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, 2006
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number: 1-11234
Kinder Morgan Energy Partners, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0380342
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
500 Dallas, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-369-9000
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Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Units New York Stock Exchange
Securities registered Pursuant to Section 12(g) of the Act:
None
Indicate by check mark 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, 2006 was
approximately $6,538,368,966. As of January 31, 2007, the registrant had
162,823,583 Common Units outstanding.
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KINDER MORGAN ENERGY PARTNERS, L.P.
TABLE OF CONTENTS
Page
Number
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PART I
Items 1 and 2. Business and Properties.................................... 4
General Development of Business........................... 4
Business Strategy........................................ 5
Recent Developments...................................... 6
Financial Information about Segments...................... 14
Narrative Description of Business......................... 14
Products Pipelines....................................... 14
Natural Gas Pipelines.................................... 22
CO2...................................................... 30
Terminals................................................ 34
Major Customers........................................... 39
Regulation................................................ 39
Environmental Matters..................................... 42
Other..................................................... 45
Financial Information about Geographic Areas.............. 45
Available Information..................................... 46
Item 1A. Risk Factors............................................... 46
Item 1B. Unresolved Staff Comments.................................. 53
Item 3. Legal Proceedings.......................................... 53
Item 4. Submission of Matters to a Vote of Security Holders........ 53
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities......... 54
Item 6. Selected Financial Data.................................... 55
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 57
Critical Accounting Policies and Estimates................ 57
Results of Operations..................................... 61
Liquidity and Capital Resources........................... 88
Recent Accounting Pronouncements.......................... 99
Information Regarding Forward-Looking Statements.......... 99
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk............................................... 101
Energy Commodity Market Risk.............................. 101
Interest Rate Risk........................................ 103
Item 8. Financial Statements and Supplementary Data................ 104
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure........................ 104
Item 9A. Controls and Procedures.................................... 104
Item 9B. Other Information.......................................... 106
PART III
Item 10. Directors, Executive Officers and Corporate Governance..... 107
Directors and Executive Officers of our General
Partner and its Delegate.................................. 107
Corporate Governance...................................... 109
Section 16(a) Beneficial Ownership Reporting Compliance... 110
Item 11. Executive Compensation..................................... 110
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................. 125
Item 13. Certain Relationships and Related Transactions, and
Director Independence...................................... 128
Item 14. Principal Accounting Fees and Services..................... 129
PART IV
Item 15. Exhibits and Financial Statement Schedules................. 131
Index to Financial Statements.............................. 134
Signatures................................................................ 241
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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 26,000 miles of pipelines and
approximately 150 terminals. Our pipelines transport more than two million
barrels per day of gasoline and other petroleum products and up to seven 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, 2006, Kinder Morgan, Inc. and its consolidated
subsidiaries, referred to in this report as KMI, owned, through its general and
limited partner interests, an approximate 14.7% interest in us. KMI's common
stock trades on the New York Stock Exchange under the symbol "KMI," and KMI 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 155 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 2006
distribution level, KMI received approximately 49% of all quarterly "Available
Cash" distributions (as defined in our partnership agreement) from us, with
approximately 42% and 7% 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.
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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, 2006, KMR, through its ownership of our i-units, owned
approximately 27.0% of all of our outstanding limited partner units.
On May 29, 2006, KMI announced that its board of directors had received a
proposal from investors led by Richard D. Kinder, Chairman and Chief Executive
Officer of KMI, to acquire all of the outstanding shares of KMI for $100 per
share in cash. The investors include members of senior management of KMI, most
of whom are also senior officers of our general partner and of KMR. KMI's board
of directors formed a special committee composed entirely of independent
directors to consider the proposal. On August 28, 2006, KMI entered into a
definitive merger agreement under which the investors would acquire all of KMI's
outstanding common stock (except for shares held by certain stockholders and
investors) for $107.50 per share in cash, without interest, and KMI's board of
directors, on the unanimous recommendation of the special committee, approved
the agreement and recommended that its stockholders approve the merger.
On December 19, 2006, KMI announced that its stockholders voted to approve
the proposed merger agreement providing for the acquisition of KMI by the
investors, which include: Richard D. Kinder, other senior members of KMI
management, co-founder Bill Morgan, current board members Fayez Sarofim and Mike
Morgan, and affiliates of Goldman Sachs Capital Partners, American International
Group, Inc., The Carlyle Group, and Riverstone Holdings LLC. On January 25,
2007, KMI announced that it had received Hart-Scott-Rodino Antitrust
Improvements Act clearance for the proposed acquisition. The Federal Trade
Commission had challenged the participation of certain investors, but those
investors reached a settlement with the FTC that clears the way for the
acquisition of KMI to proceed. Currently, the only outstanding approvals are
from certain state regulatory utility commissions. The California Public
Utilities Commission issued a procedural schedule which could delay the closing
of the transaction until the second quarter of 2007; however, KMI is working
diligently with the CPUC to try to expedite the matter and is hopeful that the
transaction can be closed in the first quarter of 2007. Upon closing of the
transaction, KMI's common stock will no longer be traded on the New York Stock
Exchange.
Business Strategy
The objective of our business strategy is to grow our portfolio of
businesses by:
o focusing on stable, fee-based energy transportation and storage assets
that are core to the energy infrastructure of growing markets within
the United States;
o increasing utilization of our existing assets while controlling costs,
operating safely, and employing environmentally sound operating
practices;
o leveraging economies of scale from incremental acquisitions and
expansions of assets that fit within our strategy and are accretive to
cash flow and earnings; and
o 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 five operating limited partnerships and
their subsidiaries and are grouped into four reportable business segments. These
segments are as follows:
o Products Pipelines--which consists of approximately 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
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product terminals and petroleum pipeline transmix processing
facilities serving customers across the United States;
o Natural Gas Pipelines--which consists of approximately 14,000 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;
o 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 ten oil
fields in West Texas; and owns and operates a crude oil pipeline
system in West Texas; and
o Terminals--which consists of approximately 95 owned or operated
liquids and bulk terminal facilities and more than 60 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.
We regularly consider and enter into discussions regarding potential
acquisitions, including those from KMI or its affiliates, and are currently
contemplating potential acquisitions. Any such transaction would be subject to
negotiation of mutually agreeable terms and conditions, receipt of fairness
opinions and approval of the respective boards of directors. While there are
currently no unannounced purchase agreements for the acquisition of any material
business or assets, such transactions can be effected quickly, may occur at any
time and may be significant in size relative to our existing assets or
operations.
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.
Recent Developments
The following is a brief listing of significant developments since December
31, 2005. Additional information regarding most of these items may be found
elsewhere in this report.
o 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
Amboy expansion involves 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 were expected to be in
service beginning in the first quarter of 2007, however, due to
inconsistencies in the soils underneath these tanks, we now estimate
that the tank foundations will cost significantly more than originally
budgeted, bringing the total investment to approximately $56 million
and delaying the in-service date to the third quarter of 2007;
o Effective February 23, 2006, Rockies Express Pipeline LLC acquired
Entrega Gas Pipeline LLC from EnCana Corporation for $244.6 million in
cash. West2East Pipeline LLC is a limited liability company and is the
sole owner of Rockies Express Pipeline LLC. We contributed 66 2/3% of
the consideration for this purchase, which corresponded to our
percentage ownership of West2East Pipeline LLC at that time.
At the time of
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acquisition, Sempra Energy held the remaining 33 1/3% ownership
interest and contributed this same proportional amount of the total
consideration.
On the acquisition date, Entrega Gas Pipeline LLC owned the Entrega
Pipeline, an interstate natural gas pipeline that now consists 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, an interstate natural gas pipeline that is
currently being developed by Rockies Express Pipeline LLC. In the
first quarter of 2006, EnCana Corporation completed construction of
the pipeline segment that extends from the Meeker Hub to the Wamsutter
Hub, and interim service began on that portion of the pipeline on
February 24, 2006. In February 2007, we completed construction of the
second pipeline segment that extends from the Wamsutter Hub to the
Cheyenne Hub and service began on the first two pipeline segments on
February 14, 2007. However, our operating revenues and our operating
expenses were not impacted during the construction or interim service
periods due to the fact that regulatory accounting provisions require
capitalization of revenues and expenses until the second segment of
the project was complete and in-service.
In April 2006, Rockies Express Pipeline LLC merged with and into
Entrega Gas Pipeline LLC, and the surviving entity was renamed Rockies
Express Pipeline LLC. Going forward, the entire pipeline system (the
two Entrega segments described above and the two Rockies Express
segments that are currently being developed and described below) will
be known as the Rockies Express Pipeline.
On May 31, 2006, Rockies Express Pipeline LLC filed an application
with the FERC for authorization to construct and operate certain
facilities comprising its proposed Rockies Express-West project. This
project is the first planned eastward extension of the certificated
Rockies Express segments, described above. The Rockies Express-West
project will be comprised of approximately 713 miles of 42-inch
diameter pipeline extending from the Cheyenne Hub to an
interconnection with Panhandle Eastern Pipe Line located in Audrain
County, Missouri. The segment extension will have capacity to
transport up to 1.5 billion cubic feet per day of natural gas across
the following five states: Wyoming, Colorado, Nebraska, Kansas and
Missouri. The project will also include certain improvements to
existing Rockies Express facilities located to the west of the
Cheyenne Hub.
On June 30, 2006, ConocoPhillips exercised its option to acquire a 25%
ownership interest in West2East Pipeline LLC (and indirectly its
subsidiary Rockies Express Pipeline LLC). On that date, a 24%
ownership interest was transferred to ConocoPhillips, and an
additional 1% interest will be transferred once construction of the
entire Rockies Express Pipeline project is completed. Through our
subsidiary Kinder Morgan W2E Pipeline LLC, we continue to operate the
project but our equity ownership interest decreased from 66 2/3% to
51%. Sempra's ownership interest in West2East Pipeline LLC decreased
to 25% (down from 33 1/3%). When construction of the entire project is
completed, our ownership interest will be reduced to 50% at which time
the capital accounts of West2East Pipeline LLC will be trued up to
reflect our 50% economics in the project. We do not anticipate any
additional changes in the ownership structure of the project.
On September 21, 2006, the FERC issued a favorable preliminary
determination on all non-environmental issues of the Rockies
Express-West project, approving Rockies Express' application (i) to
construct and operate the 713 miles of new natural gas transmission
facilities from the Cheyenne Hub and (ii) to lease capacity from
Questar Overthrust Pipeline Company, which will extend the Rockies
Express system 140 miles west from Wamsutter to the Opal Hub in
Wyoming. Pending completion of the FERC environmental review and the
issuance of a certificate, the Rockies Express-West project is
expected to begin service in January 2008.
The final segment of the Rockies Express Pipeline consists of an
approximate 635-mile pipeline segment that will extend from eastern
Missouri to the Clarington Hub in eastern Ohio. Rockies Express will
file a separate application in the future for this proposed Rockies
Express-East project. In June 2006, we made the National Environmental
Policy Act pre-filing for Rockies Express-East with the FERC. This
project is expected to begin interim service as early as December 31,
2008, and to be fully completed by June 2009. When fully
completed, the combined 1,675-mile Rockies Express Pipeline system
will be one of the largest natural gas
7
pipelines ever constructed in North America. The approximately $4.4
billion project will have the capability to transport 1.8 billion
cubic feet per day of natural gas, and binding firm commitments have
been secured for virtually all of the pipeline capacity;
o On March 7, 2006, our Pacific operations filed a revised cost of
service filing with the FERC in accordance with the FERC's December
16, 2005 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. 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.
On April 28, 2006, the FERC issued an order accepting our Pacific
operations' compliance filing and revised tariffs, which lowered its
West Line and East Line rates in conformity with previous FERC orders,
and these lower tariff rates became effective May 1, 2006. Further, we
were required to calculate estimated reparations for complaining
shippers consistent with the December 16, 2005 FERC order, and various
parties have submitted comments to the FERC challenging aspects of the
costs of service and tariff rates reflected in our compliance filings.
The FERC indicated that a subsequent order would address the issues
raised in these comments. In December 2005, we recognized a $105.0
million non-cash expense attributable to an increase in our reserves
related to our rate case liability; however, we are not able to
predict with certainty the final outcome of the pending FERC
proceedings, or whether we can reach a settlement with some or all of
the complainants. For additional information, see Note 16 to our
consolidated financial statements;
o On March 9, 2006, we announced that we have entered into a long-term
agreement with Drummond Coal Sales, Inc. that will support a $70
million expansion of our Pier IX bulk terminal located in Newport
News, Virginia. The agreement has a term that can be extended for up
to 30 years. The project includes the construction of a new ship dock
and the installation of additional equipment; it is expected to
increase throughput at the terminal by approximately 30% and will
allow the terminal to begin receiving shipments of imported coal. The
expansion is expected to be completed in the first quarter of 2008.
Upon completion, the terminal will have an import capacity of up to 9
million tons annually. Currently, our Pier IX terminal can store
approximately 1.4 million tons of coal and 30,000 tons of cement on
its 30-acre storage site;
o Effective April 1, 2006, we sold our Douglas natural gas gathering
system and our Painter Unit fractionation facility to Momentum Energy
Group, LLC for approximately $42.5 million in cash. Our investment in
net assets, including all transaction related accruals, was
approximately $24.5 million, most of which represented property, plant
and equipment, and we recognized approximately $18.0 million of gain
on the sale of these net assets.
Additionally, with regard to the natural gas operating activities of
our Douglas gathering system, we utilized certain derivative financial
contracts to offset (hedge) our exposure to fluctuating expected
future cash flows caused by periodic changes in the price of natural
gas and natural gas liquids. According to the provisions of current
accounting principles, when an asset generating a hedged transaction
is disposed of prior to the occurrence of the transaction, the net
cumulative gain or loss previously recognized in equity should be
transferred to net income in the current period. Accordingly, we
reclassified a net loss of $2.9 million from "Accumulated other
comprehensive loss" into net income on those derivative contracts that
effectively hedged uncertain future cash flows associated with
forecasted Douglas gathering transactions. We included the net amount
of the gain, $15.1 million, within the caption "Other expense
(income)" in our accompanying consolidated statement of income for the
year ended December 31, 2006;
o On April 5, 2006, Kinder Morgan Production Company L.P. purchased
various oil and gas properties from Journey Acquisition - I, L.P. and
Journey 2000, L.P. for an aggregate consideration of approximately
$63.9 million, consisting of $60.3 million in cash and $3.6 million in
assumed liabilities. The acquisition was effective March 1, 2006.
However, in the second and third quarters of 2006, we divested certain
acquired
8
properties that were not considered candidates for carbon dioxide
enhanced oil recovery, thus reducing our total investment. We received
proceeds of approximately $27.1 million from the sale of these
properties. The acquired properties are primarily located in the
Permian Basin area of West Texas and New Mexico, produce approximately
430 barrels of oil equivalent per day, and include some fields with
potential for enhanced oil recovery development near our current
carbon dioxide operations;
o On April 18, 2006, we announced that our Texas intrastate natural gas
pipeline group had entered into a long-term agreement with CenterPoint
Energy Resources Corp. to provide the natural gas utility with firm
transportation and storage services. Under the terms of the agreement,
CenterPoint has contracted for one billion cubic feet per day of
transportation capacity and 16 billion cubic feet of storage capacity,
effective April 1, 2007. CenterPoint owns and operates the largest
local natural gas distribution company in Houston, Texas, and the
agreement helps ensure the Houston metropolitan area has access to
reliable and diverse supplies of natural gas in order to meet the
growing demand;
o In April 2006, we acquired terminal assets and operations from A&L
Trucking, L.P. and U.S. Development Group in three separate
transactions for an aggregate consideration of approximately $61.9
million, consisting of $61.6 million in cash and $0.3 million in
assumed liabilities. The first transaction included the acquisition of
equipment and infrastructure for the storing and loading of bulk steel
at a 30-acre site along the Houston Ship Channel leased through the
Port of Houston. The second acquisition included the purchase of a
rail terminal at the Port of Houston that handles both bulk and
liquids products. The rail terminal offers a variety of loading,
storage and staging services for up to 900 cars at a time, and
complements our existing Texas petroleum coke terminal operations by
providing bulk product customers with rail transportation options.
Thirdly, we acquired the entire membership interest of Lomita Rail
Terminal LLC, a limited liability company that owns a high-volume rail
ethanol terminal in Carson, California. The terminal has the
capability to receive and offload up to 100 railcars within a 24-hour
period, and serves approximately 80% of the Southern California demand
for reformulated fuel blend ethanol with expandable
offloading/distribution capacity;
o On May 17, 2006, we entered into a settlement agreement and filed an
offer of settlement with the FERC in response to certain challenges by
complainants with regard to delivery tariffs and gathering enhancement
fees at our Pacific operations' Watson Station, located in Carson,
California. On August 2, 2006, the FERC approved the settlement
without modification and directed that it be implemented. Pursuant to
the settlement, we filed a new tariff, which took effect September 1,
2006, lowering our Pacific Operations' going-forward rate, and we also
paid refunds to all shippers for the period April 1, 1999 through
August 31, 2006.
On September 28, 2006, we filed a refund report with the FERC, setting
forth the refunds that had been paid and describing how the refund
calculations were made. On December 5, 2006, the FERC approved our
refund report with respect to all shippers except ExxonMobil, and it
remanded the ExxonMobil refund issue to an administrative law judge
for a determination as to whether additional funds were due. On
January 16, 2007, we and ExxonMobil informed the presiding judge that
we had reached a settlement in principle regarding the ExxonMobil
refund issue, and in February 2007, we and ExxonMobil reached
agreement regarding ExxonMobil's protest of the refund report, and
the protest was withdrawn. As of December 31, 2006, we made aggregate
payments pursuant to the agreement, including accrued interest, of
$19.1 million;
o On June 1, 2006, we announced that we had completed and fully placed
into service our $210 million expansion of our Pacific operations'
East Line pipeline segment. The completion of the project included the
construction of a new pump station, a 490,000 barrel tank facility
near El Paso, Texas, and upgrades to existing stations and terminals
between El Paso and Phoenix, Arizona. Initially proposed in October
2002, the expansion also includes the replacement of 160 miles of
8-inch diameter pipe between El Paso and Tucson, Arizona, and 84 miles
of 8-inch diameter pipe between Tucson and Phoenix with new
state-of-the-art 12-inch and 16-inch diameter pipe, respectively. We
announced the completion of the pipeline portion of the project on
April 19, 2006, and new transportation tariffs designed to earn a
return on our construction costs went into effect June 1, 2006.
In addition, we continue working on our second East Line expansion
project, which we announced on August 4, 2005. This second expansion
consists of replacing approximately 140 miles of 12-inch diameter pipe
between El Paso and Tucson with 16-inch diameter pipe, constructing
additional pump stations, and adding
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new storage tanks at Tucson. The project is expected to cost
approximately $145 million. We are currently working on engineering
design and obtaining necessary pipeline permits, and construction is
expected to begin in May 2007. The project, scheduled for completion
in December 2007, will increase East Line capacity by another 8% and
will provide the platform for further incremental expansions through
horsepower additions to the system;
o On June 8, 2006, we announced an approximate $76 million expansion
project that will significantly increase capacity at our North Dayton,
Texas natural gas storage facility. The project involves the
development of a new underground cavern that will add an estimated 5.5
billion cubic feet of incremental working natural gas storage
capacity. Currently, two existing storage caverns at the facility
provide approximately 4.2 billion cubic feet of working gas capacity.
Our North Dayton natural gas storage facility is connected to our
Texas Intrastate natural gas pipeline system, and the expansion will
greatly enhance storage options for natural gas coming from new and
growing supply areas located in East Texas and from liquefied natural
gas along the Texas Gulf Coast. Project costs are now anticipated to
range from $76 to $82 million, and the additional capacity is expected
to be available in mid-2009;
o On June 21, 2006, we announced that we, through our Kinder Morgan
Terminals Canada, ULC subsidiary, began construction on a new $115
million crude oil tank farm located in Edmonton, Alberta, Canada,
located slightly north of KMI's Trans Mountain Pipeline crude oil
storage facility. In addition, we entered into long-term contracts
with customers for all of the available capacity at the facility, with
options to extend the agreements beyond the original terms. Situated
on approximately 24 acres, the new storage facility will have nine
tanks with a combined storage capacity of approximately 2.2 million
barrels for crude oil. Service is expected to begin in the fourth
quarter of 2007, and when completed, the tank farm will serve as a
premier blending and storage hub for Canadian crude oil. The tank farm
will have access to more than 20 incoming pipelines and several major
outbound systems, including a connection with KMI's 710-mile Trans
Mountain Pipeline system, which currently transports up to 225,000
barrels per day of heavy crude oil and refined products from Edmonton
to marketing terminals and refineries located in the greater
Vancouver, British Columbia area and Puget Sound in Washington State;
o On June 23, 2006, our TransColorado Gas Transmission Company filed an
application for authorization with the FERC to construct and operate
certain facilities comprising its proposed "Blanco-Meeker Expansion
Project." Upon implementation, this approximately $58 million project
will facilitate the transportation of up to approximately 250 million
cubic feet per day of natural gas northbound from the Blanco Hub area
in San Juan County, New Mexico through TransColorado's existing
interstate pipeline for delivery to the Rockies Express Pipeline at an
existing point of interconnection located in the Meeker Hub in Rio
Blanco County, Colorado. The expansion is expected to begin service on
January 1, 2008, subject to receipt of all necessary regulatory
approvals;
o In August 2006, we completed a public offering of 5,750,000 of our
common units, including common units sold pursuant to the
underwriters' over-allotment option, at a price of $44.80 per unit,
less commissions and underwriting expenses. We received net proceeds
of $248.0 million for the issuance of these 5,750,000 common units,
and we used the proceeds to reduce the borrowings under our commercial
paper program;
o Effective August 28, 2006, we terminated our $250 million unsecured
nine month credit facility due November 21, 2006, and we increased our
five-year unsecured revolving credit facility from a total commitment
of $1.6 billion to $1.85 billion. Our five-year credit facility
remains due August 18, 2010; however, the facility can now be amended
to allow for borrowings up to $2.1 billion. There were no borrowings
under our five-year credit facility as of December 31, 2006. Our
credit facility primarily serves as a backup to our commercial paper
program, which had $1,098.2 million outstanding as of December 31,
2006;
o On September 8, 2006, we filed an application with the FERC requesting
approval to construct and operate our Kinder Morgan Louisiana
Pipeline. The project is expected to cost approximately $500 million
and will provide approximately 3.2 billion cubic feet per day of
take-away natural gas capacity from the Cheniere Sabine Pass liquefied
natural gas terminal located in Cameron Parish, Louisiana. The project
is supported by fully subscribed capacity and long-term customer
commitments with Chevron and Total. Various water and environmental
surveys have been completed and we procured long-lead items, such as
line pipe and mainline
10
block valves. We are currently finalizing interconnect agreements,
preparing detailed designs of the facilities and acquiring necessary
right-of-ways.
The Kinder Morgan Louisiana Pipeline will consist of two segments: (i)
a 132-mile, 42-inch diameter pipeline with firm capacity of
approximately 2.0 billion cubic feet per day of natural gas that will
extend from the Sabine Pass terminal to a point of interconnection
with an existing Columbia Gulf Transmission line in Evangeline Parish,
Louisiana (an offshoot will consist of approximately 2.3 miles of
24-inch diameter pipeline with firm peak day capacity of approximately
300 million cubic feet per day extending away from the 42-inch
diameter line to the existing Florida Gas Transmission Company
compressor station in Acadia Parish, Louisiana); and (ii) a 1-mile,
36-inch diameter pipeline with firm capacity of approximately 1.2
billion cubic feet per day that will extend from the Sabine Pass
terminal and connect to KMI's Natural Gas Pipeline Company of
America's natural gas pipeline. In addition, in exchange for shipper
commitments to the project, we have granted options to acquire equity
in the project, which, if fully exercised, could result in us owning a
minimum interest of 80% after the project is completed. The 132-mile
pipeline segment is expected to be in service in the second quarter of
2009, and the 1-mile segment is expected to be in service in the third
quarter of 2008.
