distributions
resulted from both increased cash distributions per unit and an increase in the
number of common units and i-units outstanding.
Cash distributions to all partners, consisting of our common and Class B
unitholders (including KMI), our general partner, and minority interests,
increased to $949.9 million in 2005 compared to $791.0 million in 2004. We also
distributed 3,760,732 and 3,500,512 i-units in quarterly distributions during
2005 and 2004, 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
2005 and 2004. 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.
The $158.5 million decrease in cash inflows from partnership equity
issuances was primarily related to the incremental cash we received from our
2004 issuances of both common and i-units over cash received from our 2005
issuance of common units. In 2005, we received proceeds of $415.6 million from
additional partnership equity issuances, primarily consisting of the following
(amounts are net of all commissions and underwriting expenses):
* $283.6 million received from our issuance of 5,750,000 common units in
an August 2005 public offering; and
* $130.1 million received from our issuance of 2,600,000 common units in a
November 2005 public offering.
In 2004, we received proceeds of $574.1 million from additional partnership
equity issuances, primarily consisting of the following (amounts are net of all
commissions and underwriting expenses):
* $237.8 million received from our issuance of 5,300,000 common units in a
February 2004 public offering;
* $14.9 million received from our issuance of 360,664 i-units in March
2004 to KMR;
* $268.3 million received from our issuance of 6,075,000 common units in a
November 2004 public offering; and
* $52.6 million received from our issuance of 1,300,000 i-units in
November 2004 to KMR.
In both 2005 and 2004, we used the proceeds from each of these issuances to
reduce the borrowings under our commercial paper program.
The $29.3 million year-to-year decrease in cash inflows from lower cash book
overdrafts, which represent outstanding checks in excess of funds on deposit,
resulted from a lower amount of outstanding checks in 2005, due to timing
differences in the payments of year-end accruals and outstanding vendor invoices
in 2005 versus 2004.
The overall year-to-year decrease in cash inflows provided by our financing
activities included a $176.8 million increase in cash inflows from overall debt
financing activities, which include issuances and payments of debt, loans to
related parties and debt issuance costs. The increase in cash inflows from our
debt financing activities was mainly attributable to the following:
* a $158.5 million increase due to higher net commercial paper borrowings
in 2005 versus 2004;
* a $98.4 million increase from net changes in our related party loan to
Plantation Pipe Line Company. In July 2004, we loaned Plantation $97.2
million, which corresponded to our 51.17% ownership interest, in
exchange for a seven year note receivable bearing interest at the rate
of 4.72% per annum. The loan allowed Plantation to pay all of its
outstanding credit facility and commercial paper borrowings. As of
December 31, 2005, the principal amount receivable from this note was
$94.2 million;
80
* an $87.9 million increase related to payments, in 2004, to redeem and
retire the principal amount of five series of tax-exempt bonds related to
certain liquids terminal facilities. Pursuant to certain provisions that
gave us the right to call and retire the bonds prior to maturity, we took
advantage of the opportunity to refinance at lower rates;
* a $28.4 million increase related to payments, in 2004, to retire a
significant portion of the $33.7 million of outstanding debt assumed as
part of our October 2004 acquisition of Kinder Morgan River Terminals,
LLC;
* a $9.5 million increase related to payments, in 2004, to retire all of
the outstanding debt assumed as part of our August 2004 acquisition of
Kinder Morgan Wink Pipeline, L.P.;
* a $200 million decrease from the retirement of senior notes due March 15,
2005. On that date, we paid a maturing amount of $200 million in
principal amount of 8.0% senior notes;
* a $3.0 million decrease related to payments, in 2005, to retire all of
the outstanding debt assumed as part of our July 2005 acquisition of
General Stevedores, L.P.; and
* a $1.8 million decrease related to payments, in 2005, to retire principal
amounts of unsecured 5.23% senior notes assumed as part of our August
2005 acquisition of the North Dayton, Texas natural gas storage facility.
In addition, in each of March 2005 and November 2004, we closed public
offerings of $500 million in principal amount of senior notes. The offerings
resulted in cash inflows, net of discounts and issuing costs, of $494.4 million
and $496.3 million, respectively.
During each of the years 2005 and 2004, we used our commercial paper
borrowings to fund our asset acquisitions, capital expansion projects and other
partnership activities. We subsequently raised funds to refinance a portion of
those borrowings by completing public offerings of senior notes, issuing
additional common units and, in 2004 only, issuing additional i-units. We used
the proceeds from these debt and equity issuances to reduce our borrowings under
our commercial paper program.
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 and net
reductions in reserves, less cash disbursements and net additions to reserves
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 2005,
2004 and 2003, we distributed 91.6%, 87.0% and 100.4%, of the total of cash
receipts less cash disbursements, respectively (calculations assume that KMR
unitholders received cash). The difference between these numbers and 100% of
distributable cash flow reflects net changes in reserves.
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. We do not distribute cash to i-unit owners
but retain the cash for use in our business. However, 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. Each time we
make a distribution, the number of i-units owned by KMR and the percentage of
our total units owned by KMR increase automatically under the provisions of our
partnership agreement.
81
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:
* 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;
* 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;
* 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
* 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 2005 was $473.9 million, while the incentive distribution paid
to our general partner during 2005 was $454.3 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 14, 2006, we paid a quarterly distribution of $0.80 per unit for
the fourth quarter of 2005. This distribution was 8% greater than the $0.74
distribution per unit we paid for the fourth quarter of 2004 and 5% greater than
the $0.76 distribution per unit we paid for the first quarter of 2005. 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 $0.80 cash distribution per common unit. We believe that future operating
results will continue to support similar levels of quarterly cash and i-unit
distributions; however, no assurance can be given that future distributions will
continue at such levels.
Litigation and Environmental Matters
As of December 31, 2005, we have recorded a total reserve for environmental
claims, without discounting and without regard to anticipated insurance
recoveries, in the amount of $51.2 million. In addition, we have recorded a
receivable of $27.6 million for expected cost recoveries that have been deemed
probable. The 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 . 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.
As of December 31, 2005, we have recorded a total reserve for legal fees,
transportation rate cases and other litigation liabilities in the amount of
$136.5 million. The reserve is primarily related to various claims from lawsuits
arising from our Pacific operations' pipeline transportation rates, and the
contingent amount is based on both the circumstances of probability and
reasonability of dollar estimates. We regularly assess the likelihood of adverse
outcomes resulting from these claims in order to determine the adequacy of our
liability provision. 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 adequate environmental and legal reserves such that the resolution
of pending environmental matters and litigation will not have a material
82
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
The Pipeline Safety Improvement Act of 2002 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
December 17, 2002, 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. 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. We have included all incremental
expenditures estimated to occur during 2006 associated with the Pipeline Safety
Improvement Act of 2002 and the integrity management of our products pipelines
in our 2006 budget and capital expenditure plan.
Please refer to Notes 16 and 17, respectively, to our consolidated financial
statements included elsewhere in this report for additional information
regarding litigation and regulatory matters.
Pursuant to our continuing commitment to operational excellence and our
focus on safe, reliable operations, we have implemented, and intend to implement
in the future, enhancements to certain of our operational practices in order to
strengthen our environmental and asset integrity performance. These enhancements
have resulted and may result in higher operating costs and sustaining capital
expenditures; however, we believe these enhancements will provide us the greater
long term benefits of improved environmental and asset integrity performance.
Recent Accounting Pronouncements
Please refer to Note 18 to our consolidated financial statements included
elsewhere in this report for information concerning recent 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," 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:
* 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 North America;
* economic activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and demand;
* changes in our tariff rates implemented by the Federal Energy Regulatory
Commission or the California Public Utilities Commission;
* 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;
83
* difficulties or delays experienced by railroads, barges, trucks, ships
or pipelines in delivering products to or from our terminals or
pipelines;
* our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
* 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;
* crude oil production from exploration and production areas that we
serve, including, among others, the Permian Basin area of West Texas;
* 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;
* changes in accounting pronouncements that impact the measurement of our
results of operations, the timing of when such measurements are to be
made and recorded, and the disclosures surrounding these activities;
* 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;
* 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;
* interruptions of electric power supply to our facilities due to natural
disasters, power shortages, strikes, riots, terrorism, war or other
causes;
* our ability to obtain insurance coverage without significant levels of
self-retention of risk;
* acts of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage limits;
* capital markets conditions;
* the political and economic stability of the oil producing nations of the
world;
* national, international, regional and local economic, competitive and
regulatory conditions and developments;
* the ability to achieve cost savings and revenue growth;
* inflation;
* interest rates;
* the pace of deregulation of retail natural gas and electricity;
* foreign exchange fluctuations;
* the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products;
* the extent of our success in discovering, developing and producing oil
and gas reserves, including the risks inherent in exploration and
development drilling, well completion and other development activities;
84
* engineering and mechanical or technological difficulties with
operational equipment, in well completions and workovers, and in
drilling new wells;
* the uncertainty inherent in estimating future oil and natural gas
production or reserves;
* the timing and success of business development efforts; and
* unfavorable results of litigation and the fruition of contingencies
referred to in Note 16 to our consolidated financial statements included
elsewhere in this report.
There is no assurance that any of the actions, events or results of the
forward-looking statements will occur, or if any of them do, what impact they
will have on our results of operations or financial condition. Because of these
uncertainties, you should not put undue reliance on any forward-looking
statements.
See Item 1A "Risk Factors" for a more detailed description of these and
other factors that may affect the forward-looking statements. When considering
forward-looking statements, one should keep in mind the risk factors described
in "Risk Factors" above. The risk factors could cause 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 have been
determined to be "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 are exposed to commodity market risk and other external risks, such as
weather-related risk, in the ordinary course of business. However, we take steps
to hedge, or limit our exposure to, these risks in order to maintain a more
stable and predictable earnings stream. Stated another way, we execute a hedging
strategy that seeks to protect our financial position against adverse price
movements and serves to minimize potential losses. Our strategy involves the use
of certain energy financial instruments to reduce and minimize our risks
associated with unpredictable changes in the market price of natural gas,
natural gas liquids, crude oil and carbon dioxide. The instruments we use
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.
Fundamentally, our hedging strategy involves taking a simultaneous position
in the futures market that is equal and opposite to our position in the cash
market (or physical product) in order to minimize the risk of financial loss
from an adverse price change. For example, as sellers of crude oil and natural
gas, we often enter into fixed price swaps and/or futures contracts to guarantee
or lock-in the sale price of our oil or the margin from the sale and purchase of
our natural gas at the time of market delivery, thereby directly offsetting any
change in prices, either positive or negative. A hedge is successful when gains
or losses in the cash market are neutralized by losses or gains in the futures
transaction.
Our risk management policies prohibit us from engaging in speculative
trading and we are not a party to leveraged derivatives. Furthermore, our
policies require that we only enter into derivative contracts with carefully
selected major financial institutions or similar counterparties based upon their
credit ratings and other factors, and we maintain strict dollar and term limits
that correspond to our counterparties' credit ratings. While we enter into
derivative transactions only with investment grade counterparties and actively
monitor their credit ratings, it is
85
nevertheless possible that 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
-------------
Morgan Stanley................................. A+
J. Aron & Company / Goldman Sachs.............. A+
BNP Paribas.................................... AA
We account for our risk management derivative instruments under Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities" (after amendment by SFAS No. 137, SFAS No. 138, and
SFAS No. 149). According to the provisions of SFAS No. 133, derivatives are
measured at fair value and recognized on the balance sheet as either assets or
liabilities, and in general, gains and losses on derivatives are reported on the
income statement. However, as discussed above, our principal use of energy
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 categorizes such use of
energy financial derivatives as cash flow hedges and prescribes special hedge
accounting treatment for such derivatives. Using derivatives to help provide us
certainty with regard to our operating cash flows helps us undertake further
capital improvement projects, attain budget results and meet distribution
targets to our partners.
In accounting for cash flow hedges, defined as hedges made with the
intention of decreasing the variability in cash flows related to future
transactions, gains and losses on the hedging instruments are reported in other
comprehensive income, not net income, but only to the extent that the gains and
losses from the change in value of the hedging instruments can later offset the
loss or gain from the change in value of the hedged future cash flows during the
period in which the hedged cash flows affect net income. That is, for cash flow
hedges, all effective components of the derivatives' gains and losses goes to
other comprehensive income, pending occurrence of the expected transaction. All
remaining gains and losses on the hedging instruments (the ineffective portion)
are included in current net income. The ineffective portion of the gain or loss
on the hedging instruments is the difference between the gain or loss from the
change in value of the hedging instrument and the effective portion of that gain
or loss.
Under current accounting rules, the accumulated components of other
comprehensive income, including the effective portion of the gain or loss on
derivative instruments designated and qualified as cash flow hedges, are to be
reported separately as accumulated other comprehensive income or loss in the
stockholders' equity section of the balance sheet. Accordingly, our application
of SFAS No. 133 has resulted in deferred net loss amounts of $1,079.7 million
and $457.3 million being reported as "Accumulated other comprehensive loss" in
the Partners' Capital section of our accompanying balance sheets as of December
31, 2005 and December 31, 2004, respectively. In future periods, as the hedged
cash flows from our actual purchases and sales of energy commodities affect our
net income, the related gains and losses included in our accumulated other
comprehensive loss as a result of our hedging are transferred to the income
statement as well, effectively offsetting the changes in cash flows stemming
from the hedged risk.
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, 2005 and 2004, value-at-risk
reached a high of $21.5 million and $8.6 million, respectively, and a low of
$7.6 million and $2.4 million, respectively. Value-at-risk as of December 31,
2005, was $9.1 million and averaged $12.7 million for 2005. Value-at-risk as of
December 31, 2004, was $8.6 million and averaged $5.1 million for 2004.
86
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, with the exception of a minor amount of
hedging inefficiency, is offset by changes in the value of the underlying
physical transactions. For more information on our risk management activities,
see Note 14 to our consolidated financial statements included elsewhere in this
report.
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 our 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, 2005 and 2004, the carrying values of our long-term fixed
rate debt were approximately $4,560.7 million and $4,209.6 million,
respectively, compared to, as of December 31, 2005 and 2004, fair values of
$4,805.0 million and $4,626.9 million, respectively. Fair values were determined
using quoted market prices, where applicable, or future cash flow discounted at
market rates for similar types of borrowing arrangements. A hypothetical 10%
change in the average interest rates applicable to such debt for 2005 and 2004,
respectively, would result in changes of approximately $193.8 million and $161.0
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 $655.9 million
as of December 31, 2005 and $495.1 million as of December 31, 2004. Fair value
was determined using future cash flows discounted based on market rates for
similar types of borrowing arrangements.
As of December 31, 2005 and 2004, we were a party to interest rate swap
agreements with notional principal amounts of $2.1 billion and $2.3 billion,
respectively. An interest rate swap agreement is a contractual agreement entered
into between two counterparties under which each agrees to make periodic
interest payments to the other for an agreed period of time based upon a
predetermined amount of principal, which is called the notional principal
amount. Normally at each payment or settlement date, the party who owes more
pays the net amount; so at any given settlement date only one party actually
makes a payment. The principal amount is notional because there is no need to
exchange actual amounts of principal. A hypothetical 10% change in the weighted
average interest rate on all of our borrowings, when applied to our outstanding
balance of variable rate debt as of December 31, 2005 and 2004, respectively,
including adjustments for notional swap amounts, would result in changes of
approximately $13.9 million and $11.7 million, respectively, in our 2005 and
2004 annual pre-tax earnings.
We entered into these swap agreements for the purpose of hedging the
interest rate risk associated with our fixed and variable rate debt obligations.
As of December 31, 2005, all of our interest rate swaps represented
fixed-for-variable rate swaps, where we agreed to pay our counterparties a
variable rate of interest on a notional principal amount of $2.1 billion,
comprised of principal amounts from various series of our long-term fixed rate
senior notes. In exchange, our counterparties agreed to pay us a fixed rate of
interest, thereby allowing us to transform our fixed rate liabilities into
variable rate obligations without the incurrence of additional loan origination
or conversion costs.
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
87
with fixed rate debt (or vice versa) or by entering into interest rate swaps or
other interest rate hedging agreements. In general, we attempt to maintain an
overall target mix of approximately 50% fixed rate debt and 50% variable rate
debt. For more information on our interest rate swaps, see Note 14 to our
consolidated financial statements included elsewhere in this report.
As of December 31, 2005, 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 107.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2005, 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, and is accumulated and
communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Exchange
Act Rule 13a-15(f). Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements. Projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate. Under the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of the
effectiveness of our internal control over financial reporting based on the
framework in Internal Control - Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on our evaluation
under the framework in Internal Control - Integrated Framework, our management
concluded that our internal control over financial reporting was effective as of
December 31, 2005.
Our management's assessment of the effectiveness of our internal control
over financial reporting as of December 31, 2005 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their report which is included elsewhere in this report.
88
Certain businesses we acquired during 2005 were excluded from the scope of
our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2005. The excluded businesses consisted
of the following:
* the working interest in the Claytonville oil field unit;
* the seven bulk terminal operations which comprise our Texas petcoke
terminal region;
* the Kinder Morgan Staten Island terminal, the Hawesville, Kentucky bulk
terminal, and the Blytheville, Arkansas terminal, each acquired in
separate transactions;
* the partnership interests in General Stevedores, L.P.; and
* the Kinder Morgan Blackhawk terminal and the Texas petcoke terminals'
repair shop, each acquired in separate transactions.
These businesses, in the aggregate, constituted .06% of our total operating
revenues for 2005 and 2.5% of our total assets as of December 31, 2005.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting
during the fourth quarter of 2005 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
89
PART III
Item 10. Directors and Executive Officers of the Registrant.
Directors and Executive Officers of our General Partner and its Delegate
Set forth below is certain information concerning the directors and
executive officers of our general partner and KMR, 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 KMR are elected annually by, and may be removed by, our general
partner as the sole holder of KMR's voting shares. Kinder Morgan (Delaware),
Inc. is a wholly owned subsidiary of KMI. All officers of the general partner
and all officers of KMR serve at the discretion of the board of directors of our
general partner.
Name Age Position with our General Partner and KMR
- ------------------------- ---- ---------------------------------------------
Richard D. Kinder........ 61 Director, Chairman and Chief Executive Officer
C. Park Shaper........... 37 Director and President
Steven J. Kean........... 44 Executive Vice President and Chief Operating Officer
Edward O. Gaylord........ 74 Director
Gary L. Hultquist........ 62 Director
Perry M. Waughtal........ 70 Director
Kimberly A. Dang......... 36 Vice President, Investor Relations and Chief Financial Officer
Jeffrey R. Armstrong..... 37 Vice President (President, Terminals)
Thomas A. Bannigan....... 52 Vice President (President, Products Pipelines)
Richard T. Bradley....... 50 Vice President (President, CO2)
David D. Kinder.......... 31 Vice President, Corporate Development and Treasurer
Joseph Listengart........ 37 Vice President, General Counsel and Secretary
Scott E. Parker.......... 45 Vice President (President, Natural Gas Pipelines)
James E. Street.......... 49 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 was elected President of KMR, Kinder
Morgan G.P., Inc. and KMI in July 2004 and served as President until May 2005.
Mr. Kinder is the uncle of David Kinder, Vice President, Corporate Development
and Treasurer of KMR, Kinder Morgan G.P., Inc. and KMI.
C. Park Shaper is Director and President of KMR and Kinder Morgan G.P., Inc.
and President of KMI. Mr. Shaper was elected President of KMR, Kinder Morgan
G.P., Inc. and KMI in May 2005. He served as Executive Vice President of KMR,
Kinder Morgan G.P., Inc. and KMI from July 2004 until May 2005. 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 its Treasurer until January 2004, and
its Chief Financial Officer until May 2005. He was elected Vice President,
Treasurer and Chief Financial Officer of KMI in January 2000, and served as its
Treasurer until January 2004, and its Chief Financial Officer until May 2005.
Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of
Kinder Morgan G.P., Inc. in January 2000, and served as its Treasurer until
January 2004, and its Chief Financial Officer until May 2005. He received a
Masters of 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.
Steven J. Kean is Executive Vice President and Chief Operating Officer of
KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kean was elected Executive Vice
President and Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and KMI
in January 2006. He served as Executive Vice President, Operations of KMR,
Kinder Morgan G.P., Inc. and KMI from May 2005 to January 2006. He served as
President, Texas Intrastate Pipeline Group from June 2002 until May 2005. He
served as Vice President of Strategic Planning for the Kinder Morgan Gas
Pipeline Group from January 2002 until June 2002. Until December 2001, Mr. Kean
was Executive Vice President and Chief of
90
Staff of Enron Corp. Mr. Kean received his Juris Doctor from the University of
Iowa in May 1985 and received a Bachelor of Arts degree from Iowa State
University in May 1982.
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.
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. Since
1994, Mr. Waughtal has been the Chairman of Songy Partners Limited, an Atlanta,
Georgia based real estate investment company. Mr. Waughtal is also a director of
HealthTronics, Inc.
Kimberly A. Dang, formerly Kimberly J. Allen, is Vice President, Investor
Relations and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and KMI.
Mrs. Dang was elected Chief Financial Officer of KMR, Kinder Morgan G.P., Inc.
and KMI in May 2005. She served as Treasurer of KMR, Kinder Morgan G.P., Inc.
and KMI from January 2004 to May 2005. She was elected Vice President, Investor
Relations of KMR, Kinder Morgan G.P., Inc. and KMI in July 2002. From November
2001 to July 2002, she served as Director, Investor Relations. From May 2001
until November 2001, Mrs. Dang was an independent financial consultant. From
September 2000 until May 2001, she served as an associate and later a principal
at Murphree Venture Partners, a venture capital firm. Mrs. Dang has received a
Masters in Business Administration degree from the J.L. Kellogg Graduate School
of Management at Northwestern University and a Bachelor of Business
Administration degree in accounting from Texas A&M University.
Jeffrey R. Armstrong is Vice President (President, Terminals) of KMR and
Kinder Morgan G.P., Inc. Mr. Armstrong became Vice President (President,
Terminals) in July 2003. He served as President, Kinder Morgan Liquids Terminals
LLC from March 1, 2001, when the company was formed via the acquisition of GATX
Terminals, through 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 an MBA from the University of Notre Dame.
Thomas A. Bannigan is Vice President (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 Vice President
(President, Products Pipelines) of KMR upon its formation in February 2001. He
was elected Vice President (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. 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.
Richard T. Bradley is Vice President (President, CO2) of KMR and of Kinder
Morgan G.P., Inc. and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley
was elected Vice President (President, CO2) of KMR upon its formation in
February 2001 and Vice President (President, CO2) of Kinder Morgan G.P., Inc. in
April 2000. Mr. Bradley has been President of Kinder Morgan CO2 Company, L.P.
(formerly known as Shell CO2 Company, Ltd.) since March 1998. 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 and Treasurer of
KMR, Kinder Morgan G.P., Inc. and KMI. Mr. Kinder was elected Treasurer of KMR,
Kinder Morgan G.P., Inc. and KMI in May 2005. He 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
91
2002. Mr. Kinder graduated cum laude with a Bachelors degree in Finance from
Texas Christian University in 1996. Mr. Kinder is the nephew of Richard D.
Kinder.
Joseph Listengart is Vice President, General Counsel and Secretary of KMR,
Kinder Morgan G.P., Inc. and KMI. Mr. Listengart was elected Vice President,
General Counsel and Secretary of KMR upon its formation in February 2001. He was
elected Vice President and General Counsel of Kinder Morgan G.P., Inc. and Vice
President, General Counsel and Secretary of KMI in October 1999. Mr. Listengart
was elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been
an employee of Kinder Morgan G.P., Inc. since 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.
Scott E. Parker is Vice President (President, Natural Gas Pipelines) of KMR,
Kinder Morgan G.P., Inc. and KMI. He was elected Vice President (President,
Natural Gas Pipelines) of KMR, Kinder Morgan G.P., Inc. and KMI in May 2005. Mr.
Parker served as Co-President of KMI's Natural Gas Pipeline Company of America,
or NGPL, from March 2003 to May 2005. Mr. Parker served as Vice President,
Business Development of NGPL from January 2001 to March 2003. He held various
positions at NGPL from January 1984 to January 2001. Mr. Parker holds a
Bachelor's degree in accounting from Governors State University.
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. 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 acts as our board of directors. 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 KMR's board, acting as our board of directors, and references to committees
mean KMR's committees, 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:
* 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, interim chief executive officer or interim executive
officer, such employment relationship ended by the date of
determination);
* If during any twelve month period within the three years prior to the
determination the director received no more than, and has no immediate
family member that received more than, $100,000 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, interim chief
92
executive officer or interim executive officer, and (iii) compensation
received by an immediate family member for service as an employee (other
than an executive officer);
* If the director is at the date of determination a current employee, or
has an immediate family member that is at the date of determination a
current executive officer, of another company that has made payments to,
or received payments from, us and our affiliates for property or services
in an amount which, in each of the three fiscal years prior to the date
of determination, was less than the greater of $1.0 million or 2% of such
other company's annual consolidated gross revenues. Contributions to
tax-exempt organizations are not considered payments for purposes of this
determination;
* 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
* 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 all regular quarterly and certain special board meetings, these
three non-management directors also meet in executive session without members of
management. In January 2006, Mr. Hultquist was elected for a one year term 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. Waughtal 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 tax-exempt organization in which any of our or
KMR's independent directors serves as an executive officer that in any single
fiscal year exceeded the greater of $1 million or 2% of such tax-exempt
organization's consolidated gross revenues.
On March 25, 2005, our chief executive officer certified to the New York
Stock Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of March 25, 2005, he was not aware of any
violation by us of the New York Stock Exchange's Corporate Governance listing
standards. We have also filed as an exhibit to this report the Sarbanes-Oxley
Act Section 302 certifications regarding the quality of our public disclosure.
We make available free of charge within the "Investors" information section
of our Internet website, at www.kindermorgan.com, and in print to any unitholder
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
that would otherwise be disclosed on Form 8-K and any waiver from a provision of
that code granted to our executive officers or directors that would otherwise be
disclosed on Form 8-K on our Internet website within four 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, the chairpersons of any of the board's
committees, the independent directors as a group or the full board by mail to
Kinder Morgan Management, LLC, 500 Dallas Street, Suite 1000, Houston,
93
Texas 77002, Attention: General Counsel, or by e-mail within the "Contact Us"
section of our Internet website, at www.kindermorgan.com. Your communication
should specify the intended recipient.
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 2005.
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(6)
- ------------------------------------ ----------- ----------- ----------- ------------- ------------- ----------------
Richard D. Kinder............... 2005 $ 1 $ -- $ -- -- $ --
Director, Chairman and CEO 2004 1 -- -- -- --
2003 1 -- -- -- --
C. Park Shaper.................. 2005 200,000 1,050,000 -- -- 10,027
Director and President 2004 200,000 975,000 -- -- 8,378
2003 200,000 875,000 5,918,000(3) -- 8,378
Steven J. Kean.................. 2005 200,000 750,000 6,263,600(4) -- 10,069
Executive Vice President and 2004 200,000 500,000 486,320(4) -- 8,420
Chief Operating Officer 2003 200,000 400,000 -- 10,000(5) 14,420
Joseph Listengart............... 2005 200,000 975,000 -- -- 9,224
Vice President, 2004 200,000 875,000 -- -- 8,378
General Counsel and Secretary 2003 200,000 825,000 3,766,000(3) -- 8,378
Scott E. Parker................. 2005 200,000 650,000 3,221,280(4) -- 9,266
Vice President (President, 2004 200,000 440,000 486,320(4) -- 8,420
Natural Gas Pipelines) 2003 199,038 375,000 -- 10,000(5) 48,378
- ----------
(1) Amounts earned in year shown but paid the following year.
(2) As of December 31, 2005, Mr. Shaper held 112,500 shares of restricted KMI
stock having a value of $10,344,375; Mr. Kean held 83,000 shares of
restricted KMI stock having a value of $7,631,850; Mr. Listengart held
72,500 shares of restricted KMI stock having a value of $6,666,375; and Mr.
Parker held 44,625 shares of restricted KMI stock having a value of
$4,103,269. Restricted stock earns dividends at the same rate as the
dividends paid to shareholders; otherwise, restricted stock awards have no
value to the recipient until the restrictions are released.
94
(3) Represent shares of restricted KMI stock awarded in 2003. The 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 at least $3.70 per share in any fiscal year; (ii) we must
distribute at least $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. All of these hurdles have been met. The 2003 awards were long-term
equity compensation for our current senior management through July 2008. The
holders of the restricted stock awards are eligible to vote and to receive
dividends declared on such shares.
(4) Represent shares of restricted KMI stock awarded in 2005 and 2004. The
awards were issued under a shareholder approved plan. For the 2005 awards,
value computed as the number of shares awarded times the closing price on
date of grant ($89.48 at July 20, 2005). 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 at least $4.22 per share in any fiscal year; (ii) we must
distribute at least $3.13 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 $90.00 per share during any consecutive 30-day
period. All of these hurdles have been met. For the 2004 awards, value
computed as the number of shares awarded times the closing price on date of
grant ($60.79 at July 20, 2004). Fifty percent of the shares vest on the
third anniversary after the date of grant and the remaining fifty percent of
the shares vest on the fifth anniversary after the date of grant. The 2005
and 2004 awards were long-term equity compensation for senior managers
through July 2010. The holders of the restricted stock awards are eligible
to vote and to receive dividends declared on such shares.
(5) Messrs. Kean and Parker were each granted 10,000 options to purchase KMI
shares on July 16, 2003 by the compensation committee of the KMI board of
directors under the 1999 Employee Stock Plan as part of the regular stock
option grant under the program. The options have an exercise price of $53.80
per share and vest on the third anniversary after the date of grant. The
compensation committee stopped granting options after 2003.
(6) Amounts represent value of 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 Messrs. Kean and Parker, in 2003, each received
a $6,000 lump sum amount in lieu of a promised salary increase. Mr. Parker
also received $34,000 in 2003 for relocation assistance.
Kinder Morgan Savings Plan. The Kinder Morgan Savings Plan is a defined
contribution 401(k) plan. The plan permits all full-time employees of Kinder
Morgan, Inc. and KMGP Services Company, Inc. 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, 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 generally 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. 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.
For employees hired on or prior to December 31, 2004, all contributions,
together with earnings thereon, are immediately vested and not subject to
forfeiture. Employer contributions for employees hired on or after January 1,
2005 will vest on the second anniversary of the date of hire. Effective October
1, 2005, for new employees of our Terminals segment, a tiered employer
contribution schedule was implemented. This tiered schedule provides for
employer contributions of 1% for service less than one year, 2% for service
between one and two years, 3% for services between two and five years, and 4%
for service of five years or more. All employer contributions for Terminal
employees hired after October 1, 2005 will vest on the fifth anniversary of the
date of hire. Vesting and contributions for bargaining employees will follow the
collective bargaining agreements.
At its July 2005 meeting, the compensation committee of the KMI board of
directors approved a special contribution of an additional 1% of base pay into
the Savings Plan for each eligible employee. Each eligible
95
employee will receive an additional 1% company contribution based on eligible
base pay each pay period beginning with the first pay period of August 2005 and
continuing through the last pay period of July 2006. The additional 1%
contribution is in the form of KMI common stock (the same as the current 4%
contribution) and does not change or otherwise impact, the annual 4%
contribution that eligible employees currently receive. It may be converted to
any other Savings Plan investment fund at any time and the vesting schedule
mirrors the company's 4% contribution. Since this additional 1% company
contribution is discretionary, compensation committee approval will be required
annually for each additional contribution. During the first quarter of 2006,
excluding the 1% additional contribution described above, we will not make any
additional discretionary contributions to individual accounts for 2005.
It is expected that sometime in 2006, an option to make after-tax "Roth"
contributions (Roth 401(k) option) to a separate participant account will be
added to the plan as an additional benefit to all participants. Unlike
traditional 401(k) plans, where participant contributions are made with pre-tax
dollars, earnings grow tax-deferred, and the withdrawals are treated as taxable
income, Roth 401(k) contributions are made with after-tax dollars, earnings are
tax-free, and the withdrawals are tax-free if they occur after both (i) the
fifth year of participation in the Roth 401(k) option, and (ii) attainment of
age 59 1/2, death or disability. Also, even though an employer matching
contribution may be based entirely, or partly, on the Roth 401(k) contribution,
the employer matching contribution will still be considered taxable income at
the time of withdrawal.
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. KMR's
compensation committee administers the option plan, and the plan has a
termination date of March 5, 2008.
No individual employee may be granted options for more than 20,000 common
units in any year. KMR's compensation committee will determine the duration and
vesting of the options to employees at the time of grant. As of December 31,
2005, options to purchase 15,300 common units were outstanding and held by 10
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. As of December 31, 2005, all 15,300 outstanding options were fully
vested.
The option plan also granted to each of our non-employee directors 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. Under this
provision, as of December 31, 2005, options to purchase 10,000 common units are
currently outstanding and held by one of Kinder Morgan G.P., Inc.'s three
non-employee directors. Forty percent of all such options will vest on the first
anniversary of the date of grant and twenty percent on each of the next three
anniversaries. The non-employee director options will expire seven years from
the date of grant. As of December 31, 2005, all 10,000 outstanding options were
fully vested.
For the year ended December 31, 2005, no options to purchase common units
were granted to or exercised by any of the individuals named in the Summary
Compensation Table above. Furthermore, as of December 31, 2005, no person named
in the Summary Compensation Table owned unexercised common unit options.
KMI Stock Plan. Under KMI's stock 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 restricted KMI stock
and grants of options to acquire shares of common stock of KMI. The compensation
committee of KMI's board of directors administers this plan. The primary purpose
for granting restricted KMI stock and KMI 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 the 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 2005, none of the
persons named in the Summary Compensation Table above were granted KMI stock
options.
96
Aggregated KMI Stock Option Exercises in 2005 and 2005 Year-End KMI Stock Option Values
Number of Shares Value of Unexercised
Underlying Unexercised In-the-Money Options
Options at 2005 Year-End At 2005 Year-End(1)
Shares Acquired Value ----------------------------- -------------------------------
Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
- -------------------- --------------- ---------- ------------- -------------- -------------- -------------
C. Park Shaper....... - $ - 195,000 25,000 $ 10,057,875 $ 874,000
Steven J. Kean....... 62,500 1,712,569 12,500 35,000 660,375 1,478,875
Joseph Listengart.... - - 56,300 - 3,671,948 -
Scott E. Parker...... 3,750 206,614 - 10,000 - 381,500
- ----------
(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 also 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 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 on January 1, 2001, 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 discretionary contributions were made for 2005 performance.
Interest is credited to the personal 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.
The following table sets forth the estimated annual benefits payable as of
December 31, 2005, 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, 2006 Plans Retirement (1)
---- ------------- ------------ ------------ ------------ --------------
Richard D. Kinder......... 5 8.8 61.2 $ 1 $ -
C. Park Shaper............ 5 32.7 37.4 200,000 62,110
Steven J. Kean............ 4 24.5 44.5 200,000 33,269
Joseph Listengart......... 5 32.5 37.6 200,000 61,358
Scott E. Parker........... 7 27.1 45.0 200,000 41,381
- ----------
(1) The estimated annual benefits payable are based on the straight-life annuity
form.
2005 Annual Incentive Plan. Effective January 18, 2005, KMI established the
2005 Annual Incentive Plan of Kinder Morgan, Inc. The plan was approved at the
KMI shareholders meeting on May 10, 2005. The plan was established, in part, to
enable the portion of an officer's or other employee's annual bonus based on
objective performance criteria to qualify as "qualified performance-based
compensation" under the Internal Revenue Code. "Qualified performance-based
compensation" is deductible for tax purposes. The plan permits annual bonuses to
be paid to KMI's officers and other employees and employees of KMI's
subsidiaries based on their individual performance, KMI's performance and the
performance of KMI's subsidiaries. The plan is administered by the compensation
committee of KMI's board of directors. Under the plan, at or before the start of
each calendar year, the compensation committee establishes written performance
objectives. The performance objectives are based on one or more criteria set
forth in the plan. The compensation committee may specify a minimum acceptable
level of achievement of each performance objective below which no bonus is
payable with respect to that objective. The maximum payout to any individual
under the plan in any year is $2.0 million, and the compensation committee has
the discretion to reduce the bonus amount in any performance period. The cash
bonuses set forth in the Summary
97
Compensation Table above were paid under the plan. Awards were granted under the
plan for calendar year 2005; awards granted for calendar years prior to 2005
were granted under the 2000 Annual Incentive Plan, which was replaced by the
2005 Plan.
Compensation Committee Interlocks and Insider Participation. As disclosed
above, the compensation committee of KMR functions as our 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. Beginning in 2005, our Common Unit Compensation Plan for
Non-Employee Directors, as discussed below, served as compensation for each of
KMR's three non-employee directors. In addition, directors are reimbursed for
reasonable expenses in connection with board meetings. Directors of KMR who are
also employees of KMI do not receive compensation in their capacity as
directors.