On January 26, 2007, the FERC issued a draft Environmental Impact
Statement which addresses the potential environmental effects of the
construction and operation of the Kinder Morgan Louisiana Pipeline.
The draft EIS was prepared to satisfy the requirements of the National
Environmental Policy Act. It concluded that approval of the proposed
project would have limited adverse environmental impact. The public
will have until March 19, 2007 to file comments on the draft, which
will be taken into account in the preparation of the final
Environmental Impact Statement;
o On September 11, 2006, we announced major expansions at our Pasadena
and Galena Park, Texas liquids terminal facilities located on the
Houston Ship Channel. The expansions will provide additional
infrastructure to help meet the growing need for refined petroleum
products storage capacity along the Gulf Coast. The investment of
approximately $195 million will include the construction of the
following: (i) new storage tanks at both our Pasadena and Galena Park
terminals; (ii) an additional cross-channel pipeline to increase the
connectivity between the two terminals; (iii) a new ship dock at
Galena Park; and (iv) an additional loading bay at our fully automated
truck loading rack located at our Pasadena terminal. The expansions
are supported by long-term customer commitments and will result in
approximately 3.4 million barrels of additional tank storage capacity
at the two terminals. Construction began in October 2006 and all of
the projects are expected to be completed by the spring of 2008;
o On October 19, 2006, we announced the third of three investments in
our CALNEV refined petroleum products pipeline system. CALNEV is a
550-mile pipeline that currently transports approximately 140,000
barrels of refined products per day of gasoline, diesel fuel and jet
fuel from the Los Angeles, California area to the Las Vegas, Nevada
market through parallel 14-inch and 8-inch diameter pipelines.
Combined, the $413 million in capital improvements will upgrade and
expand pipeline capacity and help provide sufficient fuel supply to
the Las Vegas, Nevada market for the next several years. The
investments include the following:
o the first project, estimated to cost approximately $10 million,
involves pipeline expansions that will increase current
transportation capacity by 3,200 barrels per day (2.2%), as well
as the construction of two new 80,000 barrel storage tanks at our
Las Vegas terminal;
o the second project, expected to cost approximately $15 million,
includes the installation of new and upgraded pumping equipment
and piping at our Colton, California terminal, a new booster
station with two pumps at Cajon, California, and piping upgrades
at our Las Vegas terminal; and
o the third project, expected to cost approximately $388 million,
includes construction of a new 16-inch diameter pipeline that
will further expand the system and which would increase system
capacity to approximately 200,000 barrels per day upon
completion. Capacity could be increased as necessary to over
300,000 barrels per day with the addition of pump stations. The
new 16-inch diameter pipeline will parallel existing utility
corridors between Colton and Las Vegas in order to minimize
environmental impacts. It will transport gasoline and diesel, as
well as military jet fuel for Nellis Air Force Base, which
11
is located eight miles northeast of downtown Las Vegas. The
existing 14-inch diameter pipeline will be dedicated to
commercial jet fuel service for McCarran International Airport in
Las Vegas and for any future commercial airports planned for the
Las Vegas market. The 8-inch diameter pipeline that currently
serves McCarran would be purged and held for future service. The
expansion is subject to environmental permitting, rights-of-way
acquisition and the receipt of approvals from the FERC
authorizing rates that are economic to CALNEV. Start-up of the
new pipeline is scheduled for early 2010;
In addition, we are currently working with our customers to
determine interest in the construction of a new refined products
distribution terminal to be located south of Henderson, Nevada;
o Effective November 20, 2006, we acquired all of the membership
interests of Transload Services, LLC for an aggregate consideration of
approximately $16.8 million, consisting of $15.4 million in cash, an
obligation to pay $0.9 million currently held as security for the
collection of certain accounts receivable and for the perfection of
certain real property title rights, and $0.5 million of assumed
liabilities. Transload Services, LLC is a leading provider of
innovative, high quality material handling and steel processing
services, operating 14 steel-related terminal facilities located in
the Chicago metropolitan area and various cities in the United States.
Its operations include transloading services, steel fabricating and
processing, warehousing and distribution, and project staging. The
combined operations include over 92 acres of outside storage and
445,000 square feet of covered storage that offers customers
environmentally controlled warehouses with indoor rail and truck
loading facilities for handling temperature and humidity sensitive
products;
o Effective December 1, 2006, we acquired all of the membership
interests in Devco USA L.L.C. for an aggregate consideration of
approximately $7.3 million, consisting of $4.8 million in cash, $1.6
million in common units, and $0.9 million of assumed liabilities. The
primary asset acquired was a technology based identifiable intangible
asset--a proprietary process that transforms molten sulfur into
premium solid formed pellets that are environmentally friendly, easy
to handle and store, and safe to transport. The process was developed
internally by Devco's engineers and employees. Devco, a Tulsa,
Oklahoma based company, has more than 20 years of sulfur handling
expertise and we believe the acquisition and subsequent application of
this acquired technology complements our existing dry-bulk terminal
operations;
o On December 13, 2006, we announced that we had entered into a joint
development of the Midcontinent Express Pipeline with Energy Transfer
Partners, L.P., and the start of a binding open season for the
pipeline's firm natural gas transportation capacity. The approximate
$1.25 billion interstate natural gas pipeline project will consist of
an approximate 500-mile pipeline that will originate near Bennington,
Oklahoma, be routed through Perryville, Louisiana, and terminate at an
interconnect with Williams' Transco natural gas pipeline system in
Butler, Alabama. We will own 50% of the equity in the project and
Energy Transfer Partners, L.P. will own the remaining 50% interest.
The new pipeline will also connect to KMI's Natural Gas Pipeline
Company of America's natural gas pipeline and to Energy Transfer
Partners' previously announced 135-mile, 36-inch diameter natural gas
pipeline, which extends from the Barnett Shale natural gas producing
area in North Texas to an interconnect with its 30-inch diameter
Texoma Pipeline near Paris, Texas.
The Midcontinent Express Pipeline will have an initial transportation
capacity of 1.4 billion cubic feet per day of natural gas, and pending
necessary regulatory approvals, is expected to be in service by
February 2009. The pipeline has prearranged binding commitments from
multiple shippers for approximately 850,000 cubic feet per day,
including a binding commitment for 500,000 cubic feet per day from
Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy
Corporation. Additionally, in order to provide a seamless
transportation path from various locations in Oklahoma, the
Midcontinent Express Pipeline has also executed a firm capacity lease
agreement for up to 500,000 cubic feet per day with Enogex, Inc., an
Oklahoma-based intrastate natural gas gathering and pipeline company
that is wholly-owned by OGE Energy Corp.;
o On December 14, 2006, we announced that we expect to declare cash
distributions of $3.44 per unit for 2007, an almost 6% increase over
our cash distributions of $3.26 per unit for 2006. This expectation
includes contributions from assets owned by us as of the announcement
date and does not include any potential benefits from unidentified
acquisitions. We expect our growth to accelerate in the second half of
2007, and we anticipate that our fourth quarter 2007 distribution per
unit will be approximately 10% higher than our
12
cash distribution per unit of $0.83 for the fourth quarter of 2006.
Furthermore, while we expect that we will continue to be able to grow
our distribution per unit at about 8% per year over the long-term, the
increase in 2008 is expected to be greater than 8%, due mainly to the
anticipated in service date of January 2008 for the western portion of
the Rockies Express Pipeline;
o During 2006, we spent $1,058.3 million for additions to our property,
plant and equipment, including both expansion and maintenance
projects. Our capital expenditures included the following:
o $307.7 million in our Terminals segment, largely related to
expanding the petroleum products storage capacity at our liquids
terminal facilities, including the construction of additional
liquids storage tanks at our facilities on the Houston Ship
Channel, and to various expansion projects and improvements
undertaken at multiple bulk terminal facilities;
o $283.0 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;
o $271.6 million in our Natural Gas Pipelines segment, mostly
related to the inclusion of the capital expenditures of Rockies
Express Pipeline LLC during the six-month period we included its
results in our consolidated financial statements, as well as
various expansion and improvement projects on our Texas
Intrastate natural gas pipeline systems, including the
development of additional natural gas storage capacity at our
natural gas storage facilities located at Markham and Dayton,
Texas; and
o $196.0 million in our Products Pipelines segment, mostly related
to the continued expansion work on our Pacific operations' East
Line products pipeline, the construction of an additional refined
products line on our CALNEV Pipeline in order to increase
delivery service to the growing Las Vegas, Nevada market, and to
the combined expansion projects at the 24 refined products
terminals included within our Southeast terminal operations.
o On January 15, 2007, we announced that we had entered into an
agreement with affiliates of BP to increase our ownership interest in
the Cochin pipeline system to 100%. We purchased our original
undivided 32.5% ownership interest in the Cochin pipeline system in
November 2000, and we currently own a 49.8% ownership interest. BP
Canada Energy Company, an affiliate of BP, owns the remaining 50.2%
ownership interest and is the operator of the pipeline. The agreement
is subject to due diligence, regulatory clearance and other customary
closing conditions. The transaction is expected to close in the first
quarter of 2007, and upon closing, we will become the operator of the
pipeline;
o On January 17, 2007, we announced that our CO2 business segment will
invest approximately $120 million to further expand its operations and
enable it to meet the increased demand for carbon dioxide in the
Permian Basin. The expansion activities will take place in southwest
Colorado and will include developing a new carbon dioxide source field
and adding infrastructure at both the McElmo Dome Unit and the Cortez
Pipeline. Specifically, the expansion will involve developing a new
carbon dioxide source field in Dolores County, Colorado (named the Doe
Canyon Deep Unit), adding eight carbon dioxide production wells at the
McElmo Dome Unit, increasing transportation capacity on the Cortez
Pipeline, and constructing a new pipeline that will connect the Cortez
Pipeline to the new Doe Canyon Deep Unit. Initial construction
activities have begun with expected in-service dates commencing in
early 2008. The entire expansion is expected to be completed by the
middle of 2008. Upon completion, these expansion projects are expected
to be immediately accretive to distributable cash available to our
unitholders; and
o On January 30, 2007, we completed a public offering of senior notes.
We issued a total of $1.0 billion in principal amount of senior notes,
consisting of $600 million of 6.00% notes due February 1, 2017, and
$400 million of 6.50% notes due February 1, 2037. We received proceeds
from the issuance of the notes, after underwriting discounts and
commissions, of approximately $992.8 million, and we used the proceeds
to reduce the borrowings under our commercial paper program.
13
(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 seven western states with approximately 3,000
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 2006, the three main product types
transported were gasoline (61%), diesel fuel (22%) and jet fuel (17%).
Our Pacific operations' pipeline system consists of seven pipeline
segments, which include the following:
o the West Line, which consists of approximately 515 miles of primary
pipeline and currently transports products for 37 shippers from six
refineries and three pipeline terminals in the Los Angeles Basin to
Phoenix, 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;
o the East Line, which is comprised of two parallel pipelines,
12-inch/16-inch diameter and 8-inch/12 inch diameter, originating in
El Paso, Texas and continuing approximately 300 miles west to our
Tucson terminal, and one 12-inch diameter 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 and through
inter-connections with non-affiliated pipelines;
o 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;
o 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, and which also serves Nellis Air
Force Base located in Las Vegas. It also includes approximately 55
miles of pipeline serving Edwards Air Force Base;
o 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, Stockton
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;
o the Bakersfield Line, which is a 100-mile, 8-inch diameter pipeline
serving Fresno, California; and
o the Oregon Line, which is a 114-mile pipeline transporting products to
Eugene, Oregon for 18 shippers from marine terminals in Portland,
Oregon and from the Olympic Pipeline.
14
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
13.5 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
approximately 1.2 million barrels per day of refined petroleum products,
providing pipeline service to approximately 31 customer-owned terminals, 11
commercial airports and 14 military bases. Currently, our Pacific operations'
pipelines serve approximately 93 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 178,000 barrels per day. Nevada's gasoline market is
approximately 71,000 barrels per day and Oregon's is approximately 100,000
barrels per day. The diesel and jet fuel market is approximately 545,000 barrels
per day in California, 86,000 barrels per day in Arizona, 33,000 barrels per day
in Nevada and 62,000 barrels per day in Oregon.
The volume of products transported is affected by various factors,
principally demographic growth, economic conditions, product pricing, vehicle
miles traveled, population and fleet mileage. 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.
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. We cannot predict with any certainty whether
the use of short haul trucking will decrease or increase in the future.
15
Longhorn Partners Pipeline is a pipeline that transports refined products
from refineries on the Gulf Coast to El Paso and other destinations in Texas.
Increased product supply in the El Paso area has resulted 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 could displace lower tariff
volumes supplied from Los Angeles on our West Line. 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 Oil Products U.S.
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 2006, Plantation delivered an average of 555,060 barrels per
day of refined petroleum products. These delivered volumes were comprised of
gasoline (67%), diesel/heating oil (20%) and jet fuel (13%). Average delivery
volumes for 2006 were 6.8% lower than the 595,248 barrels per day delivered
during 2005. The decrease was predominantly driven by alternative pipeline
service into Southeast markets and to changes in supply patterns from Louisiana
refineries related to new ultra low sulfur diesel and ethanol blended gasoline
requirements.
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 approximately 82% of total system volumes.
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. Plantation also 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 13% in 2006 compared to 2005, due primarily to a 19% decrease in
shipments to Atlanta Hartsfield-Jackson International Airport and a 35% 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 ten major refineries representing
approximately 2.3 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.
16
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
2006, the pipeline system transported approximately 112,000 barrels per day of
refined products, with the product mix being approximately 69% gasoline, 13%
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. In early
2007, a new tank will go into service, increasing storage capacity to
approximately 1.5 million barrels. 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 non-fuel products, predominantly
spray oil used to treat citrus crops; ethanol; and bio-diesel. These products
are delivered to the terminal by vessel or railcar and loaded onto trucks
through 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 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.
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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 7.7
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 liquids 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 2007 lease fee will be approximately
$1.1 million.
In addition, our North System has eight propane truck-loading terminals at
various points in three states along the pipeline system and one multi-product
complex at Morris, Illinois, in the Chicago area. Propane, normal butane and
natural gasoline can be loaded at our Morris terminal.
Markets. Our North System currently serves approximately 50 shippers in the
upper Midwest market, including both users and wholesale marketers of natural
gas liquids. These shippers include 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 15%) 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. In an effort to obtain the greatest benefit from our North System's
line-fill on a year round basis, we added isobutane as a component of line-fill
in 2005, and we increased the proportion of normal butane and reduced the
proportion of propane. We believe this restructured line-fill helps mitigate any
operational constraints that could result from shippers holding reduced
inventory levels at any point in the year.
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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. BP Canada Energy Company, an affiliate of BP, owns the remaining
50.2% ownership interest and is the operator of the pipeline. On January 15,
2007, we announced that we had entered into an agreement with BP Canada Energy
Company to increase our ownership interest in the Cochin pipeline system to
100%. The agreement is subject to due diligence, regulatory clearance and other
standard closing conditions. The transaction is expected to close in the first
quarter of 2007, and upon closing, we will become 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, 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.
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
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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 its formation, KMST has acquired 24 petroleum products terminals with
a total storage capacity of approximately 7.8 million barrels. These terminals
transferred approximately 347,000 barrels of refined products per day during
2006.
The 24 terminals consist of the following:
o 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;
o seven petroleum products terminals acquired from ExxonMobil
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;
o 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; and
o one petroleum products terminal acquired from Motiva Enterprises, LLC
in December 2006. The terminal, located in Roanoke, Virginia, has
storage capacity of approximately 180,000 barrels per day for refined
petroleum products and is served exclusively by the Plantation
Pipeline. Motiva Enterprises, LLC has entered into a long-term
contract to use the terminal.
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. Longer term storage is also available at many of the
terminals. 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.
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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
six separate processing facilities located in Colton, California; Richmond,
Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River,
Illinois; and Greensboro, North Carolina.
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.
Our 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. In June 2006, Duke Energy Merchants exercised an early
termination provision contained in our long term processing contract due to
expire in 2010. Following Duke's exercise, we transitioned to processing
transmix at Colton for various pipeline shippers directly on a "for fee" basis
arrangement.
Our Richmond, Virginia 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
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.
In the second quarter of 2006, we completed construction and placed into
service our approximately $11 million Greensboro, North Carolina transmix
facility, which is located along KMST's refined products tank farm. The facility
includes an atmospheric distillation column with a direct fired natural gas
heater to process up to 6,000 barrels of transmix per day for Plantation and
other interested parties. In addition to providing additional processing
business, the facility also gives Plantation a lower cost alternative that
recovers ultra low sulfur diesel, and more fully utilizes current KMST tankage
at the Greensboro, North Carolina tank farm.
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 in Southern Califormia.
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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.
Shell acquires transmix for processing at Indianola, Richmond and Wood River;
Colton is supplied by pipeline shippers of our Pacific operations; and Dorsey
Junction 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 new transmix facility located near Linden, New Jersey
and owned by Motiva Enterprises LLC is the principal competition for New York
Harbor transmix supply and for our Indianola facility. 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
14,000 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:
o our Kinder Morgan Texas Pipeline;
o our Kinder Morgan Tejas Pipeline;
o our Mier-Monterrey Mexico Pipeline; and
o our Kinder Morgan North Texas Pipeline.
The two largest systems in the group are our Kinder Morgan Texas Pipeline
and our Kinder Morgan Tejas Pipeline. 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 5.2 billion cubic feet per day of natural gas and
approximately 120 billion cubic feet of on system contracted natural gas storage
capacity. 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.
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.
Included in the operations of our Kinder Morgan Tejas system is our Kinder
Morgan Border Pipeline system. Kinder Morgan Border owns and operates an
approximately 97-mile, 24-inch diameter pipeline that extends from a point of
interconnection with the pipeline facilities of Pemex Gas Y Petroquimica Basica
at the International Border between the United States and Mexico, to a point of
interconnection with other intrastate pipeline facilities of Kinder
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Morgan Tejas located at King Ranch, Kleburg County, Texas. The 97-mile pipeline,
referred to as the import/export facility, is capable of importing Mexican gas
into the United States, and exporting domestic gas to Mexico. The imported
Mexican gas is received from, and the exported domestic gas is delivered to,
Pemex. The capacity of the import/export facility is approximately 300 million
cubic feet of natural gas per day.
Our Mier-Monterrey Pipeline 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 long-term contract (expiring in 2018) with Pemex,
which has subscribed for all of the pipeline's capacity.
Our North Texas Pipeline 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 long-term contract that expires in 2032. In 2006,
the existing system was enhanced to be bi-directional, 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 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.
Our North Dayton natural gas storage facility, located in Liberty County,
Texas, has two existing storage caverns providing 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. We have 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.
In June 2006, we announced an expansion project that will significantly increase
natural gas storage capacity at our North Dayton facility. The project is
expected to cost between $76 million and $82 million and involves the
development of a new underground storage cavern that will add an estimated 5.5
billion cubic feet of incremental working natural gas storage capacity. The
additional capacity is expected to be available in mid-2009.
We also 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.
Additionally, we lease a salt dome storage facility located near Markham,
Texas according to the provisions of an operating lease that expires in March
2013. We can, at our sole option, extend the term of this lease for two
additional ten-year periods. The facility currently consists of three salt dome
caverns with approximately 10.0 billion cubic feet of working natural gas
capacity and up to 750 million cubic feet per day of peak deliverability. A
fourth cavern, with an additional 7.0 billion cubic feet of working natural gas
capacity, is expected to be in service the second quarter of 2007. We also lease
two salt dome caverns, known as the Stratton Ridge Facilities, from BP America
Production Company in Brazoria County, Texas. The Stratton Ridge Facilities have
a combined working natural gas capacity of 1.4 billion cubic feet and a peak day
deliverability of 100 million cubic feet per day. A lease with Dow Hydrocarbon &
Resources, Inc. for a salt dome cavern containing approximately 5.0 billion
cubic feet of working capacity expires during the third quarter of 2007, and we
do not expect to extend the lease.
Markets. Texas is one of the largest natural gas consuming states in the
country. The natural gas demand profile in our Texas intrastate pipeline group's
market area is primarily composed of industrial (including on-site cogeneration
facilities), merchant and utility power and to a lesser extent local natural gas
distribution consumption.
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The industrial demand is primarily year-round load. Merchant and utility power
demand peaks in the summer months and is complemented by local natural gas
distribution demand that peaks in the winter months. As new merchant gas fired
generation has come online and displaced traditional utility generation, we have
successfully attached many of these new generation facilities to our pipeline
systems in order to maintain and grow our share of natural gas supply for power
generation. Additionally, in 2007, we have increased our capability and
commitment to serve the growing local natural gas distribution market in the
greater Houston metropolitan area.
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 2006, deliveries through the existing interconnection near Arguellas
fluctuated from zero to approximately 218 million cubic feet per day of natural
gas, and there were several days of exports to the United States which ranged up
to 202 million cubic feet per day. Deliveries to Monterrey also generally ranged
from zero to 322 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, our TransColorado Gas
Transmission Company, and our current 51% ownership interest in the Rockies
Express Pipeline (all discussed following) comprise our four Rocky Mountain
interstate natural gas pipeline systems.
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 park and loan services. For these services, KMIGT charges
rates which include the retention of fuel and gas lost and unaccounted for
in-kind. 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.
KMIGT also offers 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 through May 2014.
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
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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 5%, by volume, of KMIGT's firm contracts expire
within one year and 61% expire within one to five years. Over 99% of the
system's total firm transport capacity is currently subscribed, and our
affiliates are responsible for approximately 30% of the total contracted firm
transportation and storage capacity on KMIGT's system. The majority of this
affiliated business is dedicated to KMI's U.S. retail natural gas distribution
operations, and in August 2006, KMI entered into a definitive agreement with a
subsidiary of General Electric Company to sell KMI's U.S. retail natural gas
distribution and related operations. Pending regulatory approvals, KMI expects
this transaction to close by the end of the first quarter of 2007.
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'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 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, 2006, approximately 16% of Trailblazer's firm
contracts, by volume, expire before one year and 19%, by volume, expire within
one to five years. Affiliated entities hold less than 1% of the total firm
transportation capacity. All of the system's firm transport capacity is
currently subscribed.
Competition. 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, El
Paso's Cheyenne Plains Pipeline can transport approximately 730 million cubic
feet per day of natural gas from Weld County, Colorado to Greensburg, Kansas and
competes with Trailblazer for natural gas pipeline transportation
25
demand from the Rocky Mountain area. Additional competition could come from
proposed pipeline projects such as the 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 multiple points of
interconnection with various interstate and intrastate pipelines, gathering
systems, and local distribution companies. The pipeline system is powered by six
compressor stations having an aggregate of approximately 30,000 horsepower. KMI
manages, maintains and operates TransColorado, for which it is reimbursed at
cost.