In January 2005, KMR terminated the Directors' Unit Appreciation Rights Plan
and implemented the Kinder Morgan Energy Partners, L.P. Common Unit Compensation
Plan for Non-Employee Directors. Both plans are discussed following:
Directors' Unit Appreciation Rights Plan. On April 1, 2003, KMR's
compensation committee established our Directors' Unit Appreciation Rights Plan.
Pursuant to this plan, each of KMR's three non-employee directors was eligible
to receive common unit appreciation rights. 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. Proceeds, if
any, from the exercise of a unit appreciation right granted under the plan will
be payable only in cash (that is, no exercise will result in the issuance of
additional common units) 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.
On April 1, 2003, the date of adoption of the plan, each of KMR's three
non-employee directors was granted 7,500 unit appreciation rights. In addition,
10,000 unit appreciation rights were granted to each of KMR's three non-employee
directors on January 21, 2004, at the first meeting of the board in 2004. During
the first board meeting of 2005, the plan was terminated and replaced by the
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors; however, all unexercised awards made under the plan
remain outstanding. No unit appreciation rights were exercised during 2005, and
as of December 31, 2005, 52,500 unit appreciation rights had been granted,
vested and remained outstanding.
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors. On January 18, 2005, KMR's compensation committee
established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation
Plan. The plan is administered by KMR's compensation committee and KMR's board
has sole discretion to terminate the plan at any time. The primary purpose of
this plan was to promote our interests and the interests of our unitholders by
aligning the compensation of the non-employee members of the board of directors
of KMR with unitholders' interests. Further, 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.
98
The plan recognizes that the compensation to be paid to each non-employee
director is fixed by the KMR board, generally annually, and that the
compensation is expected to include an annual retainer payable in cash and other
cash compensation. Pursuant to the plan, in lieu of receiving the other cash
compensation, each non-employee director may elect to receive common units. Each
election shall be generally at or around the first board meeting in January of
each calendar year and will be effective for the entire calendar year. The
initial election under this plan for service in 2005 was made effective January
20, 2005. The election for 2006 was made effective January 17, 2006. A
non-employee director may make a new election each calendar year. The total
number of common units authorized under this compensation plan is 100,000.
Each annual election shall be evidenced by an agreement, the Common Unit
Compensation Agreement, between us and each non-employee director, and this
agreement will contain the terms and conditions of each award. Pursuant to this
agreement, all common units issued under this plan are subject to forfeiture
restrictions that expire six months from the date of issuance. Until the
forfeiture restrictions lapse, common units issued under the plan may not be
sold, assigned, transferred, exchanged, or pledged by a non-employee director.
In the event the director's service as a director of KMR is terminated prior to
the lapse of the forfeiture restriction either for cause, or voluntary
resignation, each director shall, for no consideration, forfeit to us all common
units to the extent then subject to the forfeiture restrictions. Common units
with respect to which forfeiture restrictions have lapsed shall cease to be
subject to any forfeiture restrictions, and we will provide each director a
certificate representing the units as to which the forfeiture restrictions have
lapsed. In addition, each non-employee director shall have the right to receive
distributions with respect to the common units awarded to him under the plan, to
vote such common units and to enjoy all other unitholder rights, including
during the period prior to the lapse of the forfeiture restrictions.
The number of common units to be issued to a non-employee director electing
to receive the other cash compensation in the form of common units will equal
the amount of such other cash compensation awarded, divided by the closing price
of the common units on the New York Stock Exchange on the day the cash
compensation is awarded (such price, the fair market value), rounded down to the
nearest 50 common units. The common units will be issuable as specified in the
Common Unit Compensation Agreement. A non-employee director electing to receive
the other cash compensation in the form of common units will receive cash equal
to the difference between (i) the other cash compensation awarded to such
non-employee director and (ii) the number of common units to be issued to such
non-employee director multiplied by the fair market value of a common unit. This
cash payment shall be payable in four equal installments (together with the
annual cash retainer) generally around March 31, June 30, September 30 and
December 31 of the calendar year in which such cash compensation is awarded.
On January 18, 2005, the date of adoption of the plan, each of KMR's three
non-employee directors was awarded a cash retainer of $40,000, which was paid
quarterly during 2005, and other cash compensation of $79,750. The total
compensation of $119,750 was for board service during 2005. Effective January
20, 2005, each non-employee director elected to receive the other cash
compensation of $79,750 in the form of our common units and was issued 1,750
common units pursuant to the plan and its agreements (based on the $45.55
closing market price of our common units on January 18, 2005, as reported on the
New York Stock Exchange). Also, consistent with the plan, the $37.50 of other
cash compensation that did not equate to a whole common unit, based on the
January 18, 2005 closing price, was paid to each of the non-employee directors
as described above. No other compensation was paid to the non-employee directors
during 2005.
On January 17, 2006, each of KMR's three non-employee directors was awarded
a cash retainer of $72,220, which will be paid quarterly during 2006, and other
cash compensation of $87,780. The total compensation of $160,000 is for board
service during 2006. Effective January 17, 2006, each non-employee director
elected to receive the other cash compensation of $87,780 in the form of our
common units and was issued 1,750 common units pursuant to the plan and its
agreements (based on the $50.16 closing market price of our common units on
January 17, 2006, as reported on the New York Stock Exchange). The annual cash
retainer will be paid to each of the non-employee directors as described above.
No other compensation will be paid to the non-employee directors during 2006.
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
The following table sets forth information as of January 31, 2006, 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
99
(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 at least 5% 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.
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)........... 315,979 * -- -- 55,695 * 24,000,000 17.90%
C. Park Shaper(7).............. 4,000 * -- -- 2,708 * 351,932 *
Edward O. Gaylord(8)........... 36,500 * -- -- -- -- 2,000 *
Gary L. Hultquist(9)........... 14,500 * -- -- -- -- -- --
Perry M. Waughtal(10).......... 40,800 * -- -- 40,202 * 60,000 *
Steven J. Kean(11)............. -- -- -- -- -- -- 113,627 *
Joseph Listengart(12).......... 4,198 * -- -- -- -- 140,230 *
Scott E. Parker(13)............ -- -- -- -- -- -- 45,316 *
Directors and Executive Officers
as a group (14 persons)(14). 429,377 * -- -- 103,351 * 25,069,687 18.70%
Kinder Morgan, Inc.(15)........ 14,355,735 9.14% 5,313,400 100.00% 8,951,851 15.46% -- --
Fayez Sarofim(16).............. 7,729,948 5.00% -- -- -- -- -- --
Kayne Anderson Capital Advisors,
L.P.(17).................... -- -- -- -- 6,250,520 10.79% -- --
OppenheimerFunds, Inc.(18)..... -- -- -- -- 5,047,640 8.72% -- --
Tortoise Capital Advisors,
L.L.C.(19)..................... -- -- -- -- 3,728,878 6.44% -- --
- ----------
* Less than 1%.
(1) Except as noted otherwise, all units, KMR shares and KMI shares involve
sole voting power and sole investment power. For KMR, see note (4). On
January 18, 2005, KMR's board of directors initiated a rule requiring each
director to own a minimum of 10,000 common units, KMR shares, or a
combination thereof. If a director does not already own the minimum number
of required securities, the director will have six years to acquire such
securities.
(2) As of January 31, 2006, we had 157,012,776 common units issued and
outstanding.
(3) As of January 31, 2006, we had 5,313,400 Class B units issued and
outstanding.
(4) Represent the limited liability company shares of KMR. As of January 31,
2006, there were 57,918,373 issued and outstanding KMR shares, including
two voting shares owned by our general partner. 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, 2006, KMI had a total of 134,041,480 shares of issued and
outstanding voting common stock, which excludes 14,592,001 shares held in
treasury.
(6) Includes (a) 7,879 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 220,000 KMI shares exercisable within 60 days
of January 31, 2006, and includes 110,000 shares of restricted KMI stock.
(8) Includes 1,750 restricted common units.
(9) Includes options to purchase 10,000 common units exercisable within 60 days
of January 31, 2006, and includes 1,750 restricted common units.
(10) Includes 1,750 restricted common units.
100
(11) Includes options to purchase 25,000 KMI shares exercisable within 60 days
of January 31, 2006, and 78,000 shares of restricted KMI stock.
(12) Includes options to purchase 56,300 KMI shares exercisable within 60 days
of January 31, 2006, and includes 70,000 shares of restricted KMI stock.
(13) Includes 44,000 shares of restricted KMI stock.
(14) Includes options to purchase 10,000 common units and 432,550 KMI shares
exercisable within 60 days of January 31, 2006, and includes 5,250
restricted common units and 489,500 shares of restricted KMI stock.
(15) Includes common units owned by KMI and its consolidated subsidiaries,
including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(16) As reported on the Schedule 13G/A filed February 13, 2006 by Fayez Sarofim
& Co. and Fayez Sarofim. Fayez Sarofim & Co. reported that in regard to
our common units, it had sole voting power over 0 common units, shared
voting power over 4,108,689 common units, sole disposition power over 0
common units and shared disposition power over 5,424,148 common units. Mr.
Sarofim reported that in regard to our common units, he had sole voting
power over 2,300,000 common units, shared voting power over 4,114,489
common units, sole disposition power over 2,300,000 common units and
shared disposition power over 5,429,948 common units. Mr. Sarofim's
address is 2907 Two Houston Center, Houston, Texas 77010.
(17) As reported on the Schedule 13G/A filed February 9, 2006 by Kayne Anderson
Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital
Advisors, L.P. reported that in regard to KMR shares, it had sole voting
power over 0 shares, shared voting power over 6,250,520 shares, sole
disposition power over 0 shares and shared disposition power over
6,250,520 shares. Mr. Kayne reports that in regard to KMR shares, he had
sole voting power over 988 shares, shared voting power over 6,250,520
shares, sole disposition power over 988 shares and shared disposition
power over 6,250,520 shares. Kayne Anderson Capital Advisors, L.P.'s and
Richard A. Kayne's address is 1800 Avenue of the Stars, Second Floor, Los
Angeles, California 90067.
(18) As reported on the Schedule 13G/A filed February 8, 2006 by
OppenheimerFunds, Inc. and Oppenheimer Capital Income Fund.
OppenheimerFunds, Inc. reported that in regard to KMR shares, it had sole
voting power over 0 shares, shared voting power over 5,047,640 shares,
sole disposition power over 0 shares and shared disposition power over
5,047,640 shares. Of those 5,047,640 KMR shares, Oppenheimer Capital
Income Fund had sole voting power over 0 shares, shared voting power over
3,510,000 shares, sole disposition power over 0 shares and shared
disposition power over 3,510,000 shares. OppenheimerFunds, Inc.'s address
is Two World Financial Center, 225 Liberty Street, 11th Floor, New York,
New York 10281, and Oppenheimer Capital Income Fund's address is 6803
South Tucson Way, Centennial, Colorado 80112.
(19) As reported on the Schedule 13G filed February 10, 2006 by Tortoise
Capital Advisors, L.L.C. Tortoise Capital Advisors, L.L.C. reported that
in regard to KMR shares, it had sole voting power over 0 shares, shared
voting power over 3,658,188 shares, sole disposition power over 0 shares
and shared disposition power over 3,728,878 shares. Tortoise Capital
Advisors, L.L.C.'s address is 10801 Mastin Blvd., Suite 222, Overland
Park, Kansas 66210.
101
Equity Compensation Plan Information
The following table sets forth information regarding our equity compensation
plans as of December 31, 2005. Specifically, the table provides information
regarding our Common Unit Option Plan described in Item 11. "Executive
Compensation" as of December 31, 2005.
Number of securities
Number of securities remaining available for
To be issued upon Weighted average future issuance under equity
exercise of exercise price compensation plans
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 25,300 $19.2494 55,400
------ ------
Total 25,300 55,400
====== ======
Item 13. Certain Relationships and Related Transactions.
See Note 12 of the notes to our 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,
2005 and 2004 (in dollars):
Year Ended December 31,
2005 2004
------------- -------------
Audit fees(1)............ $ 2,085,800 $ 2,147,000
Audit-Related fees(2).... 34,000 34,000
Tax fees(3).............. 1,479,344 1,994,956
------------- -------------
Total.................. $ 3,599,144 $ 4,175,956
============= =============
- ----------
(1) Includes fees for integrated audit of annual financial statements and
internal control over financial reporting, reviews of the related quarterly
financial statements, and reviews of documents filed with the Securities
and Exchange Commission.
(2) Includes fees for assurance and related services that are reasonably
related to the performance of the audit or review of our financial
statements.
(3) Includes fees related to professional services for tax compliance, tax
advice and tax planning.
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:
* to select, appoint, engage, oversee, retain, evaluate and terminate
our external auditors;
* 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
* to establish the fees and other compensation to be paid to our
external auditors.
102
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):
* the auditors' internal quality-control procedures;
* any material issues raised by the most recent internal quality-control
review, or peer review, of the external auditors;
* the independence of the external auditors; and
* the aggregate fees billed by our external auditors for each of the
previous two fiscal years.
103
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page 107.
(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).
*3.2 -- Amendment No. 1 dated November 19, 2004 to Third Amended and
Restated Agreement of Limited Partnership of Kinder Morgan Energy
Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan Energy
Partners, L.P. Form 8-K, filed November 22, 2004).
*3.3 -- Amendment No. 2 to Third Amended and Restated Agreement of Limited
Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit
99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed May 5,
2005).
*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 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).
*4.6 -- 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).
*4.7 -- 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).
*4.8 -- 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).
*4.9 -- 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).
*4.10 -- 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).
*4.11 -- 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).
104
*4.12 -- Certificate of Vice President and Chief Financial Officer of Kinder
Morgan Energy Partners, L.P. establishing the terms of the 7.125%
Notes due March 15, 2012 and the 7.750% Notes due March 15, 2032
(filed as Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q
for the quarter ended March 31, 2002, filed on May 10, 2002).
*4.13 -- 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).
*4.14 -- 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).
*4.15 -- 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.
Registration Statement on Form S-4 (File No. 333-100346) filed on
October 4, 2002 (the "October 4, 2002 Form S-4")).
*4.16 -- 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).
*4.17 -- 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).
*4.18 -- Senior Indenture dated January 31, 2003 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")).
*4.19 -- 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).
*4.20 -- Subordinated Indenture dated January 31, 2003 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).
*4.21 -- 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).
*4.22 -- 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 (filed as Exhibit 4.25 to Kinder
Morgan Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*4.23 -- Specimen of 5.00% Notes due December 15, 2013 in book-entry form
(filed as Exhibit 4.26 to Kinder Morgan Energy Partners, L.P. Form
10-K for 2003 filed March 5, 2004).
*4.24 -- Specimen of 5.125% Notes due November 15, 2014 in book-entry form
(filed as Exhibit 4.26 to Kinder Morgan Energy Partners, L.P. Form
10-K for 2004 filed March 4, 2005).
*4.25 -- Certificate of Executive Vice President 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 5.125%
Notes due November 15, 2014 (filed as Exhibit 4.27 to Kinder Morgan
Energy Partners, L.P. Form 10-K for 2004 filed March 4, 2005).
*4.26 -- 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
5.80% Notes due March 15, 2035 (filed as Exhibit 4.1 to Kinder Morgan
Energy Partners, L.P. Form 10-Q for the quarter ended March 31, 2005,
filed on May 6, 2005).
*4.27 -- Specimen of 5.80% Notes due March 15, 2035 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, 2005, filed on May 6, 2005).
4.28 -- 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.
*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).
105
*10.2 -- 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).
*10.3 -- Kinder Morgan Energy Partners, L.P. Directors' Unit Appreciation
Rights Plan (filed as Exhibit 10.6 to the Kinder Morgan Energy
Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*10.4 -- Amendment No. 1 to Kinder Morgan Energy Partners, L.P. Directors' Unit
Appreciation Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan
Energy Partners, L.P. Form 10-K for 2003 filed March 5, 2004).
*10.5 -- Resignation and Non-Compete agreement dated July 21, 2004 between KMGP
Services, Inc. and Michael C. Morgan, President of Kinder Morgan,
Inc., Kinder Morgan G.P., Inc. and Kinder Morgan Management, LLC
(filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form
10-Q for the quarter ended June 30, 2004, filed on August 5, 2004).
*10.6 -- Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors (filed as Exhibit 10.2 to Kinder Morgan Energy
Partners, L.P. Form 8-K filed January 21, 2005).
*10.7 -- Form of Common Unit Compensation Agreement entered into with
Non-Employee Directors (filed as Exhibit 10.1 to Kinder Morgan Energy
Partners, L.P. Form 8-K filed January 21, 2005).
*10.8 -- Five-Year Credit Agreement dated as of August 5, 2005 among Kinder
Morgan Energy Partners, L.P., the lenders party thereto and Wachovia
Bank, National Association as Administrative Agent (filed as Exhibit
10.1 to Kinder Morgan Energy Partners, L.P.'s Current Report on Form
8-K, filed on August 11, 2005).
10.9 -- Nine-Month Credit Agreement dated as of February 22, 2006 among
Kinder Morgan Energy Partners, L.P., the lenders party thereto and
Wachovia Bank, National Association as Administrative Agent.
11.1 -- Statement re: computation of per share earnings.
12.1 -- Statement re: computation of ratio of earnings to fixed charges.
21.1 -- List of Subsidiaries.
23.1 -- Consent of PricewaterhouseCoopers LLP.
23.2 -- Consent of Netherland, Sewell and Associates, Inc.
31.1 -- Certification by CEO pursuant to Rule 13a-14(a) or 15d-14(a) 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(a) or 15d-14(a) 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.
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.
106
INDEX TO FINANCIAL STATEMENTS
Page
Number
------
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm............. 108
Consolidated Statements of Income for the years ended December
31, 2005, 2004, and 2003........................................... 110
Consolidated Statements of Comprehensive Income for the years
ended December 31, 2005, 2004, and 2003............................ 111
Consolidated Balance Sheets as of December 31, 2005 and 2004........ 112
Consolidated Statements of Cash Flows for the years ended
December 31, 2005, 2004, and 2003.................................. 113
Consolidated Statements of Partners' Capital for the years
ended December 31, 2005, 2004, and 2003............................ 114
Notes to Consolidated Financial Statements.......................... 115
107
Report of Independent Registered Public Accounting Firm
To the Partners of
Kinder Morgan Energy Partners, L.P.:
We have completed integrated audits of Kinder Morgan Energy Partners, L.P.'s
2005 and 2004 consolidated financial statements and of its internal control over
financial reporting as of December 31, 2005, and an audit of its December 31,
2003 consolidated financial statements in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Our opinions, based
on our audits, are presented below.
Consolidated financial statements
- ---------------------------------
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 (collectively, the
Partnership) at December 31, 2005 and 2004, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2005 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 the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit of financial statements
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 retirement obligations effective January 1,
2003.
Internal control over financial reporting
- -----------------------------------------
Also, in our opinion, management's assessment, included in Management's Report
on Internal Control Over Financial Reporting appearing under Item 9A, that the
Partnership maintained effective internal control over financial reporting as of
December 31, 2005 based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), is fairly stated, in all material respects, based on those
criteria. Furthermore, in our opinion, the Partnership maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2005, based on criteria established in Internal Control -
Integrated Framework issued by the COSO. The Partnership's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express opinions on management's assessment
and on the effectiveness of the Partnership's internal control over financial
reporting based on our audit. We conducted our audit of internal control over
financial reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. An audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial reporting,
evaluating management's assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (i) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company;
(ii) provide reasonable
108
assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate. As described in Management's
Report on Internal Control Over Financial Reporting, management has excluded:
* the working interest in the Claytonville oil field unit;
* the seven bulk terminal operations which comprise its Texas petcoke
terminal region;
* the Kinder Morgan Staten Island terminal, the Hawesville, Kentucky
bulk terminal, and the Blytheville, Arkansas terminal, each acquired
in separate transactions;
* the partnership interests in General Stevedores, L.P.; and
* the Kinder Morgan Blackhawk terminal and the Texas petcoke terminals'
repair shop,
(the "Acquired Businesses"), each acquired in separate transactions, from its
assessment of internal control over financial reporting as of December 31, 2005
because these businesses were acquired by the Partnership in purchase business
combinations during 2005. We have also excluded these Acquired Businesses from
our audit of internal control over financial reporting. In the aggregate, these
Acquired Businesses' total assets and total operating revenues represent 2.5%
and .06%, respectively, of the related consolidated financial statement amounts
as of and for the year ended December 31, 2005.
PricewaterhouseCoopers LLP
Houston, Texas.
March 13, 2006
109
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
--------------------------------------
2005 2004 2003
---------- ---------- ----------
(In thousands except per unit amounts)
Revenues
Natural gas sales............................................... $7,198,499 $5,803,065 $4,889,235
Services........................................................ 1,851,699 1,571,504 1,377,745
Product sales and other......................................... 736,930 558,292 357,342
---------- ---------- ----------
9,787,128 7,932,861 6,624,322
---------- ---------- ----------
Costs and Expenses
Gas purchases and other costs of sales.......................... 7,167,414 5,767,169 4,880,118
Operations and maintenance...................................... 747,363 499,714 397,723
Fuel and power.................................................. 183,458 151,480 108,112
Depreciation and amortization................................... 349,827 288,626 219,032
General and administrative...................................... 216,706 170,507 150,435
Taxes, other than income taxes.................................. 108,838 81,369 62,213
---------- ---------- ----------
8,773,606 6,958,865 5,817,633
---------- ---------- ----------
Operating Income.................................................. 1,013,522 973,996 806,689
Other Income (Expense)
Earnings from equity investments................................ 91,660 83,190 92,199
Amortization of excess cost of equity investments............... (5,644) (5,575) (5,575)
Interest, net................................................... (258,861) (192,882) (181,357)
Other, net...................................................... 3,273 2,254 7,601
Minority Interest................................................. (7,262) (9,679) (9,054)
---------- ---------- ----------
Income Before Income Taxes and Cumulative Effect of a Change in
Accounting Principle ........................................... 836,688 851,304 710,503
Income Taxes...................................................... 24,461 19,726 16,631
---------- ---------- ----------
Income Before Cumulative Effect of a Change in Accounting Principle 812,227 831,578 693,872
Cumulative effect adjustment from change in accounting for asset
retirement obligations.......................................... - - 3,465
---------- ---------- ----------
Net Income........................................................ $ 812,227 $ 831,578 $ 697,337
========== ========== ==========
Calculation of Limited Partners' Interest in Net Income:
Income Before Cumulative Effect of a Change in Accounting $ 812,227 $ 831,578 $ 693,872
Principle.........................................................
Less: General Partner's interest................................ (477,300) (395,092) (326,489)
---------- ---------- ----------
Limited Partners' interest...................................... 334,927 436,486 367,383
Add: Limited Partners' interest in Change in Accounting Principle - - 3,430
---------- ---------- ----------
Limited Partners' interest in Net Income........................ $ 334,927 $ 436,486 $ 370,813
========== ========== ==========
Basic and Diluted Limited Partners' Net Income per Unit:
Income Before Cumulative Effect of a Change in Accounting $ 1.58 $ 2.22 $ 1.98
Principle.........................................................
Cumulative effect adjustment from change in accounting for asset
retirement obligations........................................ - - 0.02
---------- ---------- ----------
Net Income...................................................... $ 1.58 $ 2.22 $ 2.00
========== ========== ==========
Weighted average number of units used in computation of Limited Partners' Net
Income per Unit:
Basic............................................................. 212,197 196,956 185,384
========== ========== ==========
Diluted........................................................... 212,429 197,038 185,494
========== ========== ==========
Per unit cash distribution declared............................. $ 3.13 $ 2.87 $ 2.63
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
110
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
------------------------------------
2005 2004 2003
----------- --------- ---------
(In thousands)
Net Income.................................................. $ 812,227 $ 831,578 $ 697,337
Foreign currency translation adjustments.................... (699) 375 --
Change in fair value of derivatives used for hedging purposes (1,045,615) (494,212) (192,618)
Reclassification of change in fair value of derivatives to 423,983 192,304 82,065
----------- --------- ---------
net income....................................................
Total other comprehensive income............................ (622,331) (301,533) (110,553)
----------- --------- ---------
Comprehensive Income........................................ $ 189,896 $ 530,045 $ 586,784
=========== ========= =========
The accompanying notes are an integral part of these consolidated financial statements.
111
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
-------------------------
2005 2004
----------- -----------
ASSETS (Dollars in thousands)
Current Assets
Cash and cash equivalents................................ $ 12,108 $ -
Accounts, notes and interest receivable, net
Trade................................................. 1,011,716 739,798
Related parties....................................... 2,543 12,482
Inventories
Products.............................................. 18,820 17,868
Materials and supplies................................ 13,292 11,345
Gas imbalances
Trade................................................. 18,220 24,653
Related parties....................................... - 980
Gas in underground storage............................... 7,074 -
Other current assets..................................... 131,451 46,045
----------- -----------
1,215,224 853,171
Property, Plant and Equipment, net......................... 8,864,584 8,168,680
Investments................................................ 419,313 413,255
Notes receivable
Trade.................................................... 1,468 1,944
Related parties.......................................... 109,006 111,225
Goodwill................................................... 798,959 732,838
Other intangibles, net..................................... 217,020 15,284
Deferred charges and other assets.......................... 297,888 256,545
----------- -----------
Total Assets...............................................
$11,923,462 $10,552,942
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts.................................. $ 30,408 $ 29,866
Trade................................................. 996,174 685,034
Related parties....................................... 16,676 16,650
Current portion of long-term debt........................ - -
Accrued interest......................................... 74,886 56,930
Accrued taxes............................................ 23,536 26,435
Deferred revenues........................................ 10,523 7,825
Gas imbalances
Trade................................................. 22,948 32,452
Related parties....................................... 1,646 -
Accrued other current liabilities........................ 632,088 325,663
----------- -----------
1,808,885 1,180,855
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding........................................... 5,220,887 4,722,410
Market value of interest rate swaps................... 98,469 130,153
----------- -----------
5,319,356 4,852,563
Deferred revenues........................................ 6,735 14,680
Deferred income taxes.................................... 70,343 56,487
Asset retirement obligations............................. 42,417 37,464
Other long-term liabilities and deferred credits......... 1,019,655 468,727
----------- -----------
6,458,506 5,429,921
Commitments and Contingencies (Notes 13 and 16)
Minority Interest.......................................... 42,331 45,646
----------- -----------
Partners' Capital
Common Units (157,005,326 and 147,537,908 units issued and
outstanding as of December 31, 2005 and 2004,
respectively)......................................... 2,680,352 2,438,011
Class B Units (5,313,400 and 5,313,400 units issued and
Outstanding as of December 31, 2005 and 2004,
respectively)......................................... 109,594 117,414
i-Units (57,918,373 and 54,157,641 units issued and
outstanding as of December 31, 2005 and 2004,
respectively)......................................... 1,783,570 1,694,971
General Partner.......................................... 119,898 103,467
Accumulated other comprehensive loss..................... (1,079,674) (457,343)
------------ -----------
3,613,740 3,896,520
------------ -----------
Total Liabilities and Partners' Capital.................... $11,923,462 $10,552,942
=========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
112
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------------
2005 2004 2003
---------- ----------- -----------
(In thousands)
Cash Flows From Operating Activities
Net income................................................................ $ 812,227 $ 831,578 $ 697,337
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................................. 349,827 288,626 219,032
Amortization of excess cost of equity investments........................ 5,644 5,575 5,575
Earnings from equity investments......................................... (91,660) (83,190) (92,199)
Distributions from equity investments...................................... 63,098 65,248 83,000
Changes in components of working capital:
Accounts receivable...................................................... (240,751) (172,393) (180,632)
Other current assets..................................................... (14,129) 26,175 (1,858)
Inventories.............................................................. (13,560) (7,353) (2,945)
Accounts payable......................................................... 294,907 222,377 92,702
Accrued liabilities...................................................... 22,444 (18,482) 9,740
Accrued taxes............................................................ (2,301) 3,444 (4,904)
FERC rate reparations, refunds and reserve adjustments..................... 105,000 -- (44,944)
Other, net................................................................. (1,316) (6,497) (7,923)
---------- ----------- -----------
Net Cash Provided by Operating Activities.................................... 1,289,430 1,155,108 768,516
---------- ----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets..................................................... (307,832) (478,830) (349,867)
Additions to property, plant and equip. for expansion and maintenance (863,056) (747,262) (576,979)
projects.....................................................................
Sale of investments, property, plant and equipment, net of removal costs... 9,874 1,069 2,090
Acquisitions of investments................................................ -- (1,098) (10,000)
Contributions to equity investments........................................ (1,168) (7,010) (14,052)
Natural gas stored underground and natural gas liquids line-fill........... (18,735) (19,189) 5,459
Other...................................................................... (211) 1,810 288
---------- ----------- -----------
Net Cash Used in Investing Activities........................................ (1,181,128) (1,250,510) (943,061)
---------- ----------- -----------
Cash Flows From Financing Activities
Issuance of debt........................................................... 4,900,936 6,016,670 4,674,605
Payment of debt............................................................ (4,463,162) (5,657,566) $(4,014,296)
Repayments from (Loans to) related party................................... 2,083 (96,271) --
Debt issue costs........................................................... (6,058) (5,843) (5,204)
Increase in cash book overdrafts........................................... 542 29,866 --
Proceeds from issuance of common units..................................... 415,574 506,520 175,567
Proceeds from issuance of i-units.......................................... -- 67,528 --
Contributions from minority interest....................................... 7,839 7,956 4,181
Distributions to partners:
Common units............................................................. (460,620) (389,912) (340,927)
Class B units............................................................ (16,312) (14,931) (13,682)
General Partner.......................................................... (460,869) (376,005) (314,244)
Minority interest........................................................ (12,065) (10,117) (10,445)
Other, net................................................................. (3,866) (5,822) 1,231
---------- ----------- -----------
Net Cash Provided by (Used in) Financing Activities.......................... (95,978) 72,073 156,786
---------- ----------- -----------
Effect of exchange rate changes on cash and cash equivalents................. (216) -- --
---------- ----------- -----------
Increase (Decrease) in Cash and Cash Equivalents............................. 12,108 (23,329) (17,759)
Cash and Cash Equivalents, beginning of period............................... -- 23,329 41,088
---------- ----------- -----------
Cash and Cash Equivalents, end of period..................................... $ 12,108 $ -- $ 23,329
========== =========== ===========
Noncash Investing and Financing Activities:
Assets acquired by the issuance of units................................... $ 49,635 $ 64,050 $ 2,000
Assets acquired by the assumption of liabilities........................... 76,574 81,403 36,187
Supplemental disclosures of cash flow information:
Cash paid (received) during the year for
Interest (net of capitalized interest)..................................... 255,453 193,247 183,908
Income taxes............................................................... 7,345 (752) (261)
The accompanying notes are an integral part of these consolidated financial statements.
113
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
2005 2004 2003
------------------------- ----------------------- -------------------------
Units Amount Units Amount Units Amount
----------- ----------- ----------- ---------- ----------- ----------
(Dollars in thousands)
Common Units:
Beginning Balance............................ 147,537,908 $ 2,438,011 134,729,258 $1,946,116 129,943,218 $1,844,553
Net income................................... -- 237,779 -- 311,237 -- 265,423
Units issued as consideration pursuant to
common unit compensation plan for non-
employee directors......................... 5,250 239 -- -- -- --
Units issued as consideration in the
acquisition of assets...................... 1,022,068 49,635 1,400,000 64,050 51,490 2,000
Units issued for cash........................ 8,440,100 415,308 11,408,650 506,520 4,734,550 175,067
Distributions................................ -- (460,620) -- (389,912) -- (340,927)
----------- ----------- ----------- ---------- ----------- ----------
Ending Balance............................... 157,005,326 2,680,352 147,537,908 2,438,011 134,729,258 1,946,116
Class B Units:
Beginning Balance............................ 5,313,400 117,414 5,313,400 120,582 5,313,400 123,635
Net income................................... -- 8,492 -- 11,763 -- 10,629
Units issued for cash........................ -- -- -- -- -- --
Distributions................................ -- (16,312) -- (14,931) -- (13,682)
----------- ----------- ----------- ---------- ----------- ----------
Ending Balance............................... 5,313,400 109,594 5,313,400 117,414 5,313,400 120,582
i-Units:
Beginning Balance............................ 54,157,641 1,694,971 48,996,465 1,515,659 45,654,048 1,420,898
Net income................................... -- 88,656 -- 113,486 -- 94,761
Units issued for cash........................ -- (57) 1,660,664 65,826 -- --
Distributions................................ 3,760,732 -- 3,500,512 -- 3,342,417 --
----------- ----------- ----------- ---------- ----------- ----------
Ending Balance............................... 57,918,373 1,783,570 54,157,641 1,694,971 48,996,465 1,515,659
General Partner:
Beginning Balance............................ -- 103,467 -- 84,380 -- 72,100
Net income................................... -- 477,300 -- 395,092 -- 326,524
Units issued for cash........................ -- -- -- -- -- --
Distributions................................ -- (460,869) -- (376,005) -- (314,244)
----------- ----------- ----------- ---------- ----------- ----------
Ending Balance............................... -- 119,898 -- 103,467 -- 84,380
Accum. other comprehensive income (loss):
Beginning Balance............................ -- (457,343) -- (155,810) -- (45,257)
Foreign currency translation adjustments..... -- (699) -- 375 -- --
Change in fair value of derivatives
used for hedging purposes.................. -- (1,045,615) -- (494,212) -- (192,618)
Reclassification of change in fair value of
derivatives to net income.................. -- 423,983 -- 192,304 -- 82,065
----------- ----------- ----------- ---------- ----------- ----------
Ending Balance............................... -- (1,079,674) -- (457,343) -- (155,810)
Total Partners' Capital........................ 220,237,099 $ 3,613,740 207,008,949 $3,896,520 189,039,123 $3,510,927
=========== =========== =========== ========== =========== ==========
The accompanying notes are an integral part of these consolidated financial statements.
114
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 and presently conduct our business through four reportable
business segments. These segments and the activities performed to provide
services to our customers and create value for our unitholders are as follows:
* Products Pipelines - transporting, storing and processing refined
petroleum products;
* Natural Gas Pipelines - transporting, storing and selling natural gas;
* CO2 - producing, transporting and selling carbon dioxide, commonly called
CO2, for use in, and selling crude oil produced from, enhanced oil
recovery operations; and
* Terminals - transloading, storing and delivering a wide variety of bulk,
petroleum, petrochemical and other liquid products at terminal facilities
located across the United States.
For more information on our reportable business segments, see Note 15.
We focus on providing fee-based services to customers, generally avoiding
near-term 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 we conduct our operations through the following five operating
limited partnerships:
* Kinder Morgan Operating L.P. "A" (OLP-A);
* Kinder Morgan Operating L.P. "B" (OLP-B);
* Kinder Morgan Operating L.P. "C" (OLP-C);
* Kinder Morgan Operating L.P. "D" (OLP-D); and
* Kinder Morgan CO2 Company (KMCO2).
Combined, the five partnerships are referred to as our operating
partnerships, and we are the 98.9899% limited partner and our general partner
(described following) is the 1.0101% general partner in each. Both we and our
operating partnerships are governed by Amended and Restated Agreements of
Limited Partnership and certain other agreements that are collectively referred
to in this report as the partnership agreements.
Kinder Morgan, Inc. and Kinder Morgan G.P., 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 North America, operating or owning an
interest in, either for itself or on our behalf, approximately 43,000 miles of
pipelines and approximately 150 terminals. KMI and its consolidated subsidiaries
also distribute natural gas to approximately 1.1 million customers.
115
At December 31, 2005, KMI and its consolidated subsidiaries owned, through its
general and limited partner interests, an approximate 15.2% interest in us.
Kinder Morgan Management, LLC
Kinder Morgan Management, LLC, a Delaware limited liability company, was
formed on February 14, 2001. Its shares represent limited liability company
interests and are traded on the New York Stock Exchange under the symbol "KMR."
Kinder Morgan Management, LLC 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 has 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 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,
2005, KMR owned approximately 26.3% 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
five majority-owned and controlled operating partnerships and their
subsidiaries. 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
116
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, 2005, 2004 and 2003.
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, 2005.... $8,622 $ 203 $ - $(2,283) $6,542
Year ended December 31, 2004.... $8,783 $1,460 $ 431 $(2,052) $8,622
Year ended December 31, 2003.... $8,092 $1,448 $ - $ (757) $8,783
- ----------
(1) Amount for 2004 represents the allowance recognized when we acquired Kinder
Morgan River Terminals LLC and its consolidated subsidiaries ($393) and
TransColorado Gas Transmission Company ($38).
(2) Deductions represent the write-off of receivables.
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, 2005 and $5.1
million as of December 31, 2004.
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 report 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.
Gains and losses on minor system sales, excluding land, are recorded to the
appropriate accumulated depreciation reserve. Gains and losses for operating
systems sales and land sales are booked to income or expense accounts in
accordance with regulatory accounting guidelines.