TransColorado has the ability to flow gas south or north. TransColorado
receives gas from one coal seam natural gas treating plant located in the San
Juan Basin of Colorado and from pipeline, processing plant and gathering system
interconnections within the Paradox and Piceance Basins of western Colorado. Gas
flowing south through the pipeline moves onto the El Paso, Transwestern and
Questar Southern Trail pipeline systems. Gas moving north flows into the
Colorado Interstate, Wyoming Interstate and Questar Pipeline systems at the
Greasewood Hub and the Rockies Express Pipeline at the Meeker Hub. 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. For these services, TransColorado charges
rates which include the retention of fuel and gas lost and unaccounted for
in-kind. 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 June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado filed an
application for authorization to construct and operate certain facilities
comprising its Blanco-Meeker Expansion Project. Upon approval, this project will
facilitate additional market access to Rocky Mountain gas production by
transporting up to 250 million cubic feet per day of natural gas from the Blanco
Hub area in San Juan County, New Mexico through TransColorado's existing
facilities for deliveries to the Rockies Express Pipeline at an existing point
of interconnection located at the Meeker Hub in Rio Blanco County, Colorado. A
prearranged shipper has executed a binding precedent agreement for all capacity
on the project. The total expansion project is expected to cost approximately
$58 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 2006, TransColorado transported an average of approximately 869
million cubic feet per day of natural gas from these supply basins, an increase
of 30% over the previous year. The increase in transportation deliveries was
partially due to the completion of TransColorado's north system expansion
project, which was placed in-service on January 1, 2006. The expansion provided
for up to 300 million cubic feet per day of additional northbound transportation
capacity, and was supported by a long-term contract with Williams Companies,
Inc. that runs through 2015, with an option for a five-year extension.
Supply. During 2006, 83% of TransColorado's transport business was with
producers or their own marketing affiliates, 15% was with gathering companies,
and the remaining 2% was with various gas marketers. Approximately 70% of
TransColorado's transport business in 2006 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 93% subscribed during 2007 through 2011 and
26
TransColorado is actively pursuing contract extensions and or replacement
contracts to increase firm subscription levels beyond 2007.
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. Competing pipelines
servicing these producing basins have 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.
Rockies Express Pipeline
We operate and currently own 51% of the 1,662-mile Rockies Express Pipeline
system, which when fully completed, will be one of the largest natural gas
pipelines ever constructed in North America. The approximately $4.4 billion
project will have the capability to transport 1.8 billion cubic feet per day of
natural gas, and binding firm commitments have been secured for virtually all of
the pipeline capacity. The pipeline is owned by Rockies Express Pipeline LLC, a
wholly-owned subsidiary of West2East Pipeline LLC, and as of December 31, 2006,
we owned 51%, Sempra Energy held a 25% ownership interest and ConocoPhillips
owned the remaining 24% ownership interest. When construction of the entire
project is completed, our ownership interest will be reduced to 50% and the
capital accounts of West2East Pipeline LLC will be trued up to reflect our 50%
economics in the project. We do not anticipate any additional changes in the
ownership structure of the project.
The first part of the Rockies Express Pipeline is referred to in this
report as Rockies Express-Entrega, and consists of a 327-mile section that runs
from the Meeker Hub in northwest Colorado, across southern Wyoming to the
Cheyenne Hub in Weld County, Colorado. The first 136-miles of 36-inch diameter
pipeline from the Meeker Hub to the Wamsutter Hub in Sweetwater County, Wyoming,
provided interim service in 2006 during the construction and completion of the
second pipeline segment, a 191-mile, 42-inch diameter line extending from the
Wamsutter Hub to the Cheyenne Hub. The completed construction of the second
segment from the Wamsutter Hub to the Cheyenne Hub on February 14, 2007,
signified the completion of phase one of the total Rockies Express-Entrega
project.
On May 31, 2006, Rockies Express Pipeline LLC filed an application with the
FERC for authorization to construct and operate certain facilities comprising
its proposed Rockies Express-West project. This project is the first planned
segment extension of Rockies Express-Entrega, described above. The Rockies
Express-West project will be comprised of approximately 713 miles of 42-inch
diameter pipeline extending from the Cheyenne Hub to an interconnection with
Panhandle Eastern Pipe Line located in Audrain County, Missouri. The segment
extension proposes to transport approximately 1.5 billion cubic feet per day of
natural gas across the following five states: Wyoming, Colorado, Nebraska,
Kansas and Missouri. The project will also include certain improvements to
existing Rockies Express facilities located to the west of the Cheyenne Hub. On
September 21, 2006, the FERC made a preliminary determination that the issuance
of a certificate to Rockies Express under the provisions of the Natural Gas Act
to construct and operate the Rockies Express-West Project, and enter into a
lease with Questar Overthrust Pipeline Company, would on the basis of all
non-environmental issues be required by the public convenience and necessity. On
December 27, 2006, Rockies Express and TransColorado filed their joint responses
to the FERC's Draft Environmental Impact Statement. Rockies Express expects to
receive final FERC approval in March 2007, and plans to begin construction in
May 2007, with a targeted in-service date of January 1, 2008.
27
The final segment of the Rockies Express Pipeline, referred to as Rockies
Express-East, consists of an approximate 635-mile pipeline segment that will
extend from eastern Missouri to the Clarington Hub in eastern Ohio. Rockies
Express will file a separate application in the future for this proposed Rockies
Express-East project. In June 2006, we made the National Environmental Policy
Act pre-filing for Rockies Express-East with the FERC. From September 11-15,
2006, the FERC hosted nine scoping meetings for the preparation of an
Environmental Impact Statement along the proposed route. Rockies Express-East is
expected to begin interim service as early as December 31, 2008, and to be fully
completed by June 2009.
Kinder Morgan Louisiana Pipeline
In September 2006, we filed an application with the FERC requesting
approval to construct and operate our Kinder Morgan Louisiana Pipeline. The
natural gas pipeline project is expected to cost approximately $500 million and
will provide approximately 3.2 billion cubic feet per day of take-away natural
gas capacity from the Cheniere Sabine Pass liquefied natural gas terminal
located in Cameron Parish, Louisiana. The project is supported by fully
subscribed capacity and long-term customer commitments with Chevron and Total,
and in exchange for shipper commitments to the project, we have granted options
to acquire equity in the project, which, if fully exercised, could result in us
owning a minimum interest of 80% after the project is completed.
The Kinder Morgan Louisiana Pipeline will consist of two segments:
o a 132-mile, 42-inch diameter pipeline with firm capacity of
approximately 2.0 billion cubic feet per day of natural gas that will
extend from the Sabine Pass terminal to a point of interconnection
with an existing Columbia Gulf Transmission line in Evangeline Parish,
Louisiana (an offshoot will consist of approximately 2.3 miles of
24-inch diameter pipeline with firm peak day capacity of approximately
300 million cubic feet per day extending away from the 42-inch
diameter line to the existing Florida Gas Transmission Company
compressor station in Acadia Parish, Louisiana). This segment is
expected to be in service in the second quarter of 2009; and
o a 1-mile, 36-inch diameter pipeline with firm capacity of
approximately 1.2 billion cubic feet per day that will extend from the
Sabine Pass terminal and connect to KMI's Natural Gas Pipeline Company
of America's natural gas pipeline. This portion of the project is
expected to be in service in the third quarter of 2008.
We have designed and will construct the Kinder Morgan Louisiana Pipeline in
a manner that will minimize environmental impacts, and where possible, existing
pipeline corridors will be used to minimize impacts to communities and to the
environment. As of December 31, 2006, there were no major pipeline re-routes as
a result of any landowner requests. We are currently finalizing pipeline
interconnect agreements, preparing detailed designs of the facilities, attending
FERC inter-agency meetings and acquiring pipeline right-of-way.
Casper and Douglas Natural Gas Gathering and Processing Systems
We own and operate our Casper, Wyoming natural gas processing plant, which
is a lean oil absorption facility with full fractionation and has capacity to
process up to 70 million cubic feet per day of natural gas depending on raw gas
quality. The inlet composition of gas entering our Casper plant averages
approximately 1.5 gallons per thousand cubic feet of propane and heavier natural
gas liquids, reflecting the relatively lean gas gathered and delivered to our
Casper plant.
We also own and operate our Douglas natural gas processing facility,
located in Douglas, Wyoming. The Douglas plant is capable of processing
approximately 115 million cubic feet of natural gas per day. The plant is a
cryogenic facility which recovers the full range of natural gas liquids from
ethane through natural gasoline. The plant also has a stabilizer capable of
capturing heavy end natural gas liquids for sale into local markets at a premium
price. Residue gas is delivered from the plant into KMIGT and recovered liquids
are injected in ConocoPhillips Petroleum's natural gas liquids pipeline for
transport to Borger, Texas.
Effective April 1, 2006, we sold our Wyoming natural gas gathering system
and our Painter Unit fractionation facility to a third party for approximately
$42.5 million in cash. For more information on this sale, see Note 3 to our
consolidated financial statements included elsewhere in this report.
28
Markets. Casper and Douglas are processing plants servicing gas streams
flowing into KMIGT. Natural gas liquids processed by our Casper plant are sold
into local markets consisting primarily of retail propane dealers, oil refiners,
and ethanol production facilities. Natural gas liquids processed by our Douglas
plant are sold to ConocoPhillips via their Powder River natural gas liquids
pipeline for either ultimate consumption at the Borger refinery or for further
disposition to the natural gas liquids trading hubs located in Conway, Kansas
and Mont Belvieu, Texas.
Competition. Other regional facilities in the Greater Powder River Basin
include the Hilight plant (80 million cubic feet per day) owned and operated by
Anadarko, the Sage Creek plant (50 million cubic feet per day) owned and
operated by Merit Energy, and the Rawlins plant (50 million cubic feet per day)
owned and operated by El Paso. 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.
Red Cedar also owns Coyote Gas Treating, LLC, referred to in this report as
Coyote Gulch. Previously, we owned a 50% equity interest in Coyote Gulch and
Enterprise Field Services LLC owned the remaining 50%. Effective March 1, 2006,
the Southern Ute Indian Tribe acquired Enterprise's 50% interest in Coyote
Gulch. We and the Tribe agreed to a resolution that would transfer all of the
members' equity in Coyote Gulch to the members' equity of Red Cedar, and
effective September 1, 2006, Coyote Gulch was a wholly owned subsidiary of Red
Cedar.
The sole asset owned by Coyote Gulch is a 250 million cubic feet per day
natural gas treating facility located in La Plata County, Colorado. 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.
Red Cedar's gas gathering system currently consists of over 1,100 miles of
gathering pipeline connecting more than 920 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.
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. 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, 24,265 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
52 receipt points and can deliver treated gas to seven delivery points including
Colorado Interstate
29
Gas, Wyoming Interstate Gas Company, KMIGT and three power plants. The low
pressure gathering assets include five systems consisting of 194 miles of 4-inch
to 14-inch diameter gathering pipeline and 35,400 horsepower of field
compression. Gas is gathered from 101 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. 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.
Carbon Dioxide Reserves
We own approximately 45% of, and operate, the McElmo Dome unit, which
contains more than nine trillion cubic feet of recoverable carbon dioxide.
Deliverability and compression capacity exceeds one billion cubic feet per day.
The McElmo Dome unit is located in Montezuma County, Colorado and produces from
the Leadville formation at approximately 8,000 feet with 54 wells that combined,
produced an average of 973 million cubic feet per day in 2006. We also own
approximately 11% of the Bravo Dome unit, which contains reserves of
approximately two trillion cubic feet of recoverable carbon dioxide. Located in
the northeast quadrant of New Mexico, the Bravo Dome unit produces approximately
290 million cubic feet per day, with production coming from more than 350 wells
in the Tubb Sandstone at 2,300 feet.
We also own approximately 88% of the Doe Canyon Deep unit, which contains
more than 1.5 trillion cubic feet of carbon dioxide. We are currently installing
facilities and six wells to produce an average of 100 million cubic feet per day
of carbon dioxide beginning in January 2008. The Doe Canyon Deep unit is located
in Delores County, Colorado, and it will produce from the Leadville formation at
approximately 8,800 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, Wyoming, the
Gulf Coast, 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
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 99% of the carbon dioxide transported
downstream on our Central Basin pipeline and our Centerline pipeline.
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
30
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.
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.
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, an approximate 95%
working interest in the Katz CB Long unit, an approximate 64% working interest
in the Katz SW River unit, a 100% working interest in the Katz East River 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. 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.
As of December 2006, the SACROC unit had 355 producing wells, and the
purchased carbon dioxide injection rate was 247 million cubic feet per day, down
from an average of 258 million cubic feet per day as of December 2005. The
average oil production rate for 2006 was approximately 30,800 barrels of oil per
day, down from an
average of approximately 32,400 barrels of oil per day during 2005. The average
natural gas liquids production rate (net of the processing plant share) for 2006
was approximately 5,700 barrels per day, down from an average of approximately
6,000 barrels per day during 2005.
Our plan has been to increase the production rate and ultimate oil recovery
from Yates by combining horizontal drilling with carbon dioxide injection to
ensure a relatively steady production profile over the next several years.
31
We are implementing our plan and as of December 2006, the Yates unit was
producing about 27,000 barrels of oil per day. As of December 2005, the Yates
unit was producing approximately 24,000 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.
We also operate and own an approximate 64.5% gross working interest in the
Claytonville oil field unit located in Fisher County, Texas. The Claytonville
unit is located nearly 30 miles east of the SACROC unit in the Permian Basin of
West Texas and is currently producing approximately 200 barrels of oil per day.
We are presently evaluating operating and subsurface technical data from the
Claytonville unit to further assess redevelopment opportunities including carbon
dioxide flood operations.
On April 5, 2006, we purchased various oil and gas properties from Journey
Acquisition - I, L.P. and Journey 2000, L.P. for an aggregate consideration of
approximately $63.9 million, consisting of $60.3 million in cash and $3.6
million in assumed liabilities. The acquisition was effective March 1, 2006.
However, since our acquisition, we divested certain acquired properties that
were not considered candidates for carbon dioxide enhanced oil recovery, and we
received proceeds of approximately $27.1 million from the sale of these
properties. The retained properties, referred to in this report as the Katz
field, are the Katz CB Long unit, the Katz Southwest River unit and Katz East
River unit. The Katz field is primarily located in the Permian Basin area of
West Texas and New Mexico and, as of December 2006, was producing approximately
430 barrels of oil equivalent per day. We are presently evaluating operating and
subsurface technical data to further assess redevelopment opportunities for the
Katz field including the potential for carbon dioxide flood operations.
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,
2006. When used with respect to acres or wells, gross refers to the total acres
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.......... 2,604 1,590 1,078 766 2 2
Natural Gas........ 8 4 28 14 - -
--------- ------- -------- ------- --------- -------
Total Wells...... 2,612 1,594 1,106 780 2 2
========= ======= ======== ======= ========= =======
(a) Includes active wells and wells temporarily shut-in. As of December 31,
2006, 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, 2006. 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 and New Mexico. The following table
reflects our net productive and dry wells that were completed in each of the
three years ended December 31, 2006, 2005 and 2004:
2006 2005 2004
------ ------ ------
Productive
Development.......... 37 42 31
Exploratory.......... - - -
Dry
Development.......... - - -
Exploratory.......... - - -
------ ------ ------
Total Wells............ 37 42 31
====== ====== ======
- --------
32
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. 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, 2006:
Gross Net
-------- ---------
Developed Acres........ 72,435 67,709
Undeveloped Acres...... 8,788 8,131
-------- ---------
Total.............. 81,223 75,840
======== =========
Operating Statistics
Operating statistics from our oil and gas producing activities for each of
the years 2006, 2005 and 2004 are shown in the following table:
Results of Operations for Oil and Gas Producing
Activities - Unit Prices and Costs
Year Ended December 31,
--------------------------------
2006 2005 2004
-------- -------- -------
Consolidated Companies(a)
Production costs per barrel of oil equivalent(b)(c)(d)....... $ 13.30 $ 10.00 $ 9.71
======= ======= =======
Crude oil production (MBbl/d)................................ 37.8 37.9 32.5
======= ======= =======
Natural gas liquids production (MBbl/d)(d)................... 5.0 5.3 3.7
Natural gas liquids production from gas plants(MBbl/d)(e) 3.9 4.1 4.0
------- ------- -------
Total natural gas liquids production(MBbl/d)................ 8.9 9.4 7.7
======= ======= =======
Natural gas production (MMcf/d)(d)(f)........................ 1.3 3.7 4.4
Natural gas production from gas plants(MMcf/d)(e)(f)......... 0.3 3.1 3.9
------- ------- -------
Total natural gas production(MMcf/d)(f)..................... 1.6 6.8 8.3
======= ======= =======
Average sales prices including hedge gains/losses:
Crude oil price per Bbl(g).................................. $ 31.42 $ 27.36 $ 25.72
======= ======= =======
Natural gas liquids price per Bbl(g)........................ $ 43.52 $ 38.79 $ 31.37
======= ======= =======
Natural gas price per Mcf(h)................................ $ 6.36 $ 5.84 $ 5.27
======= ======= =======
Total natural gas liquids price per Bbl(e).................. $ 43.90 $ 38.98 $ 31.33
======= ======= =======
Total natural gas price per Mcf(e).......................... $ 7.02 $ 5.80 $ 5.24
======= ======= =======
Average sales prices excluding hedge gains/losses:
Crude oil price per Bbl(g).................................. $ 63.27 $ 54.45 $ 40.91
======= ======= =======
Natural gas liquids price per Bbl(g)........................ $ 43.52 $ 38.79 $ 31.68
======= ======= =======
Natural gas price per Mcf(h)................................ $ 6.36 $ 5.84 $ 5.27
======= ======= =======
- --------------
(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 Commisson. 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.
(g) Hedge gains/losses for crude oil and natural gas liquids are included with
crude oil.
(h) Natural gas sales were not hedged.
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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. We also operate and own 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. The Snyder gasoline plant processes gas produced from the SACROC unit and
neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell
units, all of which are located in the Permian Basin area of West Texas. The
Diamond M and the North Snyder plants contract with the Snyder plant to process
gas. Production of natural gas liquids at the Snyder gasoline plant as of
December 2006 was approximately 15,000 barrels per day, the same rate of
production as of December 2005.
Crude Oil Pipeline
We own our Kinder Morgan Wink Pipeline, a 450-mile crude oil pipeline
system consisting of three mainline sections, two gathering systems and numerous
truck off-loading stations. The entire system is 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 130,000 barrels of crude oil per day (with the use of a drag
reducing agent). The pipeline allows us to better manage crude oil deliveries
from our oil field interests in West Texas, and we have entered into a long-term
throughput agreement with Western Refining Company, L.P. to transport crude oil
into Western's 120,000 barrel per day refinery in El Paso. The 20-inch pipeline
segment transported approximately 113,000 barrels of oil per day in 2006. The
Kinder Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad
Commission.
Terminals
Our Terminals segment includes the operations of our petroleum, chemical
and other liquids terminal facilities (other than those included in our Products
Pipelines segment) as well as all of our coal, petroleum coke, steel and
dry-bulk material services, including all transload, engineering, conveying and
other in-plant services. Combined, the segment is composed of approximately 94
owned or operated liquids and bulk terminal facilities, and more than 60 rail
transloading and materials handling facilities located throughout the United
States. In 2006, the number of customers from whom our Terminals segment
received more than $0.1 million of revenue was approximately 550.
Liquids Terminals
Our liquids terminals 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 terminals
facilities possess liquids storage capacity of approximately 43.5 million
barrels, and in 2006, these terminals handled approximately 555.2 million
barrels of petroleum, petrochemical and vegetable oil products. Our major
liquids terminals 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 19.6
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 3.7 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.
In September 2006, we announced major expansions at our Pasadena and Galena
Park, Texas terminal facilities. The expansions will provide additional
infrastructure to help meet the growing need for refined petroleum products
storage capacity along the Gulf Coast. The investment of approximately $195
million includes the construction of
34
the following: (i) new storage tanks at both our Pasadena and Galena Park
terminals; (ii) an additional cross-channel pipeline to increase the
connectivity between the two terminals; (iii) a new ship dock at Galena Park;
and (iv) an additional loading bay at our fully automated truck loading rack
located at our Pasadena terminal. The expansions are supported by long-term
customer commitments and will result in approximately 3.4 million barrels of
additional tank storage capacity at the two terminals. Construction began in
October 2006, and all of the projects are expected to be completed by the spring
of 2008.
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 7.5 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. Since our
acquisition, we also completed the construction of a 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.
In January 2006, we announced the investment of approximately $45 million
for the construction of new liquids storage tanks at Perth Amboy. The Perth
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 service. 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. Due to inconsistencies in the soils underneath these tanks, we now
estimate that the tank foundations will cost significantly more than our
original budget, bringing the total investment to approximately $56 million and
delaying the in-service date to the third quarter of 2007.
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 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 3.0 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 ship and barge berths 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 petroleum product and ethanol blending facility and a
major break bulk facility for large chemical manufacturers and distributors. It
has approximately 2.5 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 liquid chemicals with a working
capacity of approximately 795,000 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.
35
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 3.0 million barrels of tankage ranging in sizes from 17,000
gallons 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 63,000 gallons 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.
In June 2006, we announced the construction of a new $115 million crude oil
tank farm located in Edmonton, Alberta, Canada, and long-term contracts with
customers for all of the available capacity at the facility. Situated on
approximately 24 acres, the new storage facility will have nine tanks with a
combined storage capacity of approximately 2.2 million barrels for crude oil.
Service is expected to begin in the fourth quarter of 2007, and when completed,
the tank farm will serve as a premier blending and storage hub for Canadian
crude oil. The tank farm will have access to more than 20 incoming pipelines and
several major outbound systems, including a connection with KMI's 710-mile Trans
Mountain Pipeline system, which currently transports up to 225,000 barrels per
day of heavy crude oil and refined products from Edmonton to marketing terminals
and refineries located in the greater Vancouver, British Columbia area and Puget
Sound in Washington state.
Competition. We are one of the largest independent operators of liquids
terminals in North America. Our primary competitors are IMTT, Magellan, Morgan
Stanley, Oil Tanking, Teppco, Valero, and Vopak.
Bulk Terminals
Our bulk terminal operations primarily involve dry-bulk material handling
services; however, we also provide terminal engineering and design services and
in-plant services covering material handling, conveying, maintenance and repair,
railcar switching and miscellaneous marine services. Combined, our dry-bulk and
material transloading facilities handled approximately 89.5 million tons of
coal, petroleum coke, steel and other dry-bulk materials in 2006. We own or
operate approximately 28 petroleum coke or coal terminals in the United States.
Our major bulk terminal assets are described below.
In 2006, we handled approximately 16.6 million tons of petroleum coke, as
compared to approximately 12.3 million tons in 2005. 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.
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 has increased in the last several years due to an increasingly
heavy crude oil supply and also to the increased use of coking units by domestic
refineries. A portion of the petroleum coke we handle is imported from or
exported to foreign markets. Most of our customers are large integrated oil
companies that choose to outsource the storage and loading of petroleum coke for
a fee.
The overall increase in petroleum coke volumes in 2006 versus 2005 was
largely driven by incremental volumes attributable to our purchase of certain
petroleum coke terminal operations from Trans-Global Solutions, Inc. in April
2005. We gave an aggregate consideration of approximately $247.2 million for
these operations, and the acquisition made us the largest independent handler of
petroleum coke in the United States, in terms of volume. 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 2006, we also handled approximately 30.8 million tons of coal. Coal
continues to be the fuel of choice for electric generation plants, accounting
for more than 50% of United States electric generation feedstock. Forecasts of
36
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 facilities.
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 Chester, Illinois, about 80 miles south of St.
Louis, Missouri. It currently 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, Kentucky 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. Our Grand Rivers
Terminal 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 1.4 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 2006. 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.
In March 2006, we announced that we had entered into a long-term agreement
with Drummond Coal Sales, Inc. that will support a $70 million expansion of the
Pier IX terminal.. The project includes the construction of a new ship dock and
the installation of additional equipment, and it is expected to increase
throughput at the terminal by approximately 30% and to allow the terminal to
begin receiving shipments of imported coal. The expansion project is expected to
be completed in the first quarter of 2008. Upon completion, the terminal will
have an import capacity of up to 9 million tons annually.
Our Shipyard River Terminal is located in Charleston, South Carolina, on
208 acres, and is both a bulk and liquids terminal. Our Shipyard facility is
able to unload, store and reload coal, petroleum coke, cement and other bulk
products imported from or exported to 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. The facility is serviced by the Norfolk Southern and CSX
railroads. 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 addition, the terminal has over 1.0 million
barrels of liquid storage capacity in 18 tanks.
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 fertilizer, aggregates and 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,
37
which is also located in Tampa. The Port Sutton terminal sits on 16 acres of
land and offers 200,000 tons of covered storage. Primary products handled in
2006 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.
Our Kinder Morgan Fairless Hills terminal consists of 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 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, grain products and cement. 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,
stevedoring 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 include the rail or truck transloading
operations owned by Kinder Morgan Materials Services LLC, Lomita Rail Terminal
LLC, Kinder Morgan Texas Terminals, L.P., Transload Services, LLC and other
stevedoring and in-plant operations. In 2006, we acquired all of the membership
interests of Lomita Rail Terminal LLC and Transload Services, LLC, and the
terminal assets and operations of A&L Trucking, L.P.--for more information on
these acquisitions, see Note 3 to our consolidated financial statements included
elsewhere in this report.
Our materials services operations consist of approximately 61 rail
transloading facilities, of which 56 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 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). We also design and build
transloading facilities, perform
38
inventory management services, and provide value-added services such as
blending, heating and sparging. In 2006, our materials services operations
handled approximately 72,000 railcars.
Major Customers
Our total operating revenues are derived from a wide customer base. For
each of the years ended December 31, 2006 and 2005, no revenues from
transactions with a single external customer accounted for 10% or more of our
total consolidated revenues. For the year ended December 31, 2004, 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.
The high percentage of our total revenues attributable to CenterPoint
Energy in 2004 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. To a far lesser extent, our CO2 business segment also
sells natural gas, and combined, total revenues from the sales of natural gas
from our Natural Gas Pipelines and CO2 business segments in 2006, 2005 and 2004
accounted for 67.5%, 73.6% and 73.2%, respectively, of our total consolidated
revenues.
As a result of our Texas intrastate group selling natural gas in the same
price environment in which it is purchased, 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. Our Texas intrastate group
reported gross margins from the sale and purchases of natural gas of $190.2
million in 2006, $142.2 million in 2005 and $111.5 million in 2004. 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.
39
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
index adjustment in 2003 eliminated the one percent reduction. Pursuant to a
subsequent review of the index by the FERC in 2005, the index is now measured by
the producer price index for finished goods plus 1.3% and it will apply for
years 2006 through 2010. As a result, we filed for indexed rate adjustments on a
number of our petroleum products pipelines and realized benefits from the new
index.
Interstate Natural Gas Transportation and Storage Regulation
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:
o Order No. 436 (1985) requiring open-access, nondiscriminatory
transportation of natural gas;
o 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
o 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:
o requiring the unbundling of sales services from other services;
o permitting holders of firm capacity on interstate natural gas
pipelines to release all or a part of their capacity for resale by the
pipeline; and
o the issuance of blanket sales certificates to interstate pipelines for
unbundled services.
Order 636 has been affirmed in all material respects upon judicial review,
and our own FERC orders approving our unbundling plans are final and not subject
to any pending judicial review.
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
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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.
On November 17, 2006, the United States Court of Appeals for the District
of Columbia Circuit vacated Order No. 2004, as applied to natural gas pipelines,
and remanded the Order back to FERC. On January 9, 2007, the FERC issued an
interim rule regarding standards of conduct in Order 690 to be effective
immediately. The interim rule repromulgated the standards of conduct that were
not challenged before the court. On January 18, 2007, the FERC issued a notice
of proposed rulemaking soliciting comments on whether or not the interim rule
should be made permanent for natural gas transmission providers.
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.
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
41
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 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 products pipeline
integrity management program. However, we dispute some of the Office of Pipeline
Safety findings and disagree that civil penalties are appropriate for them, and
we therefore 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.
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
42
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 $61.6 million as of
December 31, 2006. Our reserve estimates range in value from approximately $61.6
million to approximately $108.8 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 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
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 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, as amended, and analogous
state statutes. We believe that the operations of our pipelines, storage
facilities and terminals are in substantial compliance with such statutes. The
Clean Air Act, as amended, contains 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
43
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 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, referred to in this report as MTBE, is
commonly used as an additive in gasoline. It is manufactured by chemically
combining a portion of petrochemical production with purchased methanol and is
widely used as an oxygenate blended with gasoline to reduce emissions. Due to
environmental and health concerns, California mandated the elimination of MTBE
from gasoline by January 1, 2004. With certain scientific studies showing that
MTBE was having a detrimental effect on water supplies, 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 eliminated the oxygenate
requirement for reformulated gasoline but did 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
44
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 products terminal facilities, and the
fees we earn for 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:
o our Products Pipelines' terminals are storing and blending ethanol
because unlike MTBE, it cannot flow through refined petroleum products
pipelines;
o our Natural Gas Pipelines segment is delivering natural gas through
our pipelines to service new ethanol plants that are being constructed
in the Midwest (natural gas is the feedstock for ethanol plants); and
o our Terminals segment is entering into liquid storage agreements for
ethanol around the country, in such areas as Houston, Chicago,
Nebraska and on the East Coast. In 2006, the liquids facilities
included within our Terminals' business segment reported a 159%
increase in the volumes of ethanol handled and/or transferred.
Other
We do not have any employees. KMGP Services Company, Inc. and Kinder
Morgan, Inc. employ all persons necessary for the operation of our business.
Generally, we reimburse KMGP Services Company, Inc. and Kinder Morgan, Inc. for
the services of their employees. As of December 31, 2006, KMGP Services Company,
Inc. and Kinder Morgan, Inc. had, in the aggregate, approximately 8,600
full-time employees. Approximately 2,100 full-time hourly personnel at certain
terminals and pipelines are represented by labor unions under collective
bargaining agreements that expire between 2007 and 2011. 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 2006, 2005 and 2004 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.
45
(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 the realization 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.
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 to us, 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 and materially
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. The rates (which include reservation,
commodity, surcharges, fuel and gas lost and unaccounted for) we charge shippers
on our natural gas pipeline systems are subject to regulatory approval and
oversight. 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. Furthermore, regulators
and shippers on our natural gas pipelines have rights to challenge the rates
they are charged under certain circumstances prescribed by applicable
regulations. We can provide no assurance that we will not face challenges to the
rates we receive on our pipeline systems in the future. Any successful challenge
could materially adversely affect our future earnings and cash flows.
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 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 requires significant
expenditures. We have increased our capital expenditures to address these
matters and expect to significantly increase these expenditures in the
foreseeable future. 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.
Cost overruns and delays on our expansion and new build projects could
adversely affect our business. We currently have several major expansion and new
build projects planned or underway, including the approximate $4.4 billion
Rockies Express Pipeline and the approximate $1.25 billion Midcontinent Express
Pipeline. A variety of factors outside our control, such as weather, natural
disasters and difficulties in obtaining permits and rights-of-way or other
regulatory approvals, as well as the performance by third party contractors, may
result in increased costs or delays in construction. Cost overruns or delays in
completing a project could have an adverse effect on our results of operations
and cash flows.
46
Our rapid growth may cause difficulties integrating and constructing 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, expanding existing assets, or constructing new facilities that will
allow us to increase distributions to our unitholders. If we do not successfully
integrate acquisitions, expansions, or newly constructed facilities, we may not
realize anticipated operating advantages and cost savings. The integration of
companies that have previously operated separately involves a number of risks,
including:
o demands on management related to the increase in our size after an
acquisition, an expansion, or a completed construction project;
o the diversion of our management's attention from the management of
daily operations;
o difficulties in implementing or unanticipated costs of accounting,
estimating, reporting and other systems;
o difficulties in the assimilation and retention of necessary employees;
and
o 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 acquisition, expansion, or construction project will depend
upon our ability to manage those operations and to eliminate redundant and
excess costs. Because of difficulties in combining and expanding 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. We may need new capital to finance these acquisitions. Limitations
on our access to capital will impair our ability to execute this strategy. We
normally fund acquisitions with short-term debt and repay such debt through 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.
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,
pollution and human health and safety. 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, pay for government penalties, address
natural resource damage, compensate for human exposure or property damage,
install costly pollution control equipment or a combination of these and other
measures. The resulting costs and liabilities could negatively affect our level
of earnings and cash flows. In addition, emission controls required under the
Federal Clean Air Act and other similar federal and state laws could require
significant capital expenditures at our facilities. The impact on us of
environmental 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.
The future success of our oil and gas development and production operations
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
47
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 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, among other things, 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 counterparty 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 complex, and even
when we engage in hedging transactions (for example, to mitigate our exposure to
unfavorable 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.
48
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 pipelines on
other owners' 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.
Union Pacific Railroad Company has allowed us to construct and operate a
significant portion of our Pacific operations' pipeline system on railroad
rights-of-way. Union Pacific Railroad Company and its predecessors were given
the right to construct their railroad tracks under federal statutes enacted in
1871 and 1875. The 1871 statute was thought to be an outright grant of ownership
that would continue until the land ceased to be used for railroad purposes. Two
United States Circuit Courts, however, ruled in 1979 and 1980 that railroad
rights-of-way granted under laws similar to the 1871 statute provide only the
right to use the surface of the land for railroad purposes without any right to
the underground portion. If a court were to rule that the 1871 statute does not
permit the use of the underground portion for the operation of a pipeline, we
may be required to obtain permission from the landowners in order to continue to
maintain the pipelines. Approximately 10% of our pipeline assets are located in
the ground underneath railroad rights-of-way.
Whether we have the power of eminent domain for our pipelines varies from
state to state depending upon the type of pipeline--petroleum liquids, natural
gas or carbon dioxide--and the laws of the particular state. Our inability to
exercise the power of eminent domain could negatively affect our business if we
were to lose the right to use or occupy the property on which our pipelines are
located. For the year ended December 31, 2006, all of our right-of-way related
expenses totaled $14.0 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:
o incurring additional debt;
o entering into mergers, consolidations and sales of assets;
o granting liens; and
o entering into sale-leaseback transactions.
The instruments governing any future debt may contain similar or more
restrictive restrictions. Our ability to respond to changes in business and
economic conditions and to obtain additional financing, if needed, may be
restricted.
Because a portion of our debt is subject to variable interest rates, if
interest rates increase, our earnings could be adversely affected. As of
December 31, 2006, we had approximately $3.3 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 effectively converted to
variable rate debt through the use of interest rate swaps. Should interest rates
increase significantly, our earnings could be adversely affected. For
information on our interest rate risk, see Item 7A "Quantitative and Qualitative
Disclosures About Market Risk--Interest Rate Risk."
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, or may experience
in the future, severe financial problems that have had or may have a significant
impact on their creditworthiness. We cannot provide assurance that one or more
of our financially distressed customers will not
49
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. Furthermore, the bankruptcy of one
or more of our customers, 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 general uncertainty associated with the current world economic and
political environments in which we exist may adversely impact our financial
performance. 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
rates we believe are reasonable throughout 2007. Currently, we do not believe
that the increased cost associated with these measures will have a material
effect on our operating results.
The consummation of the proposed management-led buyout of KMI will result
in substantially more debt at KMI and could have an adverse effect on us, such
as a downgrade in the ratings of our debt securities. On August 28, 2006, KMI
entered into an agreement and plan of merger whereby investors led by Richard D.
Kinder, Chairman and CEO of KMI, would acquire all of the outstanding shares of
KMI (other than shares held by certain stockholders and investors) for $107.50
per share in cash. In connection with the merger, KMI will incur substantially
more debt, which could have an adverse effect on us, such as a downgrade in the
ratings of our debt securities. In response to this proposed transaction,
Standard & Poor's Rating Services has placed our ratings on credit watch pending
resolution of the management buyout proposal. We are not able to predict with
certainty the final outcome of the pending buyout proposal.
Our senior management's attention may be diverted from our daily operations
because of the proposed management-led buyout of KMI and other significant
transactions. The investors in the proposed buyout of KMI include members of
senior management of KMI, most of whom are also senior officers of our general
partner and of KMR. As a result, prior to the closing of the transaction, our
senior management's attention may be diverted from the management of our daily
operations. Similarly, KMI has publicly disclosed that several other significant
transactions are being considered that, if pursued, would require substantial
management time and attention.
Risks Related to Our Common Units
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.
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:
o 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;
50
o 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
o 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:
o discourage a person or group from attempting to remove the general
partner or otherwise change management; and
o reduce the price at which the 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:
o 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;
o 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
o the general partner does not breach any standard of care or duty by
resolving conflicts of interest unless the general partner acts in bad
faith.
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:
o 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
51
o 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:
o 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
o 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.
52
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. 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 2006.
53
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
---- --- ------------- -------------
2006
First Quarter $ 56.22 $ 44.70 $ 0.8100 0.018566
Second Quarter 48.80 43.62 0.8100 0.018860
Third Quarter. 46.53 42.80 0.8100 0.018981
Fourth Quarter 48.98 43.01 0.8300 0.016919
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
Distribution 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 to declare cash distributions of at least $3.44
per unit for 2007 and further, we expect that we will continue to be able to
grow our distribution per unit at about 8% per year over the long-term 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 capital costs
associated with financing the payment of reparations sought by shippers on our
Pacific operations' interstate pipelines.
As of February 1, 2007, there were approximately 190,230 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".
Effective December 1, 2006, we issued 34,627 common units as part of the
purchase price for all of the membership interests in Devco USA L.L.C. Our total
purchase price for Devco was approximately $7.3 million, consisting of $4.8
million in cash, $1.6 million in common units, and $0.9 million of assumed
liabilities. The units were issued to a single accredited investor in a
transaction not involving a public offering, exempt from registration pursuant
to Section 4(2) of the Securities Act of 1933.
We did not repurchase any units during 2006.
54
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,
----------------------------------------------------------------
2006(5) 2005(6) 2004(7) 2003(8) 2002(9)
---------- ----------- ----------- ----------- -----------
(In thousands, except per unit and ratio data)
Income and Cash Flow Data:
Revenues............................................ $ 8,954,583 $ 9,787,128 $ 7,932,861 $ 6,624,322 $ 4,237,057
Gas purchases and other costs of sales.............. 5,990,963 7,167,414 5,767,169 4,880,118 2,704,295
Operations and maintenance.......................... 769,514 747,363 499,714 397,723 376,479
Fuel and power...................................... 216,222 183,458 151,480 108,112 86,413
Depreciation, depletion and amortization............ 413,725 349,827 288,626 219,032 172,041
General and administrative.......................... 219,575 216,706 170,507 150,435 122,205
Taxes, other than income taxes...................... 118,756 108,838 81,369 62,213 51,326
Other expense (income).............................. (30,306) -- -- -- --
------------ ------------ ------------ ------------ ------------
Operating income.................................. 1,256,134 1,013,522 973,996 806,689 724,298
Other income/(expense):
Earnings from equity investments.................... 76,170 91,660 83,190 92,199 89,258
Amortization of excess cost of equity investments... (5,664) (5,644) (5,575) (5,575) (5,575)
Interest, net....................................... (331,499) (258,861) (192,882) (181,357) (176,460)
Other, net.......................................... 11,065 3,273 2,254 7,601 1,698
Minority interest................................... (15,015) (7,262) (9,679) (9,054) (9,559)
Income tax provision................................ (19,048) (24,461) (19,726) (16,631) (15,283)
------------ ------------ ------------ ------------ ------------
Income before cumulative effect of a change in
accounting principle............................. 972,143 812,227 831,578 693,872 608,377
Cumulative effect of a change in accounting principle -- -- -- 3,465 --
------------ ------------ ------------ ------------ ------------
Net income........................................ $ 972,143 $ 812,227 $ 831,578 $ 697,337 $ 608,377
Less: General Partner's interest in net income.... (512,967) (477,300) (395,092) (326,524) (270,816)
------------ ------------ ------------ ------------ ------------
Limited Partners' interest in net income.......... $ 459,176 $ 334,927 $ 436,486 $ 370,813 $ 337,561
============ ============ ============ ============ ============
Basic and Diluted Limited Partners' Net Income per
unit:
Income before cumulative effect of a change in
accounting principle(1).......................... $ 2.04 $ 1.58 $ 2.22 $ 1.98 $ 1.96
Cumulative effect of a change in accounting principle -- -- -- 0.02 --
------------ ------------ ------------ ------------ ------------
Net income.......................................... $ 2.04 $ 1.58 $ 2.22 $ 2.00 $ 1.96
============ ============ ============ ============ ============
Per unit cash distribution declared(2).............. $ 3.26 $ 3.13 $ 2.87 $ 2.63 $ 2.435
Ratio of earnings to fixed charges(3)............... 3.63 3.76 4.91 4.77 4.37
Additions to property, plant and equipment.......... $ 1,058,265 $ 863,056 $ 747,262 $ 576,979 $ 542,235
Balance Sheet Data (at end of period):
Net property, plant and equipment.................. $ 9,445,471 $ 8,864,584 $ 8,168,680 $ 7,091,558 $ 6,244,242
Total assets........................................ $12,246,394 $11,923,462 $10,552,942 $ 9,139,182 $ 8,353,576
Long-term debt(4)................................... $ 4,384,332 $ 5,220,887 $ 4,722,410 $ 4,316,678 $ 3,659,533
Partners' capital................................... $ 4,021,653 $ 3,613,740 $ 3,896,520 $ 3,510,927 $ 3,415,929
- ------------------
(1) Represents income before cumulative effect of a change in accounting
principle per unit. 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.
(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
55
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 to long-term debt
for market value of interest rate swaps totaled $42,630 as of December 31,
2006, $98,469 as of December 31, 2005, $130,153 as of December 31, 2004,
$121,464 as of December 31, 2003, and $166,956 as of December 31, 2002.
(5) Includes results of operations for the oil and gas properties acquired from
Journey Acquisition-I, L.P. and Journey 2000, L.P., the terminal assets and
operations acquired from A&L Trucking, L.P. and U.S. Development Group,
Transload Services, LLC, and Devco USA L.L.C. since effective dates of
acquisition. The April 5, 2006 acquisition of the Journey oil and gas
properties were made effective March 1, 2006. The assets and operations
acquired from A&L Trucking and U.S. Development Group were acquired in
three separate transactions in April 2006. We acquired all of the
membership interests in Transload Services, LLC effective November 20,
2006, and we acquired all of the membership interests in Devco USA L.L.C.
effective December 1, 2006. We also acquired a 66 2/3% ownership interest
in Entrega Pipeline LLC effective February 23, 2006, however, our earnings
were not materially impacted during 2006 due to the fact that regulatory
accounting provisions required capitalization of revenues and expenses
until the second segment of the Entrega Pipeline is complete and
in-service.
(6) 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.
(7) 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.
(8) 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.
(9) 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,
56
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.
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:
o a description of our business strategy found in Items 1 and 2
"Business and Properties - Business Strategy";
o a description of developments during 2006, found in Items 1 and 2
"Business and Properties - Recent Developments"; and
o 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
Accounting standards require information in financial statements about the
risks and uncertainties inherent in significant estimates, and the application
of generally accepted accounting principles involves the exercise of varying
degrees of judgment. 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 our assets and
liabilities, our revenues and expenses during the reporting period, 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,
examples of certain areas that require more judgment relative to others include
our use of estimates in determining:
o the economic useful lives of our assets;
o the fair values used to allocate purchase price and to determine
possible asset impairment charges;
o reserves for environmental claims, legal fees, transportation rate
cases and other litigation liabilities;
o provisions for uncollectible accounts receivables;
57
o exposures under contractual indemnifications; and
o various other recorded or disclosed amounts.
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 expense or
capitalize, as appropriate, environmental expenditures that relate to current
operations, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. We do not discount environmental liabilities to a net present value,
and we recognize receivables for anticipated associated insurance recoveries
when such recoveries are deemed to be probable.
The steps involved in the process of managing our environmental reporting
include:
o identifying environmental regulatory issues that may affect us with
respect to potential clean-up liabilities, and the necessary level of
investigation in order to determine the potential cost associated with
environmental exposures;
o completing a materiality analysis to determine the reporting necessary
for each environmental issue; and
o evaluating alternatives to properly manage our environmental
liabilities going forward, including items such as environmental
insurance to help limit estimated costs, thereby assuring our
unitholders that the volatility often associated with environmental
estimates will not impair the value of their holdings.
Our recording of our environmental accruals often coincides with our
completion of a feasibility study or our commitment to a formal plan of action,
but generally, we recognize and/or adjust our environmental liabilities
following routine reviews of potential environmental issues and claims that
could impact our assets or operations. In both December 2005 and December 2004,
after thorough reviews of any potential environmental issues and claims, we
trued up (adjusted) our year-end environmental liabilities to reflect revisions
to previously estimated costs. The adjustments, described more fully below,
resulted in increases in environmental expenses.
In 2006, we made quarterly adjustments to our environmental liabilities to
reflect changes in previous estimates. In addition to quarterly reviews of
potential environmental issues and resulting environmental liability
adjustments, we made supplemental liability adjustments in 2006 that were
primarily related to newly identified and/or recently incurred environmental
issues and claims (largely related to refined petroleum products pipeline
releases of us and Plantation Pipe Line Company). These supplemental
environmental liability adjustments were recorded pursuant to our management's
requirement to recognize contingent environmental liabilities whenever the
associated environmental issue is likely to occur and the amount of our
liability can be reasonably estimated. In making these liability estimations, we
considered the effect of environmental compliance, pending legal actions against
us, and potential third-party liability claims.
As a result, in 2006, we recorded a combined $35.4 million decrease in
earnings associated with total environmental liability adjustments, including a
$17.9 million decrease in earnings associated with supplemental liability
adjustments. The total environmental expense adjustments (including our share of
environmental expense associated with liability adjustments recognized by
Plantation Pipe Line Company) included a $4.1 million increase in our estimated
environmental receivables and reimbursables, a $3.5 million decrease in our
equity investments, a $34.5 million increase in our overall accrued
environmental and related claim liabilities, and a $1.5 million increase in our
accrued expense liabilities.
The $17.9 million decrease in earnings related to supplemental
environmental liability adjustments resulted in a $16.4 million increase in
expense to our Products Pipelines business segment and a $1.5 million increase
in expense to our Natural Gas Pipelines business segment. It consisted of a
$14.9 million expense recorded within "Operations
58
and maintenance," a $4.9 million expense recorded within "Earnings from equity
investments," and a $1.9 million reduction in expense recorded within "Income
Taxes" in our accompanying consolidated statement of income for 2006.
Our 2005 environmental liability adjustments resulted from both revisions
to previously estimated costs and from the necessity of properly adjusting our
environmental expenses and accrued liabilities between our reportable business
segments, and combined, the adjustments resulted in a $23.3 million increase in
environmental expense that primarily affected our Products Pipelines and
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.
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.
In 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. The net impact of the $0.3 million expense item resulted in a $30.6
million increase in expense to our Products Pipelines business segment, a $7.6
million decrease in expense to our Natural Gas Pipelines business segment, a
$4.1 million decrease in expense to our CO2 business segment, and an $18.6
million decrease in expense to 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.