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 that are incurred to
acquire leasehold and subsequent development costs are capitalized. Costs that
are associated with the drilling of successful exploration wells are capitalized
if proved reserves are found. Costs associated with the drilling of exploratory
wells that do not find proved reserves, geological and geophysical costs, and
costs of certain non-producing leasehold costs are expensed as incurred. The
capitalized costs of our
117
producing oil and gas properties are depreciated and depleted by the
units-of-production method. Other miscellaneous property, plant and equipment
are depreciated over the estimated useful lives of the asset.
A gain on the sale of property, plant and equipment used in our oil and gas
producing activities is calculated as the difference between the cost of the
asset disposed of, net of depreciation, and the sales proceeds received. A gain
on an asset disposal is recognized in income in the period that the sale is
closed. A loss on the sale of property, plant and equipment is calculated as the
difference between the cost of the asset disposed of, net of depreciation, and
the sales proceeds received or the maket value if the asset is being held for
sale. A loss is recognized when the asset is sold or when the net cost of an
asset held for sale is greater than the market value of the asset.
In addition, we engage in enhanced recovery techniques in which carbon
dioxide is injected into certain producing oil reservoirs. In some cases, the
acquisition cost of the carbon dioxide associated with enhanced recovery is
capitalized as part of our development costs when it is injected. The
acquisition cost associated with pressure maintenance operations for reservoir
management is expensed when it is injected. When carbon dioxide 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.
We evaluate our oil and gas producing properties for impairment of value on
a field-by-field basis or, in certain instances, by logical grouping of assets
if there is significant shared infrastructure, using undiscounted future cash
flows based on total proved and risk-adjusted probable and possible reserves.
Oil and gas producing properties deemed to be impaired are written down to their
fair value, as determined by discounted future cash flows based on total proved
and risk-adjusted probable and possible reserves or, if available, comparable
market values. Unproved oil and gas properties that are individually significant
are periodically assessed for impairment of value, and a loss is recognized at
the time of impairment.
We evaluate the impairment of our long-lived assets in accordance with
Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 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.
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
We account for our business acquisitions and intangible assets in accordance
with the provisions of SFAS No. 141, "Business Combinations," and SFAS No. 142,
"Goodwill and Other Intangible Assets." SFAS No. 141 requires that all
transactions fitting the description of a business combination be accounted for
using the purchase method, which establishes a new basis of accountability for
the acquired business or assets. 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. 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 requires that goodwill not be amortized, but instead should be
tested, at least on an annual basis, for impairment. Pursuant to this Statement,
goodwill and other intangible assets with indefinite useful lives can not
118
be amortized until their useful life becomes determinable. Instead, such assets
must 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 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, 2006.
Other intangible assets with definite useful economic lives are to be
amortized over their remaining 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." In addition, SFAS No. 142 requires disclosure
of information about goodwill and other intangible assets in the years
subsequent to their acquisition, including 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.
Our total unamortized excess cost over fair value of net assets in
consolidated affiliates was $799.0 million as of December 31, 2005 and $732.8
million as of December 31, 2004. 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
$138.2 million as of December 31, 2005 and $150.3 million as of December 31,
2004. 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 almost all cases, the price we paid to acquire our share of the net
assets of our equity investees differed from the underlying book value of such
net assets. This differential consists of two pieces. First, an amount related
to the discrepancy between the investee's recognized net assets at book value
and at current fair values (representing the appreciated value in plant and
other net assets), and secondly, to any premium in excess of fair value
(representing equity method goodwill as described above) we paid to acquire the
investment. The first differential, representing the excess of the fair market
value of our investees' plant and other net assets over its underlying book
value at the date of acquisition totaled $181.7 million and $184.2 million as of
December 31 2005 and 2004, respectively, and similar to our treatment of equity
method goodwill, we included these amounts within "Investments" on our
accompanying consolidated balance sheets. As of December 31, 2005, this excess
investment cost is being amortized over a weighted average life of approximately
32.6 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 accounted for under the equity method, 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, 2005, 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 throughput 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.
Revenues from the sale of oil and natural gas liquids production are
recorded using the entitlement method. Under the entitlement method, revenue is
recorded when title passes based on our net interest. We record our entitled
share of revenues based on entitled volumes and contracted sales prices.
Revenues from the sale of natural
119
gas production are recognized when the natural gas is sold. Since there is a
ready market for oil and gas production, we sell the majority of our products
soon after production at various locations, at which time title and risk of loss
pass to the buyer. As a result, we maintain a minimum amount of product
inventory in storage and the differences between actual production and sales is
not significant.
Capitalized Interest
We capitalize interest expense during the construction or upgrade of
qualifying assets. Interest expense capitalized in 2005, 2004 and 2003 was $9.8
million, $6.4 million and $5.3 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. Since all of the options were
granted at exercise prices equal to the market prices at the date of grant, no
compensation expense has been recorded. 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 current or
future revenue generation. We do not discount environmental liabilities to a net
present value, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, our recording of these accruals coincides with our
completion of a feasibility study or our commitment to a formal plan of action.
We recognize receivables for anticipated associated insurance recoveries when
such recoveries are deemed to be probable.
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.
We routinely conduct reviews of potential environmental issues and claims
that could impact our assets or operations. In December 2005, we recognized a
$23.3 million increase in environmental expense and in our overall accrued
environmental and related claim liabilities. We included this expense within
"Operations and maintenance" in our accompanying consolidated statement of
income for 2005. The $23.3 million expense item resulted from the adjustment of
our environmental expenses and accrued liabilities between our reportable
business segments, primarily affecting our Products Pipelines and our Terminals
business segments. The $23.3 million increase in environmental expense resulted
in a $19.6 million increase in expense to our Products Pipelines business
segment, a $3.5 million increase in expense to our Terminals business segment, a
$0.3 million increase in expense to our CO2 business segment, and a $0.1 million
decrease in expense to our Natural Gas Pipelines business segment.
In December 2004, we recognized a $0.2 million increase in environmental
expenses and an associated $0.1 million increase in deferred income tax expense
resulting from changes to previous estimates. The adjustment included an $18.9
million increase in our estimated environmental receivables and reimbursables
and a $19.1 million increase in our overall accrued environmental and related
claim liabilities. We included the additional $0.2 million environmental expense
within "Other, net" in our accompanying consolidated statement of income for
2004. The $0.3 million expense item, including taxes, is the net impact of a
$30.6 million increase in expense in our Products Pipelines business segment, a
$7.6 million decrease in expense in our Natural Gas Pipelines segment, a
120
$4.1 million decrease in expense in our CO2 segment, and an $18.6 million
decrease in expense 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. We expense legal costs as incurred and
all recorded legal liabilities are 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:
* our investment return assumptions;
* the significant estimates on which those assumptions are based; and
* 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 the provisions of SFAS No. 87, "Employers' Accounting for
Pensions," our net periodic pension cost includes the return on pension plan
assets, including both realized and unrealized changes in the fair market value
of pension plan assets.
A source of volatility in pension costs comes from this inclusion of
unrealized or market value gains and losses on pension assets as part of the
components recognized as pension expense. To prevent wide swings in pension
expense from occurring because of one-time changes in fund values, SFAS No. 87
allows for the use of an actuarial computed "expected value" of plan asset gains
or losses to be the actual element included in the determination of pension
expense. The actuarial derived expected return on pension assets not only
employs an expected rate of return on plan assets, but also assumes a
market-related value of plan assets, which is a calculated value that recognizes
changes in fair value in a systematic and rational manner over not more than
five years. As required, we disclose the weighted average expected long-run rate
of return on our plan assets, which is used to calculate our plan assets'
expected return. For more information on our pension disclosures, see Note 10.
Gas Imbalances
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 and shippers under various operational balancing and
shipper imbalance agreements. Natural gas imbalances are either settled in cash
or made up in-kind subject to the pipelines' various tariff provisions.
Minority Interest
As of December 31, 2005, minority interest consisted of the following:
* the 1.0101% general partner interest in each of our five operating
partnerships;
* the 0.5% special limited partner interest in SFPP, L.P.;
121
* the 50% interest in Globalplex Partners, a Louisiana joint venture
owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;
* the 33 1/3% interest in International Marine Terminals Partnership, a
Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan
Operating L.P. "C";
* 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;
* the 1% interest in River Terminals Properties, L.P., a Tennessee
partnership owned 99% and controlled by Kinder Morgan River Terminals
LLC;
* the 25% interest in Guilford County Terminal Company, LLC, a limited
liability company owned 75% and controlled by Kinder Morgan Southeast
Terminals LLC; and
* the 33 1/3% interest in West2East Pipeline LLC, a limited liability
company owned 66 2/3% and controlled by Kinder Morgan W2E Pipeline
LLC. West2East Pipeline LLC is the sole member of Rockies Express
Pipeline LLC.
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 us.
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.
Foreign Currency Translation
In October 2004, we acquired Kinder Morgan River Terminals LLC, formerly
Global Materials Services LLC. Our acquisition of Kinder Morgan River Terminals
LLC included two wholly-owned subsidiaries which conducted business outside of
the United States. The two foreign subsidiaries are Arrow Terminals, B.V., which
conducts bulk terminal operations in The Netherlands, and Arrow Terminals Canada
Company (NSULC), which conducts bulk terminal operations in Canada. We account
for these two entities in accordance with the provisions of SFAS No. 52,
"Foreign Currency Translation." We translate the assets and liabilities of each
of these two entities to U.S. dollars at year-end exchange rates. Income and
expense items are translated at weighted-average rates of exchange prevailing
during the year and stockholders' equity accounts are translated by using
historical exchange rates. Translation adjustments result from translating all
assets and liabilities at current year-end rates, while stockholders' equity is
translated by using historical and weighted-average rates. The cumulative
translation adjustments balance is reported as a component of accumulated other
comprehensive income/(loss) within Partners' Capital on our accompanying balance
sheet. Due to the limited size of our foreign operations, we do not believe
these foreign currency translations are material to our financial position.
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, 2005 and 2004,
the difference between our net income and our comprehensive income resulted from
unrealized gains or losses on derivatives utilized for hedging purposes and from
foreign currency translation adjustments. For the year ended
122
December 31, 2003, the only difference between our net income and our
comprehensive income resulted from 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 our
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 maximum potential dilution that could occur if units whose issuance
depends on the market price of the units at a future date were considered
outstanding, or if, by application of the treasury stock method, options to
issue units were exercised, both of which would result in the issuance of
additional units that would then share in our net income.
Asset Retirement Obligations
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.
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, "Accounting for
Derivative Instruments and Hedging Activities," 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 2003, 2004 and 2005, 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.
123
Allocation of Purchase Price
-------------------------------------------------------------------
(in millions)
-------------------------------------------------------------------
Property Deferred
Purchase Current Plant & Charges Minority
Ref. Date Acquisition Price Assets Equipment & Other Goodwill Interest
-------------------------------------------------------- ---------- ------- --------- -------- -------- --------
(1) 1/02 Kinder Morgan Materials Services LLC...... $ 14.4 $ 0.9 $ 13.5 $ - $ - $ -
(2) 1/03 Bulk Terminals from M.J. Rudolph.......... 31.3 0.1 18.2 0.1 12.9 -
(3) 6/03 MKM Partners, L.P......................... 25.2 - 25.2 - - -
(4) 8/03 Interest in Red Cedar Gathering Company... 10.0 - - 10.0 - -
(5) 10/03 Shell Products Terminals.................. 20.0 - 20.0 - - -
(6) 11/03 Yates Field Unit and Carbon Dioxide Assets 260.3 3.6 257.0 - - (0.3)
(7) 11/03 Interest in MidTex Gas Storage Co., LLP... 17.5 - 11.9 - - 5.6
(8) 12/03 ConocoPhillips Products Terminals......... 15.3 - 14.3 1.0 - -
(9) 12/03 Tampa, Florida Bulk Terminals............. 29.1 - 29.1 - - -
(10) 3/04 ExxonMobil Products Terminals............. 50.9 - 50.9 - - -
(11) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 77.4 22.8 - -
(12) 10/04 Interest in Cochin Pipeline System........ 10.9 - 10.9 - - -
(13) 10/04 Kinder Morgan River Terminals LLC......... 89.3 9.9 43.2 15.2 21.0 -
(14) 11/04 Charter Products Terminals................ 75.2 0.5 70.9 4.9 - (1.1)
(15) 11/04 TransColorado Gas Transmission Company.... 284.5 2.0 280.6 1.9 - -
(16) 12/04 Kinder Morgan Fairless Hills Terminal..... 7.5 0.3 5.9 1.3 - -
(17) 1/05 Claytonville Oil Field Unit .............. 6.5 - 6.5 - - -
(18) 4/05 Texas Petcoke Terminal Region ............ 247.2 - 72.5 161.4 13.3 -
(19) 7/05 Terminal Assets .......................... 36.2 0.5 35.7 - - -
(20) 7/05 General Stevedores, L.P. ................. 8.9 0.6 8.1 0.2 - -
(21) 8/05 North Dayton Natural Gas Storage Facility 109.4 - 71.7 11.7 26.0 -
(22) 8-9/05 Terminal Assets .......................... 4.3 0.4 3.9 - - -
(23) 11/05 Allied Terminal Assets ................... $ 13.3 $ 0.2 $ 12.6 $ 0.5 $ - $ -
(1) Kinder Morgan Materials Services LLC
Effective January 1, 2002, we acquired all of the equity interests of Kinder
Morgan Materials Services LLC, formerly Laser Materials Services LLC, for an
aggregate consideration of $14.4 million, consisting of approximately $11.1
million in cash and the assumption of approximately $3.3 million of liabilities,
including long-term debt of $0.4 million. These amounts include $0.3 million we
paid in the first quarter of 2005 to the previous owners for final earn-out
provisions pursuant to the purchase and sale agreement. Kinder Morgan Materials
Services LLC currently operates approximately 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.
(2) 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,
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. The acquisition expanded our
growing Terminals business segment and complemented certain of our existing
terminal facilities. We include its operations in our Terminals business
segment, and 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. 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.
124
(3) MKM Partners, L.P.
Effective June 1, 2003, we acquired the MKM joint venture's 12.75% ownership
interest in the SACROC oil field 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%.
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, which we acquired
June 1, 2003 as described above, and a 49.9% interest in the Yates Field unit,
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.
(4) Interest in Red Cedar Gathering Company
Effective August 1, 2003, we acquired reversionary interests in the Red
Cedar 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
reversionary interests, our ownership interest in Red Cedar will be maintained
at 49% in the future. The purchase price was allocated to our equity investment
in Red Cedar, included with our equity method goodwill.
(5) 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. As of our acquisition date, we expected 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 entered into a long-term contract to store products in
the terminals. The acquisition enhanced our Pacific operations and complemented
our existing West Coast Terminals. The acquired operations are included as part
of our Pacific operations and our Products Pipelines business segment.
(6) 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 $260.3 million, consisting of $230.2 million in cash and the
assumption of $30.1 million of liabilities. The assets acquired consisted of the
following:
* 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;
* Marathon's 100% interest in the crude oil gathering system surrounding
the Yates field unit; and
* Kinder Morgan Carbon Dioxide Transportation Company, formerly Marathon
Carbon Dioxide Transportation Company. Kinder Morgan 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. Since the acquisition of our
additional 65% interest in Pecos, its financial results have been
included in our consolidated results, and we have recognized the
appropriate minority interest.
Together, the acquisition of these assets 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.
125
We recorded deferred tax liabilities of $0.8 million in August 2004 and $0.4
million in November 2005 to properly reflect the tax obligations of Kinder
Morgan Carbon Dioxide Transportation Company. The acquired operations are
included as part of our CO2 business segment.
(7) Interest in MidTex Gas Storage Company, LLP
Effective November 1, 2003, we acquired the remaining approximate 32%
ownership interest in MidTex Gas Storage Company, LLP that we did not already
own from an affiliate of NiSource Inc. Our combined purchase price was
approximately $17.5 million, consisting of $15.8 million in cash and 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 in
Matagorda County, Texas. MidTex's operations are included as part of our Natural
Gas Pipelines business segment.
(8) ConocoPhillips Products Terminals
Effective December 11, 2003, we acquired seven refined petroleum products
terminals located in the southeastern United States from ConocoPhillips Company
and Phillips Pipe Line Company. Our purchase price was approximately $15.3
million, consisting of approximately $14.1 million in cash and $1.2 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 fully own and operate all of the terminals
except for the Doraville, Georgia facility, which is operated and owned 70% by
Citgo. As of our acquisition date, we expected 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 contract consists of a five-year
terminaling agreement, an intangible asset which we valued at $1.0 million. The
acquisition broadened 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.
(9) Tampa, Florida Bulk Terminals
In December 2003, we acquired two bulk terminal facilities in Tampa, Florida
for an aggregate consideration of approximately $29.1 million, consisting of
$26.3 million in cash and $2.8 million in assumed liabilities. As of our
acquisition date, we expected to invest an additional $16.9 million in the
facilities. The principal facility purchased was a marine terminal acquired from
a subsidiary of The Mosaic Company, formerly IMC Global, Inc. We entered into a
long-term agreement with Mosaic pursuant to which Mosaic will 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
purchased was the former Nitram, Inc. bulk terminal, which we have converted to
an inland bulk storage warehouse facility for overflow cargoes from our Port
Sutton, Florida 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 businesses in the
Tampa area by generating additional fee-based income.
(10) ExxonMobil Products Terminals
Effective March 9, 2004, we acquired seven refined petroleum products
terminals in the southeastern United States from Exxon Mobil Corporation. Our
purchase price was approximately $50.9 million, consisting of approximately
$48.2 million in cash and $2.7 million in assumed liabilities. 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, ExxonMobil
entered into a long-term contract to store products at the terminals. As of our
acquisition date, we expected to invest an additional $1.2 million in the
facilities. The acquisition enhanced our terminal operations in the Southeast
and complemented our December 2003
126
acquisition of seven products terminals from ConocoPhillips Company and Phillips
Pipe Line Company. The acquired operations are included as part of our Products
Pipelines business segment.
(11) Kinder Morgan Wink Pipeline, L.P.
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P. from KPL Pipeline Company, LLC and RHC Holdings,
L.P. for a purchase price of approximately $100.3 million, consisting of $89.9
million in cash and the assumption of approximately $10.4 million of
liabilities, including debt of $9.5 million. In September 2004, we paid off the
$9.5 million outstanding debt balance. We renamed the limited partnership Kinder
Morgan Wink Pipeline, L.P., and we have included its results as part of our CO2
business segment. The acquisition included a 450-mile crude oil pipeline system,
consisting of four mainline sections, numerous gathering systems and truck
off-loading stations. The mainline sections, all in Texas, have a total capacity
of 115,000 barrels of crude oil per day. As part of the transaction, we entered
into a long-term throughput agreement with Western Refining Company, L.P. to
transport crude oil into Western's 107,000 barrel per day refinery in El Paso,
Texas. The acquisition allows us to better manage crude oil deliveries from our
oil field interests in West Texas. Our allocation of the purchase price to
assets acquired and liabilities assumed was based on an appraisal of fair market
values, which was completed in the second quarter of 2005. The $22.8
million of deferred charges and other assets in the table above represents the
fair value of the intangible long-term throughput agreement.
(12) Interest in Cochin Pipeline
Effective October 1, 2004, we acquired an additional undivided 5% interest
in the Cochin Pipeline System from subsidiaries of ConocoPhillips Corporation
for approximately $10.9 million. On November 3, 2000, we acquired from NOVA
Chemicals Corporation an undivided 32.5% interest in the Cochin Pipeline System
for approximately $120.5 million. On June 20, 2001, we acquired an additional
2.3% ownership interest from Shell Canada Limited for approximately $8.1
million, and effective December 31, 2001, we purchased an additional 10%
ownership interest from NOVA Chemicals Corporation for approximately $29
million. We now own approximately 49.8% of the Cochin Pipeline System. A
subsidiary of BP owns the remaining interest and operates the pipeline. We
record our proportional share of joint venture revenues and expenses and cost of
joint venture assets with respect to the Cochin Pipeline System as part of our
Products Pipelines business segment.
(13) Kinder Morgan River Terminals LLC
Effective October 6, 2004, we acquired Global Materials Services LLC and its
consolidated subsidiaries from Mid-South Terminal Company, L.P. for
approximately $89.3 million, consisting of $31.8 million in cash and $57.5
million of assumed liabilities, including debt of $33.7 million. Global
Materials Services LLC, which we renamed Kinder Morgan River Terminals LLC,
operates a network of 21 river terminals and two rail transloading facilities
primarily located along the Mississippi River system. The network provides
loading, storage and unloading points for various bulk commodity imports and
exports. As of our acquisition date, we expected to invest an additional $9.4
million over the next two years to expand and upgrade the terminals, which are
located in 11 Mid-Continent states. The acquisition further expanded and
diversified our customer base and complemented our existing terminal facilities
located along the lower-Mississippi River system. The acquired terminals are
included in our Terminals business segment. In the last half of 2005, we made
purchase price adjustments to the acquired assets based on an appraisal of fair
market values and our final evaluation of acquired income tax assets and
liabilities. The $21.0 million of goodwill was assigned to our Terminals
business segment, and the entire amount is expected to be deductible for tax
purposes. We believe this acquisition resulted in the recognition of goodwill
primarily due to the fact that certain advantageous factors and conditions
existed that contributed to the fair value of acquired identifiable net assets
and liabilities exceeding our acquisition price - in the aggregate, these
factors represented goodwill. The $15.2 million of deferred charges and other
assets in the table above includes $11.9 million representing the fair value of
intangible customer relationships, which encompass both the contractual life of
customer contracts plus any future customer relationship value beyond the
contract life.
(14) Charter Products Terminals
Effective November 5, 2004, we acquired ownership interests in nine refined
petroleum products terminals in the southeastern United States from Charter
Terminal Company and Charter-Triad Terminals, LLC for approximately $75.2
million, consisting of $72.4 million in cash and $2.8 million of assumed
liabilities. Three terminals are located in Selma, North Carolina, and the
remaining facilities are located in Greensboro and Charlotte, North
127
Carolina; Chesapeake and Richmond, Virginia; Athens, Georgia; and North Augusta,
South Carolina. We fully own seven of the terminals and jointly own the
remaining two. The nine facilities have a combined 3.2 million barrels of
storage. All of the terminals are connected to products pipelines owned by
either Plantation Pipe Line Company or Colonial Pipeline Company. The
acquisition complemented the other terminals we own in the Southeast and
increased our southeast terminal storage capacity 76% (to 7.7 million barrels)
and terminal throughput capacity 62% (to over 340,000 barrels per day). The
acquired terminals are included as part of our Products Pipelines business
segment. In the fourth quarter of 2005, we made purchase price adjustments that
increased property, plant and equipment $11.2 million, increased investments
$1.0 million, decreased goodwill $13.1 million and increased other intangibles
$0.9 million. The changes were based on an appraisal of fair market values,
which was completed in the fourth quarter of 2005. The $4.9 million of
deferred charges and other assets in the table above includes $0.9 million
representing the fair value of intangible customer relationships, which
encompass both the contractual life of customer contracts plus any future
customer relationship value beyond the contract life.
(15) TransColorado Gas Transmission Company
Effective November 1, 2004, we acquired all of the partnership interests in
TransColorado Gas Transmission Company from two wholly-owned subsidiaries of
KMI. TransColorado Gas Transmission Company, a Colorado general partnership
referred to in this report as TransColorado, owned assets valued at
approximately $284.5 million. As consideration for TransColorado, we paid to KMI
$211.2 million in cash and approximately $64.0 million in units, consisting of
1,400,000 common units. We also assumed liabilities of approximately $9.3
million. The purchase price for this transaction was determined by the boards of
directors of KMR and our general partner, and KMI based on valuation parameters
used in the acquisition of similar assets. The transaction was approved
unanimously by the independent members of the boards of directors of both KMR
and our general partner, and KMI, with the benefit of advice of independent
legal and financial advisors, including the receipt of fairness opinions from
separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley
& Co. TransColorado owns a 300-mile interstate natural gas pipeline that
originates in the Piceance Basin of western Colorado and runs to the Blanco Hub
in northwest New Mexico. The acquisition expanded our natural gas operations
within the Rocky Mountain region and the acquired operations are included as
part of our Natural Gas Pipelines business segment.
(16) Kinder Morgan Fairless Hills Terminal
Effective December 1, 2004, we acquired substantially all of the assets used
to operate the major port distribution facility located at the Fairless
Industrial Park in Bucks County, Pennsylvania for an aggregate consideration of
approximately $7.5 million, consisting of $7.2 million in cash and $0.3 million
in assumed liabilities. The facility, referred to as our Kinder Morgan Fairless
Hills Terminal, was purchased from Novolog Bucks County, Inc. and is located
along the Delaware River. It is the largest port on the East Coast for the
handling of semi-finished steel slabs, which are used as feedstock by domestic
steel mills. The port operations at Fairless Hills also include the handling of
other types of steel and specialized cargo that caters to the construction
industry and service centers that use steel sheet and plate. In the second
quarter of 2005, after completing a final inventory count, we allocated $0.3
million of our purchase price that was originally allocated to property, plant
and equipment to current assets (materials and supplies-parts inventory). The
terminal acquisition expanded our presence along the Delaware River and
complemented our existing Mid-Atlantic terminal facilities. We include its
operations in our Terminals business segment.
(17) Claytonville Oil Field Unit
Effective January 31, 2005, we acquired an approximate 64.5% gross working
interest in the Claytonville oil field unit located in Fisher County, Texas from
Aethon I L.P. The field is located nearly 30 miles east of the SACROC unit in
the Permian Basin of West Texas. Our purchase price was approximately $6.5
million, consisting of $6.2 million in cash and the assumption of $0.3 million
of liabilities. Following our acquisition, we became the operator of the field,
which at the time of acquisition was producing approximately 200 barrels of oil
per day. The acquisition of this ownership interest complemented our existing
carbon dioxide assets in the Permian Basin, and as of our acquisition date and
pending further studies as to the technical and economic feasibility of carbon
dioxide injection, we may invest an additional $30 million in the field in order
to increase production and ultimate oil recovery. The acquired operations are
included as part of our CO2 business segment.
128
(18) Texas Petcoke Terminal Region
Effective April 29, 2005, we acquired seven bulk terminal operations from
Trans-Global Solutions, Inc. for an aggregate consideration of approximately
$247.2 million, consisting of $186.0 million in cash, $46.2 million in common
units, and an obligation to pay an additional $15 million on April 29, 2007, two
years from closing. We will settle the $15 million liability by issuing
additional common units. All of the acquired assets are located in the State of
Texas, and include facilities at the Port of Houston, the Port of Beaumont and
the TGS Deepwater Terminal located on the Houston Ship Channel. We combined the
acquired operations into a new terminal region called the Texas Petcoke region,
as certain of the terminals have contracts in place to provide petroleum coke
handling services for major Texas oil refineries. The acquisition complemented
our existing Gulf Coast terminal facilities and expanded our pre-existing
petroleum coke handling operations. The acquired operations are included as part
of our Terminals business segment. In the fourth quarter of 2005, we made
purchase price adjustments that increased property, plant and equipment $0.1
million, increased goodwill $1.0 million and decreased other intangibles $1.3
million. The changes were based on an appraisal of fair market values, which was
completed in the fourth quarter of 2005. The $13.3 million of goodwill was
assigned to our Terminals business segment and the entire amount is expected to
be deductible for tax purposes. We believe this acquisition resulted in the
recognition of goodwill primarily due to the fact that certain advantageous
factors and conditions existed that contributed to the fair value of acquired
identifiable net assets and liabilities exceeding our acquisition price - in the
aggregate, these factors represented goodwill. The $161.4 million of deferred
charges and other assets in the table above represents the fair value of
intangible customer relationships, which encompass both the contractual life of
customer contracts plus any future customer relationship value beyond the
contract life. In connection with the transaction, Trans-Global Solutions, Inc.
agreed to indemnify Kinder Morgan G.P., Inc. for any losses relating to our
failure to repay $50.9 million of indebtedness incurred to fund the acquisition,
and we agreed to indemnify Trans-Global Solutions, Inc. for any taxes of
Trans-Global Solutions, Inc. that may arise from the sale of any acquired
assets. We have no current intention to sell any of the assets acquired in this
transaction.
(19) July 2005 Terminal Assets
In July 2005, we acquired three terminal facilities in separate transactions
for an aggregate consideration of approximately $36.2 million in cash. For the
three terminals combined, as of the acquisition date, we expected to invest
approximately $14 million subsequent to acquisition in order to enhance the
terminals' operational efficiency. The largest of the transactions was the
purchase of a refined petroleum products terminal in New York Harbor from
ExxonMobil Oil Corporation. The second acquisition involved a dry-bulk river
terminal located in the State of Kentucky, and the third involved a
liquids/dry-bulk facility located in Blytheville, Arkansas. The operations of
all three facilities are included in our Terminals business segment.
The New York Harbor terminal, located on Staten Island and referred to as
the Kinder Morgan Staten Island terminal, complements our existing Northeast
liquids terminal facilities located in Carteret and Perth Amboy, New Jersey. At
the time of acquisition, the terminal had storage capacity of 2.3 million
barrels for gasoline, diesel and fuel oil, and we expected to bring several idle
tanks back into service that would add another 550,000 barrels of capacity. In
addition, we planned to rebuild a ship berth with the ability to accommodate
tanker vessels. As part of the transaction, ExxonMobil entered into a long-term
storage capacity agreement with us and has continued to utilize a portion of the
terminal.
The dry-bulk terminal, located along the Ohio River in Hawesville, Kentucky,
primarily handles wood chips and finished paper products. The acquisition
complemented our existing terminal assets located in the Ohio River Valley and
further expanded our wood-chip handling businesses. As part of the transaction,
we assumed a long-term handling agreement with Weyerhauser Company, an
international forest products company, and we planned to expand the terminal in
order to increase utilization and provide storage services for additional
products.
The assets acquired at the liquids/dry-bulk facility in Blytheville,
Arkansas consisted of storage and supporting infrastructure for 40,000 tons of
anhydrous ammonia, 9,500 tons of urea ammonium nitrate solutions and 40,000 tons
of urea. As part of the transaction, we have entered into a long-term agreement
to sublease all of the existing anhydrous ammonia and urea ammonium nitrate
terminal assets to Terra Nitrogen Company, L.P. The terminal is one of only two
facilities in the United States that can handle imported fertilizer and provide
shipment west on railcars, and the acquisition of the facility positioned us to
take advantage of the increase in fertilizer imports that has resulted from the
recent decrease in domestic production.
129
(20) General Stevedores, L.P.
Effective July 31, 2005, we acquired all of the partnership interests in
General Stevedores, L.P. for an aggregate consideration of approximately $8.9
million, consisting of $2.0 million in cash, $3.4 million in common units, and
$3.5 million in assumed liabilities, including debt of $3.0 million. In August
2005, we paid the $3.0 million outstanding debt balance. General Stevedores,
L.P. owns, operates and leases barge unloading facilities located along the
Houston, Texas ship channel. Its operations primarily consist of receiving,
storing and transferring semi-finished steel products, including coils, pipe and
billets. The acquisition complemented and further expanded our existing Texas
Gulf Coast terminal facilities, and its operations are included as part of our
Terminals business segment. Our allocation of the purchase price to assets
acquired and liabilities assumed is preliminary, pending final determination of
working capital balances at the time of acquisition. We expect these final
working capital adjustments to be made in the first quarter of 2006.
(21) North Dayton Natural Gas Storage Facility
Effective August 1, 2005, we acquired a natural gas storage facility in
Liberty County, Texas, from Texas Genco LLC for an aggregate consideration of
approximately $109.4 million, consisting of $52.9 million in cash and $56.5
million in assumed debt. The facility, referred to as our North Dayton storage
facility, has approximately 6.3 billion cubic feet of total capacity, consisting
of 4.2 billion cubic feet of working capacity and 2.1 billion cubic feet of pad
(cushion) gas. The acquisition complemented our existing Texas intrastate
natural gas pipeline group assets and positioned us to pursue expansions at the
facility that will provide or offer needed services to utilities, the growing
liquefied natural gas industry along the Texas Gulf Coast, and other natural gas
storage users. Additionally, as part of the transaction, we entered into a
long-term storage capacity and transportation agreement with Texas Genco, one of
the largest wholesale electric power generating companies in the United States,
with over 13,000 megawatts of generation capacity. The agreement covers storage
services for approximately 2.0 billion cubic feet of natural gas capacity and
expires on March 1, 2017. The North Dayton storage facility's operations are
included in our Natural Gas Pipelines business segment.
Our allocation of the purchase price to assets acquired and liabilities assumed
is preliminary, based on a preliminary appraisal of fair market values. The
appraisal is expected to be finalized in the first quarter of 2006. The $26.0
million of goodwill was assigned to our Natural Gas Pipelines business segment
and the entire amount is expected to be deductible for tax purposes. We believe
our acquisition of the North Dayton natural gas storage facility resulted in the
recognition of goodwill primarily due to the fact that the favorable location
and the favorable association with our pre-existing assets contributed to the
fair value of acquired identifiable net assets and liabilities exceeding our
acquisition price - in the aggregate, these factors represented goodwill. The
$11.7 million of deferred charges and other assets in the table above represents
the fair value of the intangible long-term natural gas storage capacity and
transportation agreement
(22) August and September 2005 Terminal Assets
In August and September 2005, we acquired certain terminal facilities and
assets, including both real and personal property, in two separate transactions
for an aggregate consideration of approximately $4.3 million in cash. In August
2005, we spent $1.9 million to acquire the Kinder Morgan Blackhawk terminal from
White Material Handling, Inc., and in September 2005, we spent $2.4 million to
acquire a repair shop and related assets from Trans-Global Solutions, Inc. The
Kinder Morgan Blackhawk terminal consists of approximately 46 acres of land,
storage buildings, and related equipment located in Black Hawk County, Iowa. The
terminal primarily stores and transfers fertilizer and salt and further expanded
our Midwest region bulk terminal operations. The acquisition of the repair shop,
located in Jefferson County, Texas, near Beaumont, consists of real and personal
property, including parts inventory. The acquisition facilitated and expanded
the earlier acquisition of our Texas Petcoke terminals from Trans-Global
Solutions in April 2005. The operations of both acquisitions are included in our
Terminals business segment.
(23) Allied Terminal Assets
Effective November 4, 2005, we acquired certain terminal assets from Allied
Terminals, Inc. for an aggregate consideration of approximately $13.3 million,
consisting of $12.1 million in cash and $1.2 million in assumed liabilities. The
assets primarily consisted of storage tanks, loading docks, truck racks, land
and other equipment and personal property located adjacent to our Shipyard River
bulk terminal in Charleston, South Carolina. The acquisition complemented an
ongoing capital expansion project at our Shipyard River terminal that together,
will add infrastructure in order to increase the terminal's ability to handle
increasing supplies of imported coal. The
130
acquired assets are counted as an external addition to our Shipyard River
terminal and are included as part of our Terminals business segment.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the years ended December 31, 2005 and 2004, assumes that all of
the acquisitions we have made and joint ventures we have entered into since
January 1, 2004, including the ones listed above, had occurred as of January 1,
2004. 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 these
acquisitions and joint ventures as of January 1, 2004 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,
2005 2004
---------- ----------
(Unaudited)
Revenues.................................................................. $9,822,532 $8,143,720
Operating Income.......................................................... 1,026,579 1,047,099
Income Before Cumulative Effect of a Change in Accounting Principle....... 819,067 893,044
Net Income................................................................ $ 819,067 $ 893,044
Basic Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a Change in Accounting Principle..... $ 1.61 $ 2.48
Net Income.............................................................. $ 1.61 $ 2.48
Diluted Limited Partners' Net Income per unit:
Income Before Cumulative Effect of a Change in Accounting Principle..... $ 1.60 $ 2.47
Net Income.............................................................. $ 1.60 $ 2.47
Acquisitions Subsequent to December 31, 2005
Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega
Gas Pipeline LLC for $240.0 million in cash. We contributed $160.0 million,
which corresponded to our 66 2/3% ownership interest in Rockies Express Pipeline
LLC. Sempra Energy holds the remaining 33 1/3% ownership interest and
contributed $80.0 million. The Entrega Gas Pipeline is an interstate natural gas
pipeline that will consist of two segments: (i) a 136-mile, 36-inch diameter
pipeline that extends from the Meeker Hub in Rio Blanco County, Colorado to the
Wamsutter Hub in Sweetwater County, Wyoming, and (ii) a 191-mile, 42-inch
diameter pipeline that extends from the Wamsutter Hub to the Cheyenne Hub in
Weld County, Colorado, where it will ultimately connect with the Rockies Express
Pipeline. In combination, the Entrega and Rockies Express pipelines have the
potential to create a major new natural gas transmission pipeline that will
provide seamless transportation of natural gas from Rocky Mountain production
areas to Midwest and eastern Ohio markets. EnCana completed construction of the
first segment of the pipeline, and under the terms of the purchase and sale
agreement, we and Sempra will construct the second segment. It is anticipated
that the entire Entrega system will be placed into service by January 1, 2007.
Entrega's operations will be included as part of our Natural Gas Pipelines
business segment. This acquisition had no effect on our consolidated financial
statements during the periods covered by these financial statements.
4. Change in Accounting for Asset Retirement Obligations
We measure the future cost to retire our tangible long-lived assets and
recognize such cost as a liability in accordance with the provisions of 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
became effective for fiscal years beginning after June 15, 2002, and 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 was to change the method of accruing for oil and gas production site
restoration costs related to our CO2 business segment. Prior to January 1, 2003,
we accounted for asset retirement
131
obligations for our CO2 segment 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:
* a liability for any existing asset retirement obligations adjusted for
cumulative accretion to the date of adoption;
* an asset retirement cost capitalized as an increase to the carrying
amount of the associated long-lived asset; and
* accumulated depreciation on that capitalized cost.
Amounts resulting from initial application of this Statement were measured
using current information, current assumptions and current interest rates. The
amount recognized as an asset retirement cost was measured as of the date the
asset retirement obligation was incurred. Cumulative accretion and accumulated
depreciation was 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 $3.4 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 and gas
wells that have been removed from service and to remove our surface wellhead
equipment and compressors. As of December 31, 2005 and 2004, we have recognized
asset retirement obligations relating to these requirements at existing sites
within our CO2 segment in the aggregate amounts of $41.5 million and $34.7
million, respectively.
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 one inactive gas processing plant,
various 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, 2005 and 2004, we have
recognized asset retirement obligations relating to the businesses within our
Natural Gas Pipelines segment in the aggregate amounts of $1.7 million and $3.6
million, respectively.
We have included $0.8 million of our total asset retirement obligations as
of both December 31, 2005 and December 31, 2004 with "Accrued other current
liabilities" in our accompanying consolidated balance sheets. The remaining
$42.4 million obligation as of December 31, 2005 and $37.5 million obligation as
of December 31, 2004 are reported separately as non-current liabilities in our
accompanying consolidated balance sheets. 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 each of years ended December 31, 2005 and 2004 is as follows (in
thousands):
132
Year Ended December 31,
------------------------------
2005 2004
----------- -----------
Balance at beginning of period........ $ 38,274 $ 35,708
Liabilities incurred.................. 5,926 1,157
Liabilities settled................... (1,778) (672)
Accretion expense..................... 1,327 2,081
Revisions in estimated cash flows..... (522) -
----------- -----------
Balance at end of period.............. $ 43,227 $ 38,274
=========== ===========
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,
-------------------------------
2005 2004 2003
-------- -------- --------
Taxes currently payable:
Federal............. $ 9,604 $ 7,515 $ 437
State............... 2,112 1,497 1,131
Foreign............. 322 70 25
-------- -------- --------
Total............... 12,038 9,082 1,593
Taxes deferred:
Federal............. 8,159 5,694 11,650
State............... 769 883 1,939
Foreign............. 3,495 4,067 1,449
-------- -------- --------
Total............... 12,423 10,644 15,038
-------- -------- --------
Total tax provision... $ 24,461 $ 19,726 $ 16,631
======== ======== ========
Effective tax rate.... 2.9% 2.3% 2.3%
The difference between the statutory federal income tax rate and our
effective income tax rate is summarized as follows:
Year Ended December 31,
----------------------------
2005 2004 2003
------- ------- -------
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.......... 1.1% 0.5% 0.5%
Income tax expense attributable to corporate
equity earnings...................................... 1.1% 1.2% 1.5%
Income tax expense attributable to foreign corporate
earnings............................................. 0.5% 0.5% 0.2%
State taxes........................................... 0.2% 0.1% 0.1%
------- ------- -------
Effective tax rate...................................... 2.9% 2.3% 2.3%
======= ======= =======
Deferred tax assets and liabilities result from the following (in
thousands):
December 31,
-----------------
2005 2004
-------- -------
Deferred tax assets:
Book accruals.................................... $ 1,112 $ 1,349
Net Operating Loss/Alternative minimum tax
credits......................................... 1,548 7,138
Other............................................ 1,445 1,472
-------- -------
Total deferred tax assets.......................... 4,105 9,959
Deferred tax liabilities:
Property, plant and equipment.................... 63,562 59,277
Other............................................ 10,886 7,169
-------- -------
Total deferred tax liabilities..................... 74,448 66,446
-------- -------
Net deferred tax liabilities....................... $ 70,343 $56,487
======== =======
We had available, at December 31, 2005, approximately $0.09 million of
foreign minimum tax credit carryforwards, which are available through 2014, and
$1.5 million of foreign and state net operating loss
133
carryforwards, which will expire between the years 2007 and 2024. 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,
------------------------
2005 2004
----------- -----------
Natural gas, liquids and carbon dioxide pipelines........... $ 4,005,612 $ 3,903,021
Natural gas, liquids and carbon dioxide pipeline station
equipment................................................. 4,146,328 3,443,817
Coal and bulk tonnage transfer, storage and services........ 131,265 512,024
Natural gas, liquids and transmix processing................ 187,061 105,375
Other....................................................... 625,615 511,787
Accumulated depreciation and depletion...................... (1,242,304) (947,660)
----------- -----------
7,853,577 7,528,364
Land and land right-of-way.................................. 440,497 371,172
Construction work in process................................ 570,510 269,144
----------- -----------
Property, Plant and Equipment, net.......................... $ 8,864,584 $ 8,168,680
=========== ===========
Depreciation and depletion expense charged against property, plant and
equipment consists of the following (in thousands):
2005 2004 2003
-------- -------- --------
Depreciation and depletion expense.. $339,580 $285,351 $217,401
7. Investments
Our significant equity investments as of December 31, 2005 consisted of:
* Plantation Pipe Line Company (51%);
* Red Cedar Gathering Company (49%);
* Thunder Creek Gas Services, LLC (25%);
* Coyote Gas Treating, LLC (Coyote Gulch) (50%);
* Cortez Pipeline Company (50%); and
* Heartland Pipeline Company (50%).
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.
In September 2003, we paid $10.0 million to acquire reversionary interests
in the Red Cedar 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 reversionary
interests, our ownership interest in Red Cedar will be maintained at 49% in the
future. For more information on this acquisition, see Note 3.
Also, on January 1, 2003, Kinder Morgan CO2 Company, L.P. owned a 15%
interest in MKM Partners, L.P., a joint venture with Marathon Oil Company. The
remaining 85% interest in MKM Partners was owned by subsidiaries of Marathon Oil
Company. The joint venture assets consisted of a 12.75% interest in the SACROC
oil
134
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, and 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. Currently,
our approximate 97% working interest in the SACROC field unit and our
approximate 50% working interest in 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. For more
information on this acquisition, see Note 3.
Our total investments consisted of the following (in thousands):
December 31,
--------------------
2005 2004
-------- --------
Plantation Pipe Line Company................... $213,072 $216,142
Red Cedar Gathering Company.................... 139,852 124,209
Thunder Creek Gas Services, LLC................ 37,254 37,122
Cortez Pipeline Company........................ 17,938 15,503
Coyote Gas Treating, LLC....................... -- 12,964
Heartland Pipeline Company..................... 5,205 5,106
All Others..................................... 5,992 2,209
-------- --------
Total Equity Investments....................... $419,313 $413,255
======== ========
Our earnings from equity investments were as follows (in thousands):
Year Ended December 31,
-------------------------------
2005 2004 2003
-------- -------- --------
Cortez Pipeline Company............. $ 26,319 $ 34,179 $ 32,198
Plantation Pipe Line Company........ 24,926 25,879 27,983
Red Cedar Gathering Company......... 32,000 14,679 18,571
Thunder Creek Gas Services, LLC..... 2,741 2,828 2,833
Coyote Gas Treating, LLC............ 2,071 2,453 2,608
Heartland Pipeline Company.......... 2,122 1,369 973
MKM Partners, L.P................... - - 5,000
All Others.......................... 1,481 1,803 2,033
-------- -------- --------
Total............................... $ 91,660 $ 83,190 $ 92,199
======== ======== ========
Amortization of excess costs........ $ (5,644) $ (5,575) $ (5,575)
======== ======== ========
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 2005 2004 2003
- ------------------------------- -------- -------- --------
Revenues.................................... $448,382 $418,186 $467,871
Costs and expenses.......................... 282,317 265,819 295,931
-------- -------- --------
Earnings before extraordinary items and
cumulative effect of a change in
accounting principle....,,............... 166,065 152,367 171,940
======== ======== ========
Net income.................................. $166,065 $152,367 $168,167
======== ======== ========
December 31,
----------------------
Balance Sheet 2005 2004
--------------------- ---------- ----------
Current assets............ $ 107,975 $ 107,954
Non-current assets........ 680,330 696,493
Current liabilities....... 182,549 218,922
Non-current liabilities... 345,227 364,406
Partners'/owners' equity.. $ 260,529 $ 221,119
135
8. Intangibles
Our intangible assets include goodwill, lease value, contracts, customer
relationships and agreements. Excluding goodwill, our other intangible assets
have definite lives, are being amortized on a straight-line basis over their
estimated useful lives, and are reported separately as "Other intangibles, net"
in our accompanying consolidated balance sheets. Following is information
related to our intangible assets subject to amortization and our goodwill (in
thousands):
December 31,
-----------------------
2005 2004
----------- ---------
Goodwill
Gross carrying amount...... $ 813,101 $ 746,980
Accumulated amortization... (14,142) (14,142)
----------- ---------
Net carrying amount........ 798,959 732,838
----------- ---------
Lease value
Gross carrying amount...... 6,592 6,592
Accumulated amortization... (1,168) (1,028)
----------- ---------
Net carrying amount........ 5,424 5,564
----------- ---------
Contracts and other
Gross carrying amount...... 221,250 10,775
Accumulated amortization... (9,654) (1,055)
----------- ---------
Net carrying amount........ 211,596 9,720
----------- ---------
Total intangibles, net..... $ 1,015,979 $ 748,122
=========== =========
Amortization expense on our intangibles consists of the following (in
thousands):
Year Ended December 31,
-----------------------------
2005 2004 2003
-------- ------- --------
Lease value.............. $ 140 $ 140 $ 140
Contracts and other...... 8,599 752 64
-------- ------- --------
Total amortization....... $ 8,739 $ 892 $ 204
======== ======= ========
In April 2005, we acquired certain bulk terminal operations from
Trans-Global Solutions, Inc. for an aggregate consideration of approximately
$247.2 million. The allocation of our purchase price included the recording of
intangible customer relationships at a fair value of $161.4 million. These
intangibles are included in "Contracts and other" in the above tables and their
fair value was based on an appraisal report of fair market values. The
intangibles are being amortized to expense over their expected useful economic
lives. For more information on this acquisition, see Note 3.
As of December 31, 2005, our weighted average amortization period for our
intangible assets is approximately 19.75 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$12.6 million, $12.3 million, $12.2 million, $12.0 million and $11.8 million,
respectively.
Goodwill
As an investor, the price we pay to acquire an ownership interest in an
investee will most likely differ from the underlying interest in book value,
with book value representing the investee's net assets per its financial
statements. This differential relates to both discrepancies between the
investee's recognized net assets at book value and at current fair values and to
any premium we pay to acquire the investment. Under ABP No. 18, any such premium
paid by an investor, which is analogous to goodwill, must be identified.
For our investments in affiliated entities that are included in our
consolidation, the excess cost over underlying fair value of net assets is
referred to as goodwill and reported separately as "Goodwill" in our
accompanying consolidated balance sheets. Under SFAS No. 142, goodwill is not
subject to amortization but must be tested for impairment at least annually.
This test requires goodwill to be assigned to an appropriate reporting unit and
to determine if the implied fair value of the reporting unit's goodwill is less
than its carrying amount.
136
Changes in the carrying amount of our goodwill for each of the two years
ended December 31, 2004 and 2005 are summarized as follows (in thousands):
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
----------- ----------- ----------- ----------- -----------
Balance as of December 31, 2003..... $ 263,182 $ 253,358 $ 46,101 $ 166,869 $ 729,510
Acquisitions...................... - - - 6,368 6,368
Purchase price adjustments........ - (3,040) - - (3,040)
Impairments....................... - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of December 31, 2004..... $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838
Acquisitions and purchase price - 38,117 - 28,004 66,121
adjs................................
Disposals......................... - - - - -
Impairments....................... - - - - -
----------- ----------- ----------- ----------- -----------
Balance as of December 31, 2005..... $ 263,182 $ 288,435 $ 46,101 $ 201,241 $ 798,959
=========== =========== =========== =========== ===========
Equity Method Goodwill
For the investments we account for under the equity method, this premium or
excess cost over underlying fair value of net assets, is referred to as equity
method goodwill and under SFAS No. 142, is not subject to amortization but
rather to impairment testing pursuant to APB 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. Therefore, 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 accounted for under the equity method, 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 caption
"Investments" in our accompanying consolidated balance sheets includes equity
method goodwill of $138.2 million as of December 31, 2005 and $150.3 million as
of December 31, 2004.
9. Debt
Our debt and credit facility as of December 31, 2005, consisted primarily
of:
* a $1.6 billion unsecured five-year credit facility due August 18,
2010;
* $250 million of 5.35% Senior Notes due August 15, 2007;
* $15 million of 7.84% Senior Notes, with a final maturity of July 23,
2008 (our subsidiary, Central Florida Pipe Line LLC, is the obligor on
the notes);
* $250 million of 6.30% Senior Notes due February 1, 2009;
* $5.3 million of Illinois Development Revenue Bonds due January 1, 2010
(our subsidiary, Arrow Terminals L.P., is the obligor on the bonds);
* $250 million of 7.50% Senior Notes due November 1, 2010;
* $700 million of 6.75% Senior Notes due March 15, 2011;
* $450 million of 7.125% Senior Notes due March 15, 2012;
* $500 million of 5.00% Senior Notes due December 15, 2013;
* $54.7 million of 5.23% Senior Notes, with a final maturity of January
2, 2014 (our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the
obligor on the notes);
* $500 million of 5.125% Senior Notes due November 15, 2014;
137
* $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);
* $23.7 million of tax-exempt bonds due April 1, 2024 (our subsidiary,
Kinder Morgan Operating L.P. "B," is the obligor on the bonds);
* $40 million of Plaquemines, Louisiana Port, Harbor, and Terminal
District Revenue Bonds due March 15, 2025 (our 66 2/3% owned
subsidiary, International Marine Terminals, is the obligor on the
bonds);
* $300 million of 7.40% Senior Notes due March 15, 2031;
* $300 million of 7.75% Senior Notes due March 15, 2032;
* $500 million of 7.30% Senior Notes due August 15, 2033;
* $500 million of 5.80% Senior Notes due March 15, 2035; and
* a $1.6 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).
Our outstanding short-term debt as of December 31, 2005 was $575.6 million.
The balance consisted of:
* $566.2 million of commercial paper borrowings;
* a $5.6 million portion of 5.23% Senior Notes (our subsidiary, Kinder
Morgan Texas Pipeline, L.P., is the obligor on the notes);
* a $5 million portion of 7.84% Senior Notes (our subsidiary, Central
Florida Pipe Line LLC, is the obligor on the notes); and
* an offset of $1.2 million (which represents the net of other
borrowings and the accretion of discounts on our senior note
issuances).
As of December 31, 2005, we intended and had the ability to refinance all of
our short-term debt on a long-term basis under our unsecured long-term credit
facility. Accordingly, such amounts have been classified as long-term debt in
our accompanying consolidated balance sheet. The weighted average interest rate
on all of our borrowings was approximately 5.0513% during 2005 and 4.4702%
during 2004.
Credit Facilities
On August 18, 2004, we replaced our existing bank credit facilities,
consisting of 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, with a $1.25 billion five-year, unsecured revolving credit facility due
August 18, 2009. There were no borrowings under our five-year credit facility as
of December 31, 2004.
On August 5, 2005, we increased our existing bank facility from $1.25
billion to $1.6 billion, and we extended the maturity one year to August 18,
2010. Similar to our previous credit facilities, our current credit facility is
with a syndicate of financial institutions and Wachovia Bank, National
Association is the administrative agent. The borrowing rates decreased slightly
under the extended agreement, and there were minor changes to the financial
covenants as compared to the covenants under our previous bank facility.
There were no borrowings under our five-year credit facility as of December
31, 2005. The amount available for borrowing under our credit facility as of
December 31, 2005 was reduced by:
* our outstanding commercial paper borrowings ($566.2 million as of
December 31, 2005);
138
* a combined $534 million in five letters of credit that support our
hedging of commodity price risks associated with the sale of natural
gas, natural gas liquids, oil and carbon dioxide;
* a combined $49 million in two letters of credit that support
tax-exempt bonds; and
* $16.3 million of other letters of credit supporting other obligations
of us and our subsidiaries.
Our five-year credit facility permits us to obtain bids for fixed rate loans
from members of the lending syndicate. Interest on our credit facility accrues
at our option at a floating rate equal to either:
* the administrative agent's base rate (but not less than the Federal
Funds Rate, plus 0.5%); or
* LIBOR, plus a margin, which varies depending upon the credit rating of
our long-term senior unsecured debt.
Our credit facility included the following restrictive covenants as of
December 31, 2005:
* requirements to maintain certain financial ratios:
* total debt divided by earnings before interest, income taxes,
depreciation and amortization for the preceding four quarters may
not exceed 5.0;
* total indebtedness of all consolidated subsidiaries shall at no
time exceed 15% of consolidated indebtedness; and
* consolidated indebtedness shall at no time exceed 65% of total
capitalization;
* certain limitations on entering into mergers, consolidations and sales
of assets;
* limitations on granting liens; and
* prohibitions on making any distribution to holders of units if an
event of default exists or would exist upon making such distribution.
In addition to normal repayment covenants, under the terms of our credit
facility, the occurrence at any time of any of the following would constitute an
event of default:
* our failure to make required payments of any item of indebtedness or
any payment in respect of any hedging agreement, provided that the
aggregate outstanding principal amount for all such indebtedness or
payment obligations in respect of all hedging agreements is equal to
or exceeds $75 million;
* our general partner's failure to make required payments of any item of
indebtedness, provided that the aggregate outstanding principal amount
for all such indebtedness is equal to or exceeds $75 million;
* adverse judgments rendered against us for the payment of money in an
aggregate amount in excess of $75 million, if this same amount remains
undischarged for a period of thirty consecutive days during which
execution shall not be effectively stayed; and
* voluntary or involuntary commencements of any proceedings or petitions
seeking our liquidation, reorganization or any other similar relief
under any federal, state or foreign bankruptcy, insolvency,
receivership or similar law.
Excluding the relatively non-restrictive specified negative covenants and
events of defaults, our credit facility does not contain any provisions designed
to protect against a situation where a party to an agreement is unable to find a
basis to terminate that agreement while its counterparty's impending financial
collapse is revealed and perhaps hastened through the default structure of some
other agreement. The credit facility does not contain a material adverse change
clause coupled with a lockbox provision; however, the facility does provide that
the margin
139
we will pay with respect to borrowings and the facility fee that we will pay on
the total commitment will vary based on our senior debt investment rating. None
of our debt is subject to payment acceleration as a result of any change to our
credit ratings.
In addition, on February 22, 2006, we entered into a second credit facility:
a $250 million unsecured nine month credit facility that matures November 21,
2006. This new credit facility includes covenants and requires payment of
facility fees that are similar in nature to the covenants and facility fees
required by our five-year credit facility as discussed above.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 14.
Commercial Paper Program
On October 15, 2004, we increased our commercial paper program by $200
million to provide for the issuance of up to $1.25 billion. As of December 31,
2004, we had $416.9 million of commercial paper outstanding with an average
interest rate of 2.2856%.
On August 5, 2005, we increased our commercial paper program by $350 million
to provide for the issuance of up to $1.6 billion. Our $1.6 billion unsecured
five-year credit facility supports our commercial paper program, and borrowings
under our commercial paper program reduce the borrowings allowed under our
credit facility. As of December 31, 2005, we had $566.2 million of commercial
paper outstanding with an average interest rate of 4.3184%. The borrowings under
our commercial paper program were used principally to finance the acquisitions
and capital expansions we made during 2004 and 2005.
Senior Notes
On November 12, 2004, we closed a public offering of $500 million in
principal amount of 5.125% senior notes due November 15, 2014 at a price to the
public of 99.914% per note. In the offering, we received proceeds, net of
underwriting discounts and commissions, of approximately $496.3 million. We used
the proceeds to reduce the outstanding balance on our commercial paper
borrowings.
On March 15, 2005, we paid $200 million to retire the principal amount
of our 8.0% senior notes that matured on that date. Also on March 15, 2005, we
closed a public offering of $500 million in principal amount of 5.80% senior
notes due March 15, 2035 at a price to the public of 99.746% per note. In the
offering, we received proceeds, net of underwriting discounts and commissions,
of approximately $494.4 million. We used the proceeds remaining after the
repayment of the 8.0% senior notes to reduce the outstanding balance on our
commercial paper borrowings.
As of December 31, 2005, the outstanding balance on the various series of
our senior notes was as follows (in millions):
5.35% senior notes due August 15, 2007..... $ 249.9
6.30% senior notes due February 1, 2009.... 249.7
7.50% senior notes due November 1, 2010.... 249.2
6.75% senior notes due March 15, 2011...... 698.9
7.125% senior notes due March 15, 2012..... 448.7
5.00% senior notes due December 15, 2013... 497.5
5.125% senior notes due November 15, 2014.. 499.6
7.40% senior notes due March 15, 2031...... 299.4
7.75% senior notes due March 15, 2032...... 298.7
7.30% senior notes due August 15, 2033..... 499.1
5.80% senior notes due March 15, 2035...... 498.8
---------
Total.................................... $ 4,489.5
=========
140
Kinder Morgan Wink Pipeline, L.P. Debt
Effective August 31, 2004, we acquired all of the partnership interests in
Kaston Pipeline Company, L.P., which we renamed Kinder Morgan Wink Pipeline,
L.P. (see Note 3). As part of our purchase price, we assumed Kaston's $9.5
million note payable to Western Refining Company, L.P. In September 2004, we
paid the $9.5 million outstanding balance under the note, and following our
repayment of the note, Kinder Morgan Wink Pipeline, L.P. had no outstanding
debt.
International Marine Terminals Debt
Since February 1, 2002, we have owned a 66 2/3% interest in International
Marine Terminals partnership. The principal assets owned by IMT are dock and
wharf facilities financed by the Plaquemines Port, Harbor and Terminal District
(Louisiana) $40,000,000 Adjustable Rate Annual Tender Port Facilities Revenue
Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B.
As of December 31, 2005, the interest rate on these bonds was 2.6%.
On March 15, 2005, these bonds were refunded and the maturity date was
extended from March 15, 2006 to March 15, 2025. No other changes were made under
the bond provisions. 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.
Central Florida Pipeline LLC Debt
Effective January 1, 2001, we acquired Central Florida Pipeline LLC. As part
of our purchase price, we assumed an aggregate principal amount of $40 million
of senior notes originally issued to a syndicate of eight insurance companies.
The senior notes have a fixed annual interest rate of 7.84% with repayments in
annual installments of $5 million beginning July 23, 2001. The final payment is
due July 23, 2008. Interest is payable semiannually on January 1 and July 23 of
each year. In both July 2004 and July 2005, we made an annual repayment of $5.0
million and as of December 31, 2005, Central Florida's outstanding balance under
the senior notes was $15.0 million.
Kinder Morgan River Terminals LLC
Effective October 6, 2004, we acquired Global Materials Services LLC and its
consolidated subsidiaries (see Note 3). We renamed Global Materials Services LLC
as Kinder Morgan River Terminals LLC, and as part of our purchase price, we
assumed debt of $33.7 million, consisting of third-party notes payables, current
and non-current bank borrowings, and long-term bonds payable. In October 2004,
we paid $28.4 million of the assumed debt and following these repayments, the
only remaining outstanding debt was a $5.3 million principal amount of
Adjustable Rate Industrial Development Revenue Bonds issued by the Illinois
Development Finance Authority. Our subsidiary, Arrow Terminals L.P., is the
obligor on these bonds. The bonds have a maturity date of January 1, 2010, and
interest on these bonds is paid and computed quarterly at the Bond Market
Association Municipal Swap Index. The bonds are collateralized by a first
mortgage on assets of Arrow's Chicago operations and a third mortgage on assets
of Arrow's Pennsylvania operations. As of December 31, 2005, the interest rate
was 3.157%. The bonds are also backed by a $5.4 million letter of credit issued
by JP Morgan Chase that backs-up the $5.3 million principal amount of the bonds
and $0.1 million of interest on the bonds for up to 45 days computed at 12% per
annum on the principal amount thereof.
Kinder Morgan Texas Pipeline, L.P. Debt
Effective August 1, 2005, we acquired a natural gas storage facility in
Liberty County, Texas (see Note 3). As part of our purchase price, we assumed
debt having a fair value of $56.5 million. We valued the debt equal to the
present value of amounts to be paid determined using an approximate interest
rate of 5.23%. The debt consisted of privately placed unsecured senior notes
with a fixed annual stated interest rate as of August 1, 2005, of 8.85%. The
assumed principal amount, along with interest, is due in monthly installments of
approximately $0.7 million. The
141
final payment is due January 2, 2014. Our subsidiary, Kinder Morgan Texas
Pipeline, L.P., is the obligor on the notes, and as of December 31, 2005, KMTP's
outstanding balance under the senior notes was $54.7 million.
Additionally, the unsecured senior notes may be prepaid at any time in
amounts of at least $1.0 million at a price equal to the higher of par value or
the present value of the remaining scheduled payments of principal and interest
on the portion being prepaid. The notes also contain certain covenants similar
to those contained in our current five-year, unsecured revolving credit
facility. We do not believe that these covenants will materially affect
distributions to our partners.
Kinder Morgan Liquids Terminals LLC Debt
Effective January 1, 2001, we acquired Kinder Morgan Liquids Terminals LLC.
As part of our purchase price, we assumed debt of $87.9 million, consisting of
five series of tax-exempt industrial revenue bonds. Kinder Morgan Liquids
Terminals LLC was the obligor on the bonds, which consisted of the following:
* $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due
September 1, 2019;
* $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,
2022;
* $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due
September 1, 2022;
* $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,
2023; and
* $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,
2024.
In May 2004, we exercised our right to call and retire all of the industrial
revenue bonds (other than the $3.6 million of 6.625% bonds due February 1, 2024)
prior to maturity at a redemption price of $84.3 million, plus approximately
$1.9 million for interest, prepayment premiums and redemption fees. In October
2004, we exercised our right to call and retire the remaining $3.6 million of
bonds due February 1, 2024 prior to maturity at a redemption price of $3.6
million, plus approximately $0.1 million for interest, prepayment premiums and
redemption fees. For both of these redemptions and retirements, we borrowed the
necessary funds under our commercial paper program. Pursuant to Accounting
Principles Board Opinion No. 26, "Early Extinguishment of Debt," we recognized
the $1.6 million excess of our reacquisition price over both the carrying value
of the bonds and unamortized debt issuance costs as a loss on bond repurchases
and we included this amount under the caption "Other, net" in our accompanying
consolidated statement of income.
In November 2001, we acquired a liquids terminal in Perth Amboy, New Jersey
from Stolthaven Perth Amboy Inc. and Stolt-Nielsen Transportation Group, Ltd. As
part of our purchase price, we assumed $25.0 million of Economic Development
Revenue Refunding Bonds issued by the New Jersey Economic Development Authority.
These bonds have a maturity date of January 15, 2018. Interest on these bonds is
computed on the basis of a year of 365 or 366 days, as applicable, for the
actual number of days elapsed during Commercial Paper, Daily or Weekly Rate
Periods and on the basis of a 360-day year consisting of twelve 30-day months
during a Term Rate Period. As of December 31, 2005, the interest rate was
2.933%. 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.
Kinder Morgan Operating L.P. "B" Debt
This $23.7 million principal amount of tax-exempt bonds due April 1, 2024
was issued by the Jackson-Union Counties Regional Port District. These bonds
bear interest at a weekly floating market rate. As of December 31, 2005, the
interest rate on these bonds was 3.134%. As of December 31, 2005, we had an
outstanding letter of credit issued by Wachovia in the amount of $24.1 million
that backs-up the $23.7 million principal amount of the bonds and $0.4 million
of interest on the bonds for up to 55 days computed at 12% per annum on the
principal amount thereof. The letter of credit that supports these tax-exempt
bonds was issued under our credit facility and reduces the amount available for
borrowing under our credit facility.
142
General Stevedores, L.P. Debt
Effective July 31, 2005, we acquired all of the partnership interests in
General Stevedores, L.P. (see Note 3). As part of our purchase price, we assumed
approximately $3.0 million in principal amount of outstanding debt, primarily
consisting of commercial bank loans. In August 2005, we paid the $3.0 million
outstanding debt balance, and following our repayment, General Stevedores, L.P.
had no outstanding debt.
Maturities of Debt
The scheduled maturities of our outstanding debt, excluding market value of
interest rate swaps, as of December 31, 2005, are summarized as follows (in
thousands):
2006........ $ 575,601
2007........ 259,714
2008........ 10,053
2009........ 255,463
2010........ 261,172
Thereafter.. 3,858,884
----------
Total....... $5,220,887
==========
Fair Value of Financial Instruments
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. 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, 2005 and
December 31, 2004 and is disclosed below.
December 31, 2005 December 31, 2004
----------------------- ------------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
---------- ---------- ---------- ----------
(In thousands)
Total Debt $5,220,887 $5,465,215 $4,722,410 $5,139,747
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 Kinder Morgan, Inc. Retirement
Plan. The benefits under this plan are based primarily upon years of service and
final average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.
Net periodic benefit costs and weighted-average assumptions for these plans
include the following components (in thousands):
Other Post-retirement Benefits
----------------------------------
2005 2004 2003
------- ------- ------
Net periodic benefit cost
Service cost...................... $ 9 $ 111 $ 41
Interest cost..................... 310 389 807
Expected return on plan assets.... -- -- --
Amortization of prior service cost (117) (125) (622)
Actuarial (gain).................. (511) (976) --
------- ------- ------
Net periodic benefit cost......... $ (309) $ (601) $ 226
======= ======= ======
143
Other Post-retirement Benefits
--------------------------------
2005 2004 2003
------- ------- -------
Additional amounts recognized
Curtailment (gain) loss......... $ -- $ -- $ --
Weighted-average assumptions as of
December 31:
Discount rate..................... 5.25% 5.75% 6.00%
Expected return on plan assets.... -- -- --
Rate of compensation increase..... 3.9% 3.9% 3.9%
The discount rate was set by Burlington Northern Santa Fe, the parent of the
former general partner of SFPP, L.P., using information for its benefit plans.
BNSF based the discount rate on the Moody's Investor Services' Aa corporate bond
yield adjusted to reflect the difference between the duration of its plan's cash
flows and the duration of the Moody's Aa index.
Information concerning benefit obligations, plan assets, funded status and
recorded values for these plans follows (in thousands):
Other Post-retirement
Benefits
--------------------------
2005 2004
-------- --------
Change in benefit obligation
Benefit obligation at Jan. 1........ $ 5,555 $ 6,176
Service cost........................ 9 111
Interest cost....................... 310 389
Participant contributions........... 158 166
Amendments.......................... -- (207)
Actuarial (gain) loss............... (76) (632)
Benefits paid from plan assets...... (667) (448)
-------- --------
Benefit obligation at Dec. 31....... $ 5,289 $ 5,555
======== ========
Change in plan assets
Fair value of plan assets at Jan. 1. $ -- $ --
Actual return on plan assets........ -- --
Employer contributions.............. 509 282
Participant contributions........... 158 166
Benefits paid from plan assets...... (667) (448)
-------- --------
Fair value of plan assets at Dec. 31 $ -- $ --
======== ========
Funded status....................... $ (5,289) $ (5,555)
Unrecognized net actuarial (gain) loss (5,949) (6,383)
Unrecognized prior service (benefit) (592) (710)
Adj. for 4th qtr. employer 104 91
-------- --------
contributions.......................
Accrued benefit cost................ $(11,726) $(12,557)
======== ========
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, a 10.5% annual rate of increase in the per capita cost of
covered health care benefits was assumed for 2006. The rate was assumed to
decrease gradually to 5% by 2012 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):
1-Percentage 1-Percentage
Point Increase Point Decrease
-------------- --------------
Effect on total of service and interest
cost components............................. $ 33 $ (28)
Effect on postretirement benefit
obligation.................................. $ 498 $ (423)
144
Amounts recognized in our consolidated balance sheets consist of (in
thousands):
As of December 31,
-------------------------
2005 2004
---------- ----------
Prepaid benefit cost............................. $ - $ -
Accrued benefit liability........................ (11,726) (12,557)
Intangible asset................................. - -
Accumulated other comprehensive income........... - -
---------- ----------
Net amount recognized as of Dec. 31............ $ (11,726) $ (12,557)
========== ==========
We expect to contribute approximately $0.3 million to our post-retirement
benefit plans in 2006. The following benefit payments, which reflect expected
future service, as appropriate, are expected to be paid (in thousands):
Other Post-retirement Benefits
--------------------------------
2006............. $ 337
2007.............. 337
2008.............. 330
2009.............. 340
2010.............. 343
2011-2015......... 1,672
-----------
Total............. $ 3,359
===========
Multiemployer Plans
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 $6.3 million for the year ended
2005 and $5.5 million for the year ended 2004.
Kinder Morgan Savings Plan
The Kinder Morgan Savings Plan is a defined contribution 401(k) plan. The
plan permits all full-time employees of Kinder Morgan, Inc. and KMGP Services
Company, Inc. 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, 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 generally 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. Participants
may direct the investment of their contributions into a variety of investments.
Plan assets are held and distributed pursuant to a trust agreement.
For employees hired on or prior to December 31, 2004, all contributions,
together with earnings thereon, are immediately vested and not subject to
forfeiture. Employer contributions for employees hired on or after January 1,
2005 will vest on the second anniversary of the date of hire. Effective October
1, 2005, for new employees of our Terminals segment, a tiered employer
contribution schedule was implemented. This tiered schedule provides for
employer contributions of 1% for service less than one year, 2% for service
between one and two years, 3% for services between two and five years, and 4%
for service of five years or more. All employer contributions for Terminal
employees hired after October 1, 2005 will vest on the fifth anniversary of the
date of hire.
At its July 2005 meeting, the compensation committee of the KMI board of
directors approved a special contribution of an additional 1% of base pay into
the Savings Plan for each eligible employee. Each eligible employee will receive
an additional 1% company contribution based on eligible base pay each pay period
beginning with the first pay period of August 2005 and continuing through the
last pay period of July 2006. The additional 1% contribution is in the form of
KMI common stock (the same as the current 4% contribution) and does not change
or
145
otherwise impact, the annual 4% contribution that eligible employees currently
receive. It may be converted to any other Savings Plan investment fund at any
time and it will vest on the second anniversary of the employee's date of hire.
Since this additional 1% company contribution is discretionary, compensation
committee approval will be required annually for each additional contribution.
During the first quarter of 2006, excluding the 1% additional contribution
described above, we will not make any additional discretionary contributions to
individual accounts for 2005.
The total amount charged to expense for our Savings Plan was $7.9 million
during 2005 and $6.5 million during 2004. 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.
Cash Balance Retirement Plan
Employees of KMGP Services Company, Inc. and KMI are also 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 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 on January 1,
2001, 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 discretionary contributions
were made for 2005 performance. Interest is credited to the personal 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, 2005 and 2004, our partners' capital consisted of the
following limited partner units:
December 31, December 31,
----------- -----------
2004 2005
----------- -----------
Common units.................. 157,005,326 147,537,908
Class B units................. 5,313,400 5,313,400
i-units....................... 57,918,373 54,157,641
----------- ----------
Total limited partner units. 220,237,099 207,008,949
=========== ===========
The total limited partner units represent our limited partners' interest, 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, 2005, our common unit total consisted of 142,649,591
units held by third parties, 12,631,735 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, 2004, our common unit total consisted of 133,182,173
units held by third parties, 12,631,735 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.
All of our Class B units were issued in December 2000 to KMI. The Class B
units are similar to our common units except that they are not eligible for
trading on the New York Stock Exchange.
146
Our 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 us, and controlling and managing our business and affairs and
the business and affairs of our operating limited partnerships and their
subsidiaries. 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.
Under the terms of our partnership agreement, we agreed that we will not,
except in liquidation, make a distribution on an i-unit other than in additional
i-units or a security that has in all material respects the same rights and
privileges as our i-units. The number of i-units we distribute to KMR is based
upon the amount of cash we distribute to the owners of our common units. When
cash is paid to the holders of our common units, we will issue additional
i-units to KMR. The fraction of an i-unit paid per i-unit owned by KMR will have
a value based on 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 932,292 i-units on November 14, 2005.
These additional i-units distributed were based on the $0.79 per unit
distributed to our common unitholders on that date. During the year ended
December 31, 2005, KMR received distributions of 3,760,732 i-units. These
additional i-units distributed were based on the $3.07 per unit distributed to
our common unitholders during 2005.