In December 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,
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, among others: (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 intended to respond to the complaints, which included
the compliance filing we submitted to the FERC on March 7, 2006.
59
In accordance with the FERC's December 2005 Order and February 2006 Order
on Rehearing, rate reductions were implemented on May 1, 2006. We assume that
reparations and accrued interest thereon will be paid no earlier than the second
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, OR96-2, and IS05-230
proceedings.
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 December 2005 and February 2006 FERC Orders, 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. We estimate that the actual, partial year impact on 2006 distributable
cash flow was approximately $15.7 million. As of December 31, 2006, our total
reserve related to various claims from lawsuits arising from our Pacific
operations' pipeline transportation rates amounted to $108.3 million.
In addition, in the third quarter of 2006, we made refund payments of $19.1
million to certain shippers on our Pacific operations' pipelines and we reduced
our rate case liability. The payment related to a settlement agreement reached
in May 2006 that resolved certain challenges by complainants with regard to
delivery tariffs and gathering enhancement fees at our Pacific operations'
Watson Station, located in Carson, California.
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, 2007. As of January 1, 2007, our goodwill was $829.0
million.
Our remaining intangible assets, excluding goodwill, include lease value,
contracts, customer relationships, technology-based assets 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, 2006 and 2005, these intangibles totaled $213.2 million and $217.0
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.
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 or
negatively, as additional information becomes available and as contractual,
economic and political conditions change.
60
Hedging Activities
We engage in a hedging program that utilizes derivative contracts to
mitigate (offset) 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 complex, and even when we
engage in hedging transactions that are effective economically, these
transactions may not be considered effective for accounting purposes.
According to the provisions of current accounting standards, to be
considered effective, changes in the value of a derivative contract or its
resulting cash flows must substantially offset changes in the value or cash
flows of the item being hedged. A perfectly effective hedge is one in which
changes in the value of the derivative contract exactly offset changes in the
value of the hedged item or expected cash flow of the future transactions in
reporting periods covered by the derivative contract. The ineffective portion of
the gain or loss and any component excluded from the computation of the
effectiveness of the derivative contract must be reported in earnings
immediately; accordingly, our financial statements may reflect some volatility
due to these hedges.
In addition, it is not always possible for us to engage in a hedging
transaction that completely mitigates our exposure to unfavorable changes in
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, but due to the fact that the part of
the hedging transaction that is not effective in offsetting undesired changes in
commodity prices (the ineffective portion) is required to be recognized
currently in earnings, 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:
o helping customers by providing energy, bulk commodity and liquids
products transportation, storage and distribution; and
o 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.
Consolidated
Year Ended December 31,
---------------------------------------------
2006 2005 2004
---------- ---------- ----------
(In thousands)
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments
Products Pipelines.................................................. $ 491,150 $ 370,052 $ 444,865
Natural Gas Pipelines............................................... 574,799 500,324 418,261
CO2................................................................. 488,170 470,887 357,636
Terminals........................................................... 408,133 314,606 281,738
----------- ----------- -----------
Segment earnings before depreciation, depletion and
amortization of excess cost of equity investments(a)............ 1,962,252 1,655,869 1,502,500
Depreciation, depletion and amortization expense.................... (413,725) (349,827) (288,626)
Amortization of excess cost of investments.......................... (5,664) (5,644) (5,575)
Interest and corporate administrative expenses(b)................... (570,720) (488,171) (376,721)
----------- ----------- -----------
Net income........................................................ $ 972,143 $ 812,227 $ 831,578
=========== =========== ===========
61
- -----------------
(a) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses and other
expense (income). Operating expenses include natural gas purchases and
other costs of sales, operations and maintenance expenses, fuel and power
expenses and taxes, other than income taxes.
2006 amount includes supplemental environmental liability adjustments
resulting in a $16,448 increase in expense to our Products Pipelines
business segment and a $1,500 increase in expense to our Natural Gas
Pipelines business segment. Also includes a $15,114 gain to our Natural Gas
Pipelines business segment from the combined sale of our Douglas natural
gas gathering system and Painter Unit fractionation facility, an $11,275
net increase in income to our Terminals business segment from the combined
effect of a property casualty insurance gain and incremental repair and
clean-up expenses (both associated with the 2005 hurricane season), a
$6,244 reduction in expense to our Natural Gas Pipelines business segment
due to the release of a reserve related to a natural gas pipeline contract
obligation, a $5,700 increase in income to our Products Pipelines business
segment from the settlement of transmix processing contracts, and a $1,819
decrease in revenues to our CO2 business segment related to a loss on
derivative contracts used to hedge forecasted crude oil sales.
2005 amount includes a rate case liability adjustment resulting in a
$105,000 expense to our Products Pipelines business segment, a $13,691
increase in expense to our Products Pipelines business segment resulting
from a North System liquids inventory reconciliation adjustment, and
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 amount includes environmental liability adjustments resulting in a
$30,611 increase 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 and loss from early
extinguishment of debt (2004 only).
Driven by strong financial results from natural gas sales, storage and
processing activities, and by incremental earnings from both dry-bulk product
and petroleum liquids terminal operations, we achieved a record level of net
income in 2006. For the year 2006, our net income was $972.1 million ($2.04 per
diluted unit) on revenues of $8,954.6 million. This compares with net income of
$812.2 million ($1.58 per diluted unit) on revenues of $9,787.1 million in 2005,
and net income of $831.6 million ($2.22 per diluted unit) on revenues of
$7,932.9 million in 2004.
Segment earnings before depreciation, depletion and amortization expenses
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 segment earnings before depreciation,
depletion and amortization expenses (defined in the table above) internally as a
measure of profit and loss used for evaluating segment performance and for
deciding how to allocate resources to our four reportable business segments.
Combined, our four business segments reported earnings before depreciation,
depletion and amortization of $1,962.3 million in 2006, $1,655.9 million in 2005
and $1,502.5 million in 2004.
Both the $306.4 million (19%) increase in total segment earnings before
depreciation, depletion, and amortization in 2006 compared to 2005, and the
$153.4 million (10%) increase in 2005 compared to 2004 were attributable to
internal growth and expansion and to incremental contributions from assets and
operations acquired since the end of 2004. Combined, the net effect of the
certain other items described in footnote (a) in the table above resulted in a
$160.6 million (8%) increase in total segment earnings before depreciation,
depletion and amortization expenses in 2006 relative to 2005, and a $141.7
million (8%) decrease in segment earnings in 2005 relative to 2004. The
remaining increases of $145.8 million (3%) and $295.1 million (20%),
respectively, in total segment earnings before depreciation, depletion and
amortization in 2006 and 2005, relative to prior years, consisted of the
following:
62
o increases of $78.7 million (4%) and $55.0 million (21%), respectively,
from our Terminals segment--primarily driven by both higher revenues
earned from transporting and storing higher volumes of petroleum and
petrochemical-related liquids and dry-bulk material products, and
incremental earnings from the impact of completed internal expansion
projects and acquired terminal operations since the end of 2004;
o increases of $54.7 million (11%) and $89.6 million (22%),
respectively, from our Natural Gas Pipelines segment--largely due to
improved sales margins on renewal and incremental natural gas sales
contracts, higher earnings from natural gas storage, gathering and
treating operations, and in 2006, to higher earnings from natural gas
processing activities;
o increases of $18.8 million (4%) and $117.7 million (33%),
respectively, from our CO2 segment--primarily due to higher sales of
carbon dioxide, crude oil, and natural gas processing plant liquids
products at higher average prices, and to higher revenues from carbon
dioxide transportation and related services associated with enhanced
crude oil recovery operations; and
o a decrease of $6.4 million (1%) and an increase of $32.8 million (7%),
respectively, from our Products Pipelines segment. As described more
fully below in "--Products Pipelines," the decrease in 2006 compared
to 2005 was largely related to incremental pipeline maintenance
expenses related to a change (beginning in the third quarter of 2006)
that transferred certain pipeline integrity management costs from
sustaining capital expenditures to expense. The increase in segment
earnings before depreciation, depletion and amortization in 2005
compared to 2004 was mainly due to higher revenues from deliveries of
refined petroleum products and natural gas liquids, higher revenues
from refined products terminal operations, and to incremental earnings
from the acquisition of Southeast terminal operations acquired in
2004;
While it is difficult to predict change in demand for energy
transportation, as well as future prices for energy commodity products and
overall economic trends, going forward, we anticipate a 12% increase in our
total segment earnings before depreciation, depletion, and amortization expenses
in 2007 compared to 2006. The key to our anticipated growth in 2007 will be the
continued expansion of our businesses, principally through capital investments
that will add throughput capacity to our refined products and natural gas
pipeline systems, increase our natural gas storage capacity, expand and enhance
our terminal services, and add infrastructure to our crude oil development and
carbon dioxide flooding operations.
Additionally, we declared a cash distribution of $0.83 per unit for the
fourth quarter of 2006 (an annualized rate of $3.32 per unit). This distribution
was 4% higher than the $0.80 per unit distribution we made for the fourth
quarter of 2005, and 12% higher than the $0.74 per unit distribution we made for
the fourth quarter of 2004. We expect to declare cash distributions of at least
$3.44 per unit for 2007; 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 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,
-------------------------------------------
2006 2005 2004
---------- ---------- ----------
(In thousands, except operating statistics)
Revenues............................................................. $ 776,268 $ 711,886 $ 645,249
Operating expenses(including adjustments)(a)......................... (308,296) (366,048) (222,036)
Earnings from equity investments(b).................................. 16,336 28,446 29,050
Interest income and Other, net- income (expense)(c).................. 12,017 6,111 4,677
Income taxes(d)...................................................... (5,175) (10,343) (12,075)
---------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments..... 491,150 370,052 444,865
Depreciation, depletion and amortization expense..................... (82,888) (79,199) (71,263)
Amortization of excess cost of equity investments.................... (3,362) (3,350) (3,281)
---------- ----------- -----------
Segment earnings................................................... $ 404,900 $ 287,503 $ 370,321
========== =========== ===========
63
Year Ended December 31,
-------------------------------------------
2006 2005 2004
---------- ---------- ----------
(In thousands, except operating statistics)
Gasoline (MMBbl)..................................................... 455.2 457.8 459.1
Diesel fuel (MMBbl).................................................. 161.0 166.0 161.7
Jet fuel (MMBbl)..................................................... 119.5 118.1 117.8
---------- ----------- -----------
Total refined products volumes (MMBbl)............................. 735.7 741.9 738.6
Natural gas liquids (MMBbl).......................................... 38.8 37.3 43.9
---------- ----------- -----------
Total delivery volumes (MMBbl)(e).................................. 774.5 779.2 782.5
========== =========== ===========
- --------------
(a) 2006 amount includes expense of $13,458 associated with supplemental
environmental liability adjustments. 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 liability adjustments.
(b) 2006 amount includes expense of $4,861 associated with environmental
liability adjustments on Plantation Pipe Line Company.
(c) 2006 amount includes income of $5,700 from the settlement of transmix
processing contracts.
(d) 2006 amount includes a decrease in expense of $1,871 associated with the
tax effect on our share of environmental expenses incurred by Plantation
Pipe Line Company and described in footnote (b).
(e) Includes Pacific, Plantation, North System, CALNEV, Central Florida,
Cypress and Heartland pipeline volumes.
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 $491.2 million on revenues of $776.3 million in
2006. This compares with earnings before depreciation, depletion and
amortization of $370.1 million on revenues of $711.9 million in 2005, and
earnings before depreciation, depletion and amortization of $444.9 million on
revenues of $645.2 million in 2004.
Segment Earnings before Depreciation, Depletion and Amortization
The segment's overall $121.1 million (33%) increase in earnings before
depreciation, depletion and amortization expenses in 2006 compared with 2005 and
its $74.8 million (17%) decrease in earnings before depreciation, depletion and
amortization expenses in 2005 compared with 2004 included an increase of $127.5
million and a decrease of $107.6 million, respectively, from the combined net
effect of the certain other items described in the footnotes to the table above.
These items consisted of the following:
o an increase in earnings of $5.7 million in 2006--related to two
separate contract settlements from our petroleum transmix processing
operations. First, we recorded income of $6.2 million from fees
received for the early termination of a long-term transmix processing
agreement at our Colton, California processing facility. Secondly, we
recorded an expense of $0.5 million related to payments we made to
Motiva Enterprises LLC in June 2006 to settle claims for prior period
transmix purchase costs at our Richmond, Virginia processing facility.
We included the net income of $5.7 million from these two items within
"Other, net" in our accompanying consolidated statement of income for
the year ended December 31, 2006;
o a decrease in earnings of $105.0 million in 2005--due to an increase
in operating expenses related to an adjustment to our products
pipelines rate case liability in December 2005. This adjustment is
more fully described above in "Critical Accounting Policies and
Estimates--Legal Matters;"
o a decrease in earnings of $16.4 million, $19.6 million and $30.6
million, respectively in 2006, 2005 and 2004--due to the increases in
expenses associated with the adjustments of our environmental
liabilities as more fully described above in "Critical Accounting
Policies and Estimates--Environmental Matters;" and
o a decrease in earnings of $13.6 million in 2005--due to an increase in
operating expenses related to adjustments made to account for
differences between physical and book natural gas liquids inventory on
our North System natural gas liquids pipeline. This inventory expense
was based on a reconciliation of our North System's natural gas
liquids inventory that was completed in the fourth quarter of 2005.
64
The remaining $6.4 million (1%) decrease in earnings before depreciation,
depletion and amortization expenses in 2006 compared with 2005, and the
remaining $32.8 million (7%) increase in earnings before depreciation, depletion
and amortization expenses in 2005 compared with 2004 consisted of the following
items:
o a decrease in earnings of $24.2 million in 2006--due to incremental
pipeline maintenance expenses recognized in the last half of 2006.
Beginning in the third quarter of 2006, the refined petroleum products
pipelines and associated terminal operations included within our
Products Pipelines segment (including Plantation Pipe Line Company,
our 51%-owned equity investee) began recognizing certain costs
incurred as part of its pipeline integrity management program as
maintenance expense in the period incurred, and in addition, recorded
an expense for costs previously capitalized during the first six
months of 2006. The overall decrease in earnings consisted of an $11.6
million decrease related to a change that transferred certain pipeline
integrity management costs from sustaining capital expenditures
(within "Property, plant and equipment, net" on our accompanying
consolidated balance sheets) to maintenance expense (within
"Operations and maintenance" in our accompanying consolidated
statements of income) and a $12.6 million decrease related to the
expensing of pipeline integrity costs in the second half of 2006.
Pipeline integrity costs encompass those costs incurred as part of an
overall pipeline integrity management program, which is a process for
assessing and mitigating pipeline risks in order to reduce both the
likelihood and consequences of incidents. An effective pipeline
integrity program is a systematic, comprehensive process that entails
pipeline assessment services, maintenance and repair services, and
regulatory compliance. Our pipeline integrity program is designed to
provide our management the information needed to effectively allocate
resources for appropriate prevention, detection and mitigation
activities. Combined, this change reduced the segment's earnings
before depreciation, depletion and amortization expenses by $24.2
million in 2006--increasing maintenance expenses by $20.1 million,
decreasing earnings from equity investments by $6.6 million, and
decreasing income tax expenses by $2.5 million;
o increases of $4.9 million (15%) and $18.6 million (133%),
respectively, from our Southeast refined products terminal operations.
Our Southeast terminal operations consist of 24 refined products
terminals located in the southeastern United States that we acquired
since December 2003. The increase in earnings before depreciation,
depletion and amortization in 2006 compared to 2005 was driven by
higher liquids throughput volumes at higher rates, relative to 2005,
and higher margins from ethanol blending and sales activities.
The 2005 increase included incremental earnings of $12.2 million from
both the seven refined products terminal operations we acquired in
March 2004 from ExxonMobil Corporation and the nine refined products
terminal operations we acquired in November 2004 from Charter Terminal
Company and Charter-Triad Terminals, LLC. This incremental amount
represents the acquired terminals' earnings during the additional
months of ownership in 2005, as compared to 2004, and does not include
increases or decreases during the same months we owned the assets in
both years. The remaining $6.4 million (46%) increase in earnings in
2005 versus 2004 (representing the increase from the same months we
owned all assets in both years) was primarily due to higher product
throughput revenues;
o increases of $4.1 million (1%) and $20.8 million (7%), respectively,
from our combined Pacific and CALNEV Pipeline operations. The increase
in earnings in 2006 compared to 2005 was primarily due to a $22.6
million (6%) increase in operating revenues, which more than offset an
$18.3 million (18%) increase in combined operating expenses. The
increase in operating revenues consisted of a $14.7 million (5%)
increase from refined products deliveries and a $7.9 million (8%)
increase from terminal and other fee revenue. The increase in
operating expenses included incremental environmental expenses of $7.3
million and incremental fuel and power expenses of $8.3 million. These
incremental environmental expenses were associated with our quarterly
true-ups of estimated environmental liability adjustments and were not
included with the expenses associated with the supplemental
environmental liability adjustments discussed above in "Critical
Accounting Policies and Estimates--Environmental Matters." The
increase in fuel and power expenses in 2006 compared to 2005 was
largely the result of higher electricity usage and higher utility
rates in 2006.
The increase in earnings in 2005 compared to 2004 was primarily
revenue driven--revenues from refined petroleum products deliveries
increased $24.1 million (9%) and terminal service revenues increased
$7.5 million (8%). The increase reflects higher pipeline delivery
revenues from our Pacific operations' North Line
65
pipeline, largely due to our completion of a $95 million capital
expansion project in December 2004. The expansion project increased
the capacity of the North Line by approximately 40%, and involved the
replacement of an existing 70-mile, 14-inch diameter pipeline segment
with a new 20-inch diameter line and the rerouting of certain pipeline
segments away from environmentally sensitive areas and residential
neighborhoods;
o increases of $3.7 million (12%) and $1.2 million (4%), respectively,
from our Central Florida Pipeline. Both increases were mainly due to
higher year-over-year product delivery revenues--the 2006 revenue
increase was driven by higher average tariff and terminal rates, and
the 2005 revenue increase resulted from an 8% increase in throughput
delivery volumes;
o an increase of $3.1 million (11%) and a decrease of $1.7 million (6%)
respectively, from the combined operations of our North System and
Cypress natural gas liquids pipelines. The increase in earnings in
2006 compared to 2005 consisted of a $3.3 million (15%) increase from
our North System and a $0.2 million (4%) decrease from our Cypress
Pipeline. The increase from our North System was primarily due to a
$2.5 million (6%) increase in system throughput revenues, and the
decrease from Cypress was mainly due to higher fuel and power costs,
related to an over 2% increase in natural gas liquids delivery volumes
in 2006 versus 2005.
The decrease in earnings in 2005 compared to 2004 consisted of a $0.8
million (4%) decrease from our North System and a $0.9 million (15%)
decrease from our Cypress Pipeline. The North System decrease was
mainly due to higher product storage expenses, related to both a new
storage contract agreement entered into in April 2004 and higher
levels of year-end inventory in 2005. The Cypress Pipeline 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.
o an increase of $2.6 million (13%) and a decrease of $2.0 million (9%),
respectively, from our petroleum pipeline transmix processing
operations. The 2006 increase consisted of incremental earnings of
$3.0 million from the inclusion of our Greensboro, North Carolina
transmix facility in 2006, and a decrease in earnings of $0.4 million
from the combined operations of our remaining transmix facilities,
largely due to higher operating, fuel and power costs which offset
increases in processing revenues. In the second quarter of 2006, we
completed construction and placed into service the approximate $11
million Greensboro facility, which is capable of processing 6,000
barrels of transmix per day for Plantation and other interested
parties. In 2006, the facility earned revenues of $3.6 million and
incurred operating expenses of $0.6 million.
The $2.0 million decrease in earnings in 2005 relative to 2004 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 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;
o an increase of $1.6 million (8%) and a decrease of $3.4 million (15%),
respectively, from our 49.8% ownership interest in the Cochin pipeline
system. The 2006 increase was largely related to lower pipeline
operating expenses in 2006 compared to 2005. The decrease in expenses,
including labor and power costs, resulted from year-to-year decreases
in both pipeline delivery volumes and pipeline repair costs. The
decrease in expenses more than offset a 1% drop in operating revenues
in 2006 versus 2005, due mainly to a decrease in transportation
volumes resulting from pipeline operating pressure restrictions.
The decrease in earnings in 2005 resulted from both lower
transportation revenues and higher operating expenses, when compared
to 2004. The decrease in revenues was due to a drop in delivery
volumes caused by extended pipeline testing and repair activities and
by warmer winter weather, and the increase in operating expenses was
due principally to higher pipeline repair, maintenance and testing
costs;
o decreases of $2.0 million (5%) and $2.6 million (6%), respectively,
from our West Coast terminal operations. The 2006 decrease reflects
incremental environmental expenses of $6.2 million recognized in 2006
and not included with the expenses associated with the supplemental
environmental liability adjustments discussed
66
above. These environmental expenses followed quarterly reviews of any
potential environmental issues that could impact our West Coast
terminal operations and, when aggregated with all remaining expenses,
resulted in a combined $9.0 million (46%) increase in operating
expenses in 2006 versus 2005. The higher expenses more than offset a
$6.5 million (11%) increase in operating revenues, 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 products
terminal.
The decrease in earnings in 2005 compared to 2004 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 products terminal located in
San Pedro, California; and
o a decrease of $0.2 million (0%) and an increase of $1.9 million (6%),
respectively, from our approximate 51% ownership interest in
Plantation Pipe Line Company. Earnings before depreciation, depletion
and amortization from our investment in Plantation were essentially
flat in 2006 versus 2005, as lower equity earnings were mostly offset
by lower operatorship expenses. The decrease in both lower net income
and pipeline operating expenses were associated with lower
year-to-year transportation revenues, due primarily to an almost 7%
drop in overall refined products delivery volumes in 2006. The decline
in volumes was primarily due to alternative pipeline service into
Southeast markets and to changes in supply from Louisiana and
Mississippi refineries related to new ultra low sulfur diesel and
ethanol blended gasoline requirements. The drop in revenues was
largely offset by lower operating and power expenses, due to the lower
transportation volumes.
The increase in earnings in 2005 relative to 2004 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.
Segment Details
Revenues for the segment increased $64.4 million (9%) in 2006 compared to
2005, and increased $66.7 million (10%) in 2005 compared to 2004. The respective
year-to-year increases in segment revenues were principally due to the
following:
o increases of $24.5 million (43%) and $33.1 million (141%),
respectively, from our Southeast terminals. The 2006 increase was
largely attributable to higher ethanol blending and sales revenues and
higher liquids inventory sales (offset by higher costs of sales, as
described below). The 2005 increase was primarily due to terminal
acquisitions--including incremental revenues of $23.5 million
attributable to the Charter terminals we acquired in November 2004,
and $2.6 million attributable to the ExxonMobil terminals we acquired
in March 2004;
o increases of $16.2 million (5%) and $26.6 million (8%), respectively,
from our Pacific operations. The increase in revenues in 2006 compared
to 2005 consisted of a $9.8 million (4%) increase in refined products
delivery revenues and a $6.4 million (7%) increase in refined products
terminal revenues in 2006, compared to 2005. The increase from product
deliveries reflect a 2% increase in mainline delivery volumes in 2006,
and includes the impact of both rate reductions that went into effect
on May 1, 2006, based on FERC filings associated with our Pacific
operations' rate litigation, and rate increases that went into effect
July 1, 2006 and July 1, 2005, according to the FERC annual index rate
increase (a producer price index-finished goods adjustment). The
increase from terminal revenues was due to the higher transportation
barrels and to incremental service revenues, including diesel
lubricity-improving injection services that we began offering in May
2005.