Equity Issuances
On February 9, 2004, we issued, in a public offering, 5,300,000 of our
common units at a price of $46.80 per unit, less commissions and underwriting
expenses. After commissions and underwriting expenses, we received net proceeds
of $237.8 million for the issuance of these common units.
On March 25, 2004, KMR issued 360,664 of its shares at a price of $41.59 per
share, less closing fees and commissions. The net proceeds from the offering
were used to buy additional i-units from us. After closing and commission
expenses, we received net proceeds of $14.9 million for the issuance of 360,664
i-units.
On November 10, 2004, we issued, in a public offering, 5,500,000 of our
common units. On December 8, 2004, we issued an additional 575,000 units upon
exercise by the underwriters of an over-allotment option. We issued these
6,075,000 units at a price of $46.00 per unit, less commissions and underwriting
expenses. After commissions and underwriting expenses, we received net proceeds
of $268.3 million for the issuance of these common units.
On November 10, 2004, KMR issued 1,300,000 of its shares at a price of
$41.29 per share, less closing fees and commissions. The net proceeds from the
offering were used to buy additional i-units from us. We received proceeds of
$52.6 million for the issuance of 1,300,000 i-units.
On August 16, 2005, we issued, in a public offering, 5,000,000 of our common
units at a price of $51.25 per unit, less commissions and underwriting expenses.
At the time of the offering, we granted the underwriters a 30-day option to
purchase up to an additional 750,000 common units from us on the same terms and
conditions, and pursuant to this option, we issued an additional 750,000 common
units on September 9, 2005 upon exercise of this option. After commissions and
underwriting expenses, we received net proceeds of $283.6 million for the
issuance of these 5,750,000 common units.
On November 8, 2005, we issued, in a public offering, 2,600,000 of our
common units at a price of $51.75 per unit, less commissions and underwriting
expenses. After commissions and underwriting expenses, we received net proceeds
of $130.1 million for the issuance of these common units.
We used the proceeds from each of these six issuances to reduce the
borrowings under our commercial paper program.
147
Income Allocation and Declared Distributions
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, 2005, 2004 and 2003, we declared
distributions of $3.13, $2.87 and $2.63 per unit, respectively. Our
distributions to unitholders for 2005, 2004 and 2003 required incentive
distributions to our general partner in the amount of $473.9 million, $390.7
million and $322.8 million, respectively. The increased incentive distributions
paid for 2005 over 2004 and 2004 over 2003 reflect the increase in amounts
distributed per unit as well as the issuance of additional units. Distributions
for the fourth quarter of each year are declared and paid during the first
quarter of the following year.
On January 18, 2006, we declared a cash distribution of $0.80 per unit for
the quarterly period ended December 31, 2005. This distribution was paid on
February 14, 2006, to unitholders of record as of January 31, 2006. 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 $0.80
distribution per common unit. The number of i-units distributed was 997,180. For
each outstanding i-unit that KMR held, a fraction of an i-unit (0.017217) was
issued. The fraction was determined by dividing:
* $0.80, the cash amount distributed per common unit
by
* $46.467, the average of KMR's limited liability shares' closing market
prices from January 12-26, 2006, the ten consecutive trading days
preceding the date on which the shares began to trade ex-dividend under
the rules of the New York Stock Exchange.
This February 14, 2006 distribution required an incentive distribution to
our general partner in the amount of $125.6 million. Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2005 balance sheet as a distribution payable.
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
148
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 Interests and 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:
* its 1.0101% direct general partner ownership interest (accounted for
as minority interest in our consolidated financial statements); and
* its 0.9899% ownership interest indirectly owned via its 1% ownership
interest in us.
As of December 31, 2005, our general partner owned 1,724,000 common units,
representing approximately 0.78% 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 and net
reductions in reserves, less cash disbursements and net additions to reserves
and amounts payable to the former general partner of SFPP, L.P. in respect of
its remaining 0.5% interest in SFPP.
Our general partner is granted discretion by our partnership agreement,
which discretion has been delegated to KMR, subject to the approval of our
general partner in certain cases, to establish, maintain and adjust reserves for
future operating expenses, debt service, maintenance capital expenditures, rate
refunds and distributions for the next four quarters. These reserves are not
restricted by magnitude, but only by type of future cash requirements with which
they can be associated. When KMR determines our quarterly distributions, it
considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level.
Our general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. We do not distribute cash to i-unit owners
but retain the cash for use in our business. However, 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.
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:
* 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;
* 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;
149
* 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
* 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, 2005, 2004 and 2003 were $473.9
million, $390.7 million and $322.8 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, 2005, KMI directly owned
8,838,095 common units and 5,313,400 Class B units, indirectly owned 5,517,640
common units through its consolidated affiliates, including our general partner,
and owned 9,980,494 KMR shares, representing an indirect ownership interest of
9,980,494 i-units. Together, these units represented approximately 13.5% of our
outstanding limited partner units. Including both its general and limited
partner interests in us, at the 2005 distribution level, KMI received
approximately 51% of all quarterly distributions from us, of which approximately
42% is attributable to its general partner interest and 9% 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, 2005, KMR, our general partner's delegate, remained the
sole owner of our 57,918,373 i-units.
Asset Acquisitions and Sales
From time to time in the ordinary course of business, we buy and sell
pipeline and related services from KMI and its subsidiaries. Such transactions
are conducted in accordance with all applicable laws and regulations and on an
arms' length basis consistent with our policies governing such transactions.
2004 Kinder Morgan, Inc. Asset Sales and Contributions
In June 2004, we bought two LM6000 gas-fired turbines and two boilers from a
subsidiary of KMI for their estimated fair market value of $21.1 million, which
we paid in cash. This equipment was a portion of the equipment that became
surplus as a result of KMI's decision to exit the power development business and
is currently employed in conjunction with our CO2 business segment.
Effective November 1, 2004, we acquired all of the partnership interests in
TransColorado Gas Transmission Company from two wholly-owned subsidiaries of
KMI. TransColorado Gas Transmission Company, a Colorado general partnership
referred to in this report as TransColorado, owned assets valued at
approximately $284.5 million. As consideration for TransColorado, we paid to KMI
$211.2 million in cash and approximately $64.0 million in units, consisting of
1,400,000 common units. We also assumed liabilities of approximately $9.3
million. The purchase price for this transaction was determined by the boards of
directors of KMR and our general partner, and KMI based on valuation parameters
used in the acquisition of similar assets. The transaction was approved
unanimously by the independent members of the boards of directors of both KMR
and our general partner, and KMI, with the benefit of advice of independent
legal and financial advisors, including the receipt of fairness opinions from
separate investment banks, specifically Goldman, Sachs & Co. and Morgan Stanley
& Co. Also, in conjunction with our acquisition of TransColorado Gas
Transmission Company, KMI became a guarantor of approximately $210.8 million of
our debt.
150
In November 2004, Kinder Morgan Operating L.P. "A" sold a natural gas
gathering system to Kinder Morgan, Inc.'s retail division for $75,000. The
gathering system primarily consisted of approximately 23,000 miles of 6-inch
diameter pipeline located in Campbell County, Wyoming that was no longer being
used by Kinder Morgan Operating L.P. "A".
1999 and 2000 Kinder Morgan, Inc. 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. Thus, taking into consideration the guarantee of debt
associated with our TransColorado acquisition discussed above, KMI was a
guarantor of a total of approximately $733.5 million of our debt as of December
31, 2005. KMI would be obligated to perform under this guarantee only if we
and/or our assets were unable to satisfy our obligations.
Operations
Natural Gas Pipelines Business Segment
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 its own 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
as well as our North System and Cypress Pipeline, which are part of our Products
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. The amounts paid to KMI for corporate general and administrative costs,
including amounts related to Trailblazer Pipeline Company, were $5.5 million of
fixed costs and $24.2 million of actual costs incurred for 2005, and $8.8
million of fixed costs and $13.1 million of actual costs incurred for 2004. 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 2006 will be approximately $40.3 million, which includes
$1.0 million of fixed costs (adjusted for inflation) and $39.3 million of actual
costs. The expected increase in actual costs and expected decrease in fixed
costs, in 2006 relative to 2005, relate to a higher level of future
reimbursements being based on actual incurred expenses versus negotiated/fixed
amounts.
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 exactly match 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 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 our assets.
CO2 Business Segment
KMI or its subsidiaries operate and maintain for us the power plant we
constructed at the SACROC oil field unit, located in the Permian Basin area of
West Texas. Kinder Morgan Production Company, a subsidiary of one of our
operating limited partnerships, completed construction of the power plant in
June 2005 at an approximate cost of $76 million. The power plant provides the
majority of SACROC's current electricity needs.
Kinder Morgan Power Company, a subsidiary of KMI, operates and maintains the
power plant under a five-year contract entered into in June 2005. Pursuant to
the contract, KMI incurs the costs and expenses related to operating and
maintaining the power plant for the production of electrical energy at the
SACROC field. Such costs include supervisory personnel and qualified operating
and maintenance personnel in sufficient numbers to accomplish the services
provided in accordance with good engineering, operating and maintenance
practices. Kinder Morgan
151
Production Company fully reimburses KMI's expenses, including all agreed-upon
labor costs, and also pays to KMI an operating fee of $20,000 per month.
In addition, Kinder Morgan Production Company is responsible for processing
and directly paying invoices for fuels utilized by the plant. Other materials,
including but not limited to lubrication oil, hydraulic oils, chemicals, ammonia
and any catalyst are purchased by KMI and invoiced monthly as provided by the
contract, if not paid directly by Kinder Morgan Production Company. The amount
paid to KMI in 2005 for operating and maintaining the power plant was $0.8
million. We estimate the total reimbursement to be paid to KMI for operating and
maintaining the plant for 2006 will be approximately $2.2 million. Furthermore,
we believe the amounts paid to KMI for the services they provide each year
fairly reflect the value of the services performed.
Risk Management
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. We perform risk management activities that involve the use of
energy financial instruments to reduce these risks and protect our profit
margins. 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 a separately designated standing
committee comprised of 15 executive-level employees of KMI or KMGP Services
Company, Inc. whose job responsibilities involve operations exposed to commodity
market risk and other external risks in the ordinary course of business. For
more information on our risk management activities see Note 14.
KM Insurance, Ltd.
KM Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and
wholly-owned subsidiary of KMI. KMIL was formed during the second quarter of
2005 as a Class 2 Bermuda insurance company, the sole business of which is to
issue policies for KMI and us to secure the deductible portion of our workers
compensation, automobile liability, and general liability policies placed in the
commercial insurance market. We accrue for the cost of insurance, which is
included in the related party general and administrative expenses.
Notes Receivable
Plantation Pipe Line Company
We own a 51.17% equity interest in Plantation Pipe Line Company. An
affiliate of ExxonMobil owns the remaining 48.83% interest. In July 2004,
Plantation repaid a $10 million note outstanding and $175 million in outstanding
commercial paper borrowings with funds of $190 million borrowed from its owners.
We loaned Plantation $97.2 million, which corresponds to our 51.17% ownership
interest, in exchange for a seven year note receivable bearing interest at the
rate of 4.72% per annum. The note provides for semiannual payments of principal
and interest on December 31 and June 30 each year beginning on December 31, 2004
based on a 25 year amortization schedule, with a final principal payment of
$157.9 million due July 20, 2011. We funded our loan of $97.2 million with
borrowings under our commercial paper program. An affiliate of ExxonMobil owns
the remaining 48.83% equity interest in Plantation and funded the remaining
$92.8 million on similar terms.
As of December 31, 2004, the principal amount receivable from this note was
$96.3 million. We included $2.2 million of this balance within "Accounts, notes
and interest receivable, net-Related parties" on our consolidated balance sheet
as of December 31, 2004, and we included the remaining $94.1 million balance
within "Notes receivable-Related parties."
In 2005, Plantation paid to us $2.1 million in principal amount under the
note, and as of December 31, 2005, the principal amount receivable from this
note was $94.2 million. We included $2.2 million of this balance within
"Accounts, notes and interest receivable, net-Related parties" on our
consolidated balance sheet as of December 31, 2005, and we included the
remaining $92.0 million balance within "Notes receivable-Related parties."
152
Coyote Gas Treating, LLC
We own a 50% equity interest in Coyote Gas Treating, LLC, referred to in
this report as Coyote Gulch. Coyote Gulch is a joint venture, and Enterprise
Field Services LLC owns the remaining 50% equity interest. We are the managing
partner of Coyote Gulch. In June 2001, Coyote repaid the $34.2 million in
outstanding borrowings under its 364-day credit facility with funds borrowed
from its owners. We loaned Coyote $17.1 million, which corresponds to our 50%
ownership interest, in exchange for a one-year note receivable bearing interest
payable monthly at LIBOR plus a margin of 0.875%. On June 30, 2002 and June 30,
2003, the note was extended for one year. On June 30, 2004, the term of the note
was made month-to-month. In 2005, we reduced our investment in the note by $0.1
million to account for our share of investee losses in excess of the carrying
value of our equity investment in Coyote. As of December 31, 2004 and December
31, 2005, we included the principal amount of $17.1 million and $17.0 million,
respectively, related to this note within "Notes Receivable-Related Parties" on
our consolidated balance sheets.
Red Cedar Gathering Company
We own a 49% equity interest in the Red Cedar Gathering Company. Red Cedar
is a joint venture and the Southern Ute Indian Tribe owns the remaining 51%
equity interest. On December 22, 2004, we entered into a $10 million unsecured
revolving credit facility due July 1, 2005, with the Southern Ute Indian Tribe
and us, as lenders, and Red Cedar, as borrower. Subject to the terms of the
agreement, the lenders may severally, but not jointly, make advances to Red
Cedar up to a maximum outstanding principal amount of $10 million. On April 1,
2005, the maximum outstanding principal amount was automatically reduced to $5
million.
In January 2005, Red Cedar borrowed funds of $4 million from its owners
pursuant to this credit agreement, and we loaned Red Cedar approximately $2.0
million, which corresponded to our 49% ownership interest. The interest on all
advances made under this credit facility were calculated as simple interest on
the combined outstanding balance of the credit agreement at 6% per annum based
upon a 360 day year. In March 2005, Red Cedar paid the $4 million outstanding
balance under this revolving credit facility, and the facility expired on July
1, 2005.
Other
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 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.
153
13. Leases and Commitments
Capital Leases
We acquired certain leases classified as capital leases as part of our
acquisition of Kinder Morgan River Terminals LLC in October 2004. We lease our
Memphis, Tennessee port facility under an agreement accounted for as a capital
lease. The lease is for 24 years and expires in 2017. Additionally, we have
three equipment leases accounted for as capital leases which expire from 2006 to
2007.
Amortization of assets recorded under capital leases is included with
depreciation expense. The components of property, plant and equipment recorded
under capital leases are as follows (in thousands):
December 31,
-----------
2005
-----------
Leasehold improvements........... $ 4,089
Machinery and equipment.......... 44
-----------
4,133
Less: Accumulated amortization... (2,038)
-----------
$ 2,095
===========
Future commitments under capital lease obligations as of December 31, 2005
are as follows (in thousands):
Year Commitment
---- ----------
2006...................... $ 180
2007...................... 169
2008...................... 168
2009...................... 168
2010...................... 167
Thereafter................ 1,160
----------
2,012
Less: Amount representing interest (834)
----------
Present value of minimum capital
lease payments $ 1,178
==========
Operating Leases
Including probable elections to exercise renewal options, the remaining
terms on our operating leases range from one to 63 years. Future commitments
related to these leases as of December 31, 2005 are as follows (in thousands):
Year Commitment
---- ----------
2006...................... $ 29,446
2007...................... 25,984
2008...................... 21,464
2009...................... 16,799
2010...................... 11,393
Thereafter................ 43,580
----------
Total minimum payments.... $ 148,666
==========
We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $7.5 million. Total lease and rental expenses
were $47.3 million for 2005, $39.3 million for 2004 and $25.3 million for 2003.
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.
154
During 2004, 33,650 options to purchase common units were exercised at an
average price of $17.50 per unit. The common units underlying these options had
an average fair market value of $45.92 per unit. As of December 31, 2004,
outstanding options to purchase 95,400 common units were held by employees of
KMI or KMGP Services Company, Inc. at an average exercise price of $17.44 per
unit. Outstanding options to purchase 20,000 common units were held by 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, 2004, all 115,400 outstanding
options were fully vested.
During 2005, 90,100 options to purchase common units were exercised at an
average price of $17.63 per unit. The common units underlying these options had
an average fair market value of $47.56 per unit. As of December 31, 2005,
outstanding options to purchase 15,300 common units were held by employees of
KMI or KMGP Services Company, Inc. at an average exercise price of $17.82 per
unit. Outstanding options to purchase 10,000 common units were held by one of
Kinder Morgan G.P., Inc.'s three non-employee directors at an average exercise
price of $21.44 per unit. As of December 31, 2005, all 25,300 outstanding
options were fully vested.
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. We have not granted
common unit options since May 2000. 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, has not been provided because the impact is not
material.
Directors' Unit Appreciation Rights Plan
On April 1, 2003, KMR's compensation committee established our Directors'
Unit Appreciation Rights Plan. Pursuant to this plan, each of KMR's three
non-employee directors was eligible to receive common unit appreciation rights.
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. Proceeds, if any, from the exercise of a unit
appreciation right granted under the plan will be payable only in cash (that is,
no exercise will result in the issuance of additional common units) 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.
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 were granted to each of KMR's three non-employee
directors on January 21, 2004, at the first meeting of the board in 2004. During
the first board meeting of 2005, the plan was terminated and replaced by the
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors; however, all unexercised awards made under the plan
remain outstanding. No unit appreciation rights were exercised during 2005, and
as of December 31, 52,500 unit appreciation rights had been granted, vested and
remained outstanding.
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors
On January 18, 2005, KMR's compensation committee established the Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan. The plan is
administered by KMR's compensation committee and KMR's board
155
has sole discretion to terminate the plan at any time. The primary purpose of
this plan was to promote our interests and the interests of our unitholders by
aligning the compensation of the non-employee members of the board of directors
of KMR with unitholders' interests. Further, 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.
The plan recognizes that the compensation to be paid to each non-employee
director is fixed by the KMR board, generally annually, and that the
compensation is expected to include an annual retainer payable in cash and other
cash compensation. Pursuant to the plan, in lieu of receiving the other cash
compensation, each non-employee director may elect to receive common units. Each
election shall be generally at or around the first board meeting in January of
each calendar year and will be effective for the entire calendar year. The
initial election under this plan for service in 2005 was made effective January
20, 2005. The election for 2006 was made effective January 18, 2006. A
non-employee director may make a new election each calendar year. The total
number of common units authorized under this compensation plan is 100,000.
Each annual election shall be evidenced by an agreement, the Common Unit
Compensation Agreement, between us and each non-employee director, and this
agreement will contain the terms and conditions of each award. Pursuant to this
agreement, all common units issued under this plan are subject to forfeiture
restrictions that expire six months from the date of issuance. Until the
forfeiture restrictions lapse, common units issued under the plan may not be
sold, assigned, transferred, exchanged, or pledged by a non-employee director.
In the event the director's service as a director of KMR is terminated prior to
the lapse of the forfeiture restriction either for cause, or voluntary
resignation, each director shall, for no consideration, forfeit to us all common
units to the extent then subject to the forfeiture restrictions. Common units
with respect to which forfeiture restrictions have lapsed shall cease to be
subject to any forfeiture restrictions, and we will provide each director a
certificate representing the units as to which the forfeiture restrictions have
lapsed. In addition, each non-employee director shall have the right to receive
distributions with respect to the common units awarded to him under the plan, to
vote such common units and to enjoy all other unitholder rights, including
during the period prior to the lapse of the forfeiture restrictions.
The number of common units to be issued to a non-employee director electing
to receive the other cash compensation in the form of common units will equal
such other cash compensation awarded, divided by the closing price of the common
units on the New York Stock Exchange on the day the cash compensation is awarded
(such price, the fair market value), rounded down to the nearest 50 common
units. The common units will be issuable as specified in the Common Unit
Compensation Agreement. A non-employee director electing to receive the other
cash compensation in the form of common units will receive cash equal to the
difference between (i) the other cash compensation awarded to such non-employee
director and (ii) the number of common units to be issued to such non-employee
director multiplied by the fair market value of a common unit. This cash payment
shall be payable in four equal installments (together with the annual cash
retainer) generally around March 31, June 30, September 30 and December 31 of
the calendar year in which such cash compensation is awarded.
On January 18, 2005, the date of adoption of the plan, each of KMR's three
non-employee directors was awarded a cash retainer of $40,000, which was paid
quarterly during 2005, and other cash compensation of $79,750. The total
compensation of $119,750 was for board service during 2005. Effective January
20, 2005, each non-employee director elected to receive the other cash
compensation of $79,750 in the form of our common units and was issued 1,750
common units pursuant to the plan and its agreements (based on the $45.55
closing market price of our common units on January 18, 2005, as reported on the
New York Stock Exchange). Also, consistent with the plan, the $37.50 of other
cash compensation that did not equate to a whole common unit, based on the
January 18, 2005 $45.55 closing price, was paid to each of the non-employee
directors as described above. No other compensation was paid to the non-employee
directors during 2005.
On January 17, 2006, each of KMR's three non-employee directors was awarded
a cash retainer of $72,220, which will be paid quarterly during 2006, and other
cash compensation of $87,780. The total compensation of $160,000 is for board
service during 2006. Effective January 17, 2006, each non-employee director
elected to receive the other cash compensation of $87,780 in the form of our
common units and was issued 1,750 common units pursuant to the plan and its
agreements (based on the $50.16 closing market price of our common units on
January 17, 2006, as reported on the New York Stock Exchange). The annual cash
retainer will be paid to each of
156
the non-employee directors as described above. No other compensation will be
paid to the non-employee directors during 2006.
Contingent Debt
We apply the disclosure provisions of Financial Accounting Standards Board
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 SFAS 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 partners of
Cortez Pipeline Company (Kinder Morgan CO2 Company, L.P. - 50% partner; a
subsidiary of Exxon Mobil Corporation - 37% partner; and Cortez Vickers Pipeline
Company - 13% partner) are required, on a several, 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 partners 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
partners further severally guarantee, on a percentage basis, the obligations of
the Cortez Pipeline Company partners 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 several guaranty obligations
jointly and severally; however, we are obligated to indemnify Shell for
liabilities it incurs in connection with such guaranty. With respect to Cortez's
long-term revolving credit facility, Shell is released of its guaranty
obligations on December 31, 2006. Furthermore, with respect to Cortez's
short-term commercial paper program and Series D notes, we must use commercially
reasonable efforts to have Shell released of its guaranty obligations by
December 31, 2006. If we are unable to obtain Shell's release in respect of the
Series D Notes by that date, we are required to provide Shell with collateral (a
letter of credit, for example) to secure our indemnification obligations to
Shell.
As of December 31, 2005, the debt facilities of Cortez Capital Corporation
consisted of:
* $75 million of Series D notes due May 15, 2013;
* a $125 million short-term commercial paper program; and
* a $125 million five-year committed revolving credit facility due December
22, 2009 (to support the above-mentioned $125 million commercial paper
program).
As of December 31, 2005, Cortez Capital Corporation had $91.6 million of
commercial paper outstanding with an average interest rate of 4.255%, the
average interest rate on the Series D notes was 7.14%, and there were no
borrowings under the credit facility.
Red Cedar Gathering Company Debt
In October 1998, Red Cedar 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
Gathering Company. The Senior Notes are also guaranteed by us and the other
owner of Red Cedar Gathering Company jointly and severally. The principal is to
be repaid in seven equal
157
installments beginning on October 31, 2004 and ending on October 31, 2010. As of
December 31, 2005, $39.3 million in principal amount of notes were outstanding
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. The bond
indenture is for 30 years and allows the bonds to remain outstanding until
December 1, 2020. 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. Principal
payments on the bonds are made on the first of December each year and reductions
are made to the letter of credit. As of December 31, 2005, the value of this
letter of credit outstanding under our credit facility was $24.9 million.
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. 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. These risk management instruments are also called derivatives,
which are defined as a financial instrument or other contract which derives its
value from the value of some other financial instrument or variable. The value
of a derivative (for example, options, swaps, futures contracts, etc.) is a
function of the underlying (for example, a specified interest rate, commodity
price, foreign exchange rate, or other variable) and the notional amount (for
example, a number of currency units, shares, commodities, or other units
specified in a derivative instrument), and while the value of the underlying
changes due to changes in market conditions, the notional amount remains
constant throughout the life of the derivative contract.
Current accounting standards require derivatives to be reflected as assets
or liabilities at their fair market values and the fair value of our 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.
Pursuant to our management's approved risk management policy, we are to
engage in these activities as a hedging mechanism against price volatility
associated with:
* pre-existing or anticipated physical natural gas, natural gas liquids
and crude oil sales;
* pre-existing or anticipated physical carbon dioxide sales that have
pricing tied to crude oil prices;
* natural gas purchases; and
* system use and storage.
Our risk management activities are primarily 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.
158
Specifically, our risk management committee is a separately designated
standing committee comprised of 15 executive-level employees of KMI or KMGP
Services Company, Inc. whose job responsibilities involve operations exposed to
commodity market risk and other external risks in the ordinary course of
business. Our risk management committee is chaired by our President and is
charged with the following three responsibilities:
* establish and review risk limits consistent with our risk tolerance
philosophy;
* recommend to the audit committee of our general partner's delegate any
changes, modifications, or amendments to our risk management policy;
and
* address and resolve any other high-level risk management issues.
Our derivatives hedge the commodity price risks derived from 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 hedged forecasted
transaction affects earnings. If the transaction results in an asset or
liability, amounts in accumulated other comprehensive income should be
reclassified into earnings when the asset or liability affects earnings through
cost of sales, depreciation, interest expense, etc. 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 and any component excluded
from the computation of the effectiveness of the derivative instrument is
reported in earnings immediately.
The gains and losses that are included in "Accumulated other comprehensive
loss" in our accompanying consolidated balance sheets are primarily related to
the derivative instruments associated with our commodity market risk hedging
activities, and these gains and losses are reclassified into earnings as the
hedged sales and purchases take place. During the year ended December 31, 2004,
we reclassified $192.3 million of Accumulated other comprehensive loss into
earnings as a result of hedged sales and purchases during the period. During the
year ended December 31, 2005, we reclassified $424.0 million of Accumulated
other comprehensive loss into earnings as a result of hedged sales and purchases
during the period. For all of our derivatives combined, approximately $406.3
million of the Accumulated other comprehensive loss balance of $1,079.7 million
as of December 31, 2005 is expected to be reclassified into earnings during the
next twelve months.
None of the reclassification of Accumulated other comprehensive loss into
earnings during 2005 or 2004 resulted from the discontinuance of cash flow
hedges due to a determination that the forecasted transactions would no longer
occur by the end of the originally specified time period, but rather resulted
from the hedged forecasted transactions actually affecting earnings (for
example, when the forecasted sales and purchases actually occurred).
As discussed above, the ineffective portion of the gain or loss on a cash
flow hedging instrument is required to be recognized currently in earnings.
Accordingly, we recognized a loss of $0.6 million during 2005, a gain of $0.1
million during 2004 and a gain of $0.5 million during 2003 as a result of
ineffective hedges. All gains and losses recognized as a result of ineffective
hedges are reported within the captions "Natural gas sales" and "Gas purchases
and other costs of sales" in our accompanying consolidated statements of income.
For each of the years ended December 31, 2005, 2004 and 2003, 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 commodity market hedging activities are
included within "Other current assets," "Deferred charges and other assets,"
"Accounts payable-Related parties," "Accrued other current liabilities" and
"Other long-term liabilities and deferred credits" in our accompanying
consolidated balance sheets. The following table summarizes the net fair value
of our energy financial instruments associated with our commodity market risk
management activities and included on our accompanying consolidated balance
sheets as of December 31, 2005 and December 31, 2004 (in thousands):
159
December 31, December 31,
2005 2004
------------ ------------
Derivatives-net asset/(liability)
Other current assets...................... $ 109,437 $ 41,010
Deferred charges and other assets......... 47,682 17,408
Accounts payable-Related parties.......... (16,057) --
Accrued other current liabilities......... (507,306) (218,967)
Other long-term liabilities and deferred
credits................................. $ (727,929) $ (309,035)
Given our portfolio of businesses as of December 31, 2005, our principal use
of derivative energy financial instruments was to mitigate the risk associated
with market movements in the price of energy commodities. Our net short natural
gas derivatives position primarily represented our hedging of anticipated future
natural gas purchases and sales. Our net short crude oil derivatives position
represented our crude oil derivative purchases and sales made to hedge
anticipated oil purchases and sales. Finally, our net short natural gas liquids
derivatives position reflected the hedging of our forecasted natural gas liquids
purchases and sales. As of December 31, 2005, 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 2011.
As of December 31, 2005, 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.............................. $ (1,672) $ (1,076,545) $ (1,078,217)
Contract Amounts -- Gross............................. $ 19,636 $ 1,816,990 $ 1,836,626
Contract Amounts -- Net............................... $ (11,925) $ (1,355,251) $ (1,367,176)
(Number of contracts(1))
Natural Gas
Notional Volumetric Positions: Long................. 39 1,041 1,080
Notional Volumetric Positions: Short................ (166) (915) (1,081)
Net Notional Totals to Occur in 2006................ (127) 361 234
Net Notional Totals to Occur in 2007 and Beyond..... -- (235) (235)
Crude Oil
Notional Volumetric Positions: Long................. -- 2,254
2,254
Notional Volumetric Positions: Short................ -- (43,348) (43,348)
Net Notional Totals to Occur in 2006................ -- (12,263) (12,263)
Net Notional Totals to Occur in 2007 and Beyond..... -- (28,831) (28,831)
Natural Gas Liquids
Notional Volumetric Positions: Long................. -- -- --
Notional Volumetric Positions: Short................ -- (398) (398)
Net Notional Totals to Occur in 2006................ -- (398) (398)
Net Notional Totals to Occur in 2007 and Beyond..... -- -- --
- ----------
(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 both December 31, 2005
and December 31, 2004, we were essentially in a net payable position and 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.
160
In addition, in conjunction with the purchase of exchange-traded derivatives
or when the market value of our derivatives with specific counterparties exceeds
established limits, we are required to provide collateral to our counterparties,
which may include posting letters of credit or placing cash in margin accounts.
As of December 31, 2005, we had five outstanding letters of credit totaling $534
million in support of our hedging of commodity price risks associated with the
sale of natural gas, natural gas liquids, crude oil and carbon dioxide. As of
December 31, 2004, we had one outstanding letter of credit totaling $50 million
in support of our hedging of commodity price risks. As of December 31, 2005, we
had no cash margin deposits associated with our commodity contract positions and
over-the-counter swap partners. As of December 31, 2004, our margin deposits
associated with our commodity contract positions and over-the-counter swap
partners totaled $4.4 million.
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. As a result, we do not significantly hedge our
exposure to fluctuations in foreign currency.
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, 2005 and 2004, we were a party to interest rate swap agreements
with notional principal amounts of $2.1 billion and $2.3 billion, respectively.
We entered into these agreements for the purpose of hedging the interest rate
risk associated with our fixed and variable rate debt obligations.
As of December 31, 2005, a notional principal amount of $2.1 billion of
these agreements effectively converted 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:
* $200 million principal amount of our 5.35% senior notes due August 15,
2007;
* $250 million principal amount of our 6.30% senior notes due February
1, 2009;
* $200 million principal amount of our 7.125% senior notes due March 15,
2012;
* $250 million principal amount of our 5.0% senior notes due December
15, 2013;
* $200 million principal amount of our 5.125% senior notes due November
15, 2014;
* $300 million principal amount of our 7.40% senior notes due March 15,
2031;
* $200 million principal amount of our 7.75% senior notes due March 15,
2032;
* $400 million principal amount of our 7.30% senior notes due August 15,
2033; and
* $100 million principal amount of our 5.80% senior notes due March 15,
2035.
These swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes, therefore, as of December 31, 2005,
the maximum length of time over which we have hedged a portion of our exposure
to the variability in the value of this debt due to interest rate risk is
through March 15, 2035. 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.
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
161
provisions at the then-current economic value in March 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 or seven
years.
As of December 31, 2004, we also had swap agreements that effectively
converted 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, matured on August 1, 2005, and the
remaining half matured on September 1, 2005. These 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.
The differences between fair value and the original carrying value
associated with our interest rate swap agreements are included within "Deferred
charges and other assets" and "Other long-term liabilities and deferred credits"
in our accompanying consolidated balance sheets. The offsetting entry to adjust
the carrying value of the debt securities whose fair value was being hedged is
recognized as "Market value of interest rate swaps" on our accompanying
consolidated balance sheets.
The following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of December 31, 2005
and December 31, 2004 (in thousands):
December 31, December 31,
2005 2004
---------- ----------
Derivatives-net asset/(liability)
Deferred charges and other assets......... $ 112,386 $ 132,210
Other long-term liabilities and deferred (13,917) (2,057)
---------- ----------
credits.....................................
Market value of interest rate swaps..... $ 98,469 $ 130,153
========== =========
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:
* Products Pipelines;
* Natural Gas Pipelines;
* CO2; and
* 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 before depreciation, depletion and
amortization, which exclude general and administrative expenses, third-party
debt costs and interest expense, unallocable interest income and minority
interest. Our reportable segments are strategic business units that
162
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 sale, transmission,
storage and gathering of natural gas. Our CO2 segment derives its revenues
primarily from the production and sale of crude oil from fields in the Permian
Basin of West Texas and from the transportation and marketing of carbon dioxide
used as a flooding medium for recovering crude oil from mature oil fields. 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):
2005 2004 2003
------------- ------------- -------------
Revenues
Products Pipelines............................ $ 711,886 $ 645,249 $ 585,376
Natural Gas Pipelines......................... 7,718,384 6,252,921 5,316,853
CO2........................................... 657,594 492,834 248,535
Terminals..................................... 699,264 541,857 473,558
------------- ------------- -------------
Total consolidated revenues................... $ 9,787,128 $ 7,932,861 $ 6,624,322
============= ============= =============
Operating expenses(a)
Products Pipelines............................. $ 366,048 $ 191,425 $ 169,526
Natural Gas Pipelines.......................... 7,254,979 5,862,159 4,967,531
CO2............................................ 212,636 173,382 82,055
Terminals...................................... 373,410 272,766 229,054
------------- ------------- -------------
Total consolidated operating expenses.......... $ 8,207,073 $ 6,499,732 $ 5,448,166
============= ============= =============
Depreciation, depletion and amortization
Products Pipelines........................... $ 79,199 $ 71,263 $ 67,345
Natural Gas Pipelines........................ 61,661 53,112 53,785
CO2.......................................... 149,890 121,361 60,827
Terminals.................................... 59,077 42,890 37,075
------------- ------------- -------------
Total consol. depreciation, depletion and
amortiz..................................... $ 349,827 $ 288,626 $ 219,032
============= ============= =============
Earnings from equity investments
Products Pipelines............................ $ 28,446 $ 29,050 $ 30,948
Natural Gas Pipelines......................... 36,812 19,960 24,012
CO2........................................... 26,319 34,179 37,198
Terminals..................................... 83 1 41
------------- ------------- -------------
Total consolidated equity earnings............ $ 91,660 $ 83,190 $ 92,199
============= ============= =============
Amortization of excess cost of equity investments
Products Pipelines............................ $ 3,350 $ 3,281 $ 3,281
Natural Gas Pipelines......................... 277 277 277
CO2........................................... 2,017 2,017 2,017
Terminals..................................... -- -- --
------------- ------------- -------------
Total consol. amortization of excess cost of
invests..................................... $ 5,644 $ 5,575 $ 5,575
============= ============= =============
Interest income
Products Pipelines............................. $ 4,595 $ 2,091 $ --
Natural Gas Pipelines.......................... 747 -- --
CO2............................................ -- -- --
Terminals...................................... -- -- --
------------- ------------- -------------
Total segment interest income.................. 5,342 2,091 --
Unallocated interest income.................... 4,155 1,199 1,420
------------- ------------- -------------
Total consolidated interest income............. $ 9,497 $ 3,290 $ 1,420
============= ============= =============
163
2005 2004 2003
------------- ------------ -------------
Other, net-income (expense)(b)
Products Pipelines..................................... $ 1,516 $ (28,025) $ 6,471
Natural Gas Pipelines................................. 1,982 9,434 1,082
CO2.................................................... (5) 4,152 (40)
Terminals.............................................. (220) 18,255 88
------------- ------------ -------------
Total segment Other, net-income (expense).............. 3,273 3,816 7,601
Loss from early extinguishment of debt................. -- (1,562) --
------------- ----------- ------------
Total consolidated Other, net-income (expense)......... $ 3,273 $ 2,254 $ 7,601
============= ============ =============
Income tax benefit (expense)
Products Pipelines..................................... $ (10,343) $ (12,075) $ (11,669)
Natural Gas Pipelines.................................. (2,622) (1,895) (1,066)
CO2.................................................... (385) (147) (39)
Terminals(c)........................................... (11,111) (5,609) (3,857)
-------------- ------------- -------------
Total consolidated income tax benefit (expense)........ $ (24,461) $ (19,726) $ (16,631)
============= ============ =============
Segment earnings
Products Pipelines..................................... $ 287,503 $ 370,321 $ 370,974
Natural Gas Pipelines.................................. 438,386 364,872 319,288
CO2.................................................... 318,980 234,258 140,755
Terminals.............................................. 255,529 238,848 203,701
------------- ------------ -------------
Total segment earnings(d).............................. 1,300,398 1,208,299 1,034,718
Interest and corporate administrative expenses(e)...... (488,171) (376,721) (337,381)
------------- ------------ -------------
Total consolidated net income.......................... $ 812,227 $ 831,578 $ 697,337
============= ============ =============
Segment earnings before depreciation, depletion,
amortization and amortization of excess cost of
equity investments(f)
Products Pipelines..................................... $ 370,052 $ 444,865 $ 441,600
Natural Gas Pipelines.................................. 500,324 418,261 373,350
CO2.................................................... 470,887 357,636 203,599
Terminals.............................................. 314,606 281,738 240,776
------------- ------------ -------------
Total segment earnings before DD&A..................... 1,655,869 1,502,500 1,259,325
Consolidated depreciation and amortization............. (349,827) (288,626) (219,032)
Consolidated amortization of excess cost of invests.... (5,644) (5,575) (5,575)
Interest and corporate administrative expenses......... (488,171) (376,721) (337,381)
------------- ------------ -------------
Total consolidated net income.......................... $ 812,227 $ 831,578 $ 697,337
============= ============ =============
Capital expenditures
Products Pipelines................................... $ 271,506 $ 213,746 $ 94,727
Natural Gas Pipelines................................ 102,914 106,358 101,679
CO2.................................................. 302,032 302,935 272,177
Terminals............................................ 186,604 124,223 108,396
------------- ------------ -------------
Total consolidated capital expenditures(g)........... $ 863,056 $ 747,262 $ 576,979
============= ============ =============
Investments at December 31
Products Pipelines................................... $ 223,729 $ 223,196 $ 226,680
Natural Gas Pipelines................................ 177,105 174,296 164,924
CO2.................................................. 17,938 15,503 12,591
Terminals............................................ 541 260 150
------------- ------------ -------------
Total consolidated investments....................... $ 419,313 $ 413,255 $ 404,345
============= ============ =============
Assets at December 31
Products Pipelines................................... $ 3,873,939 $ 3,651,657 $ 3,198,107
Natural Gas Pipelines................................ 4,139,969 3,691,457 3,253,792
CO2.................................................. 1,772,756 1,527,810 1,177,645
Terminals............................................ 2,052,457 1,576,333 1,368,279
------------- ------------ -------------
Total segment assets................................. 11,839,121 10,447,257 8,997,823
Corporate assets(h).................................. 84,341 105,685 141,359
Total consolidated assets............................ $ 11,923,462 $ 10,552,942 $ 9,139,182
============= ============ =============
(a) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes. 2005 amounts include a rate case liability adjustment resulting in a
$105.0 million expense to our
164
Products Pipelines business segment, a North System liquids inventory
reconciliation adjustment resulting in a $13.7 million expense to our
Products Pipelines business segment, and environmental liability
adjustments resulting in a $19.6 million expense to our Products Pipelines
business segment, a $0.1 million reduction in expense to our Natural Gas
Pipelines business segment, a $0.3 million expense to our CO2 business
segment and a $3.5 million expense to our Terminals business segment.
(b) 2004 amounts include environmental liability adjustments resulting in a
$30.6 million expense to our Products Pipelines business segment, a $7.6
million earnings increase to our Natural Gas Pipelines business segment, a
$4.1 million earnings increase to our CO2 business segment and an $18.7
million earnings increase to our Terminals business segment.
(c) 2004 amount includes expenses of $0.1 million related to environmental
expense adjustments.
(d) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses,
depreciation, depletion and amortization, and amortization of excess cost
of equity investments.
(e) Includes unallocated interest income, interest and debt expense, general
and administrative expenses, minority interest expense, loss from early
extinguishment of debt (2004 only) and cumulative effect adjustment from a
change in accounting principle (2003 only).
(f) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses.
(g) Includes sustaining capital expenditures of $140,805 in 2005, $119,244 in
2004 and $92,837 in 2003. Sustaining capital expenditures are defined as
capital expenditures which do not increase the capacity of an asset.
(h) Includes cash, cash equivalents, restricted deposits and certain
unallocable deferred charges.
We do not attribute interest and debt expense to any of our reportable
business segments. For each of the years ended December 31, 2005, 2004 and 2003,
we reported (in thousands) total consolidated interest expense of $268,358,
$196,172 and $182,777, respectively.
Our total operating revenues are derived from a wide customer base. For the
year ended December 31, 2005, no revenues from transactions with a single
external customer amounted to 10% or more of our total consolidated revenues.
For each of the years ended December 31, 2004 and 2003, only one customer
accounted for more than 10% of our total consolidated revenues. Total
transactions within our Natural Gas Pipelines segment with CenterPoint Energy
accounted for 14.3% and 16.8% of our total consolidated revenues during 2004 and
2003, respectively.
16. Litigation, Environmental and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P., referred to in this report 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, including shippers' complaints
regarding interstate rates on our Pacific operations' pipeline systems.
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
165
part of ConocoPhillips Company). The FERC has ruled that the complainants have
the burden of proof in this proceeding.
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 "substantially changed circumstances" with respect to those
rates and that the rates 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 "substantially 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 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 aggregate payments of $44.9 million in 2003
for reparations and refunds pursuant to a FERC order.
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
166
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. On July 20, 2004, the Court of Appeals
issued its opinion in BP West Coast Products, LLC v. Federal Energy Regulatory
Commission, No. 99-1020, On Petitions for Review of Orders of the Federal Energy
Regulatory Commission (Circuit opinion), addressing in part the tariffs of SFPP,
L.P. Among other things, the court's opinion vacated the income tax allowance
portion of the FERC opinion and the order allowing recovery in SFPP's rates for
income taxes and remanded to the FERC this and other matters for further
proceedings consistent with the court's opinion. In reviewing a series of FERC
orders involving SFPP, the Court of Appeals held, among other things, that the
FERC had not adequately justified its policy of providing an oil pipeline
limited partnership with an income tax allowance equal to the proportion of its
limited partnership interests owned by corporate partners. By its terms, the
portion of the opinion addressing SFPP only pertained to SFPP, L.P. and was
based on the record in that case.
The Court of Appeals held that, in the context of the Docket No. OR92-8, et
al. proceedings, all of SFPP's West Line rates were grandfathered other than the
charge for use of SFPP's Watson Station gathering enhancement facility and the
rate for turbine fuel movements to Tucson under SFPP Tariff No. 18. It concluded
that the FERC had a reasonable basis for concluding that the addition of a West
Line origin point at East Hynes, California did not involve a new "rate" for
purposes of the Energy Policy Act. It rejected arguments from West Line Shippers
that certain protests and complaints had challenged West Line rates prior to the
enactment of the Energy Policy Act.
The Court of Appeals also held that complainants had failed to satisfy their
burden of demonstrating substantially changed circumstances, and therefore could
not challenge grandfathered West Line rates in the Docket No. OR92-8 et al.
proceedings. It specifically rejected arguments that other shippers could
"piggyback" on the special Energy Policy Act exception permitting Navajo to
challenge grandfathered West Line rates, which Navajo had withdrawn under a
settlement with SFPP. The court remanded to the FERC the changed circumstances
issue "for further consideration" in light of the court's decision regarding
SFPP's tax allowance. While, the FERC had previously held in the OR96-2
proceeding (discussed following) that the tax allowance policy should not be
used as a stand-alone factor in determining when there have been substantially
changed circumstances, the FERC's May 4, 2005 income tax allowance policy
statement (discussed following) may affect how the FERC addresses the changed
circumstances and other issues remanded by the court.
The Court of Appeals upheld the FERC's rulings on most East Line rate
issues; however, it found the FERC's reasoning inadequate on some issues,
including the tax allowance.
The Court of Appeals held the FERC had sufficient evidence to use SFPP's
December 1988 stand-alone capital structure to calculate its starting rate base
as of June 1985; however, it rejected SFPP arguments that would have resulted in
a higher starting rate base.
The Court of Appeals accepted the FERC's treatment of regulatory litigation
costs, including the limitation of recoverable costs and their offset against
"unclaimed reparations" - that is, reparations that could have been awarded to
parties that did not seek them. The court also accepted the FERC's denial of any
recovery for the costs of civil litigation by East Line shippers against SFPP
based on the 1992 re-reversal of the six-inch line between Tucson and Phoenix.
However, the court did not find adequate support for the FERC's decision to
allocate the limited litigation costs that SFPP was allowed to recover in its
rates equally between the East Line and the West Line, and ordered the FERC to
explain that decision further on remand.
The Court of Appeals held the FERC had failed to justify its decision to
deny SFPP any recovery of funds spent to recondition pipe on the East Line, for
which SFPP had spent nearly $6 million between 1995 and 1998. It concluded that
the Commission's reasoning was inconsistent and incomplete, and remanded for
further explanation, noting that "SFPP's shippers are presently enjoying the
benefits of what appears to be an expensive pipeline reconditioning program
without sharing in any of its costs."
167
The Court of Appeals affirmed the FERC's rulings on reparations in all
respects. It held the Arizona Grocery doctrine did not apply to orders requiring
SFPP to file "interim" rates, and that "FERC only established a final rate at
the completion of the OR92-8 proceedings." It held that the Energy Policy Act
did not limit complainants' ability to seek reparations for up to two years
prior to the filing of complaints against rates that are not grandfathered. It
rejected SFPP's arguments that the FERC should not have used a "test period" to
compute reparations that it should have offset years in which there were
underrecoveries against those in which there were overrecoveries, and that it
should have exercised its discretion against awarding any reparations in this
case.
The Court of Appeals also rejected:
* Navajo's argument that its prior settlement with SFPP's predecessor
did not limit its right to seek reparations;
* Valero's argument that it should have been permitted to recover
reparations in the Docket No. OR92-8 et al. proceedings rather than
waiting to seek them, as appropriate, in the Docket No. OR96-2 et al.
proceedings;
* arguments that the former ARCO and Texaco had challenged East Line
rates when they filed a complaint in January 1994 and should therefore
be entitled to recover East Line reparations; and
* Chevron's argument that its reparations period should begin two years
before its September 1992 protest regarding the six-inch line reversal
rather than its August 1993 complaint against East Line rates.
On September 2, 2004, BP West Coast Products, ChevronTexaco, ConocoPhillips
and ExxonMobil filed a petition for rehearing and rehearing en banc asking the
Court of Appeals to reconsider its ruling that West Line rates were not subject
to investigation at the time the Energy Policy Act was enacted. On September 3,
2004, SFPP filed a petition for rehearing asking the court to confirm that the
FERC has the same discretion to address on remand the income tax allowance issue
that administrative agencies normally have when their decisions are set aside by
reviewing courts because they have failed to provide a reasoned basis for their
conclusions. On October 4, 2004, the Court of Appeals denied both petitions
without further comment.
On November 2, 2004, the Court of Appeals issued its mandate remanding the
Docket No. OR92-8 proceedings to the FERC. SFPP and shipper parties subsequently
filed various pleadings with the FERC regarding the proper nature and scope of
the remand proceedings. On December 2, 2004, the FERC issued a Notice of Inquiry
and opened a new proceeding (Docket No. PL05-5) to consider how broadly the
court's ruling on the tax allowance issue in BP West Coast Products, LLC, v.
FERC should affect the range of entities the FERC regulates. The FERC sought
comments on whether the court's ruling applies only to the specific facts of the
SFPP proceeding, or also extends to other capital structures involving
partnerships and other forms of ownership. Comments were filed by numerous
parties, including our Rocky Mountain natural gas pipelines, in the first
quarter of 2005. On May 4, 2005, the FERC adopted a policy statement in Docket
No. PL05-5, providing that all entities owning public utility assets - oil and
gas pipelines and electric utilities - would be permitted to include an income
tax allowance in their cost-of-service rates to reflect the actual or potential
income tax liability attributable to their public utility income, regardless of
the form of ownership. Any tax pass-through entity seeking an income tax
allowance would have to establish that its partners or members have an actual or
potential income tax obligation on the entity's public utility income. The FERC
expressed the intent to implement its policy in individual cases as they arise.
On December 17, 2004, the Court of Appeals issued orders directing that the
petitions for review relating to FERC orders issued after November 2001 in
OR92-8, which had previously been severed from the main Court of Appeals docket,
should continue to be held in abeyance pending completion of the remand
proceedings before the FERC. Petitions for review of orders issued in other FERC
dockets have since been returned to the court's active docket (discussed further
below in relation to the OR96-2 proceedings).
On January 3, 2005, SFPP filed a petition for a writ of certiorari asking
the United States Supreme Court to review the Court of Appeals' ruling that the
Arizona Grocery doctrine does not apply to "interim" rates, and that "FERC only
established a final rate at the completion of the OR92-8 proceedings." BP West
Coast Products and ExxonMobil also filed a petition for certiorari, on December
30, 2004, seeking review of the Court of Appeals' ruling that there was no
pending investigation of West Line rates at the time of enactment of the Energy
Policy Act
168
(and thus that those rates remained grandfathered). On April 6, 2005, the
Solicitor General filed a brief in opposition to both petitions on behalf of the
FERC and United States, and Navajo, ConocoPhillips, Ultramar, Valero and Western
Refining filed an opposition to SFPP's petition. SFPP filed a reply to those
briefs on April 18, 2005. On May 16, 2005, the Supreme Court issued orders
denying the petitions for certiorari filed by SFPP and by BP West Coast Products
and ExxonMobil.
On June 1, 2005, the FERC issued its Order on Remand and Rehearing, which
addressed issues in both the OR92-8 and OR96-2 proceedings (discussed
following).
With respect to the OR92-8 proceedings, the June 1, 2005 order ruled on
several issues that had been remanded by the Court of Appeals in BP West Coast
Products. With respect to the income tax allowance, the FERC held that its May
4, 2005 policy statement would apply in the OR92-8 and OR96-2 proceedings and
that SFPP "should be afforded an income tax allowance on all of its partnership
interests to the extent that the owners of those interests had an actual or
potential tax liability during the periods at issue." It directed SFPP and
opposing parties to file briefs regarding the state of the existing record on
those questions and the need for further proceedings. Those filings are
described below in the discussion of the OR96-2 proceedings. The FERC held that
SFPP's allowable regulatory litigation costs in the OR92-8 proceedings should be
allocated between the East Line and the West Line based on the volumes carried
by those lines during the relevant period. In doing so, it reversed its prior
decision to allocate those costs between the two lines on a 50-50 basis. The
FERC affirmed its prior decision to exclude SFPP's pipeline reconditioning costs
from the cost of service in the OR92-8 proceedings, but stated that SFPP will
have an opportunity to justify much of those reconditioning expenses in the
OR96-2 proceedings. The FERC deferred further proceedings on the
non-grandfathered West Line turbine fuel rate until completion of its review of
the initial decision in phase two of the OR96-2 proceedings. The FERC held that
SFPP's contract charge for use of the Watson Station gathering enhancement
facilities was not grandfathered and required further proceedings before an
administrative law judge to determine the reasonableness of that charge; those
proceedings are currently in settlement negotiations before a FERC settlement
judge.
Petitions for review of the June 1, 2005 order by the United States Court of
Appeals for the District of Columbia Circuit have been filed by SFPP, Navajo,
Western Refining, BP West Coast Products, ExxonMobil, Chevron, ConocoPhillips,
Ultramar and Valero. SFPP has moved to intervene in the review proceedings
brought by the other parties.
On December 16, 2005, the FERC issued its Order on Initial Decision and on
Certain Remanded Cost Issues, which provided further guidance regarding
application of the FERC's income tax allowance policy in this case, which is
discussed below in connection with the OR96-2 proceedings. The December 16, 2005
order required SFPP to submit a revised East Line cost of service following
FERC's rulings regarding the income tax allowance and the ruling in its June 1,
2005 order regarding the allocation of litigation costs. SFPP is required to
file interim East Line rates effective May 1, 2006 using the lower of the
revised OR92-8 (1994 test year) or OR96-2 (1999 test year) rates, as adjusted
for indexing through April 30, 2006. The December 16, 2005 order also required
SFPP to calculate costs-of-service for West Line turbine fuel movements based on
both a 1994 and 1999 test year and to file interim turbine fuel rates to be
effective May 1, 2006, using the lower of the two test year rates as indexed
through April 30, 2006. SFPP was further required to calculate estimated
reparations for complaining shippers consistent with the order. As described
further below, various parties filed requests for rehearing and petitions for
review of the December 16, 2005 order.
Sepulveda proceedings. In December 1995, Texaco filed a complaint at the
FERC (Docket No. OR96-2) alleging that movements on SFPP's Sepulveda pipeline
(Line Sections 109 and 110) to Watson Station, in the Los Angeles basin, were
subject to the 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.
In an August 1997 order, the FERC held that the movements on the Sepulveda
pipeline were subject to its jurisdiction. On October 6, 1997, SFPP filed a
tariff establishing the initial interstate rate for movements on the Sepulveda
pipeline at 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.
169
In December 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.
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 pipeline is just and reasonable. Hearings in this
proceeding were held in February and March 2005. SFPP asserted various defenses
against the shippers' claims for reparations and refunds, including the
existence of valid contracts with the shippers and grandfathering protection. In
August 2005, the presiding administrative law judge issued an initial decision
finding that for the period from 1993 to November 1997 (when the Sepulveda FERC
tariff went into effect) the Sepulveda rate should have been lower. The
administrative law judge recommended that SFPP pay reparations and refunds for
alleged overcollections. SFPP filed in October 2005 a brief to the FERC taking
exception to this and other portions of the initial decision.
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar
Diamond Shamrock Corporation filed a complaint at the 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 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 SFPP's
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 Western 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 in June
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.
On March 26, 2004, the FERC issued an order on the phase one initial
decision. The FERC's phase one order reversed the initial decision by finding
that SFPP's rates for its North and Oregon Lines should remain "grandfathered"
and amended the initial decision by finding that SFPP's West Line rates (i) to
Yuma, Tucson and CalNev, as of 1995, and (ii) to Phoenix, as of 1997, should no
longer be "grandfathered" and are not just and reasonable. The FERC upheld these
findings in its June 1, 2005 order, although it appears to have found
substantially changed circumstances as to SFPP's West Line rates on a somewhat
different basis than in the phase one order. The FERC's phase one order did not
address prospective West Line rates and whether reparations were necessary. As
discussed below, those issues have been addressed in the FERC's December 16,
2005 order on phase two issues. The FERC's phase one order also did not address
the "grandfathered" status of the Watson Station fee, noting that it would
address that issue once it was ruled on by the Court of Appeals in its review of
the FERC's Opinion No. 435 orders; as noted above, the FERC held in its June 1,
2005 order that the Watson Station fee is not
170
grandfathered. Several of the participants in the proceeding requested rehearing
of the FERC's phase one order. The FERC denied those requests in its June 1,
2005 order. In addition, several participants, including SFPP, filed petitions
with the United States Court of Appeals for the District of Columbia Circuit for
review of the FERC's phase one order. On August 13, 2004, the FERC filed a
motion to dismiss the pending petitions for review of the phase one order, which
Petitioners, including SFPP, answered on August 30, 2004. On December 20, 2004,
the Court of Appeals referred the FERC's motion to the merits panel and directed
the parties to address the issues in that motion on brief, thus effectively
dismissing the FERC's motion. In the same order, the Court of Appeals granted a
motion to hold the petitions for review of the FERC's phase one order in
abeyance and directed the parties to file motions to govern future proceeding 30
days after FERC disposition of the pending rehearing requests. In August 2005,
the FERC and SFPP jointly moved that the Court of Appeals hold the petitions for
review of the March 26, 2004 and June 1, 2005 orders in abeyance due to the
pendency of further action before the FERC on income tax allowance issues. In
December 2005, the Court of Appeals denied this motion and placed the petitions
seeking review of the two orders on the active docket.
The FERC's phase one order also held that SFPP failed to seek authorization
for the accounting entries necessary to reflect in SFPP's books, and thus in its
annual report to the FERC ("FERC Form 6"), the purchase price adjustment ("PPA")
arising from our 1998 acquisition of SFPP. The phase one order directed SFPP to
file for permission to reflect the PPA in its FERC Form 6 for the calendar year
1998 and each subsequent year. In its April 26, 2004 compliance filing, SFPP
noted that it had previously requested such permission and that the FERC's
regulations require an oil pipeline to include a PPA in its Form 6 without first
seeking FERC permission to do so. Several parties protested SFPP's compliance
filing. In its June 1, 2005 order, the FERC accepted SFPP's compliance filing.
In the June 1, 2005 order, the FERC directed SFPP to file a brief addressing
whether the records developed in the OR92-8 and OR96-2 cases were sufficient to
determine SFPP's entitlement to include an income tax allowance in its rates
under the FERC's new policy statement. On June 16, 2005, SFPP filed its brief
reviewing the pertinent records in the pending cases and applicable law and
demonstrating its entitlement to a full income tax allowance in its interstate
rates. SFPP's opponents in the two cases filed reply briefs contesting SFPP's
presentation. It is not possible to predict with certainty the ultimate
resolution of this issue, particularly given the likelihood that the FERC's
policy statement and its decision in these cases will be appealed to the federal
courts.
On September 9, 2004, the presiding administrative law judge in OR96-2
issued his initial decision in the phase two portion of this proceeding,
recommending establishment of prospective rates and the calculation of
reparations for complaining shippers with respect to the West Line and East
Line, relying upon cost of service determinations generally unfavorable to SFPP.
On December 16, 2005, the FERC issued an order addressing issues remanded by
the Court of Appeals in the Docket No. OR92-8 proceeding (discussed above) and
the phase two cost of service issues, including income tax allowance issues
arising from the briefing directed by the FERC's June 1, 2005 order. The FERC
directed SFPP to submit compliance filings and revised tariffs by February 28,
2006 (as extended to March 7, 2006) which are to address, in addition to the
OR92-8 matters discussed above, the establishment of interim West Line rates
based on a 1999 test year, indexed forward to a May 1, 2006 effective date and
estimated reparations. The FERC also resolved favorably a number of
methodological issues regarding the calculation of SFPP's income tax allowance
under the May 2005 policy statement and, in its compliance filings, directed
SFPP to submit further information establishing the amount of its income tax
allowance for the years at issue in the OR92-8 and OR96-2 proceedings.
SFPP and Navajo have filed requests for rehearing of the December 16, 2005
order. ExxonMobil, BP West Coast Products, Chevron, Ultramar, and ConocoPhillips
have filed petitions for review of the December 16, 2005 order with the United
States Court of Appeals for the District of Columbia Circuit. On February 13,
2006, the FERC issued an order addressing the pending rehearing requests,
granting the majority of SFPP's requested changes regarding reparations and
methodological issues.
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 final outcome will depend, in part, on the outcomes of the
appeals of these proceedings and the OR92-8, et al. proceedings taken by SFPP,
complaining shippers, and an intervenor.
171
We estimated, as of December 31, 2003, that shippers' claims for reparations
totaled approximately $154 million and that prospective rate reductions would
have an aggregate average annual impact of approximately $45 million, with the
reparations amount and interest increasing as the timing for implementation of
rate reductions and the payment of reparations has extended (estimated at a
quarterly increase of approximately $9 million). Based on the December 16, 2005
order, rate reductions will be implemented on May 1, 2006. We now assume that
reparations and accrued interest thereon will be paid no earlier than the first
quarter of 2007; however, the timing, and nature, of any rate reductions and
reparations that may be ordered will likely be affected by the final disposition
of the application of the FERC's new policy statement on income tax allowances
to our Pacific operations in the FERC Docket Nos. OR92-8 and OR96-2 proceedings.
In 2005, we recorded an accrual of $105.0 million for an expense attributable to
an increase in our reserves related to our rate case liability. We had
previously estimated the combined annual impact of the rate reductions and the
payment of reparations sought by shippers would be approximately 15 cents of
distributable cash flow per unit. Based on our review of the FERC's December 16
order and the FERC's February 13 order on rehearing, and subject to the ultimate
resolution of these issues in our compliance filings and subsequent judicial
appeals, we now expect the total annual impact will be less than 15 cents per
unit. The actual, partial year impact on 2006 distributable cash flow per unit
will likely be closer to 5 cents per unit.
Chevron complaint OR02-4 and OR03-5 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 June 30, 2003, Chevron filed another complaint against SFPP (OR03-5) -
substantially similar to its previous complaint - and moved to consolidate the
complaint with the Docket No. OR96-2, et al. proceeding. 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. 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 August 18, 2003, SFPP filed a motion to dismiss Chevron's petition for
review in OR02-4 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 FERC's
decision in OR03-5 consolidated with Chevron's appeal of the FERC's decision in
the OR02-4 proceeding. Following motions to dismiss by the FERC and SFPP, on
December 10, 2004, the Court dismissed Chevron's petition for review in Docket
No. OR03-5 and set Chevron's appeal of the FERC's orders in OR02-4 for briefing.
On January 4, 2005, the Court granted Chevron's request to hold such briefing in
abeyance until after final disposition of the OR96-2 proceeding. Chevron
continues to participate in the Docket No. OR96-2 et al. proceeding as an
intervenor.
Airlines OR04-3 proceeding. On September 21, 2004, America West Airlines,
Inc., Southwest Airlines, Co., Northwest Airlines, Inc. and Continental
Airlines, Inc. (collectively, the "Airlines") filed a complaint against SFPP at
the FERC. The Airlines' complaint alleges that the rates on SFPP's West Line and
SFPP's charge for its gathering enhancement service at Watson Station are not
just and reasonable. The Airlines seek rate reductions and reparations for two
years prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, ConocoPhillips Company, Navajo Refining Company,
L.P., and ChevronTexaco Products Company all filed timely motions to intervene
in this proceeding. Valero Marketing and Supply Company filed a motion to
intervene one day after the deadline. SFPP answered the Airlines' complaint on
October 12, 2004. On October 29, 2004, the Airlines filed a response to SFPP's
answer and on November 12, 2004, SFPP replied to the Airlines' response. In
March and June 2005, the Airlines filed motions seeking expedited action on
their complaint, and in July 2005, the Airlines filed a motion seeking to sever
issues related to the Watson Station gathering enhancement
172
fee from the OR04-3 proceeding and consolidate them in the proceeding regarding
the justness and reasonableness of that fee that the FERC docketed as part of
the June 1, 2005 order. In August 2005, the FERC granted the Airlines' motion to
sever and consolidate the Watson Station fee issues.
OR05-4 and OR05-5 proceedings. On December 22, 2004, BP West Coast Products
LLC and ExxonMobil Oil Corporation filed a complaint against SFPP at the FERC,
which the FERC docketed as OR05-4. The complaint alleges that SFPP's interstate
rates are not just and reasonable, that certain rates found grandfathered by the
FERC are not entitled to such status, and, if so entitled, that "substantially
changed circumstances" have occurred, removing such protection. The complainants
seek rate reductions and reparations for two years prior to the filing of their
complaint and ask that the complaint be consolidated with the Airlines'
complaint in the OR04-3 proceeding. ConocoPhillips Company, Navajo Refining
Company, L.P., and Western Refining Company, L.P. all filed timely motions to
intervene in this proceeding. SFPP answered the complaint on January 24, 2005.
On December 29, 2004, ConocoPhillips filed a complaint against SFPP at the
FERC, which the FERC docketed as OR05-5. The complaint alleges that SFPP's
interstate rates are not just and reasonable, that certain rates found
grandfathered by the FERC are not entitled to such status, and, if so entitled,
that "substantially changed circumstances" have occurred, removing such
protection. ConocoPhillips seeks rate reductions and reparations for two years
prior to the filing of their complaint. BP West Coast Products LLC and
ExxonMobil Oil Corporation, Navajo Refining Company, L.P., and Western Refining
Company, L.P. all filed timely motions to intervene in this proceeding. SFPP
answered the complaint on January 28, 2005.
On February 25, 2005, the FERC consolidated the complaints in Docket Nos.
OR05-4 and OR05-5 and held them in abeyance until after the conclusion of the
various pending SFPP proceedings, deferring any ruling on the validity of the
complaints. On March 28, 2005, BP West Coast and ExxonMobil requested rehearing
of one aspect of the February 25, 2005 order; they argued that any tax allowance
matters in these proceedings could not be decided in, or as a result of, the
FERC's inquiry into income tax allowance in Docket No. PL05-5. On June 8, 2005,
the FERC denied the request for rehearing.
On February 13, 2006, the FERC consolidated the complaints in Docket Nos.
OR03-5, OR04-3, OR05-4, and OR05-5 and set for hearing the portions of those
complaints attacking SFPP's North Line and Oregon Line rates, which rates remain
grandfathered under the Energy Policy Act of 1992. The FERC also indicated in
that order that it would address the remaining portions of these complaints in
the context of its disposition of SFPP's compliance filings in the OR92-8/OR96-2
proceedings.
North Line rate case, IS05-230 proceeding. In April 2005, SFPP filed to
increase its North Line interstate rates to reflect increased costs, principally
due to the installation of replacement pipe between Concord and Sacramento,
California. Under FERC regulations, SFPP was required to demonstrate that there
was a substantial divergence between the revenues generated by its existing
North Line rates and its increased costs. SFPP's rate increase was protested by
various shippers and accepted subject to refund by the FERC. An investigation
and hearing regarding the rate increase is proceeding, with a hearing held in
January and February 2006.
Trailblazer Pipeline Company
On March 22, 2005, Marathon Oil Company filed a formal complaint with the
FERC alleging that Trailblazer Pipeline Company violated the FERC's Negotiated
Rate Policy Statement and the Natural Gas Act by failing to offer a recourse
rate option for its Expansion 2002 capacity and by charging negotiated rates
higher than the applicable recourse rates. Marathon requested that the FERC
require Trailblazer to refund all amounts paid by Marathon above Trailblazer's
Expansion 2002 recourse rate since the facilities went into service in May 2002,
with interest. In addition, Marathon asked the FERC to require Trailblazer to
bill Marathon the Expansion 2002 recourse rate for future billings. Marathon
estimated that the amount of Trailblazer's refund obligation at the time of the
filing was over $15 million. Trailblazer filed its response to Marathon's
complaint on April 13, 2005. On May 20, 2005, the FERC issued an order denying
the Marathon complaint and found that (i) Trailblazer did not violate FERC
policy and regulations and (ii) there is insufficient justification to initiate
further action under Section 5 of the Natural Gas Act to invalidate and change
the negotiated rate. On June 17, 2005, Marathon filed its Request for Rehearing
of the May 20, 2005 order. On January 19, 2006, the FERC issued an order which
denied Marathon's rehearing request.
173
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 may occur within the second quarter of
2006.
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 may be
resolved by the CPUC in the second quarter of 2006.
On November 22, 2004, SFPP filed an application with the CPUC requesting a
$9 million increase in existing intrastate rates to reflect the in-service date
of SFPP's replacement and expansion of its Concord-to-Sacramento pipeline. The
requested rate increase, which automatically became effective as of December 22,
2004 pursuant to California Public Utilities Code Section 455.3, is being
collected subject to refund, pending resolution of protests to the application
by Valero Marketing and Supply Company, Ultramar Inc., BP West Coast Products
LLC, Exxon Mobil Oil Corporation and ChevronTexaco Products Company. The CPUC is
not expected to resolve the matter before the third quarter of 2006.
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, referred to above, such
refunds could total about $6 million per year from October 2002 to the
anticipated date of a CPUC decision.
174
On January 26, 2006, SFPP filed a request for an annual rate increase of
approximately $5.4 million with the CPUC, to be effective as of March 2, 2006.
Protests to SFPP's rate increase application have been filed by Tesoro Refining
and Marketing Company, BP West Coast Products LLC and ExxonMobil Oil
Corporation, Southwest Airlines Company, and Valero Marketing and Supply
Company, Ultramar Inc. and Chevron Products Company, asserting that the
requested rate increase is unreasonable. Pending the outcome of protests to
SFPP's filing, the rate increase, which will be collected in the form of a
surcharge to existing rates, will be collected subject to refund.
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.
Other Regulatory Matters
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 or that such challenges will not have a material adverse effect on our
business, financial position, results of operations or cash flows. 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 a material
adverse effect on our business, financial position, results of operations or
cash flows.
Carbon Dioxide Litigation
Kinder Morgan CO2 Company, L.P., Kinder Morgan G.P., Inc., and Cortez
Pipeline Company were among the named defendants in Shores, et al. v. Mobil Oil
Corp., et al., No. GC-99-01184 (Statutory Probate Court, Denton County, Texas
filed December 22, 1999) and First State Bank of Denton, et al. v. Mobil Oil
Corp., et al., No. 8552-01 (Statutory Probate Court, Denton County, Texas filed
March 29, 2001). These cases were originally filed as class actions on behalf of
classes of overriding royalty interest owners (Shores) and royalty interest
owners (Bank of Denton) for damages relating to alleged underpayment of
royalties on carbon dioxide produced from the McElmo Dome Unit. Although classes
were initially certified at the trial court level, appeals resulted in the
decertification and/or abandonment of the class claims. On February 22, 2005,
the trial judge dismissed both cases for lack of jurisdiction. Some of the
individual plaintiffs in these cases re-filed their claims in new lawsuits
(discussed below).
On May 13, 2004, William Armor, one of the former plaintiffs in the Shores
matter whose claims were dismissed by the Court of Appeals for improper venue,
filed a new case alleging the same claims for underpayment of royalties against
the same defendants previously sued in the Shores case, including Kinder Morgan
CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. Armor v. Shell Oil
Company, et al, No. 04-03559 (14th Judicial District Court, Dallas County, Texas
filed May 13, 2004). Defendants filed their answers and special exceptions on
June 4, 2004. Trial, originally scheduled for July 25, 2005, has been
rescheduled for June 12, 2006.
On May 20, 2005, Josephine Orr Reddy and Eastwood Capital, Ltd., two of the
former plaintiffs in the Bank of Denton matter, filed a new case in Dallas state
district court alleging the same claims for underpayment of royalties. Reddy and
Eastwood Capital, Ltd. v. Shell Oil Company, et al., No. 05-5021 (193rd Judicial
District Court, Dallas County, Texas filed May 20, 2005). The defendants include
Kinder Morgan CO2 Company, L.P. and Kinder Morgan Energy Partners, L.P. On June
23, 2005, the plaintiff in the Armor lawsuit filed a motion to transfer and
consolidate the Reddy lawsuit with the Armor lawsuit. On June 28, 2005, the
court in the Armor lawsuit granted the motion to transfer and consolidate and
ordered that the Reddy lawsuit be transferred and consolidated into the Armor
lawsuit. The defendants filed their answer and special exceptions on August 10,
2005. The consolidated Armor/Reddy trial is set for June 12, 2006.
Shell CO2 Company, Ltd., predecessor in interest to Kinder Morgan CO2
Company, L.P., is among the named counter-claim defendants in Shell Western E&P
Inc. v. Gerald O. Bailey and Bridwell Oil Company; No. 98-28630 (215th Judicial
District Court, Harris County, Texas filed June 17, 1998) (the "Bailey State
Court Action"). The counter-claim plaintiffs are overriding royalty interest
owners in the McElmo Dome Unit and have sued seeking
175
damages for underpayment of royalties on carbon dioxide produced from the McElmo
Dome Unit. In the Bailey State Court Action, the counter-claim plaintiffs
asserted claims for fraud/fraudulent inducement, real estate fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, negligence,
negligence per se, unjust enrichment, violation of the Texas Securities Act, and
open account. The trial court in the Bailey State Court Action granted a series
of summary judgment motions filed by the counter-claim defendants on all of the
counter-plaintiffs' counter-claims except for the fraud-based claims. In 2004,
one of the counter-plaintiffs (Gerald Bailey) amended his counter-suit to allege
purported claims as a private relator under the False Claims Act and antitrust
claims. The federal government elected to not intervene in the False Claims Act
counter-suit. On March 24, 2005, Bailey filed a notice of removal, and the case
was transferred to federal court. Shell Western E&P Inc. v. Gerald O. Bailey and
Bridwell Oil Company, No. H-05-1029 (S.D. Tex., Houston Division removed March
24, 2005) (the "Bailey Houston Federal Court Action"). Also on March 24, 2005,
Bailey filed an instrument under seal in the Bailey Houston Federal Court Action
that was later determined to be a motion to transfer venue of that case to the
federal district court of Colorado, in which Bailey and two other plaintiffs
have filed another suit against Kinder Morgan CO2 Company, L.P. asserting claims
under the False Claims Act. The Houston federal district judge ordered that
Bailey take steps to have the False Claims Act case pending in Colorado
transferred to the Bailey Houston Federal Court Action, and also suggested that
the claims of other plaintiffs in other carbon dioxide litigation pending in
Texas should be transferred to the Bailey Houston Federal Court Action. In
response to the court's suggestion, the case of Gary Shores et al. v. ExxonMobil
Corp. et al., No. 05-1825 (S.D. Tex., Houston Division) was consolidated with
the Bailey Houston Federal Court Action on July 18, 2005. That case, in which
the plaintiffs assert claims for McElmo Dome royalty underpayment, includes
Kinder Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., and Cortez
Pipeline Company as defendants. Bailey requested the Houston federal district
court to transfer the Bailey Houston Federal Court Action to the federal
district court of Colorado. Bailey also filed a petition for writ of mandamus in
the Fifth Circuit Court of Appeals, asking that the Houston federal district
court be required to transfer the case to the federal district court of
Colorado. On June 3, 2005, the Fifth Circuit Court of Appeals denied Bailey's
petition for writ of mandamus. On June 22, 2005, the Fifth Circuit denied
Bailey's petition for rehearing en banc. On September 14, 2005, Bailey filed a
petition for writ of certiorari in the United States Supreme Court, which the
U.S. Supreme Court denied on November 28, 2005. On November 21, 2005, the
federal district court in Colorado transferred Bailey's False Claims Act case
pending in Colorado to the Houston federal district court. On November 30, 2005,
Bailey filed a petition for mandamus seeking to vacate the transfer. The Tenth
Circuit Court of Appeals denied the petition on December 19, 2005. The Houston
federal district court subsequently realigned the parties. Pursuant to the
Houston federal district court's order, Bailey and the other realigned
plaintiffs have filed amended complaints in which they assert claims for
fraud/fraudulent inducement, real estate fraud, negligent misrepresentation,
breach of fiduciary and agency duties, breach of contract and covenants,
violation of the Colorado Unfair Practices Act, civil theft under Colorado law,
conspiracy, unjust enrichment, and open account. Bailey also asserted claims as
a private relator under the False Claims Act and for violation of federal and
Colorado antitrust laws. The realigned plaintiffs seek actual damages, treble
damages, punitive damages, a constructive trust and accounting, and declaratory
relief. Kinder Morgan CO2 Company, L.P. and the Shell plaintiffs have filed a
motion for partial summary judgment and, pursuant to the Houston federal
district court's order, will file a motion for summary judgment on all claims.