Our Pacific operations' $26.6 million increase in revenues in 2005
relative to 2004 included increases of $21.2 million (9%) from
mainline refined products delivery revenues and $5.4 million (6%) from
incremental terminal revenues. The increase from products delivery
revenues was driven by a 2% increase in mainline
67
delivery volumes and by increases in average mainline tariff rates;
the increase from terminal operations was primarily due to increased
terminal and ethanol blending services, largely as a result of the
increase in pipeline throughput, and to incremental revenues from
diesel lubricity-improving injection services.
The increase in mainline tariff rates included both FERC approved
annual indexed interstate tariff increases in July 2004 and 2005, 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 December 22,
2004, but is being collected subject to refund, pending resolution of
protests to the application by certain shippers;
o an increase of $6.5 million (11%) in 2006 versus 2005 from our West
Coast terminals. Terminal revenues were flat across both 2005 and
2004, but increased in 2006 compared to 2005 due to storage rent
escalations, higher throughput barrels and rates at various locations,
and additional tank capacity at our Carson/Los Angeles Harbor system
terminals;
o increases of $6.4 million (11%) and $5.0 million (9%), respectively,
from our CALNEV Pipeline. The increase in 2006 compared to 2005
consisted of a $4.9 million (11%) increase from higher refined
products deliveries and a $1.5 million (11%) increase from overall
terminal revenues. The increase from products deliveries was due to a
4% increase in delivery volumes and a 6% increase in average tariff
rates (including FERC annual index rate increases in July 2006 and
2005). The higher terminal revenues resulted primarily from additional
transportation barrel deliveries at our Barstow, California and Las
Vegas, Nevada terminals, and from higher diesel lubricity additive
injection service revenues. The $5.0 million increase in revenues in
2005 versus 2004 consisted of a $2.9 million (7%) increase from
refined products delivery revenues, primarily due to volume growth,
and a $2.1 million (19%) increase from terminal operations, due to
higher product storage, injection and ethanol blending services;
o increases of $3.8 million (10%) and $2.8 million (8%), respectively,
from our Central Florida Pipeline. The 2006 increase was due to a 10%
increase in average tariff rates compared to 2005. The increased rates
reflect reductions in zone-based credits in 2006 versus 2005. The
year-to-year increase in 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;
o increases of $2.5 million (6%) and $1.4 million (3%), respectively,
from our North System. The 2006 increase was due to higher natural gas
liquids delivery revenues in 2006 versus 2005, driven by a 5% increase
in system throughput volumes. The volume increase was primarily
related to additional refinery demand in 2006 versus 2005.
The 2005 increase was due to higher average tariff rates, which more
than offset a drop in revenues caused by a decline in delivery
volumes. The increase in tariff rates in 2005 over 2004 resulted from
both a higher ratio of long haul shipments to shorter haul shipments
and, to a lesser extent, higher published tariff rates that were
approved by the FERC and became effective April 1, 2005. The new rates
were associated with a cost of service filing that was approved by the
FERC. The decline in volumes was mainly related to lower propane
demand due to warmer winter weather in the Midwest during 2005
relative to 2004; and
o decreases of $0.5 million (1%) and $1.8 million (5%), respectively,
from our ownership interest in the Cochin pipeline system, as
described above.
Combining all of the segment's operations, total delivery volumes of
refined petroleum products decreased 0.8% in 2006 compared to 2005, but
increased 0.4% in 2005 compared to 2004. Compared to last year, our Pacific
operations' total delivery volumes were up 1.7%, due in part to the East Line
expansion which was in service for the last seven months of 2006. The expansion
project substantially increased pipeline capacity from El Paso, Texas to Tucson
and Phoenix, Arizona. In addition, our CALNEV Pipeline delivery volumes were up
4.2% in 2006 versus 2005, due primarily to strong demand from the Southern
California and Las Vegas, Nevada markets. The overall decrease in year-to-year
segment deliveries of refined products was largely related to a 6.8% drop in
volumes from
68
the Plantation Pipeline in 2006, as described above. Compared to 2005, total
deliveries of natural gas liquids increased 4.0% in 2006, driven by the
higher volumes on our North System.
For 2005, the overall increase in delivery volumes compared with 2004
included 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 and the Cypress Pipeline. The drop in demand on the North
System was primarily due to a minimal grain drying season and to warmer weather
in 2005; the drop on Cypress was chiefly due to reduced demand from a
petrochemical plant located in Lake Charles, Louisiana, resulting from
hurricane-related closures in 2005.
The segment's operating expenses, which consist of all cost of sales
expenses, operating and maintenance expenses, fuel and power expenses, and all
tax expenses, excluding income taxes, decreased $57.8 million (16%) in 2006
versus 2005 and increased $144.0 million (65%) in 2005 versus 2004. Combined,
the net effect attributable to four items previously discussed: (i) the
expensing of pipeline integrity costs in 2006; (ii) the adjusting of segment
environmental liability balances in 2006, 2005 and 2004; (iii) the adjusting of
our Pacific operations' pipeline rate case liability in 2005; and (iv) the
expensing of inventory costs associated with the reconciliation of our North
System's inventory balances in 2005, resulted in a $104.7 million decrease in
operating expenses in 2006 relative to 2005, and a $107.6 million increase in
operating expenses in 2005 relative to 2004.
The remaining year-over-year increases of $46.9 million (21%) in 2006
compared to 2005 and $36.4 million (19%) in 2005 compared to 2004, primarily
consisted of the following:
o increases of $19.6 million (82%) and $14.5 million (153%),
respectively, from our Southeast terminals. The 2006 increase was
largely attributable to higher costs of sales related to higher
ethanol blending and higher ethanol and liquids purchases (offset by
higher ethanol revenues). The 2005 increase was primarily due to
incremental expenses related to the terminal operations we acquired in
2004--including expenses of $13.0 million attributable to the Charter
terminals we acquired in November 2004, and $0.9 million attributable
to the ExxonMobil terminals we acquired in March 2004;
o increases of $18.3 million (18%) and $11.7 million (13%),
respectively, from our combined Pacific and CALNEV Pipeline
operations. The 2006 increase was due to a lower capitalization of
expenses, relative to 2005, higher fuel and power, and higher remedial
and repair expenses. The decrease in capitalized costs was primarily
due to the expensing of pipeline integrity management costs in 2006,
versus capitalizing such costs in the prior year. The increase in fuel
and power expenses was due to higher refined products delivery volumes
and higher average utility rates in 2006, and to a utility rebate
credit received in the first quarter of 2005. The increase in pipeline
repair expenses was largely related to pipeline failures and releases
that have occurred since the end of 2005.
The $11.7 million increase in expenses in 2005 compared to 2004 was
mainly due to higher labor and operating expenses, including
incremental power expenses, associated with increased transportation
volumes and terminal operations. The segment also incurred higher
maintenance and inspection expenses during 2005 as a result of
environmental issues, 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;
o increases of $9.0 million (46%) and $1.6 million (9%), respectively,
from our West Coast terminals. The increase in expenses in 2006
relative to 2005 was primarily related to incremental environmental
expenses of $6.2 million (not related to the segment's supplemental
environmental liability adjustments in 2006) and to higher materials
and supplies expense as a result of lower capitalized overhead. The
increase in operating expenses in 2005 compared to 2004 was chiefly
due to higher property tax expenses, described above, and higher cost
of sales related to incremental terminal services;
o increases of $0.2 million (2%) and $1.4 million (18%), respectively,
from our Central Florida Pipeline operations. The increase in 2006
compared to 2005 was due to incremental environmental expenses (not
69
related to the segment's supplemental environmental liability
adjustments in 2006). The increase in operating expenses in 2005
compared to 2004 was primarily due to higher maintenance expenses, due
to additional expense accruals related to a pipeline release occurring
in September 2005;
o a decrease of $1.7 million (10%) and an increase of $2.9 million
(22%), respectively, from our proportionate interest in the Cochin
Pipeline. The decrease in expenses in 2006 was mainly due to the drop
in throughput volumes in 2006 compared to 2005. The increase in
expenses in 2005 versus 2004 was primarily due to higher labor and
outside services associated with pipeline maintenance and testing
costs, and partly due to a full year's inclusion of an additional 5%
ownership interest in Cochin. 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%; and
o a decrease of $0.5 million (3%) and an increase of $2.9 million (16%),
respectively, from our North System. The 2006 decrease was due to both
higher product gains and lower fuel and power expenses relative to
2005, partly offset by higher property tax expenses related to an
expense true-up recognized in the third quarter of 2006. The 2005
increase was primarily due to higher liquids storage expenses in 2005,
as discussed above.
Earnings from our Products Pipelines' equity investments were $16.3 million
in 2006, $28.4 million in 2005 and $29.1 million in 2004. Earnings from equity
investments consist primarily of our approximate 51% interest in the pre-tax
income of Plantation Pipe Line Company and our 50% interest in the net income of
Heartland Pipeline Company and Johnston County Terminal, LLC. We include our
proportionate share of Plantation's income tax expenses within "Income taxes" in
our accompanying statements of income, and the interest income we earn on loans
to Plantation are reported within "Interest, net" in our accompanying statements
of income.
The $12.1 million (43%) decrease in equity earnings in 2006 compared to
2005 was mainly due to lower equity earnings from Plantation, due to both a $6.6
million decrease for our proportionate share of Plantation's pre-tax pipeline
integrity expenses that were recognized in the second half of 2006, and a $4.9
million decrease for our proportionate share of pre-tax environmental expenses
recognized by Plantation in the second quarter of 2006. This environmental
expense was related to supplemental environmental and clean-up liability
adjustments associated with an April 17, 2006 pipeline release of turbine fuel
from Plantation's 12-inch petroleum products pipeline located in Henrico County,
Virginia.
The $0.7 million (2%) decrease in equity earnings in 2005 compared to 2004
primarily consisted of 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 was due to lower
overall pre-tax income earned by Plantation, due to, among other things, higher
operating expenses and higher interest expenses. For our investment in
Heartland, the increase was due to Heartland's higher net income, primarily due
to higher pipeline delivery volumes in 2005 versus 2004.
The segment's income from allocable interest income and other income and
expense items increased $5.9 million (97%) in 2006 compared to 2005, and
increased $1.4 million (31%) in 2005 compared to 2004. The 2006 increase was
primarily due to the $5.7 million other income item from the favorable
settlement of transmix processing contracts in the second quarter of 2006, and
partly due to higher administrative overhead collected by our West Coast
terminals from reimbursable projects. 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.
Income tax expenses decreased $5.2 million (50%) in 2006 compared to 2005,
and decreased $1.7 million (14%) in 2005 compared to 2004. The decrease in 2006
versus 2005 was related to the lower pre-tax earnings from Cochin and
Plantation, and the decrease in 2005 versus 2004 was mainly due to lower income
tax on Cochin 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 $86.3 million, $82.5 million
and $74.5 million in each of the years ended December 31, 2006, 2005 and 2004,
respectively. The $3.8 million (5%) increase in 2006 compared to 2005 was
primarily due to higher depreciation expenses from our Pacific and Southeast
terminal operations. The increase from our Pacific operations related to higher
depreciable costs as a result of capital spending for both pipeline and storage
expansion since the end of 2005
70
in order to strengthen and enhance our business operations on the West Coast.
The increase from our Southeast terminal operations related to incremental
depreciation charges resulting from final purchase price allocations, made in
the fourth quarter of 2005, for depreciable terminal assets we acquired in
November 2004 from Charter Terminal Company and Charter-Triad Terminals, LLC.
The overall $8.0 million (11%) increase in depreciation expenses in 2005
compared to 2004 was primarily due to higher depreciation expenses from our
Pacific operations, related to the capital investments made since the end of
2004, as well as to incremental depreciation expenses of $1.8 million related to
the Southeast terminal assets we acquired in March and November 2004.
Natural Gas Pipelines
Year Ended December 31,
--------------------------------------------
2006 2005 2004
---------- ---------- ----------
(In thousands, except operating statistics)
Revenues............................................................. $ 6,577,661 $ 7,718,384 $ 6,252,921
Operating expenses (including environmental adjustments)(a).......... (6,042,639) (7,254,979) (5,854,557)
Earnings from equity investments..................................... 40,447 36,812 19,960
Interest income and Other, net - income (expense).................... 753 2,729 1,832
Income taxes......................................................... (1,423) (2,622) (1,895)
------------- ------------ ------------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments..... 574,799 500,324 418,261
Depreciation, depletion and amortization expense..................... (65,374) (61,661) (53,112)
Amortization of excess cost of equity investments.................... (285) (277) (277)
------------- ------------ ------------
Segment earnings................................................... $ 509,140 $ 438,386 $ 364,872
============= ============ =============
Natural gas transport volumes (Trillion Btus)(b)..................... 1,440.9 1,317.9 1,353.1
============= ============ =============
Natural gas sales volumes (Trillion Btus)(c)......................... 909.3 924.6 992.4
============= ============ =============
- ----------------
(a) 2006 amount includes expense of $1,500 associated with supplemental
environmental liability adjustments, a $6,244 reduction in expense due to
the release of a reserve related to a natural gas pipeline contract
obligation, and a $15,114 gain from the combined sale of our Douglas
natural gas gathering system and Painter Unit fractionation facility. 2005
and 2004 amounts include decreases in expense of $89 and $7,602,
respectively, 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 marketing,
transporting, storing, gathering and processing natural gas through both
intrastate and interstate pipeline systems and related facilities. In 2006, the
segment reported earnings before depreciation, depletion and amortization of
$574.8 million on revenues of $6,577.7 million. This compares with earnings
before depreciation, depletion and amortization of $500.3 million on revenues of
$7,718.4 million in 2005 and earnings before depreciation, depletion and
amortization of $418.3 million on revenues of $6,252.9 million in 2004.
Segment Earnings before Depreciation, Depletion and Amortization
The segment's overall $74.5 million (15%) increase in earnings before
depreciation, depletion and amortization expenses in 2006 compared with 2005 and
its $82.0 million (20%) increase in earnings before depreciation, depletion and
amortization expenses in 2005 compared with 2004 included an increase of $19.8
million and a decrease of $7.6 million, respectively, from the combined net
effect of the certain other items described in footnote (a) to the table above.
These items consisted of the following:
o an increase in earnings of $15.1 million in 2006--due to the sale of
our Douglas natural gas gathering system and Painter Unit
fractionation facility in April 2006. Effective April 1, 2006, we sold
these two assets to a third party for approximately $42.5 million in
cash, and we included a net gain of $15.1 million within "Other
expense (income)" in our accompanying consolidated statement of income
for 2006. For more information on this gain, see Note 2 to our
consolidated financial statements included elsewhere in this report;
71
o an increase in earnings of $6.2 million in 2006--due to release of a
reserve related to a natural gas purchase/sales contract associated
with the operations of our West Clear Lake natural gas storage
facility located in Harris County, Texas. We acquired this storage
facility as part of our acquisition of Kinder Morgan Tejas on January
31, 2002, and upon acquisition, we established a reserve for a
contract liability; and
o a decrease in earnings of $1.5 million in 2006 and an increase in
earnings of $7.6 million in 2004--due to changes in environmental
operating expenses associated with the adjustments of our
environmental liabilities as more fully described above in "Critical
Accounting Policies and Estimates--Environmental Matters."
The segment's remaining $54.7 million (11%) increase in earnings before
depreciation, depletion and amortization expenses in 2006 compared with 2005 was
driven by higher earnings from our Texas intrastate natural gas pipeline group,
primarily from improved margins resulting from the negotiation of renewal and
incremental gas purchase and sales contracts, and by higher earnings from
natural gas storage and processing activities. Our Texas intrastate group
includes the operations of the following four natural gas pipeline systems:
Kinder Morgan Tejas (including Kinder Morgan Border Pipeline), Kinder Morgan
Texas Pipeline, Kinder Morgan North Texas Pipeline and our Mier-Monterrey Mexico
Pipeline. Combined, the group accounted for 55% of the total increase in segment
earnings before depreciation, depletion and amortization in 2006 versus 2005.
The segment's remaining $89.6 million (22%) increase in earnings in 2005
compared with 2004 was mainly due to higher margins on recurring natural gas
sales business and higher storage and service revenues from our Texas intrastate
group, and to 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 on November 1, 2004, and
the incremental amounts above relate to TransColorado's operations during the
first ten months of 2005 and do not include increases or decreases during the
same two months we owned the asset in both 2005 and 2004.
Specifically, the respective remaining changes in year-to-year segment
earnings before depreciation, depletion and amortization expense in 2006 versus
2005, and 2005 versus 2004, consisted of the following:
o increases of $34.6 million (13%) and $30.1 million (13%),
respectively, from our Texas intrastate natural gas pipeline
group--due primarily to improved margins on the group's natural gas
purchase and sales activities, described above. With regard to our
natural gas sales activities, 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. In 2006, our Texas intrastate group's natural gas sales
margin increased $48.0 million (34%) over 2005; and in 2005, the
group's margin increased $30.7 million (28%) over 2004. The group's
margin can vary depending upon, among other things, the price
volatility of natural gas produced and delivered in Texas and in the
surrounding Gulf Coast region, the changes in availability and demand
for transportation and storage capacities, and any changes in the
terms or conditions in which natural gas is purchased and sold.
Additionally, we manage price risk associated with unfavorable changes
in natural gas prices by using energy derivative contracts, 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;
o increases of $10.2 million (10%) and $2.4 million (2%), respectively,
from our Kinder Morgan Interstate Gas Transmission system. The
increase in 2006, relative to 2005, was due largely to higher revenues
earned in 2006 from both operational sales of natural gas and natural
gas park and loan services. The increase in 2006 earnings from these
incremental revenues more than offset a relative decrease in earnings
resulting from favorable natural gas imbalance valuation adjustments
recognized in 2005.
The increase in earnings in 2005 compared to 2004 was due mainly to
higher revenues from both favorable fuel recovery volumes and prices
and favorable imbalance valuation adjustments. In addition, KMIGT
realized lower operating expenses in 2005 compared to 2004, primarily
due to the expensing, in the fourth quarter of 2004, of certain
capitalized project costs that no longer held realizable economic
benefits. The
72
increase in revenues in 2005 versus 2004 was partially offset by lower
margins on operational gas sales and reduced cushion gas volumes sold;
o increases of $4.3 million (13%) and $17.3 million (119%),
respectively, from our 49% equity investment in Red Cedar Gathering
Company--due largely to higher natural gas gathering revenues and to
higher prices on incremental sales of excess fuel gas. Additionally,
since the end of 2004, we reduced the amount of natural gas lost and
used within the system during gathering operations, which in turn has
increased natural gas volumes available for sale;
o increases of $3.8 million (10%) and $33.5 million respectively, from
our TransColorado Pipeline--the 2006 increase was largely due to
higher natural gas transmission revenues earned in 2006 compared to
2005. The revenue increase related to higher natural gas delivery
volumes resulting from both system improvements and the successful
negotiation of incremental firm transportation contracts. The pipeline
system improvements were associated with an expansion, completed since
the end of the first quarter of 2005, on the northern portion of the
pipeline. TransColorado's north system expansion project was
in-service on January 1, 2006, and provides for up to 300 million
cubic feet per day of additional northbound transportation capacity.
The overall increase in earnings in 2005 compared to 2004 was
primarily due to incremental earnings of $31.8 million, representing
TransColorado's earnings before depreciation, depletion and
amortization expenses in the first ten months of 2005 (after acquiring
the pipeline on November 1, 2004);
o an increase of $2.3 million (21%) and a decrease of $5.1 million
(32%), respectively, from the combined operations of our Casper
Douglas and Painter natural gas gathering and processing operations.
The 2006 increase in earnings was primarily related to incremental
earnings associated with favorable hedge settlements from our Casper
Douglas natural gas gathering and processing operations. We benefited
from comparative differences in hedge settlements associated with the
rolling-off of older low price crude oil and propane positions at
December 31, 2005. The 32% decrease in earnings in 2005 versus 2004
was mainly due to higher cost of sales expense and higher commodity
hedging costs in 2005. The higher cost of sales expense reflected
higher natural gas purchase costs, due to higher average gas prices in
2005. The higher commodity hedging costs was chiefly due to
unfavorable changes in settlement prices;
o increases of $0.3 million (1%) and $10.9 million (28%), respectively,
from our Trailblazer Pipeline--due primarily to timing differences on
the settlements of pipeline transportation imbalances in 2006 and
2005, compared to the respective year-earlier periods. These pipeline
imbalances are due to differences between the volumes received and the
volumes delivered at inter-connecting points on the pipeline, and
generally, our imbalances are either settled in cash or made up in
kind subject to both the pipelines' various tariff provisions and
operational balancing agreements with shippers. The increase in
earnings in 2006 compared to 2005 was also due to incremental sales of
operational natural gas in the fourth quarter of 2006, largely related
to timing differences; and
o a decrease of $0.8 million (13%) and an increase of $0.5 million (9%),
respectively, from the combined earnings of our remaining natural gas
operations, including our previous 50% investment in Coyote Gas
Treating, LLC and our 25% investment in Thunder Creek Gas Services,
LLC--the decrease in 2006 was due to both the absence of equity
earnings from our investment in Coyote and to lower natural gas
gathering income from Thunder Creek. Effective September 1, 2006, we
and the Southern Ute Indian Tribe contributed the value of our
respective 50% ownership interests in Coyote Gas Treating, LLC to Red
Cedar, and as a result, Coyote Gas Treating, LLC became a wholly owned
subsidiary of Red Cedar.
The increase in earnings in 2005 compared to 2004 was largely due to
incremental interest income from our long-term note receivable from
Coyote. In 2005, we allocated this interest income to our Natural Gas
Pipelines business segment, versus treating it as unallocated interest
income in 2004. In March 2006, we contributed the principal amount of
$17.0 million related to this note to our equity investment in Coyote.
For more information on this note and on our equity contribution to
Red Cedar, see Note 12 to our consolidated financial statements
included elsewhere in this report.
73
Segment Details
In 2006, total segment operating revenues, including revenues from natural
gas sales, decreased $1,140.7 million (15%) compared to 2005, and combined
operating expenses, including natural gas purchase costs, decreased $1,212.3
million (17%). In 2005, the segment reported significant increases in both
revenues and operating expenses when compared to the year-earlier
period--revenues increased $1,465.5 million (23%) and operating expenses
increased $1,400.4 million (24%). The year-to-year changes in total segment
revenues and total segment operating expenses largely represented the respective
changes in our Texas intrastate group's natural gas sales revenues and natural
gas purchase expenses, due primarily to year-over-year changes in natural gas
prices.
Our Intrastate 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. We did, however, realize incremental revenues of $36.2 million and
incremental operating expenses of $4.5 million from the ownership of our
TransColorado Pipeline in the first ten months of 2005.
As discussed above, our Texas intrastate group both purchases and sells
significant volumes of natural gas. Compared to the respective prior year,
revenues from the sales of natural gas from our Intrastate group decreased
$1,154.4 million (16%) in 2006, and increased $1,404.1 million (24%) in 2005;
similarly, the group's costs of sales expense, including natural gas purchase
costs, decreased $1,202.4 million (17%) in 2006, and increased $1,373.4 million
(24%) in 2005.
Since our Texas intrastate group sells natural gas in the same price
environment in which it is purchased, any increases in its gas purchase costs
are largely offset by corresponding increases in its sales revenues. Due to this
offsetting of revenues and expenses, we believe that margin is a better
comparative performance indicator than either revenues or cost of sales, and our
objective is to match purchases and sales in the aggregate, and to lock-in an
acceptable margin by capturing the difference between our average gas sales
prices and our average gas purchase and cost of fuel prices. Our strategy
involves relying mainly on long-term natural gas sales and purchase agreements,
with some purchases and sales being made in the spot market in order to provide
some flexibility to balance supply and demand in reaction to changing market
conditions.
Our Texas intrastate groups' natural gas sales margin increased $48.0
million (34%) and $30.7 million (28%), respectively, in 2006 and 2005, when
compared to the year-earlier period. The variations in natural gas sales margin
were driven by changes in natural gas prices and sales volumes--the $48.0
million margin increase in 2006 consisted of a $59.3 million increase from
favorable changes in average sales versus average purchase prices (favorable
price variance), and a $11.3 million decrease from lower volumes (unfavorable
volume variance)--the $30.7 million margin increase in 2005 consisted of a $40.0
million increase from favorable changes in average sales prices versus average
purchase prices, and a $9.3 million decrease from lower volumes. Also, the
intrastate groups' margins from natural gas processing activities increased
$10.1 million (53%) in 2006 compared to 2005, and decreased $3.8 million (17%)
in 2005 compared to 2004.
We account for the segment's investments in Red Cedar Gathering Company,
Thunder Creek Gas Services, LLC, and prior to September 1, 2006, Coyote Gas
Treating, LLC under the equity method of accounting. Combined earnings from
these three investees increased $3.6 million (10%) and $16.9 million (84%),
respectively, in 2006 and 2005, when compared to year-earlier periods. The
increases were chiefly due to higher net income earned by Red Cedar during 2006
and 2005, partially offset by lower net income from our combined investments in
Coyote Gas Treating LLC and Thunder Creek Gas Services, LLC, all discussed
above.
The segment's combined interest income and earnings from other income items
(Other, net) decreased $2.0 million (72%) in 2006 compared to 2005, and
increased $0.9 million in 2005 compared to 2004. The 2006 decrease was chiefly
due to a gain from a property disposal by our Kinder Morgan Tejas Pipeline in
the third quarter of 2005. The 2005 increase was mainly due to the allocation of
interest income earned, in 2005, on our note receivable from Coyote Gas
Treating, LLC. Income tax expenses changed slightly over both 2006 and
2005--decreasing $1.2 million (46%) in 2006, and increasing $0.7 million (38%)
in 2005, when compared to prior years. The changes primarily related to tax
accrual adjustments related to the operations of our Mier-Monterrey Mexico
Pipeline.
74
The segment's non-cash depreciation, depletion and amortization charges,
including amortization of excess cost of investments increased $3.7 million (6%)
in 2006 compared to 2005, and increased $8.5 million (16%) in 2005 compared to
2004. The 2006 increase was largely attributable to higher year-to-year
depreciation expenses from our Texas intrastate natural gas pipeline group, due
both to incremental capital spending during 2006, and to additional depreciation
charges related to the group's acquisition of our North Dayton, Texas natural
gas storage facility in August 2005. The 2005 increase was due to incremental
depreciation expenses of $4.2 million from the inclusion of the acquired
TransColorado Pipeline, and 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.
CO2
Year Ended December 31,
--------------------------------------------
2006 2005 2004
---------- ---------- ----------
(In thousands, except operating statistics)
Revenues(a).......................................................... $ 736,524 $ 657,594 $ 492,834
Operating expenses (including environmental adjustments)(b).......... (268,111) (212,636) (169,256)
Earnings from equity investments..................................... 19,173 26,319 34,179
Other, net - income (expense)........................................ 808 (5) 26
Income taxes......................................................... (224) (385) (147)
----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments..... 488,170 470,887 357,636
Depreciation, depletion and amortization expense(c).................. (190,922) (149,890) (121,361)
Amortization of excess cost of equity investments.................... (2,017) (2,017) (2,017)
----------- ----------- -----------
Segment earnings................................................... $ 295,231 $ 318,980 $ 234,258
=========== =========== ===========
Carbon dioxide delivery volumes (Bcf)(d)............................... 669.2 649.3 640.8
=========== =========== ===========
SACROC oil production (gross)(MBbl/d)(e)............................... 30.8 32.1 28.3
=========== =========== ===========
SACROC oil production (net)(MBbl/d)(f)................................. 25.7 26.7 23.6
=========== =========== ===========
Yates oil production (gross)(MBbl/d)(e)................................ 26.1 24.2 19.5
=========== =========== ===========
Yates oil production (net)(MBbl/d)(f).................................. 11.6 10.8 8.6
=========== =========== ===========
Natural gas liquids sales volumes (net)(MBbl/d)(f)..................... 8.9 9.4 7.7
=========== =========== ===========
Realized weighted average oil price per Bbl(g)(h)...................... $ 31.42 $ 27.36 $ 25.72
=========== =========== ===========
Realized weighted average natural gas liquids price per
Bbl(h)(i).............................................................. $ 43.90 $ 38.98 $ 31.33
=========== =========== ===========
- -------------
(a) 2006 amount includes a $1,819 loss on derivative contracts used to hedge
forecasted crude oil sales.
(b) Includes expense of $298 in 2005 and a decrease in expense of $4,126 in
2004 associated with environmental liability adjustments.
(c) Includes depreciation, depletion and amortization expense associated with
oil and gas producing and gas processing activities in the amount of
$171,332 for 2006, $132,286 for 2005, and $105,890 for 2004. Includes
depreciation, depletion and amortization expense associated with sales and
transportation services activities in the amount of $19,590 for 2006,
$17,604 for 2005, and $15,471 for 2004.
(d) Includes Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos
pipeline volumes.
(e) 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.
(f) Net to Kinder Morgan, after royalties and outside working interests.
(g) Includes all Kinder Morgan crude oil production properties.
(h) Hedge gains/losses for crude 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.
Our CO2 segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates. The segment's primary businesses involve the
production, marketing and transportation of both carbon dioxide (commonly called
CO2) and crude oil, and the production and marketing of natural gas and natural
gas liquids. In 2006, our CO2 segment reported earnings before depreciation,
depletion and amortization of $488.2 million on revenues of $736.5 million. This
compares with earnings before depreciation, depletion and amortization of $470.9
million on revenues of $657.6 million in 2005, and earnings before depreciation,
depletion and amortization of $357.6 million on revenues of $492.8 million in
2004.
75
The segment's overall $17.3 million (4%) increase in earnings before
depreciation, depletion and amortization expenses in 2006 compared with 2005 and
its $113.3 million (32%) increase in earnings before depreciation, depletion and
amortization expenses in 2005 compared with 2004 included decreases of $1.5
million and $4.4 million, respectively, from the combined net effect of the
certain other items described in footnotes (a) and (b) to the table above. These
items consisted of the following:
o an decrease in earnings of $1.8 million in 2006--due to a $1.8 million
loss on derivative contracts used to hedge forecasted crude oil sales;
and
o a decrease in earnings of $0.3 million in 2005 and an increase in
earnings of $4.1 million in 2004--due to changes in environmental
operating expenses associated with the adjustments of our
environmental liabilities as more fully described above in "Critical
Accounting Policies and Estimates--Environmental Matters."
The segment's remaining $18.8 million (4%) increase in earnings before
depreciation, depletion and amortization expenses in 2006 compared with 2005 was
driven by higher earnings from the segment's carbon dioxide sales and
transportation activities; the remaining $117.7 million (33%) increase in
earnings before depreciation, depletion and amortization expenses in 2005
compared with 2004 was primarily due to higher earnings from the segment's oil
and gas producing activities.
Segment Earnings before Depreciation, Depletion and Amortization
Sales and Transportation Activities
The segment's carbon dioxide sales and transportation activities reported
earnings before depreciation, depletion and amortization of $186.8 million in
2006, $162.4 million in 2005, and $123.6 million in 2004. The increases in
earnings were driven by higher revenues--from both carbon dioxide sales and
deliveries, and from crude oil pipeline transportation. The overall increases
were partly offset by lower equity earnings from the segment's 50% ownership
interest in Cortez Pipeline Company.
The increases in carbon dioxide sales revenues were due to both higher
average prices and higher sales volumes. Correlating closely with the increase
in crude oil prices since the end of 2004, average carbon dioxide sales prices
increased 18% and 44%, respectively, in 2006 and 2005, when compared to the
prior year. In addition, we did not use derivative contracts to hedge or help
manage the financial impacts associated with the increases in carbon dioxide
prices, and as always, we did not recognize profits on carbon dioxide sales to
ourselves.
The increases in volumes were largely attributable to the continued strong
demand for carbon dioxide from tertiary oil recovery projects in the Permian
Basin area since the end of 2004, and to increased carbon dioxide production
from the McElmo Dome source field. We operate and own a 45% interest in McElmo
Dome, which supplies carbon dioxide to oil recovery fields in the Permian Basin
of southeastern New Mexico and West Texas. 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 3% in 2006 and 1%
in 2005, when compared to the respective prior years.
The increases in revenues from carbon dioxide and crude oil transportation
were due to higher delivery volumes and higher rates. The increase in volumes
was largely related to infrastructure expansions at the SACROC and Yates oil
field units. The SACROC and Yates units are the two largest oil field units in
which we hold ownership interests--these 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 unit, located south of Midland,
Texas.
In 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 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 allowed us to better manage crude oil deliveries
from our oil field interests in West Texas. During the first eight months of
2005, the Kinder Morgan Wink Pipeline accounted for
76
incremental earnings before depreciation, depletion and amortization of $13.4
million, revenues of $16.7 million and operating expenses of $3.3 million.
Oil and Gas Producing Activities
The remaining changes in year-to-year segment earnings before depreciation,
depletion and amortization--a decrease of $7.1 million (2%) in 2006 versus 2005,
and an increase of $74.5 million (32%) in 2005 versus 2004, were attributable to
the segment's crude oil and natural gas producing activities, which also include
its natural gas processing activities. 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. Combined, our CO2 segment's oil and gas
producing and gas processing activities reported earnings before depreciation,
depletion and amortization of $301.4 million in 2006, $308.5 million in 2005,
and $234.0 million in 2004.
In both 2006 and 2005, we made significant capital investments to increase
the capacity and deliverability of carbon dioxide and crude oil in and around
the Permian Basin. Our investments were made in order to benefit from rising
price trends for energy commodity products and from continued strong demand for
carbon dioxide from tertiary oil recovery projects, which commonly inject carbon
dioxide into reservoirs adjacent to producing crude oil wells. Once injected
into the reservoir, the carbon dioxide gas often enhances crude oil recovery in
two ways--first, by expanding and pushing additional oil to the production
wellbore, and secondly, by dissolving into the oil in order to lower its
viscosity and improve its flow rate. In 2006, capital expenditures for our CO2
business segment totaled $283.0 million; this compares with capital expenditures
of $302.1 million in 2005 and $302.9 million in 2004. The expenditures primarily
represent incremental spending for new well and injection compression facilities
at the SACROC and, to a lesser extent, Yates oil field units.
The year-over-year $7.1 million (2%) decrease in earnings in 2006 compared
to 2005 was primarily due to higher combined operating expenses and to a
previously disclosed drop in crude oil production at the SACROC oil field unit.
The higher operating expenses included higher field operating and maintenance
expenses (including well workover expenses), higher property and severance
taxes, and higher fuel and power expenses. The increases in expenses more than
offset higher overall crude oil and natural gas plant product sales revenues,
which increased primarily from higher realized sales prices and partly from
higher crude oil production at the Yates oil field unit. The year-over-year
increase in earnings of $74.5 million (32%) in 2005 compared to 2004 was
primarily driven by increased crude oil and natural gas processing plant liquids
production volumes, and by higher realized weighted average sale prices for
crude oil and gas plant products.
The year-to-year decline in crude oil production at the SACROC unit in 2006
was announced in the first quarter of 2006. At that time, we used information
obtained from production performance to change our previous estimates of proved
crude oil reserves at SACROC; however, due to the fact that the decrease in
production is largely specific to one section of the field that is
underperforming, we do not expect this reserve revision to have a material
impact on our financial statements or capital spending in future periods. For
more information on our ownership interests in the net quantities of proved oil
and gas reserves and our measures of discounted future net cash flows from oil
and gas reserves, please see Note 20 to our consolidated financial statements
included elsewhere in this report.
As a result of our carbon dioxide and oil reserve ownership interests, we
are exposed to commodity price risk associated with physical crude oil and
natural gas liquids sales; however we mitigate this price risk through a
long-term hedging strategy that uses derivative contracts to reduce the impact
of unpredictable changes in crude oil and natural gas liquids sales prices. Our
goal is to use derivative contracts in order to prevent or reduce the
possibility of future losses, and to generate more stable realized prices. Our
hedging strategy involves the use of financial derivative contracts to manage
this price risk on certain activities, including firm commitments and
anticipated transactions for the sale of crude oil and natural gas liquids. 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 derivative contracts 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.
77
Had we not used energy derivative contracts to transfer commodity price
risk, our crude oil sales prices would have averaged $63.27 per barrel in 2006,
$54.45 per barrel in 2005 and $40.91 per barrel in 2004. In periods of rising
prices for crude oil and natural gas liquids, we often surrender profits that
would result from period-to-period price increases. We believe, however, that
our use of derivative contracts protects our unitholders from unpredictable
adverse events. 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.
Segment Details
Including the $1.8 million hedge ineffectiveness loss in 2006, our CO2
segment's revenues increased $78.9 million (12%) in 2006 compared to 2005, and
$164.8 million (33%) in 2005 compared to 2004. The respective year-over-year
increases were primarily due to the following:
o increases of $56.0 million (15%) and $71.7 million (23%),
respectively, from crude oil sales--attributable to increases of 15%
and 6%, respectively, in our realized weighted average price of crude
oil and, in 2005, to a 16% increase in year-over-year sales volumes.
Our overall crude oil sales volumes were flat across both 2006 and
2005. On a gross basis, meaning total quantity produced, combined
daily oil production from the SACROC and Yates units increased 1% in
2006 compared to 2005, and 18% in 2005 compared to 2004. In 2006, a 4%
drop in crude oil production at SACROC was offset by an 8% increase in
oil production at the Yates oil field unit. In 2005, gross crude oil
production increased 13% at SACROC and 24% at Yates, when compared to
2004;
o increases of $14.6 million (28%) and $26.1 million (103%),
respectively, from carbon dioxide sales--due mainly to higher average
sales prices, discussed above, and to year-over-year increases of 7%
in sales volumes in both 2006 and 2005;
o increases of $8.9 million (15%) and $18.0 million (44%), respectively,
from carbon dioxide and crude oil pipeline transportation
revenues--due largely to increases in system-wide carbon dioxide
delivery volumes and, in 2005, to incremental crude oil transportation
revenues from the Kinder Morgan Wink Pipeline;
o increases of $7.9 million (6%) and $45.1 million (51%), respectively,
from natural gas liquids sales--reflecting increases of 13% and 24%,
respectively, in our realized weighted average natural gas liquids
price per barrel. In 2005, we also benefited from a 22% increase in
liquids processing volumes, as compared to 2004, primarily due to the
capital expenditures and infrastructure improvements we made since the
end of 2004. The 2006 increase in natural gas liquids sales was
partially offset by a 5% decrease in sales volumes, primarily related
to the lower crude oil production at SACROC; and
o decreases of $10.4 million (72%) and $1.5 million (9%), respectively,
from natural gas sales--due entirely to lower year-over-year sales
volumes. The decreases in volumes were mainly attributable to lower
volumes of gas available for sale since the second quarter of 2005,
due partly to the overall declining production at the SACROC field and
partly to natural gas volumes used at the power plant we constructed
at the SACROC oil field unit and placed in service in June 2005.
Construction of the plant began in mid-2004, and the project was
completed at a cost of approximately $76 million. We constructed the
SACROC power plant in order to reduce our purchases of electricity
from third-parties, but it reduces our sales of natural gas because
some natural gas volumes are consumed by the plant. The power plant
now provides approximately half of SACROC's current electricity needs.
KMI operates and maintains the power plant under a five-year contract
expiring in June 2010, and we pay KMI an annual operating and
maintenance fee.
Compared to the respective prior years, the segment's operating expenses
increased $55.5 million (26%) in 2006 and $43.4 million (26%) in 2005. The
increases consisted of the following:
o increases of $35.3 million (36%) and $7.7 million (9%), respectively,
from combined cost of sales and field operating and maintenance
expenses--largely due to additional labor and field expenses,
including well
78
workover expenses, related to infrastructure expansions at the SACROC
and Yates oil field units since the end of 2004. Workover expenses
relate to incremental operating and maintenance charges incurred on
producing wells in order to restore or increase production, and are
often performed in order to stimulate production, add pumping
equipment, remove fill from the wellbore, or mechanically repair the
well.
Our oil and gas operations, coupled with carbon dioxide flooding,
often require a high level of investment, including ongoing expenses
for facility upgrades, wellwork and drilling. We continue to
aggressively pursue opportunities to drill new wells and/or expand
existing wells for both carbon dioxide and crude oil in order to
benefit from robust demand for energy commodities in and around the
Permian Basin area. 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 $100.5 million, $74.7
million and $70.6 million for the years ended December 31, 2006, 2005
and 2004, respectively;
o increases of $13.8 million (19%) and $16.0 million (28%),
respectively, from fuel and power expenses--due to increased carbon
dioxide compression and equipment utilization, higher fuel costs, and
higher electricity expenses due to higher rates as a result of higher
fuel costs to electricity providers. Overall higher electricity costs
were partly offset, however, by the benefits provided from the power
plant we constructed at the SACROC oil field unit;
o increases of $6.7 million (16%) and $15.3 million (56%), respectively,
from taxes, other than income taxes--attributable mainly to higher
property and production (severance) taxes. The higher property taxes
related to both increased asset infrastructure and higher assessed
property values since the end of 2004. The higher severance taxes,
which are primarily based on the gross wellhead production value of
crude oil and natural gas, were driven by the higher period-to-period
crude oil revenues; and
o a decrease of $0.3 million and an increase of $4.4 million,
respectively, due to changes in environmental operating expenses
associated with the adjustments of our environmental liabilities as
more fully described above in "Critical Accounting Policies and
Estimates--Environmental Matters."
Earnings from equity investments, representing equity earnings from our 50%
ownership interest in the Cortez Pipeline Company, decreased $7.1 million (27%)
in 2006 compared to 2005, and $7.9 million (23%) in 2005 compared to 2004.
Cortez 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 decreases in equity earnings were due to lower year-over-year
net income earned by Cortez since 2004, mainly as a result of lower carbon
dioxide transportation revenues. The decreases in transportation revenues
resulted from lower year-to-year average tariff rates, which more than offset
incremental revenues realized as a result of higher carbon dioxide delivery
volumes. The decreases in tariff rates were expected because we benefited from
higher tariffs in prior years, when tariffs were set higher in order to make up
for under-collected revenues.
Non-cash depreciation, depletion and amortization charges, including
amortization of excess cost of equity investments, increased $41.0 million (27%)
in 2006 compared to 2005, and $28.5 million (23%) in 2005 compared to 2004. The
increases were due to both higher depreciable costs, as a result of incremental
capital spending since the end of 2004, and higher combined depreciation and
depletion charges, related to year-over-year increases in crude oil production
volumes. In 2006, we also realized incremental depreciation charges of $3.4
million attributable to the various oil and gas properties we acquired in April
2006 from Journey Acquisition - I, L.P. and Journey 2000, L.P.
The increase in depreciation expenses in 2006 compared to 2005 was also due
to a higher unit-of-production depletion rate used in 2006, related to changes
in estimated oil and gas reserves at the SACROC oil field unit. Our capitalized
costs of proved oil and gas properties must be amortized by the unit of
production method so that each unit produced is assigned a pro rata portion of
the unamortized costs. These amortization rates must be revised at least
annually, but are also adjusted if there is an indication that total estimated
units are different than previously estimated.
79
Terminals
Year Ended December 31,
--------------------------------------------
2006 2005 2004
---------- ---------- ----------
(In thousands, except operating statistics)
Revenues............................................................. $ 864,844 $ 699,264 $ 541,857
Operating expenses (including environmental adjustments)(a).......... (446,817) (373,410) (254,115)
Earnings from equity investments..................................... 214 83 1
Other, net - income (expense)........................................ 2,118 (220) (396)
Income taxes(b)...................................................... (12,226) (11,111) (5,609)
----------- ----------- -----------
Earnings before depreciation, depletion and amortization
expense and amortization of excess cost of equity investments..... 408,133 314,606 281,738
Depreciation, depletion and amortization expense..................... (74,541) (59,077) (42,890)
Amortization of excess cost of equity investments.................... - - -
----------- ----------- -----------
Segment earnings................................................... $ 333,592 $ 255,529 $ 238,848
=========== =========== ===========
Bulk transload tonnage (MMtons)(c)................................... 89.5 85.5 84.1
=========== =========== ===========
Liquids leaseable capacity (MMBbl)................................... 43.5 42.4 36.8
=========== =========== ===========
Liquids utilization %................................................ 96.3% 95.4% 96.0%
=========== =========== ===========
- ------------------
(a) 2006 amount includes an increase in expense of $2,792 related to hurricane
clean-up and repair activities, and a gain of $15,192 from property
casualty indemnifications. Also, includes an increase in expense of $3,535
in 2005 and a decrease in expense of $18,651 in 2004 associated with
environmental liability adjustments.
(b) 2006 amount includes expense of $1,125 associated with hurricane expenses
and casualty gain. 2004 amount includes expense of $80 associated with
environmental liability adjustments.
(c) Volumes include all acquired 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), and all of our coal, petroleum coke, steel and
other dry-bulk material services facilities. Refining, manufacturing, mining and
quarrying companies worldwide depend on these facilities to provide liquids and
bulk handling services, transload, engineering, and other in-plant services to
supply marine, rail, truck, temporary storage, and other distribution means
needed to move dry-bulk, bulk petroleum, and chemicals across the United States.
The segment reported earnings before depreciation, depletion and amortization of
$408.1 million on revenues of $864.8 million in 2006. This compares with
earnings before depreciation, depletion and amortization of $314.6 million on
revenues of $699.3 million in 2005 and earnings before depreciation, depletion
and amortization of $281.7 million on revenues of $541.9 million in 2004.
The segment's overall $93.5 million (30%) increase in earnings before
depreciation, depletion and amortization expenses in 2006 compared with 2005 and
its $32.9 million (12%) increase in earnings before depreciation, depletion and
amortization expenses in 2005 compared with 2004, included an increase of $14.8
million and a decrease of $22.1 million, respectively, from the combined net
effect of the certain other items described in footnotes (a) and (b) to the
table above. These items consisted of the following:
o an increase in earnings of $11.3 million in 2006--from the combined
effect of a gain from the settlement of property casualty insurance
claims and incremental repair and clean-up expenses, both related to
the 2005 hurricane season. 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. 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.
The $11.3 million increase in segment earnings consisted of: (i) a
$15.2 million property casualty gain; (ii) a $2.8 million increase in
operating and maintenance expenses from hurricane repair and recovery
activities; and (iii) a $1.1 million increase in income tax expense
associated with the segment's overall hurricane income and expense
items. Including an additional $0.4 million decrease in general and
administrative expenses, and a $3.1 million increase in minority
interest expense, both related to hurricane activity and
80
described below in "--Other," total hurricane income and expense
items increased our net income by $8.6 million in 2006. For more
information on our property casualty gain, see Note 6 to our
consolidated financial statements included elsewhere in this report;
and
o a decrease in earnings of $3.5 million in 2005 and an increase in
earnings of $18.6 million in 2004--due to changes in environmental
operating expenses associated with the adjustments of our
environmental liabilities as more fully described above in "Critical
Accounting Policies and Estimates--Environmental Matters."