No current trial date is set.
On March 1, 2004, Bridwell Oil Company, one of the named
defendants/realigned plaintiffs in the Bailey actions, filed a new matter in
which it asserts claims which are virtually identical to the counter-claims it
asserts against Shell CO2 Company, Ltd. in the Bailey lawsuit. Bridwell Oil Co.
v. Shell Oil Co. et al, No. 160,199-B (78th Judicial District Court, Wichita
County, Texas filed March 1, 2004). The defendants in this action include Kinder
Morgan CO2 Company, L.P., Kinder Morgan Energy Partners, L.P., various Shell
entities, ExxonMobil entities, and Cortez Pipeline Company. On June 25, 2004,
defendants filed answers, special exceptions, pleas in abatement, and motions to
transfer venue back to the Harris County District Court. On January 31, 2005,
the Wichita County judge abated the case pending resolution of the Bailey State
Court Action. The case remains abated.
Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company are among the
named defendants in Celeste C. Grynberg, et al. v. Shell Oil Company, et al.,
No. 98-CV-43 (Colo. Dist. Ct., Montezuma County filed March 2, 1998). This case
involves claims by overriding royalty interest owners in the McElmo Dome and Doe
Canyon Units seeking damages for underpayment of royalties on carbon dioxide
produced from the McElmo Dome Unit, failure to develop carbon dioxide reserves
at the Doe Canyon Unit, and failure to develop hydrocarbons at both McElmo Dome
and Doe Canyon. The plaintiffs also possess a small working interest at Doe
Canyon. Plaintiffs claim breaches of contractual and potential fiduciary duties
owed by the defendants and also allege other theories of
176
liability including breach of covenants, civil theft, conversion,
fraud/fraudulent concealment, violation of the Colorado Organized Crime Control
Act, deceptive trade practices, and violation of the Colorado Antitrust Act. In
addition to actual or compensatory damages, plaintiffs seek treble damages,
punitive damages, and declaratory relief relating to the Cortez Pipeline tariff
and the method of calculating and paying royalties on McElmo Dome carbon
dioxide. The Court denied plaintiffs' motion for summary judgment concerning
alleged underpayment of McElmo Dome overriding royalties on March 2, 2005. The
parties are continuing to engage in discovery. No trial date is currently set.
Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor in
interest to Shell CO2 Company, Ltd., are among the named defendants in CO2
Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November
28, 2005. The arbitration arises from a dispute over a class action settlement
agreement which became final on July 7, 2003 and disposed of five lawsuits
formerly pending in the U.S. District Court, District of Colorado. The
plaintiffs in such lawsuits primarily included overriding royalty interest
owners, royalty interest owners, and small share working interest owners who
alleged underpayment of royalties and other payments on carbon dioxide produced
from the McElmo Dome Unit in southwest Colorado. The settlement imposed certain
future obligations on the defendants in the underlying litigation. The plaintiff
in the current arbitration is an entity that was formed as part of the
settlement for the purpose of monitoring compliance with the obligations imposed
by the settlement agreement. The plaintiff alleges that, in calculating royalty
and other payments, defendants used a transportation expense in excess of what
is allowed by the settlement agreement, thereby causing alleged underpayments of
approximately $10.3 million. The plaintiff also alleges that Cortez Pipeline
Company should have used certain funds to further reduce its debt, which, in
turn, would have allegedly increased the value of royalty and other payments by
approximately $0.2 million. Defendants deny that there was any breach of the
settlement agreement. The arbitration is currently scheduled to commence on June
26, 2006.
J. Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually
and on behalf of all other private royalty and overriding royalty owners in the
Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan
CO2 Company, L.P., No. 04-26-CL (8th Judicial District Court, Union County New
Mexico)
Involves a purported class action against Kinder Morgan CO2 Company, L.P.
alleging that it has failed to pay the full royalty and overriding royalty
("royalty interests") on the true and proper settlement value of compressed
carbon dioxide produced from the Bravo Dome Unit in the period beginning January
1, 2000. The complaint purports to assert claims for violation of the New Mexico
Unfair Practices Act, constructive fraud, breach of contract and of the covenant
of good faith and fair dealing, breach of the implied covenant to market, and
claims for an accounting, unjust enrichment, and injunctive relief. The
purported class is comprised of current and former owners, during the period
January 2000 to the present, who have private property royalty interests
burdening the oil and gas leases held by the defendant, excluding the
Commissioner of Public Lands, the United States of America, and those private
royalty interests that are not unitized as part of the Bravo Dome Unit. The
plaintiffs allege that they were members of a class previously certified as a
class action by the United States District Court for the District of New Mexico
in the matter Doris Feerer, et al. v. Amoco Production Company, et al., USDC
N.M. Civ. No. 95-0012 (the "Feerer Class Action"). Plaintiffs allege that Kinder
Morgan CO2 Company's method of paying royalty interests is contrary to the
settlement of the Feerer Class Action. Kinder Morgan CO2 Company has filed a
Motion to Compel Arbitration of this matter pursuant to the arbitration
provisions contained in the Feerer Class Action Settlement Agreement, which
motion was denied by the trial court. An appeal of that ruling has been filed
and is pending before the New Mexico Court of Appeals. No date for arbitration
or trial is currently set. Oral arguments are scheduled to take place before the
New Mexico Court of Appeals on March 23, 2006.
In addition to the matters listed above, various audits and administrative
inquiries concerning Kinder Morgan CO2 Company L.P.'s royalty and tax payments
on carbon dioxide produced from the McElmo Dome Unit are currently ongoing.
These audits and inquiries involve various federal agencies, the State of
Colorado, the Colorado oil and gas commission, and Colorado county taxing
authorities.
177
Commercial Litigation Matters
Union Pacific Railroad Company Easements
SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern
Pacific Transportation Company) are engaged in two proceedings 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 UPRR should be adjusted pursuant to existing
contractual arrangements for each of the ten year periods beginning January 1,
1994 and January 1, 2004 (Southern Pacific Transportation Company vs. Santa Fe
Pacific Corporation, SFP Properties, Inc., Santa Fe Pacific Pipelines, Inc.,
SFPP, L.P., et al., Superior Court of the State of California for the County of
San Francisco, filed August 31, 1994; and Union Pacific Railroad Company vs.
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D",
Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for
the County of Los Angeles, filed July 28, 2004). On July 16, 2003, the trial
court set the rent for years 1994 - 2003 at approximately $5.0 million per year
as of January 1, 1994, subject to annual inflation increases throughout the ten
year period. On February 23, 2005, the California Court of Appeals affirmed the
trial court's ruling, except that it reversed a small portion of the decision
and remanded it back to the trial court for determination. On remand, the trial
court held that there was no adjustment to the rent relating to the portion of
the decision that was reversed, but awarded Southern Pacific Transportation
Company interest on rental amounts owing as of May 7, 1997. We do not believe
that the assessment of interest by the trial court was proper and intend to
appeal that award.
In addition, SFPP, L.P. and Union Pacific Railroad Company are engaged in a
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 UPRR should be
adjusted pursuant to existing contractual arrangements for the ten year period
beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific
Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. "D", Kinder Morgan
G.P., Inc., et al., Superior Court of the State of California for the County of
Los Angeles, filed July 28, 2004). SFPP was served with this lawsuit on August
17, 2004. SFPP expects that the trial in this matter will occur in late 2006.
ARB, Inc. Dispute
ARB, Inc, a general contractor engaged by SFPP, L.P. to build a 20-inch
diameter, 70-mile pipeline from Concord to Sacramento, California, and numerous
third party contractors recorded liens against SFPP, L.P. based on an assertion
that SFPP, L.P. owed ARB, Inc. and third party contractors additional payments
ranging from $13.1 million to $16.8 million on the project. SFPP, L.P. engaged
construction claims specialists and auditors to review project records and
determine what additional payments, if any, should be made. On or about
September 15, 2005, SFPP, L.P. agreed to settle all disputes with ARB, Inc. and
third party contractors for substantially less than the recorded lien amounts.
As part of the settlement, all recorded liens and other potential claims arising
from the construction project were released with prejudice.
RSM Production Company, et al. v. Kinder Morgan Energy Partners, L.P., et
al. (Cause No. 4519, in the District Court, Zapata County Texas, 49th Judicial
District).
On October 15, 2001, Kinder Morgan Energy Partners, L.P. was served with the
First Supplemental Petition filed by RSM Production Corporation on behalf of the
County of Zapata, State of Texas and Zapata County Independent School District
as plaintiffs. Kinder Morgan Energy Partners, L.P. was sued in addition to 15
other defendants, including two other Kinder Morgan affiliates. Certain entities
we acquired in the Kinder Morgan Tejas acquisition are also defendants in this
matter. The Petition alleges that these taxing units relied on the reported
volume and analyzed heating content of natural gas produced from the wells
located within the appropriate taxing jurisdiction in order to properly assess
the value of mineral interests in place. The suit further alleges that the
defendants undermeasured the volume and heating content of that natural gas
produced from privately owned wells in Zapata County, Texas. The Petition
further alleges that the County and School District were deprived of ad valorem
tax revenues as a result of the alleged undermeasurement of the natural gas by
the defendants. On December 15, 2001, the defendants filed motions to transfer
venue on jurisdictional grounds. On June 12, 2003, plaintiff served discovery
requests on certain defendants. On July 11, 2003, defendants moved to stay any
responses to such discovery.
178
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 Claims
Act and involves allegations of mismeasurement of natural gas produced from
federal and Indian lands. The Department of Justice has decided not to intervene
in support of the action. The complaint is part of a larger series of similar
complaints filed by Mr. Grynberg against 77 natural gas pipelines (approximately
330 other defendants). Certain entities we acquired in the Kinder Morgan Tejas
acquisition are also defendants in this matter. An earlier single action making
substantially similar allegations against the pipeline industry was dismissed by
Judge Hogan of the U.S. District Court for the District of Columbia on grounds
of improper joinder and lack of jurisdiction. As a result, Mr. Grynberg filed
individual complaints in various courts throughout the country. In 1999, these
cases were consolidated by the Judicial Panel for Multidistrict Litigation, and
transferred to the District of Wyoming. The multidistrict litigation matter is
called In Re Natural Gas Royalties Qui Tam Litigation, Docket No. 1293. Motions
to dismiss were filed and an oral argument on the motion to dismiss occurred on
March 17, 2000. On July 20, 2000, the United States of America filed a motion to
dismiss those claims by Grynberg that deal with the manner in which defendants
valued gas produced from federal leases, referred to as valuation claims. Judge
Downes denied the defendant's motion to dismiss on May 18, 2001. The United
States' motion to dismiss most of plaintiff's valuation claims has been granted
by the court. Grynberg has appealed that dismissal to the 10th Circuit, which
has requested briefing regarding its jurisdiction over that appeal.
Subsequently, Grynberg's appeal was dismissed for lack of appellate
jurisdiction. Discovery to determine issues related to the Court's subject
matter jurisdiction arising out of the False Claims Act is complete. Briefing
has been completed and oral arguments on jurisdiction were held before the
Special Master on March 17 and 18, 2005. On May 7, 2003, Grynberg sought leave
to file a Third Amended Complaint, which adds allegations of undermeasurement
related to carbon dioxide production. Defendants have filed briefs opposing
leave to amend. Neither the Court nor the Special Master has ruled on Grynberg's
Motion to Amend.
On May 13, 2005, the Special Master issued his Report and Recommendations to
Judge Downes in the In Re Natural Gas Royalties Qui Tam Litigation, Docket No.
1293. The Special Master found that there was a prior public disclosure of the
mismeasurement fraud Grynberg alleged, and that Grynberg was not an original
source of the allegations. As a result, the Special Master recommended dismissal
of the Kinder Morgan defendants on jurisdictional grounds. On June 27, 2005,
Grynberg filed a motion to modify and partially reverse the Special Master's
recommendations and the Defendants filed a motion to adopt the Special Master's
recommendations with modifications. An oral argument was held on December 9,
2005 on the motions concerning the Special Master's recommendations. It is
likely that Grynberg will appeal any dismissal to the 10th Circuit Court of
Appeals.
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 alleged 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.
On March 24, 2005, we announced a settlement of this case. Under the terms
of the settlement, we agreed to pay $25 million to the defendants in full
settlement of any possible claims related to this case. We included this amount
as general and administrative expense in March 2005, and we made payment in
April 2005.
Weldon Johnson and Guy Sparks, individually and as Representative of Others
Similarly Situated v. Centerpoint Energy, Inc. et. al., No. 04-327-2 (Circuit
Court, Miller County Arkansas).
On October 8, 2004, plaintiffs filed the above-captioned matter against
numerous defendants including Kinder Morgan Texas Pipeline L.P.; Kinder Morgan
Energy Partners, L.P.; Kinder Morgan G.P., Inc.; KM Texas Pipeline, L.P.; Kinder
Morgan Texas Pipeline G.P., Inc.; Kinder Morgan Tejas Pipeline G.P., Inc.;
Kinder Morgan Tejas Pipeline, L.P.; Gulf Energy Marketing, LLC; Tejas Gas, LLC;
and Midcon Corp. (the "Kinder Morgan
179
Defendants"). The Complaint purports to bring a class action on behalf of those
who purchased natural gas from the Centerpoint defendants from October 1, 1994
to the date of class certification.
The Complaint alleges that Centerpoint Energy, Inc., by and through its
affiliates, has artificially inflated the price charged to residential consumers
for natural gas that it allegedly purchased from the non-Centerpoint defendants,
including the above-listed Kinder Morgan entities. The Complaint further alleges
that in exchange for Centerpoint's purchase of such natural gas at above market
prices, the non-Centerpoint defendants, including the above-listed Kinder Morgan
entities, sell natural gas to Centerpoint's non-regulated affiliates 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, unlawful enrichment and civil conspiracy
against all of the defendants, and seeks relief in the form of actual, exemplary
and punitive damages, interest, and attorneys' fees. The Complaint was served on
the Kinder Morgan Defendants on October 21, 2004. On November 18, 2004, the
Centerpoint Defendants removed the case to the United States District Court,
Western District of Arkansas, Texarkana Division, Civ. Action No. 04-4154. On
January 26, 2005, the Plaintiffs moved to remand the case back to state court,
which motion was granted on June 2, 2005. On July 11, 2005, the Kinder Morgan
Defendants filed a Motion to Dismiss the Complaint, which motion is currently
pending. On October 3, 2005, the court issued a Scheduling and Case Management
Order in which it ordered that discovery could proceed, scheduled a hearing on
certain of the Kinder Morgan Defendants' Motions to Dismiss for February 14,
2006, deferred certain other motions to August 15, 2006, and scheduled a class
certification hearing, if necessary, for March 16, 2006. 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.
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 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 from November 1987 through March 1997 in the
amount of $30.7 million. On May 2, 2003, Plaintiff added claims for the period
from 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 matter went to trial on June 21, 2004. On June 30, 2004, the jury returned a
unanimous verdict in favor of all defendants as to all counts. Final Judgment
was entered in favor of the defendants on August 19, 2004. Plaintiff has
appealed the jury's verdict to the 14th Court of Appeals for the State of Texas.
On February 21, 2006, the Court of Appeals unanimously affirmed the judgment in
our favor entered by the trial court, and ordered ExxonMobil to pay
180
all costs incurred in the appeal. ExxonMobil has 45 days to file an appeal of
this decision to the Texas Supreme Court.
Cannon Interests-Houston v. Kinder Morgan Texas Pipeline, L.P., No.
2005-36174 (333rd Judicial District, Harris County, Texas).
On June 6, 2005, after unsuccessful mediation, Cannon Interests sued Kinder
Morgan Texas Pipeline, L.P. and alleged breach of contract for the purchase of
natural gas storage capacity and for failure to pay under a profit-sharing
arrangement. KMTP counterclaimed that Cannon Interests failed to provide it with
five billion cubic feet of winter storage capacity in breach of the contract.
The plaintiff is claiming approximately $13 million in damages. The parties are
in the discovery phase. A trial date has been set for September 18, 2006. KMTP
will defend the case vigorously, and based upon the information available to
date, it believes that the claims against it are without merit and will be more
than offset by its claims against Cannon-Interests.
Federal Investigation at Cora and Grand Rivers Coal Facilities
On June 22, 2005, we announced that the Federal Bureau of Investigation is
conducting an investigation related to our coal terminal facilities located in
Rockwood, Illinois and Grand Rivers, Kentucky. The investigation involves
certain coal sales from our Cora, Illinois and Grand Rivers, Kentucky coal
terminals that occurred from 1997 through 2001. During this time period, we sold
excess coal from these two terminals for our own account, generating less than
$15 million in total net sales. Excess coal is the weight gain that results from
moisture absorption into existing coal during transit or storage and from scale
inaccuracies, which are typical in the industry. During the years 1997 through
1999, we collected, and, from 1997 through 2001, we subsequently sold, excess
coal for our own account, as we believed we were entitled to do under
then-existing customer contracts.
We have conducted an internal investigation of the allegations and
discovered no evidence of wrongdoing or improper activities at these two
terminals. Furthermore, we have contacted customers of these terminals during
the applicable time period and have offered to share information with them
regarding our excess coal sales. Over the five year period from 1997 to 2001, we
moved almost 75 million tons of coal through these terminals, of which less than
1.4 million tons were sold for our own account (including both excess coal and
coal purchased on the open market). We have not added to our inventory of excess
coal since 1999 and we have not sold coal for our own account since 2001, except
for minor amounts of scrap coal. We are fully cooperating with federal law
enforcement authorities in this investigation. In September 2005 and subsequent
thereto, we responded to a subpoena in this matter by producing a large volume
of documents, which, we understand, is being reviewed by the FBI and auditors
from the Tennessee Valley Authority, which is a customer of the Cora and Grand
Rivers terminals. We do not expect that the resolution of the investigation will
have a material adverse impact on our business, financial position, results of
operations or cash flows.
Queen City Railcar Litigation
On August 28, 2005, a railcar containing the chemical styrene began leaking
styrene gas in Cincinnati, Ohio while en route to our Queen City Terminal. The
railcar was sent by the Westlake Chemical Corporation from Louisiana,
transported by Indiana & Ohio Railway, and consigned to Westlake at its
dedicated storage tank at Queen City Terminals, Inc., a subsidiary of Kinder
Morgan Bulk Terminals, Inc. The railcar leak resulted in the evacuation of many
residents and the alleged temporary closure of several businesses in the
Cincinnati area. Within three weeks of the incident, seven separate class action
complaints were filed in the Hamilton County Court of Common Pleas, including
case numbers: A0507115, A0507120, A0507121, A0507149, A0507322, A0507332, and
A0507913. In addition, a complaint was filed by the city of Cincinnati,
described further below.
On September 28, 2005, the court consolidated the complaints under
consolidated case number A0507913. Concurrently, thirteen designated class
representatives filed a Master Class Action Complaint against Westlake Chemical
Corporation, Indiana and Ohio Railway Corporation, Queen City Terminals, Inc.,
Kinder Morgan Liquids Terminals, LLC, Kinder Morgan GP, Inc. and Kinder Morgan
Energy Partners, L.P., collectively the defendants, in the Hamilton County Court
of Common Pleas, case number A0507105. The complaint alleges negligence,
absolute nuisance, nuisance, trespass, negligence per se, and strict liability
against all defendants stemming from the styrene leak. The complaint seeks
compensatory damages in excess of $25,000, punitive damages, pre and
post-judgment
181
interest, and attorney fees. The claims against the Indiana and Ohio Railway and
Westlake are based generally on an alleged failure to deliver the railcar in a
timely manner which allegedly caused the styrene to become unstable and leak
from the railcar. The plaintiffs allege that we had a legal duty to monitor the
movement of the railcar en route to our terminal and guarantee its timely
arrival in a safe and stable condition.
On October 28, 2005, we filed an answer denying the material allegations of
the complaint. On December 1, 2005, the plaintiffs filed a motion for class
certification. On December 12, 2005, we filed a motion for an extension of time
to respond to plaintiffs' motion for class certification in order to conduct
discovery regarding class certification. On February 10, 2005, the court granted
our motion for additional time to conduct class discovery. The court has not
established a scheduling order or trial date, and discovery is ongoing.
On September 6, 2005, the city of Cincinnati, the plaintiff, filed a
complaint on behalf of itself and in parens patriae against Westlake, Indiana
and Ohio Railway, Kinder Morgan Liquids Terminals, LLC, Queen City Terminals,
Inc. and Kinder Morgan GP, Inc., collectively the defendants, in the Court of
Common Pleas, Hamilton County, Ohio, case number A0507323. Plaintiff's complaint
arose out of the same railcar incident reported immediately above. The
plaintiff's complaint alleges public nuisance, negligence, strict liability, and
trespass. The complaint seeks compensatory damages in excess of $25,000,
punitive damages, pre and post-judgment interest, and attorney fees. On
September 28, 2005, Kinder Morgan filed a motion to dismiss the parens patriae
claim. On December 15, 2005, Kinder Morgan filed a motion for summary judgment.
The plaintiff has not responded to either motion. A trial date has not been set.
Leukemia Cluster Litigation
We are a party to several lawsuits in Nevada that allege that the plaintiffs
have developed leukemia as a result of exposure to harmful substances. 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 these matters are without merit and intend
to defend against them vigorously. The following is a summary of these cases.
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.
182
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 filed a Notice of Appeal to the United
States Court of Appeals for the 9th Circuit. On March 15, 2004, the 9th Circuit
affirmed the dismissal of this case.
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 April 13, 2004,
plaintiffs' counsel voluntarily stipulated to a dismissal with prejudice of the
entire case in State Court. The court has accepted the stipulation and the case
was dismissed on April 27, 2004.
Also on June 20, 2003, the plaintiffs in the previously filed Galaz matters
(now dismissed) 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, 2004. The Motion to Dismiss was granted with prejudice on April 30,
2004. On May 7, 2004, Plaintiff filed a Notice of Appeal in the United States
Court of Appeals for the 9th Circuit. Briefing and oral argument of the appeal
have been completed and the parties are awaiting a decision.
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. 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 (ultra hazardous acts), and aiding and abetting, and
seek unspecified special, general and punitive damages. The Jernee case has been
consolidated for pretrial purposes with the Sands case (see below). Plaintiffs
have filed a Third Amended Complaint and all defendants have filed motions to
dismiss all causes of action excluding plaintiffs' cause of action for
negligence. Plaintiffs have filed opposition to such motions, and defendants'
replies in support of motions to dismiss and motions to strike portions of the
complaint are due to be filed on or before March 7, 2006. As is its practice,
the court has not scheduled argument on any such motions.
In addition to the above, the parties have filed motions to implement Case
Management Orders, the Jernee matter having now been deemed "complex" by the
court. Such orders are designed to stage discovery, motions and pretrial
183
proceedings. The court has not scheduled a hearing with respect to the
implementation of any Case Management Order at this time.
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. The Kinder Morgan defendants were served with
the Complaint on January 10, 2004. 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 (ultra hazardous acts), and aiding
and abetting, and seek unspecified special, general and punitive damages. The
Sands case has been consolidated for pretrial purposes with the Jernee case (see
above). Plaintiffs have filed a Second Amended Complaint and all defendants have
filed motions to dismiss all causes of action excluding plaintiffs' cause of
action for negligence. Plaintiffs have filed opposition to such motions, and
defendants' replies in support of motions to dismiss and motions to strike
portions of the complaint are due to be filed on or before March 7, 2006. As is
its practice, the court has not scheduled argument on any such motions.
In addition to the above, the parties have filed motions to implement Case
Management Orders, the Sands matter having now been deemed "complex" by the
court. Such orders are designed to stage discovery, motions and pretrial
proceedings. The court has not scheduled a hearing with respect to the
implementation of any Case Management Order at this time.
Pipeline Integrity and Releases
Meritage Homes Corp., Monterey Homes Construction, Inc., and Monterey Homes
Arizona, Inc. v. Kinder Morgan Energy Partners, L.P. and SFPP Limited
Partnership, No. CIV 05 021 TUCCKJ, United States District Court, Arizona.
On January 28, 2005, Meritage Homes Corp. and its above-named affiliates
filed a Complaint in the above-entitled action against us and SFPP, LP. The
Plaintiffs are homebuilders who constructed a subdivision known as Silver Creek
II located in Tucson, Arizona. Plaintiffs allege that, as a result of a July 30,
2003 pipeline rupture and accompanying release of petroleum products, soil and
groundwater adjacent to, on and underlying portions of Silver Creek II became
contaminated. Plaintiffs allege that they have incurred and continue to incur
costs, damages and expenses associated with the delay of closings of home sales
within Silver Creek II and damage to their reputation and goodwill as a result
of the rupture and release. Plaintiffs' complaint purports to assert claims for
negligence, breach of contract, trespass, nuisance, strict liability,
subrogation and indemnity, and negligence per se. Plaintiffs seek "no less than
$1,500,000 in compensatory damages and necessary response costs," a declaratory
judgment, interest, punitive damages and attorneys' fees and costs. The parties
have agreed to submit the claims to arbitration and are currently engaged in
discovery. We dispute the legal and factual bases for many of Plaintiffs'
claimed compensatory damages, deny that punitive damages are appropriate under
the facts, and intend to vigorously defend this action.
Walnut Creek, California Pipeline Rupture
On November 9, 2004, Mountain Cascade, Inc., a third-party contractor on a
water main replacement project hired by East Bay Municipal Utility District,
struck and ruptured an underground petroleum pipeline owned and operated by
SFPP, LP in Walnut Creek, California. An explosion occurred immediately
following the rupture that resulted in five fatalities and several injuries to
employees or contractors of Mountain Cascade. The explosion and fire also caused
other property damage.
184
On May 5, 2005, the California Division of Occupational Safety and Health
("CalOSHA") issued two civil citations against us relating to this incident
assessing civil fines of $140,000 based upon our alleged failure to mark the
location of the pipeline properly prior to the excavation of the site by the
contractor. CalOSHA, with the assistance of the Contra Costa County District
Attorney's office, is continuing to investigate the facts and circumstances
surrounding the incident for possible criminal violations. In addition, on June
27, 2005, the Office of the California State Fire Marshal, Pipeline Safety
Division ("CSFM") issued a Notice of Violation against us which also alleges
that we did not properly mark the location of the pipeline in violation of state
and federal regulations. The CSFM assessed a proposed civil penalty of $500,000.
The location of the incident was not our work site, nor did we have any direct
involvement in the water main replacement project. We believe that SFPP acted in
accordance with applicable law and regulations, and further that according to
California law, excavators, such as the contractor on the project, must take the
necessary steps (including excavating with hand tools) to confirm the exact
location of a pipeline before using any power operated or power driven
excavation equipment. Accordingly, we disagree with certain of the findings of
CalOSHA and the CSFM, and we have appealed the civil penalties while, at the
same time, continuing to work cooperatively with CalOSHA and the CSFM to resolve
these matters.
As a result of the accident, fifteen separate lawsuits have been filed.
Eleven are personal injury and wrongful death actions. These are: Knox, et al.
v.. Mountain Cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-00281); Farley
v. Mountain cascade, et al. (Contra Costa Sup. Ct. Case No. C 05-01573); Reyes,
et al. v. East Bay Municipal Utility District, et al. (Alameda Sup. Ct. Case No.
RG-05-207720); Arias, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case No.
RG-05-195567); Angeles, et al. v. Kinder Morgan, et al. (Alameda Sup. Ct. Case
No. RG-05-195680); Ramos, et al. v. East Bay Municipal Utility District, et al.
(Contra Costa County Superior Court Case No. C05-01840); Taylor, et al. v. East
Bay Municipal Utility District, et al. (Contra Costa County Superior Court Case
No. C05-02306); Becerra v. Kinder Morgan Energy Partners, L.P., et al., (Contra
Costa County Superior Court Case No. C05-02451); Im, et al. v. Kinder Morgan,
Inc. et al. (Contra Costa County Superior Court Case No. C05-02077); Paasch, et
al. v. East Bay Municipal Utility District, et al. (Contra Costa County Superior
Court Case No. C05-01844); and Fuentes et al. v. Kinder Morgan, et al. (Contra
Costa County Superior Court Case No. C05-02286). These complaints all allege
that SFPP/Kinder Morgan failed to properly field mark the area where the
accident occurred. All of these plaintiffs seek compensatory and punitive
damages. These complaints also allege that the general contractor who struck the
pipeline, Mountain Cascade, Inc. ("MCI"), and EBMUD were at fault for
negligently failing to locate the pipeline. Some of these complaints also name
various engineers on the project for negligently failing to draw up adequate
plans indicating the bend in the pipeline. A number of these actions also name
Comforce Technical Services as a defendant. Comforce supplied SFPP with
temporary employees/independent contractors who performed line marking and
inspections of the pipeline on behalf of SFPP. Some of these complaints also
named various governmental entities--such as the City of Walnut Creek, Contra
Costa County, and the Contra Costa Flood Control and Water Conservation
District--as defendants.
Two of the fifteen suits are related to alleged damage to a residence near
the accident site. These are: USAA v. East Bay Municipal Utility District, et
al., (Contra Costa County Superior Court Case No. C05-02128); and Chabot v. East
Bay Municipal Utilities District, et al., (Contra Costa Superior Court Case No.
C05-02312). The remaining two suits are by MCI and the welding subcontractor,
Matamoros. These are: Matamoros v. Kinder Morgan Energy Partners, L.P., et al.,
(Contra Costa County Superior Court Case No. C05-02349); and Mountain Cascade,
Inc. v. Kinder Morgan Energy Partners, L.P., et al, (Contra Costa County
Superior Court Case No. C-05-02576). Like the personal injury and wrongful death
suits, these lawsuits allege that SFPP/Kinder Morgan failed to properly mark its
pipeline, causing damage to these plaintiffs. The Chabot and USAA plaintiffs
allege property damage, while MCI and Matamoros Welding allege damage to their
business as a result of SFPP/Kinder Morgan's alleged failures, as well as
indemnity and other common law and statutory tort theories of recovery.
Fourteen of these lawsuits are currently coordinated in Contra Costa County
Superior Court; the fifteenth is expected to be coordinated with the other
lawsuits in the near future. There are also several cross-complaints for
indemnity between the co-defendants in the coordinated lawsuits.
Based upon our investigation of the cause of the rupture of SFPP, LP's
petroleum pipeline by Mountain Cascade, Inc. and the resulting explosion and
fire, we intend to deny liability for the resulting deaths, injuries and
damages, to vigorously defend against such claims, and to seek contribution and
indemnity from the responsible parties.
185
Cordelia, California
On April 28, 2004, we discovered a spill of diesel fuel into a marsh near
Cordelia, California from a section of our Pacific operations' 14-inch Concord
to Sacramento, California products pipeline. Estimates indicated that the size
of the spill was approximately 2,450 barrels. Upon discovery of the spill and
notification to regulatory agencies, a unified response was implemented with the
United States Coast Guard, the California Department of Fish and Game, the
Office of Spill Prevention and Response and us. The damaged section of the
pipeline was removed and replaced, and the pipeline resumed operations on May 2,
2004. We have completed recovery of diesel from the marsh and have completed an
enhanced biodegradation program for removal of the remaining constituents bound
up in soils. The property has been turned back to the owners for its stated
purpose. There will be ongoing monitoring under the oversight of the California
Regional Water Quality Control Board until the site conditions demonstrate there
are no further actions required.
In April 2005, we were informed by the office of the Attorney General of
California that the office was contemplating filing criminal charges against us
claiming discharge of diesel fuel arising from the April 2004 rupture and the
failure to make timely notice of the discharge to appropriate state agencies. In
addition, we were told that the California Attorney General was also
contemplating filing charges alleging other releases and failures to provide
timely notice regarding certain environmental incidents at certain of our
facilities in California.
On April 26, 2005, we announced that we had entered into an agreement with
the Attorney General of the State of California and the District Attorney of
Solano County, California, to settle misdemeanor charges of the unintentional,
non-negligent discharge of diesel fuel resulting from this release and the
failure to provide timely notice of a threatened discharge to appropriate state
agencies as well as other potential claims in California regarding alleged
notice and discharge incidents. In addition to the charges settled by this
agreement, we entered into an agreement in principle to settle similar
additional misdemeanor charges in Los Angeles County, California, in connection
with the unintentional, non-negligent release of approximately five gallons of
diesel fuel at our Carson refined petroleum products terminal in Los Angeles
Harbor in May 2004.
Under the settlement agreement related to the Cordelia, California incident,
SFPP, L.P. agreed to plead guilty to four misdemeanors and to pay approximately
$5.2 million in fines, penalties, restitution, environmental improvement project
funding, and enforcement training in the State of California, and agreed to be
placed on informal, unsupervised probation for a term of three years. Under the
settlement agreement related to the Carson terminal incident, we agreed to plead
guilty to two additional misdemeanors and to pay approximately $0.2 million in
fines and penalties.
In addition, we are currently in negotiations with the United States
Environmental Protection Agency, the United States Fish & Wildlife Service, the
California Department of Fish & Game and the San Francisco Regional Water
Quality Control Board regarding potential civil penalties and natural resource
damages assessments. In 2005, we have included a combined $8.4 million as
general and administrative expense related to these environmental issues, and we
have made payments in the amount of $5.4 million as of December 31, 2005. Since
the April 2004 release in the Suisun Marsh area near Cordelia, California, we
have cooperated fully with federal and state agencies and have worked diligently
to remediate the affected areas. As of December 31, 2005, the remediation was
substantially complete.
Baker, California
In November 2004, our CALNEV pipeline, which transports refined petroleum
products from Colton, California to Las Vegas, Nevada, experienced a failure in
the line from external damage, resulting in a release of gasoline that affected
approximately two acres of land in the high desert administered by The Bureau of
Land Management, an agency within the U.S. Department of the Interior.
Remediation has been conducted and continues for product in the soils. All
agency requirements have been met and the site will be closed upon completion of
the soil remediation.
186
Oakland, California
In February 2005, we were contacted by the U.S. Coast Guard regarding a
potential release of jet fuel in the Oakland, California area. Our northern
California team responded and discovered that one of our product pipelines had
been damaged by a third party, which resulted in a release of jet fuel which
migrated to the storm drain system. We have coordinated the remediation of the
impacts from this release, and are investigating the identity of the third party
who damaged the pipeline in order to obtain contribution, indemnity, and to
recover any damages associated with the rupture. We have recently been informed
that the United States Environmental Protection Agency, the San Francisco Bay
Regional Water Quality Control Board, the California Department of Fish and
Game, and possibly the County of Alameda are planning to assert civil penalty
claims with respect to this release. We expect to receive a collective demand on
behalf of these agencies in the very near future. We will vigorously contest any
unsupported, duplicative or excessive civil penalty claims, but hope to be able
to eventually resolve the demands by each governmental entity through
out-of-court settlements.
Donner Summit, California
In April 2005, our SFPP pipeline in Northern California, which transports
refined petroleum products to Reno, Nevada, experienced a failure in the line
from external damage, resulting in a release of product that affected a limited
area adjacent to the pipeline near the summit of Donner Pass. The release was
located on land administered by the Forest Service, an agency within the U.S.
Department of Agriculture. Initial remediation has been conducted in the
immediate vicinity of the pipeline. All agency requirements have been met and
the site will be closed upon completion of the remediation. We have been
informed that we will soon receive civil penalty claims on behalf of the United
States Environmental Protection Agency, the California Department of Fish and
Game, and perhaps the Lahontan Regional Water Quality Control Board. We will try
to obtain out-of-court settlements with respect to any civil penalty demands
made by these agencies.
Long Beach, California
In May 2005, our SFPP, L.P. pipeline in Long Beach, California experienced
a failure at the block valve and affected a limited area adjacent to the
pipeline. The release was located along the Southern California Edison power
line right-of-way and also affected a botanical nursery. Initial remediation has
been conducted and no further remediation appears to be necessary. All agency
requirements have been met and this site will be closed upon completion of the
remediation.
El Paso, Texas
In May 2005, our SFPP, L.P. pipeline in El Paso, Texas experienced a
failure on the 12-inch line located on the Fort Bliss Army Base. Initial
remediation has been conducted and we are conducting an evaluation to determine
the extent of impacts. All agency requirements have been met and this site will
be closed upon completion of the remediation.
Plant City, Florida
In September 2005, our Central Florida Pipeline, which transports refined
petroleum products from Tampa, Florida to Orlando, Florida, experienced a
pipeline release of diesel fuel affecting approximately two acres of land.
Several residential properties and commercial properties were impacted by the
release. Initial remedial measures have been implemented involving removal of
impacted soils, vegetation and restoration of the landowner's properties. All
agency requirements have been met and we are in the process of implementing
long-term site assessment and remediation activities.
Marion County, Mississippi Litigation
In 1968, Plantation Pipe Line Company 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
187
exposure from the 1968 release, including claims for property damage and
personal injury. During the first quarter of 2005, settlements and/or dismissals
were completed with all of the plaintiffs.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Office of Pipeline
Safety ("OPS") issued a Proposed Civil Penalty and Proposed Compliance Order
concerning alleged violations of certain federal regulations concerning our
products pipeline integrity management program. The violations alleged in the
proposed order are based upon the results of inspections of our integrity
management program at our products pipelines facilities in Orange, California
and Doraville, Georgia conducted in April and June of 2003, respectively. As a
result of the alleged violations, the OPS seeks to have us implement a number of
changes to our integrity management program and also seeks to impose a proposed
civil penalty of approximately $0.3 million. We have already addressed a number
of the concerns identified by the OPS and intend to continue to work with the
OPS to ensure that our integrity management program satisfies all applicable
regulations. However, we dispute some of the OPS findings and disagree that
civil penalties are appropriate, and therefore requested an administrative
hearing on these matters according to the U.S. Department of Transportation
regulations. An administrative hearing was held on April 11 and 12, 2005. We
have provided supplemental information to the hearing officer and to the OPS. It
is anticipated that the decision in this matter and potential administrative
order will be issued by the end of the first quarter of 2006.
Pipeline and Hazardous Materials Safety Administration Corrective Action
Order
On August 26, 2005, we announced that we had received a Corrective Action
Order issued by the U.S. Department of Transportation's Pipeline and Hazardous
Materials Safety Administration, referred to in this report as the PHMSA. The
corrective order instructs us to comprehensively address potential integrity
threats along the pipelines that comprise our Pacific operations. The corrective
order focused primarily on eight pipeline incidents, seven of which occurred in
the State of California. The PHMSA attributed five of the eight incidents to
"outside force damage," such as third-party damage caused by an excavator or
damage caused during pipeline construction. Following the issuance of the
corrective order, we engaged in cooperative discussions with the PHMSA and we
have reached an agreement in principle on the terms of a Consent Agreement with
the PHMSA, subject to the PHMSA's obligation to provide notice and an
opportunity to comment on the Consent Agreement to appropriate state officials
pursuant to 49 USC Section 60112(c). This comment period will close on March 26,
2006. Upon final approval, the Consent Order will, among other things, require
us to perform a thorough analysis of recent pipeline incidents, provide for a
third-party independent review of our operations and procedural practices, and
restructure our internal inspections program. Furthermore, we have reviewed all
of our policies and procedures and are currently implementing various measures
to strengthen our integrity management program, including a comprehensive
evaluation of internal inspection technologies and other methods to protect our
pipelines. We do not expect that our compliance with the Consent Order will have
a material adverse effect on our business, financial position, results of
operations or cash flows.
General
Although no assurances can be given, we believe that we have meritorious
defenses to all of these actions. Furthermore, to the extent an assessment of
the matter is possible, if it is probable that a liability has been incurred and
the amount of loss can be reasonably estimated, we believe that we have
established an adequate reserve to cover potential liability. We also believe
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 severable
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, among others, 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 law and regulations, risks of additional costs
188
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:
* several groundwater and soil remediation efforts under administrative
orders or related state remediation programs issued by the California
Regional Water Quality Control Board and several other state and local
agencies for assets associated with SFPP, L.P.;
* 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, KM Liquids
Terminals L.P., CALNEV Pipe Line LLC and Central Florida Pipeline LLC;
* groundwater and soil remediation efforts under administrative orders or
related state remediation programs issued by various regulatory agencies
on those assets purchased from ExxonMobil, ConocoPhillips, and Charter
Triad, comprising Kinder Morgan Southeast Terminals, LLC.; and
* groundwater and soil remediation efforts under administrative orders or
related state remediation programs issued by various regulatory agencies
on those assets comprising Plantation Pipe Line Company.
San Diego, California
In June 2004, we entered into discussions with the City of San Diego with
respect to impacted groundwater beneath the City's stadium property in San Diego
resulting from operations at the Mission Valley terminal facility. The City has
requested that SFPP work with the City as they seek to re-develop options for
the stadium area including future use of both groundwater aquifer and real
estate development. The City of San Diego and SFPP are working cooperatively
towards a settlement and a long-term plan as SFPP continues to remediate the
impacted groundwater. We do not expect the cost of any settlement and
remediation plan to be material. This site has been, and currently is, under the
regulatory oversight and order of the California Regional Water Quality Control
Board.
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, Exxon Mobil Corporation filed a 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 the
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 obligation we may owe to ST
Services for 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 have completed
limited discovery. In October 2004, the judge assigned to the case dismissed
himself from the case based on a conflict, and the new judge has ordered the
parties
189
to participate in mandatory mediation. The parties participated in a mediation
on November 2, 2005 but no resolution was reached regarding the claims set out
in the lawsuit. At this time, the parties are considering another mediation
session but no date is confirmed.
Other Environmental
On March 30, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a
Notice of Enforcement Action related to our CO2 segment's Snyder Gas Plant. On
August 4, 2005, we received an executed settlement agreement with the TCEQ for
approximately $0.3 million, of which approximately $0.1 million was applied to a
supplemental environmental project in Scurry County, Texas.
Our Kinder Morgan Transmix Company has been in discussions with the United
States Environmental Protection Agency regarding allegations by the EPA that it
violated certain provisions of the Clean Air Act and the Resource Conservation &
Recovery Act. Specifically, the EPA claims that we failed to comply with certain
sampling protocols at our Indianola, Pennsylvania transmix facility in violation
of the Clean Air Act's provisions governing fuel. The EPA further claims that we
improperly accepted hazardous waste at our transmix facility in Indianola.
Finally, the EPA claims that we failed to obtain batch samples of gasoline
produced at our Hartford (Wood River), Illinois facility in 2004. In addition to
injunctive relief that would require us to maintain additional oversight of our
quality assurance program at all of our transmix facilities, the EPA is seeking
monetary penalties of $0.6 million.
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 and Kinder Morgan Tejas
indicates possible environmental impacts from petroleum releases into the soil
and groundwater at nine sites. Further delineation and remediation of any
environmental impacts from these matters will be conducted. Reserves have been
established to address these issues.
See "--Pipeline Integrity and Ruptures" above for information with respect
to the environmental impact of recent ruptures of some of our pipelines.
We are also involved with and have been identified as a potentially
responsible party in several federal and state superfund sites. Environmental
reserves have been established for those sites where our contribution is
probable and reasonably estimable.
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.
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. However, we are not able to reasonably estimate when the eventual
settlements of these claims will occur. Many factors may change in the future
affecting our reserve estimates, such as regulatory changes, groundwater and
land use near our sites, and changes in cleanup technology. As of December 31,
2005, we have accrued an environmental reserve of $51.2 million.
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. Regulatory Matters
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 in this report as FERC, under the Interstate Commerce
190
Act. The Interstate Commerce Act requires, among other things, that interstate
petroleum products pipeline rates be just and reasonable and nondiscriminatory.
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, expanded 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, 2005, 2004 and 2003, the application of the indexing methodology
did not significantly affect tariff rates on our interstate petroleum products
pipelines.
FERC Order No. 2004
On November 25, 2003, the FERC issued Order No. 2004, adopting new Standards
of Conduct to become effective February 9, 2004. Every interstate natural gas
pipeline was required to file a compliance plan by that date and was required to
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 natural gas pipeline's interaction with many more affiliates
(referred to as "energy affiliates"), including intrastate/Hinshaw natural gas
pipelines (in general, a Hinshaw pipeline is a pipeline that receives gas at or
within a state boundary, is regulated by an agency of that state, and all the
gas it transports is consumed within that state), 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 natural gas
pipeline. Local distribution companies are excluded, however, if they do not
make sales to customers not physically attached to their system. 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 an 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. 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 sales to customers not physically attached
to their system, to be excluded from the rule's definition of energy affiliate.
Separation from these entities would be the most burdensome requirement of the
new rules for us.
On April 16, 2004, the FERC issued Order No. 2004-A. The FERC extended the
effective date of the new Standards of Conduct from June 1, 2004, to September
1, 2004. Otherwise, the FERC largely denied rehearing of Order No. 2004, but
provided further clarification or adjustment in several areas. The FERC
continued the exemption for local distribution companies which do not make
off-system sales, but clarified that the local distribution company exemption
still applies if the local distribution company is also a Hinshaw pipeline. The
FERC also clarified that a local distribution company can engage in certain
sales and other energy affiliate activities to the limited extent necessary to
support sales to customers located on its distribution system, and sales
necessary to remain in balance under pipeline tariffs, without becoming an
energy affiliate. The FERC declined to exempt natural gas producers. The FERC
also declined to exempt natural gas intrastate and Hinshaw pipelines, processors
and gatherers, but did clarify that such entities will not be energy affiliates
if they do not participate in gas or electric commodity markets, interstate
capacity markets (as capacity holder, agent or manager), or in financial
transactions related to such markets.
The FERC also clarified further the personnel and functions which can be
shared by interstate natural gas pipelines and their energy affiliates,
including senior officers and risk management personnel, and the permissible
role of holding or parent companies and service companies. The FERC also
clarified that day-to-day operating information can be shared by interconnecting
entities. Finally, the FERC clarified that an interstate natural gas pipeline
and its energy affiliate can discuss potential new interconnects to serve the
energy affiliate, but subject to very onerous posting and record-keeping
requirements.
On July 21, 2004, Kinder Morgan Interstate Gas Transmission LLC and
Trailblazer Pipeline Company filed additional joint requests with the interstate
natural gas pipelines owned by KMI asking for limited exemptions from certain
requirements of FERC Order 2004 and asking for an extension of the deadline for
full compliance with
191
Order 2004 until 90 days after the FERC has completed action on the pipelines'
various rehearing and exemption requests. These exemptions request relief from
the independent functioning and information disclosure requirements of Order
2004. The exemption requests propose to treat as energy affiliates, within the
meaning of Order 2004, two groups of employees:
* individuals in the Choice Gas Commodity Group within KMI's retail
operations; and
* commodity sales and purchase personnel within our Texas intrastate
natural gas operations.
Order 2004 regulations governing relationships between interstate pipelines
and their energy affiliates would apply to relationships with these two groups.
Under these proposals, certain critical operating functions could continue to be
shared.
On August 2, 2004, the FERC issued Order No. 2004-B. In this order, the FERC
extended the effective date of the new Standards of Conduct from September 1,
2004 to September 22, 2004. Also in this order, among other actions, the FERC
denied the request for rehearing made by the interstate pipelines of KMI and us
to clarify the applicability of the local distribution company and parent
company exemptions to them. In addition, the FERC denied the interstate
pipelines' request for a 90 day extension of time to comply with Order 2004.
On September 20, 2004, the FERC issued an order which conditionally granted
the July 21, 2004 joint requests for limited exemptions from the requirements of
the Standards of Conduct described above. In that order, the FERC directed
Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company and
the affiliated interstate pipelines owned by KMI to submit compliance plans
regarding these exemptions within 30 days. These compliance plans were filed on
October 19, 2004, and set out certain steps taken by us to assure that employees
in the Choice Gas Commodity Group of KMI and the commodity sales and purchase
personnel of our Texas intrastate organizations do not have access to restricted
interstate natural gas pipeline information or receive preferential treatment as
to interstate natural gas pipeline services. The FERC will not enforce
compliance with the independent functioning requirement of the Standards of
Conduct as to these employees until 30 days after it acts on these compliance
filings. In all other respects, we were required to comply with the Standards of
Conduct as of September 22, 2004.
We have implemented compliance with the Standards of Conduct as of September
22, 2004, subject to the exemptions described in the prior paragraph. Compliance
includes, among other things, the posting of compliance procedures and
organizational information for each interstate pipeline on its Internet website,
the posting of discount and tariff discretion information and the implementation
of independent functioning for energy affiliates not covered by the prior
paragraph (electric and gas gathering, processing or production affiliates).
On December 21, 2004, the FERC issued Order No. 2004-C. In this order, the
FERC granted rehearing on certain issues and also clarified certain provisions
in the previous FERC 2004 orders. The primary impact on us from Order 2004-C is
the granting of rehearing and allowing local distribution companies to
participate in hedging activity related to on-system sales and still qualify for
exemption from being an energy affiliate.
By an order issued on April 19, 2005, the FERC accepted the compliance plans
filed by us without modification, but subject to further amplification and
clarification as to the intrastate group in three areas:
* further description and explanation of the information or events relating
to intrastate pipeline business that the shared transmission function
personnel may discuss with our commodity sales and purchase personnel
within our Texas intrastate natural gas operations;
* additional posting of organizational information about the commodity
sales and purchase personnel within our Texas intrastate natural gas
operations; and
* clarification that the president of our intrastate natural gas pipeline
group has received proper training and will not be a conduit for
improperly sharing transmission or customer information with our
commodity sales and purchase personnel within our Texas intrastate
natural gas operations.
192
Our interstate pipelines made a compliance filing on May 18, 2005.
FERC Policy statement re: Use of Gas Basis Differentials for Pricing
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. Moreover, in subsequent orders in individual
pipeline cases, the FERC has allowed negotiated rate transactions using pricing
indices so long as revenue is capped by the applicable maximum rate(s). In a
FERC order on rehearing and clarification issued January 19, 2006, the FERC
modified its previous policy statement and now will again permit the use of gas
commodity basis differentials in negotiated rate transactions without regard to
rate or revenue caps.
Accounting for Integrity Testing Costs
On November 5, 2004, the FERC issued a Notice of Proposed Accounting Release
that would require FERC jurisdictional entities to recognize costs incurred in
performing pipeline assessments that are a part of a pipeline integrity
management program as maintenance expense in the period incurred. The proposed
accounting ruling was in response to the FERC's finding of diverse practices
within the pipeline industry in accounting for pipeline assessment activities.
The proposed ruling would standardize these practices. Specifically, the
proposed ruling clarifies the distinction between costs for a "one-time
rehabilitation project to extend the useful life of the system," which could be
capitalized, and costs for an "on-going inspection and testing or maintenance
program," which would be accounted for as maintenance and charged to expense in
the period incurred. Comments, along with responses to specific questions posed
by the FERC concerning the Notice of Proposed Accounting Release, were due
January 19, 2005. We filed our comments on January 19, 2005, asking the FERC to
modify the accounting release to allow capitalization of pipeline assessment
costs associated with projects involving 100 feet or more of pipeline being
replaced or recoated (including discontinuous sections) and to adopt an
effective date for the final rule which is no earlier than January 1, 2006.
On June 30, 2005, the FERC issued an order providing guidance to the
industry on accounting for costs associated with pipeline integrity management
requirements. The order is effective prospectively from January 1, 2006. Under
the order, the costs to be expensed include those to:
* prepare a plan to implement the program;
* identify high consequence areas;
* develop and maintain a record keeping system; and
* inspect affected pipeline segments.
The costs of modifying the pipeline to permit in-line inspections, such as
installing pig launchers and receivers, are to be capitalized, as are certain
costs associated with developing or enhancing computer software or to add or
replace other items of plant.
The Interstate Natural Gas Association of America sought rehearing of the
FERC's June 30, 2005 order. The FERC denied INGAA's request for rehearing on
September 19, 2005. On December 15, 2005, INGAA filed with the United States
Court of Appeals for the District of Columbia Circuit, in docket No. 05-1426, a
petition for review asking the court whether the FERC lawfully ordered that
interstate pipelines subject to FERC rate regulation and related accounting
rules must treat certain costs incurred in complying with the Pipeline Safety
Improvement Act of 2002, along with related pipeline testing costs, as expenses
rather than capital items for purposes of complying with the FERC's regulatory
accounting regulations. We are currently reviewing the effects of this order on
our financial statements; however, we do not believe that this order will have a
material impact on our operations, financial results or cash flows. In addition,
our intrastate natural gas pipelines located within the State of Texas are not
193
FERC-regulated but instead follow accounting regulations promulgated by the
Railroad Commission of Texas. We will maintain our current accounting procedures
with respect to our accounting for pipeline integrity testing costs for our
intrastate natural gas pipelines.
Selective Discounting
On November 22, 2004, the FERC issued a notice of inquiry seeking comments
on its policy of selective discounting. Specifically, the FERC is asking parties
to submit comments and respond to inquiries regarding the FERC's practice of
permitting pipelines to adjust their ratemaking throughput downward in rate
cases to reflect discounts given by pipelines for competitive reasons - when the
discount is given to meet competition from another gas pipeline. Comments were
filed by numerous entities, including Natural Gas Pipeline Company of America (a
Kinder Morgan, Inc. affiliate), on March 2, 2005. Several reply comments have
subsequently been filed. By an order issued on May 31, 2005, the FERC reaffirmed
its existing policy on selective discounting by interstate pipelines without
change. Several entities filed for rehearing; however, by an order issued on
November 17, 2005, the FERC denied all requests for rehearing. On January 9,
2006, a petition for judicial review of the FERC's May 31, 2005 and November 17,
2005 orders was filed by the Northern Municipal District Group/Midwest Region
Gas Task Force Association.
Index of Customer Audit
On July 14, 2005, the FERC commenced an audit of TransColorado Gas
Transmission Company, as well as a number of other interstate gas pipelines, to
test compliance with the FERC's requirements related to the filing and posting
of the Index of Customers report. On September 21, 2005, the FERC's staff issued
a draft audit report which cited two minor issues with TransColorado's Index of
Customers filings and postings. Subsequently, on October 11, 2005, the FERC
issued a final order which closed its examination, citing the minor issues
contained in its draft report and approving the corrective actions planned or
already taken by TransColorado. TransColorado has implemented corrective actions
and has applied those actions to its most recent Index of Customer filing, dated
October 1, 2005. No further compliance action is expected and TransColorado
anticipates operating in compliance with applicable FERC rules regarding the
filing and posting of its future Index of Customers reports.
Notice of Proposed Rulemaking - Market Based Storage Rates
On December 22, 2005, the FERC issued a notice of proposed rulemaking to
amend its regulations by establishing two new methods for obtaining market based
rates for underground natural gas storage services. First, the FERC is proposing
to modify its market power analysis to better reflect competitive alternatives
to storage. Doing so would allow a storage applicant to include other storage
services as well as non-storage products such as pipeline capacity, local
production, or liquefied natural gas supply in its calculation of market
concentration and its analysis of market share. Secondly, the FERC is proposing
to modify its regulations to permit the FERC to allow market based rates for new
storage facilities even if the storage provider is unable to show that it lacks
market power. Such modifications would be allowed provided the FERC finds that
the market based rates are in the public interest, are necessary to encourage
the construction of needed storage capacity, and that customers are adequately
protected from the abuse of market power. KMI's Natural Gas Pipeline Company of
America and our Kinder Morgan Interstate Gas Transmission LLC, as well as
numerous other parties, filed comments on the notice of proposed rulemaking on
February 27, 2006.
18. Recent Accounting Pronouncements
SFAS No. 123R
In December 2004, the Financial Accounting Standards Board issued SFAS No.
123R (revised 2004), "Share-Based Payment." This Statement amends SFAS No. 123,
"Accounting for Stock-Based Compensation," and requires companies to expense the
value of employee stock options and similar awards. Significant provisions of
SFAS No. 123R include the following:
194
* share-based payment awards result in a cost that will be measured at fair
value on the awards' grant date, based on the estimated number of awards
that are expected to vest. Compensation cost for awards that vest would
not be reversed if the awards expire without being exercised;
* when measuring fair value, companies can choose an option-pricing model
that appropriately reflects their specific circumstances and the
economics of their transactions;
* companies will recognize compensation cost for share-based payment awards
as they vest, including the related tax effects. Upon settlement of
share-based payment awards, the tax effects will be recognized in the
income statement or additional paid-in capital; and
* public companies are allowed to select from three alternative transition
methods - each having different reporting implications.
For us, this Statement became effective January 1, 2006. However, we have
not granted common unit options or made any other share-based payment awards
since May 2000, and as of December 31, 2005, all outstanding options to purchase
our common units were fully vested. Therefore, the adoption of this Statement
did not have an effect on our consolidated financial statements due to the fact
that we have reached the end of the requisite service period for any
compensation cost resulting from share-based payments made under our common unit
option plan.
FIN 47
In March 2005, the Financial Accounting Standards Board issued
Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement
Obligations--an interpretation of FASB Statement No. 143". This interpretation
clarifies that the term "conditional asset retirement obligation" as used in
SFAS No. 143, "Accounting for Asset Retirement Obligations," refers to a legal
obligation to perform an asset retirement activity in which the timing and (or)
method of settlement are conditional on a future event that may or may not be
within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the timing and
(or) method of settlement. Thus, the timing and (or) method of settlement may be
conditional on a future event.
Accordingly, an entity is required to recognize a liability for the fair
value of a conditional asset retirement obligation if the fair value of the
liability can be reasonably estimated. The fair value of a liability for the
conditional asset retirement obligation should be recognized when
incurred-generally upon acquisition, construction, or development and (or)
through the normal operation of the asset. Uncertainty about the timing and (or)
method of settlement of a conditional asset retirement obligation should be
factored into the measurement of the liability when sufficient information
exists. FIN 47 also clarifies when an entity would have sufficient information
to reasonably estimate the fair value of an asset retirement obligation.
This Interpretation was effective no later than the end of fiscal years
ending after December 15, 2005 (December 31, 2005, for us). The adoption of this
Interpretation had no effect on our consolidated financial statements.
SFAS No. 154
In June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error
Corrections." This Statement replaces Accounting Principles Board Opinion No.
20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in
Interim Financial Statements." SFAS No. 154 applies to all voluntary changes in
accounting principle, and changes the requirements for accounting for and
reporting of a change in accounting principle.
SFAS No. 154 requires retrospective application to prior periods' financial
statements of a voluntary change in accounting principle unless it is
impracticable. In contrast, APB No. 20 previously required that most voluntary
changes in accounting principle be recognized by including in net income of the
period of the change the cumulative effect of changing to the new accounting
principle. The FASB believes the provisions of SFAS No. 154 will improve
financial reporting because its requirement to report voluntary changes in
accounting principles via
195
retrospective application, unless impracticable, will enhance the consistency of
financial information between periods.
The provisions of this Statement are effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005
(January 1, 2006 for us). Earlier application is permitted for accounting
changes and corrections of errors made occurring in fiscal years beginning after
June 1, 2005. The Statement does not change the transition provisions of any
existing accounting pronouncements, including those that are in a transition
phase as of the effective date of this Statement. Adoption of this Statement
will not have any immediate effect on our consolidated financial statements, and
we will apply this guidance prospectively.
EITF 04-5
In June 2005, the Emerging Issues Task Force reached a consensus on Issue
No. 04-5, or EITF 04-5, "Determining Whether a General Partner, or the General
Partners as a Group, Controls a Limited Partnership or Similar Entity When the
Limited Partners Have Certain Rights." EITF 04-5 provides guidance for purposes
of assessing whether certain limited partners rights might preclude a general
partner from controlling a limited partnership.
For general partners of all new limited partnerships formed, and for
existing limited partnerships for which the partnership agreements are modified,
the guidance in EITF 04-5 is effective after June 29, 2005. For general partners
in all other limited partnerships, the guidance is effective no later than the
beginning of the first reporting period in fiscal years beginning after December
15, 2005 (January 1, 2006, for us). The adoption of EITF 04-5 will not have an
effect on our consolidated financial statements.
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)
2005
First Quarter..... $1,971,932 $ 268,977 $ 223,621 $ 0.54 $ 0.54
Second Quarter.... 2,126,355 275,129 221,826 0.50 0.50
Third Quarter..... 2,631,254 298,611 245,387 0.58 0.57
Fourth Quarter.... 3,057,587 170,805 121,393 (0.02) (0.02)
2004
First Quarter..... $1,822,256 $ 225,142 $ 191,754 $ 0.52 $ 0.52
Second Quarter.... 1,957,182 231,364 195,218 0.51 0.51
Third Quarter..... 2,014,659 252,836 217,342 0.59 0.59
Fourth Quarter.... 2,138,764 264,654 227,264 0.59 0.59
20. Supplemental Information on Oil and Gas Producing Activities (Unaudited)
The Supplementary Information on Oil and Gas Producing Activities is
presented as required by SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." The supplemental information includes capitalized costs related to
oil and gas producing activities; costs incurred for the acquisition of oil and
gas producing activities, exploration and development activities; and the
results of operations from oil and gas producing activities. Supplemental
information is also provided for per unit production costs; oil and gas
production and average sales prices; the estimated quantities of proved oil and
gas reserves; the standardized measure of discounted future net cash flows
associated with proved oil and gas reserves; and a summary of the changes in the
standardized measure of discounted future net cash flows associated with proved
oil and gas reserves.
196
Our capitalized costs consisted of the following (in thousands):
Capitalized Costs Related to Oil and Gas Producing Activities
December 31,
------------------------------------
Consolidated Companies(a) 2005 2004 2003
---------- ---------- ----------
Wells and equipment, facilities
and other.............................. $1,097,863 $ 815,311 $ 601,744
Leasehold............................... 320,702 315,100 234,996
---------- ---------- ----------
Total proved oil and gas properties..... 1,418,565 1,130,411 836,740
Accumulated depreciation
and depletion.......................... (303,284) (174,802) ( 72,572)
---------- ---------- ----------
Net capitalized costs................... $1,115,281 $ 955,609 $ 764,168
========== ========== ==========
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries. Includes capitalized asset retirement costs and associated
accumulated depreciation. There are no capitalized costs associated with
unproved oil and gas properties for the periods reported.
Our costs incurred for property acquisition, exploration and development
were as follows (in thousands):
Costs Incurred in Exploration, Property Acquisitions and Development
Year Ended December 31,
------------------------------------
Consolidated Companies(a) 2005 2004 2003
---------- ---------- ----------
Property Acquisition
Proved oil and gas properties...... $ 6,426$ $ - $ 325,022
Development.......................... 281,728 293,671 265,849
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries. There are no capitalized costs associated with unproved oil
and gas properties for the periods reported. All capital expenditures were
made to develop our proved oil and gas properties and no exploration costs
were incurred for the periods reported.
For the year ended December 31, 2003, we incurred development costs related
to our previous 15% ownership interest in MKM Partners, L.P. in the amount of
$1.8 million. MKM Partners, L.P. was dissolved on June 30, 2003, and prior to
its dissolution, we accounted for our investment under the equity method.
Our results of operations from oil and gas producing activities for each of
the years 2005, 2004 and 2003 are shown in the following table (in thousands):
Results of Operations for Oil and Gas Producing Activities
Year Ended December 31,
---------------------------------------
Consolidated Companies(a) 2005 2004 2003
----------- ----------- -----------
Revenues(b).......................................... $ 469,149 $ 361,809 $ 171,270
Expenses:
Production costs..................................... 159,640 131,501 63,929
Other operating expenses(c).......................... 58,978 44,043 22,387
Depreciation, depletion and amortization expenses.... 130,485 104,147 47,404
----------- ----------- -----------
Total expenses..................................... 349,103 279,691 133,720
----------- ----------- -----------
Results of operations for oil and gas producing
activities........................................... $ 120,046 $ 82,118 $ 37,550
=========== =========== ===========
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) Revenues include losses attributable to our hedging contracts of $374.3
million, $181.8 million and $52.5 million for the years ended December 31,
2005, 2004 and 2003, respectively.
(c) Consists primarily of carbon dioxide expense.
For the year ended December 31, 2003, the results of operations related to
our previous 15% equity interest in MKM Partners, L.P. was $3.7 million.
197
The table below represents our estimate of proved crude oil, natural gas
liquids and natural gas reserves based upon our evaluation of pertinent
geological and engineering data in accordance with United States Securities and
Exchange Commission regulations. Estimates of proved reserves have been prepared
by our team of reservoir engineers and geoscience professionals and are reviewed
by members of our senior management with professional training in petroleum
engineering to ensure that we consistently apply rigorous professional standards
and the reserve definitions prescribed by the United States Securities and
Exchange Commission.
Netherland, Sewell and Associates, Inc., independent oil and gas
consultants, have audited the estimates of proved reserves of natural gas,
natural gas liquids and crude oil that we have attributed to our net interest in
oil and gas properties as of December 31, 2005. Based upon their audit of
more than 99% of our reserve estimates, it is their judgment that the estimates
are reasonable in the aggregate.
We believe the geologic and engineering data examined provides reasonable
assurance that the proved reserves are recoverable in future years from known
reservoirs under existing economic and operating conditions. Estimates of
proved reserves are subject to change, either positively or negatively, as
additional information become available and contractual and economic conditions
change.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, that is,
prices and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual
arrangements, but not
199
on escalations or declines based upon future conditions. Proved developed
reserves are the quantities of crude oil, natural gas liquids and natural gas
expected to be recovered through existing investments in wells and field
infrastructure under current operating conditions. Proved undeveloped reserves
require additional investments in wells and related infrastructure in order to
recover the production.
During 2005, we filed estimates of our oil and gas reserves for the year
2004 with the Energy Information Administration of the U. S. Department of
Energy on Form EIA-23. The data on Form EIA-23 was presented on a different
basis, and included 100% of the oil and gas volumes from our operated properties
only, regardless of our net interest. The difference between the oil reserves
reported on Form EIA-23 and those reported in this report exceeds 5%.
Reserve Quantity Information
Consolidated Companies(a)
-------------------------
Crude Oil NGLs Nat. Gas
(MBbls) (MBbls) (MMcf)(d)
--------- --------- ---------
Proved developed and undeveloped reserves:
As of December 31, 2002.................... 70,719 15,843 18,196
Revisions of previous estimates(b)....... 2,037 (1,404) (14,538)
Production............................... (6,579) (444) (582)
Purchases of reserves in place........... 50,431 2,268 217
--------- --------- ---------
As of December 31, 2003.................... 116,608 16,263 3,293
Revisions of previous estimates(b)....... 19,030 5,350 (120)
Production............................... (11,907) (1,368) (1,583)
--------- --------- ---------
As of December 31, 2004.................... 123,731 20,245 1,590
Revisions of previous estimates.......... 9,807 (4,278) 1,608
Improved Recovery........................ 21,715 4,847 242
Production............................... (13,815) (1,920) (1,335)
Purchases of reserves in place........... 513 89 48
--------- --------- ---------
As of December 31, 2005.................... 141,951 18,983 2,153
========= ========= =========
Equity Investee(c)
As of December 31, 2002.................... 5,454 362 370
Proved developed reserves:
As of December 31, 2002.................... 15,918 3,211 5,149
As of December 31, 2003(b)................. 64,879 8,160 2,551
As of December 31, 2004(b)................. 71,307 8,873 1,357
As of December 31, 2005.................... 78,755 9,918 1,650
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) The downward revision in natural gas reserves was primarily attributable to
natural gas reserves used as fuel on lease for the power generation
facility.
(c) Amounts relate to our previous 15% ownership interest in MKM Partners,
L.P., which we accounted for under the equity method. MKM Partners, L.P.
was dissolved on June 30, 2003.
(d) Natural gas reserves are computed at 14.65 pounds per square inch absolute
and 60 degress fahrenheit.
The standardized measure of discounted cash flows and summary of the changes
in the standardized measure computation from year-to-year are prepared in
accordance with SFAS No. 69. The assumptions that underly the computation of the
standardized measure of discounted cash flows may be summarized as follows:
* the standardized measure includes our estimate of proved crude oil,
natural gas liquids and natural gas reserves and projected future
production volumes based upon year-end economic conditions;
* pricing is applied based upon year-end market prices adjusted for fixed
or determinable contracts that are in existence at year-end;
* future development and production costs are determined based upon actual
cost at year-end;
199
* the standardized measure includes projections of future abandonment costs
based upon actual costs at year-end; and
* a discount factor of 10% per year is applied annually to the future net
cash flows.
Our standardized measure of discounted future net cash flows from proved
reserves were as follows (in thousands):
Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves
As of December 31,
----------------------------------------
Consolidated Companies(a) 2005 2004 2003
----------- ----------- -----------
Future cash inflows from production......... $ 9,150,576 $ 5,799,658 $ 4,149,369
Future production costs..................... (2,756,535) (1,935,597) (1,347,822)
Future development costs(b)................. (869,034) (502,172) (540,900)
----------- ----------- -----------
Undiscounted future net cash flows........ 5,525,007 3,361,889 2,260,647
10% annual discount......................... (2,450,002) (1,316,923) (852,832)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows................... $ 3,075,005 $ 2,044,966 $ 1,407,815
=========== =========== ===========
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) Includes abandonment costs.
The following table represents our estimate of changes in the standardized
measure of discounted future net cash flows from proved reserves (in thousands):
Changes in the Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves
Consolidated Companies(a) 2005 2004 2003
----------- ----------- -----------
Present value as of January 1......................... $ 2,044,966 $ 1,407,815 $ 514,112
Changes during the year:
Revenues less production and other costs(b)....... (250,070) (186,265) (84,954)
Net changes in prices, production and other costs(b) 639,105 324,260 331,366
Development costs incurred........................ 281,728 293,671 265,849
Net changes in future development costs........... (492,307) (270,114) (309,843)
Purchases of reserves in place.................... 9,413 - 689,593
Revisions of previous quantity estimates.......... 51,063 396,946 (23,412)
Improved Recovery................................. 587,537 - -
Accretion of discount............................. 204,412 136,939 51,183
Timing differences and other...................... (842) (58,286) (26,079)
----------- ----------- -----------
Net change for the year............................. 1,030,039 637,151 893,703
----------- ----------- -----------
Present value as of December 31....................... $ 3,075,005 $ 2,044,966 $ 1,407,815
=========== =========== ===========
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) Includes the effect of losses attributable to our hedging contracts of
$374.3 million, $181.8 million and $52.5 million for the years ended
December 31, 2005, 2004 and 2003, respectively.
200
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/ KIMBERLY A. DANG
---------------------------------
Kimberly A. Dang,
Vice President and Chief Financial Officer
Date: March 14, 2006
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/ KIMBERLY A. DANG Vice President and Chief March 14, 2006
- --------------------- Financial
Kimberly A. Dang Officer of Kinder Morgan
Management, LLC, Delegate of
Kinder Morgan G.P., Inc.
(principal financial officer and
principal accounting officer)
/s/ RICHARD D. KINDER Chairman of the Board and Chief March 14, 2006
- --------------------- Executive Officer of Kinder
Richard D. Kinder Morgan Management, LLC, Delegate
of Kinder Morgan G.P., Inc.
(principal executive officer)
/s/ EDWARD O. GAYLORD Director of Kinder Morgan March 14, 2006
- --------------------- Management, LLC, Delegate of
Edward O. Gaylord Kinder Morgan G.P., Inc.
/s/ GARY L. HULTQUIST Director of Kinder Morgan March 14, 2006
- --------------------- Management, LLC, Delegate of
Gary L. Hultquist Kinder Morgan G.P., Inc.
/s/ PERRY M. WAUGHTAL Director of Kinder Morgan March 14, 2006
- --------------------- Management, LLC, Delegate of
Perry M. Waughtal Kinder Morgan G.P., Inc.
/s/ C. PARK SHAPER Director and President of March 14, 2006
- --------------------- Kinder Morgan Management, LLC,
C. Park Shaper Delegate of Kinder Morgan G.P.,
Inc.
201