The segment's remaining $78.7 million (4%) increase in earnings before
depreciation, depletion and amortization expenses in 2006 compared with 2005,
and its remaining $55.0 million (21%) increase in 2005 compared to 2004 were
driven by a combination of internal expansions and strategic acquisitions. We
make and continue to seek key terminal acquisitions in order to gain access to
new markets, to complement and/or enlarge our existing terminal operations, and
to benefit from the economies of scale resulting from increases in storage,
handling and throughput capacity.
Segment Earnings before Depreciation, Depletion and Amortization
Terminal Acquisitions
Our significant terminal acquisitions since the beginning of 2005 included
the following:
o our Texas Petcoke terminals, located in and around the Ports of
Houston and Beaumont, Texas, acquired effective April 29, 2005;
o 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;
o all of the ownership interests in General Stevedores, L.P., which
operates a break-bulk terminal facility located along the Houston Ship
Channel, acquired July 31, 2005;
o our Kinder Morgan Blackhawk terminal located in Black Hawk County,
Iowa, acquired in August 2005;
o a terminal-related repair shop located in Jefferson County, Texas,
acquired in September 2005;
o three terminal operations acquired separately in April 2006: terminal
equipment and infrastructure located on the Houston Ship Channel, a
rail terminal located at the Port of Houston, and a rail ethanol
terminal located in Carson, California; and
o all of the membership interests of Transload Services, LLC, which
provides material handling and steel processing services at 14
steel-related terminal facilities located in the Chicago metropolitan
area and various cities in the United States, acquired November 20,
2006.
We have invested approximately $305.5 million in cash and $49.6 million in
common units to acquire these terminal assets and combined, these operations
accounted for incremental amounts of earnings before depreciation, depletion and
amortization of $33.5 million, revenues of $68.8 million and operating expenses
of $35.3 million, respectively, in 2006. A majority of these increases in
earnings, revenues and expenses from terminal acquisitions were attributable to
the inclusion of our Texas petroleum coke terminals and repair shop assets,
which we acquired from Trans-Global Solutions, Inc. on April 29, 2005 for an
aggregate consideration of approximately $247.2 million. The primary assets
acquired included facilities and railway equipment located at the Port of
Houston, the Port of Beaumont and the TGS Deepwater terminal located on the
Houston Ship Channel. Combined, these operations accounted for incremental
amounts of earnings before depreciation, depletion and amortization of $16.8
million, revenues of $31.0 million and operating expenses of $14.2 million,
respectively, in 2006.
For 2005, we benefited significantly from the incremental contributions
attributable to the bulk and liquids terminal businesses we acquired since the
end of the third quarter of 2004. In addition to the 2005 acquisitions referred
to above, these acquisitions included:
81
o 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; and
o our Kinder Morgan Fairless Hills terminal located along the Delaware
River in Bucks County, Pennsylvania, acquired effective December 1,
2004.
Combined, terminal operations acquired since the end of the third quarter
of 2004 accounted for incremental amounts of earnings before depreciation,
depletion and amortization of $45.5 million, revenues of $113.8 million and
operating expenses of $65.0 million, respectively, in 2005. All of the
incremental amounts listed above for both 2006 and 2005, represent the earnings,
revenues and expenses from the acquired terminals' operations during the
additional months of ownership in 2006, and 2005, respectively, and do not
include increases or decreases during the same months we owned the assets in
2005 and 2004, respectively. For more information in regard to our terminal
acquisitions, see Note 3 to our consolidated financial statements included
elsewhere in this report.
Terminal Operations Owned During Both Comparable Years
For all other terminal operations (those owned during the same months of
both comparable years), earnings before depreciation, depletion and amortization
increased $60.0 million (19%) in 2006 compared to 2005, and decreased $12.6
million (4%) in 2005 compared to 2004; however, as described above, the net
effect of the property casualty gain, hurricane repair expenses (net of income
tax), and environmental liability adjustments resulted in a $14.8 million
increase in earnings before depreciation, depletion and amortization in 2006
relative to 2005, and a $22.1 million decrease in 2005 relative to 2004. The
remaining change in the earnings before depreciation, depletion and amortization
expenses from terminal operations owned during both years consisted of a $45.2
million (14%) increase in 2006 compared to 2005, and a $9.5 million (4%)
increase in 2005 compared to 2004. These respective year-to-year increases in
earnings primarily consisted of the following:
o increases of $17.4 million (23%) and $13.7 million (22%),
respectively, from our Gulf Coast region. This region includes the
operations of 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 since the end of 2004, have contributed
incremental earnings attributable to internal growth complemented by
the completion of expansion projects undertaken to increase leaseable
liquids capacity.
The year-over-year increase in earnings in 2006 versus 2005 was
primarily revenue related, driven by increases from new and
incremental customer agreements, additional liquids tank capacity from
capital expansions at our Pasadena terminal since the end of 2005,
higher truck loading rack service fees, higher ethanol throughput, and
incremental revenues from customer deficiency charges.
Since the end of 2004, we have obtained additional customer contracts,
extended existing customer contracts and remarketed expiring
contracted capacity at competitive rates. For our Gulf Coast and other
liquids terminals, our existing contracts generally mature at various
times and in varying amounts of throughput capacity, therefore, we
continue to manage our recontracting process in order to limit the
risk of significant impacts on our revenues. The increase in earnings
in 2005 versus 2004 was also largely due to higher revenues, driven by
higher sales of petroleum transmix, new customer agreements, and
escalations in annual contract provisions;
o an increase of $9.4 million (29%) and a decrease of $3.3 million
(10%), respectively, from our Mid-Atlantic region. The 2006 increase
was driven by a $5.7 million increase from our Shipyard River
terminal, located in Charleston, South Carolina; a $2.6 million
increase from our Fairless Hills, Pennsylvania bulk terminal; and a
$1.2 million increase from our North Charleston, South Carolina
liquids terminal. The increase from Shipyard reflects higher revenues
from liquids warehousing and coal and cement handling, the increase
from Fairless Hills was due to higher volumes of steel imports and
heavier shipping activity on the Delaware River, and the increase from
North Charleston was due to higher revenues, associated with
additional liquids tank leasing and a utilization capacity rate that
approached 100% (full capacity).
82
The decrease in earnings in 2005 compared to 2004 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 facility, located in Sparrows Point, Maryland.
The decrease from Pier IX was primarily due to higher operating
expenses in 2005 compared to 2004, due to incremental operating
expenses associated with a new synfuel maintenance program and 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;
o an increase of $4.6 million (19%) and a decrease of $0.8 million,
respectively, from terminals included in our Texas Petcoke region. The
increase in 2006 compared to 2005 was primarily revenue driven,
resulting from a year-over-year increase in petroleum coke handling
volumes. The decrease in 2005 compared to 2004 was related to
incremental overhead expenses allocated to our Texas Petcoke region,
which was newly formed in April 2005;
o an increase of $4.5 million (16%) and a decrease of $7.2 million
(21%), respectively, from terminals included in our Lower Mississippi
River (Louisiana) region. The increase in 2006 compared to 2005 was
primarily due to incremental earnings from our Amory and DeLisle
Mississippi bulk terminals, and from higher earnings from our Kinder
Morgan St. Gabriel, Louisiana terminal. Our Amory terminal began
operations in July 2005. The higher earnings from our DeLisle
terminal, which was negatively impacted by hurricane damage in 2005,
was primarily due to higher bulk transfer revenues in 2006. The
increase from our St. Gabriel terminal was primarily due to a $1.8
million income item, recognized in 2006, related to a favorable
settlement associated with the purchase of the terminal in September
2002.
The overall decrease in earnings from our Louisiana region terminals
in 2005 compared to 2004 was largely related to the negative effects
of the two Gulf Coast hurricanes in 2005, resulting in an overall
general loss of business. In addition to property damage incurred,
throughput at the facilities impacted by the storms decreased in 2005
compared to 2004 largely due to post-hurricane production issues at a
number of Gulf Coast refineries. In 2005, our Terminals segment
realized 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. We also
recognized another $0.8 million to repair damaged facilities following
Hurricane Rita, but estimates of lost business at our terminal sites
are difficult because of insurance complexities and the extended
recovery time involved;
o an increase of $3.7 million (8%) and a decrease of $1.0 million (2%),
respectively, from terminals included in our Northeast region. The
increase in 2006 compared to 2005 was primarily due to higher earnings
from our liquids terminals located in Carteret, New Jersey and Staten
Island, New York. The increase was largely due to higher revenues from
new and renegotiated customer contracts at Carteret, additional
tankage available for lease at our Kinder Morgan Staten Island
terminal, and an overall increase in petroleum imports to New York
Harbor, resulting in an 8% increase in total liquids throughput at
Carteret and higher distillate volumes at our Staten Island terminal.
The decrease in 2005 compared to 2004 was driven by lower earnings
from the dry-bulk services at our Port Newark, New Jersey facility.
The decrease was largely due to lower salt tonnage, shipping activity,
and stevedoring services, all primarily due to warmer winter weather
in 2005; and
o increases of $2.2 million (4%) and $4.4 million (10%), respectively,
from terminals in our Midwest region. The year-over-year increase in
earnings in 2006 was mainly attributable to higher earnings from the
combined operations of our Argo and Chicago, Illinois liquids
terminals, and from our Cora, Illinois coal terminal. The increase
from the liquids terminals was due to higher revenues from increased
ethanol throughput and incremental liquids storage and handling
business. The year-to-year increase in earnings at Cora was due to
higher revenues resulting from an almost 24% increase in coal transfer
volumes.
The overall increase in 2005 compared to 2004 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
83
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.
Segment Details
Segment revenues from terminal operations owned during identical periods of
both 2006 and 2005 increased $96.7 million (14%) in 2006, when compared to the
prior year. The overall increase was primarily due to the following:
o a $24.1 million (29%) increase from our Mid-Atlantic region, due
primarily to higher revenues of $11.7 million from Fairless Hills,
$9.7 million from Shipyard River, and $1.6 million from our North
Charleston terminals, all discussed above. Also, our Philadelphia,
Pennsylvania liquids terminal reported a $2.5 million increase in
revenues in 2006 versus 2005 largely due to an increase in fuel grade
ethanol volumes, annual rate escalations on certain customer
contracts, and a 2006 liquids capacity utilization rate of
approximately 97%;
o a $19.6 million (19%) increase from our Gulf Coast liquids facilities,
due primarily to higher revenues from Pasadena and Galena Park, as
discussed above;
o a $19.1 million (43%) increase from our Texas Petcoke terminal region,
due primarily to higher petroleum coke transfer volumes;
o a $13.4 million (92%) increase from engineering and terminal design
services, due to both incremental revenues from new clients,
additional project phase revenues, and increased revenues from
material sales;
o a $5.5 million (5%) increase from terminals included in our Midwest
region, due largely to the increased liquids throughput, storage and
ethanol activities from our two Chicago liquids terminals and to the
increased coal volumes from our Cora coal terminal, both described
above. The overall increase in revenues was also due to higher marine
oil fuel and asphalt sales from our Dravosburg, Pennsylvania bulk
terminal;
o a $5.1 million (16%) increase from our Ferro alloys region, largely
due to increased ores and metals handling at our Chicago and Industry,
Pennsylvania terminals; and
o a $4.6 million (5%) increase from our Northeast terminals, largely due
to the revenue increases at our Carteret and Kinder Morgan Staten
Island terminals, as discussed above.
For all bulk terminal facilities combined, total transloaded bulk tonnage
volumes increased over 4.5% in 2006, when compared to 2005. The overall
increase in bulk tonnage volumes included a 10% increase in coal transfer
volumes and a 13% increase in ores/metals transload volumes. We also
completed, in 2006, capital expansion and betterment projects at certain of
our liquids terminal facilities that included the construction of additional
petroleum products storage tanks. The construction, when combined with
increases from external acquisitions, increased our liquids storage capacity
by approximately 1.1 million barrels (2.6%) in 2006. At the same time, we
increased our liquids utilization capacity rate by 1%, compared to the prior
year. Our liquids terminals utilization rate is the ratio of our actual
leased capacity to our estimated potential capacity. Potential capacity is
generally derived from measures of total capacity, taking into account
periodic changes to our terminal facilities due to additions, disposals,
obsolescence, or other factors.
Segment revenues for all terminals owned during identical periods of both
2005 and 2004 increased $43.6 million (8%) in 2005, when compared to the
prior year. The increase was primarily due to the following:
o 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;
84
o a $12.3 million (14%) 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;
o a $6.8 million (11%) increase from our Mid-Atlantic region, due
primarily to higher coal volumes and higher dockage revenues at our
Shipyard River terminal, 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;
o a $4.0 million (38%) increase from our engineering and terminal design
services, due to increased fee revenues discussed above;
o a $3.9 million (9%) increase from our Southeast region, due primarily
to both higher fertilizer and ammonia volumes and higher stevedoring
services at our terminal operations located in and around the Tampa,
Florida area. These operations include the import and export business
of our Kinder Morgan Tampaplex terminal, the commodity transfer
operations of our Port Sutton terminal, and the terminal stevedoring
services we perform along Tampa Bay; and
o a $2.8 million (3%) decrease from terminals included in our Louisiana
region. The decrease was largely due to the negative impact and
business interruptions resulting from the two hurricanes that struck
the Gulf Coast in the second half of 2005.
Operating expenses from all terminals owned during identical periods of
both 2006 and 2005 increased $38.1 million (10%) in 2006 compared to 2005.
Combined, the net effect of the environmental liability adjustments,
hurricane repair expenses, and the property casualty gain on terminals owned
during the same portions of both comparable periods resulted in a $15.9
million decrease in segment operating expenses in 2006 relative to 2005. The
remaining change in year-to-year operating expenses--an increase of $54.0
million (15%)--from all terminals owned during identical periods of both 2006
and 2005 primarily consisted of the following:
o a $15.3 million (111%) increase from engineering-related services, due
primarily to higher salary, overtime and other employee-related
expenses related to new hiring, as well as increased contract labor,
all associated with the increased project work described above;
o a $15.0 million (75%) increase from our Texas Petcoke terminal region,
due largely to higher labor expenses, rail service and railcar
maintenance expenses, and harbor and barge expenses, all related to
higher petroleum coke volumes;
o a $14.1 million (28%) increase from our Mid-Atlantic terminals,
largely due to higher operating and maintenance expenses at our
Fairless Hills, Shipyard River, and Philadelphia terminals. The
increase at Fairless Hills was largely due to higher wharfage,
trucking and general maintenance expenses, related to the increase in
steel products handled. The increase at Shipyard was due to higher
labor, equipment rentals and general maintenance expenses, all
associated with increased tonnage. The increase at our Philadelphia
liquids terminal was due to higher expenses related to certain
environmental liability accruals;
o a $4.0 million (21%) increase from terminals in our Ferro alloys
region, due primarily to higher labor expenses and higher equipment
maintenance and rental expenses, all related to increased ores and
metals handling volumes; and
o a $3.7 million (6%) increase from our Midwest region terminals, due
primarily to higher marine fuel costs of sales expenses at our
Dravosburg terminal; higher maintenance and outside service expenses
associated with increases in coal transfer volumes at our Cora,
Illinois and Grand Rivers, Kentucky coal terminals; and additional
labor and equipment rental expenses from the combined operations of
our Argo and Chicago, Illinois liquids terminals, due to increased
ethanol throughput and incremental liquids storage and handling
business.
85
For terminal operations owned during the same months of both 2005 and 2004,
operating expenses increased $54.3 million (21%) in 2005 compared to 2004.
The overall increase included a $22.1 million increase in expense
attributable to the 2005 and 2004 environmental liability adjustments. The
remaining $32.2 million (12%) increase in operating expenses in 2005 versus
2004 from terminal operations owned during both years primarily consisted of
the following:
o a $10.1 million (36%) increase from our Mid-Atlantic terminals,
largely due to higher operating, maintenance and labor expenses at our
Pier IX and Chesapeake Bay facilities, discussed above, and to higher
operating, equipment maintenance and labor expenses at our Shipyard
River terminal, due to higher bulk tonnage volumes;
o an $8.5 million (18%) increase from our Midwest region terminals, due
primarily to higher expenses at our Milwaukee, Dravosburg and Dakota
bulk handling terminals. The increase at our Milwaukee bulk commodity
terminal was due to increased trucking and maintenance expenses
associated with the increase in coal volumes. The increase at
Dravosburg was largely due to higher cost of sales expenses, due to
marine oil purchasing costs and inventory maintenance, and the
increase at our St. Paul, Minnesota Dakota bulk terminal was due to
both 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;
o a $3.1 million (5%) increase from our Louisiana terminals, largely due
to property damage, demurrage and other expenses, which in large part
related to the effects of hurricanes Katrina and Rita in the last half
of 2005. However, since the affected properties were insured, our
expenses were limited to the amount of the deductible under our
insurance policies;
o a $2.9 million (12%) increase from our Pasadena and Galena Park Gulf
Coast liquids terminals, due chiefly to higher labor, and higher fuel
and power expenses associated with increased terminal activities; and
o a $2.6 million (21%) increase from the terminals in our West region,
due mainly to higher labor expenses and port fees resulting from
increased tonnage at our terminal facilities located at Longview and
Vancouver, Washington. Both facilities provide ship loading services
along the Columbia River.
The segment's earnings from equity investments remained flat across both
2006 and 2005, when compared to prior years. Income from other items was
essentially unchanged in 2005 versus 2004, but increased $2.3 million in 2006
compared to 2005. The increase in 2006 was chiefly due to the $1.8 million
income item related to a settlement associated with our Kinder Morgan St.
Gabriel terminal, discussed above, and to a $1.2 million increase related to a
disposal loss, recognized in 2005, on warehouse property at our Elizabeth River
bulk terminal, located in Chesapeake, Virginia.
Income tax expenses totaled $12.2 million in 2006, $11.1 million in 2005
and $5.6 million in 2004. The $1.1 million (10%) increase in 2006 versus 2005
reflects, among other things, incremental income tax expense associated with
hurricane related income and expense items. The $5.5 million (98%) increase in
2005 compared to 2004 was mainly attributable to the year-to-year changes in
both taxable income and certain permanent differences between taxable income and
financial income of 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.
In general, the segment's income tax expenses will change period to period based
on the classification of income before taxes between amounts earned by corporate
subsidiaries and amounts earned by partnership subsidiaries.
Non-cash depreciation, depletion and amortization charges increased $15.5
million (26%) in 2006 compared to 2005 and $16.2 million (38%) in 2005 compared
to 2004. The year-over-year increases in depreciation expenses reflect a rising
depreciable capital base since the end of 2004, with growth due to a combination
of business acquisitions and internal capital spending. Collectively, the
terminal assets we acquired since the beginning of 2005 and listed above
accounted for incremental depreciation expenses of $8.2 million in 2006, and the
assets we acquired since the third quarter of 2004 and listed above accounted
for incremental depreciation expenses of $12.4 million in 2005. The remaining
increases in year-to-year depreciation expenses were associated with capital
86
spending on numerous improvement projects completed since 2004 in order to
expand and enhance our terminal services.
Other
Year Ended December 31,
2006 2005 2004
----------- ----------- ------------
(In thousands - income/(expense))
General and administrative expenses(a)................. $ (219,575) $ (216,706) $ (170,507)
Unallocable interest, net.............................. (336,130) (264,203) (194,973)
Minority interest(b)................................... (15,015) (7,262) (9,679)
Loss from early extinguishment of debt................. - - (1,562)
----------- ----------- ------------
Interest and corporate administrative expenses....... $ (570,720) $ (488,171) $ (376,721)
__________
(a) 2006 amount includes a decrease in expense of $393 related to the
allocation of general and administrative expenses on hurricane related
capital expenditures for the replacement and repair of assets.
(b) 2006 amount includes an expense of $3,075 related to the allocation of
International Marine Terminals' earnings from hurricane income and expense
items to minority interest.
Items not attributable to any segment include general and administrative
expenses, unallocable interest income, interest expense and minority interest.
We also included the $1.6 million loss from our early extinguishment of debt in
2004 as an item 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 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.
Our general and administrative expenses include such items as salaries and
employee-related expenses, payroll taxes, insurance, office supplies and
rentals, unallocated litigation and environmental expenses, and shared corporate
services--including accounting, information technology, human resources and
legal services. Overall general and administrative expenses totaled $219.6
million in 2006, $216.7 million in 2005 and $170.5 million in 2004. Generally,
the year-to-year increases in our general and administrative expenses reflect
increased spending levels in support of our growth initiatives, and we continue
to aggressively manage our infrastructure expense and to focus on our
productivity and expense controls.
The $2.9 million (1%) increase in overall general and administrative
expenses in 2006 compared to 2005 was primarily due to higher corporate service
charges and higher corporate and employee-related insurance expenses in 2006,
when compared to the prior year. The increase in corporate services was largely
due to higher corporate overhead expenses associated with the business
operations we acquired since the end of 2005. The increase in insurance expenses
was partly due to incremental expenses related to the cancellation of certain
commercial insurance polices in the second quarter of 2006, as well as to the
overall variability in year-to-year commercial property and medical insurance
costs. Pursuant to certain provisions that gave us the right to cancel certain
commercial policies prior to maturity, we took advantage of the opportunity to
reinsure at lower rates.
The overall increase in general and administrative expenses in 2006
compared to 2005 was partly offset a $33.4 million decrease in unallocated
litigation and environmental settlement expenses and a $0.4 million decrease in
expense from the allocation of general and administrative overhead expenses to
hurricane related capital projects. The decrease in expense from unallocated
litigation and environmental settlement expenses consisted of: (i) a $25.0
million expense in 2005 for a settlement reached between us and a former joint
venture partner on our Kinder Morgan Tejas natural gas pipeline system; and (ii)
a cumulative $8.4 million expense in 2005 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 $46.2 million (27%) increase in general and administrative expenses in
2005 compared to 2004 was due to the incremental litigation and environmental
settlement expenses of $33.4 million described above, as well as higher
87
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 expenses.
Interest expense, net of unallocable interest income, totaled $336.1
million in 2006, $264.2 million in 2005 and $195.0 million in 2004. The $71.9
million (27%) increase in net interest expense in 2006 compared to 2005 was due
to both higher average debt levels and higher effective interest rates. In 2006,
average borrowings (excluding the market value of interest rate swaps) increased
10% and the weighted average interest rate on all of our borrowings increased
17%, when compared to 2005 (the weighted average interest rate on all of our
borrowings was approximately 6.1779% during 2006 and 5.3019% during 2005). The
increase in average borrowings was mainly due to higher capital spending in
2006, the acquisition of external assets and businesses since the end of 2005,
and a net increase, since March 2005, of $300 million in principal amount of
long-term senior notes.
Generally, we fund both our capital spending (including payments for
pipeline project construction costs) and our acquisition outlays from borrowings
under our commercial paper program. The net changes in the principal amount of
our senior notes relate to changes occurring on March 15, 2005. On that date, we
both closed a public offering of $500 million in principal amount of senior
notes and retired a principal amount of $200 million. From time to time we issue
senior notes in order to refinance our commercial paper borrowings. For more
information on our capital expansion and acquisition expenditures, see
"Liquidity and Capital Resources - Investing Activities".
The increase in our average borrowing rate in 2006 reflects a general rise
in variable interest rates since the end of 2005. 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.
The $69.2 million (35%) increase in net interest charges in 2005 versus
2004 was also due to both higher average debt borrowings and higher effective
interest rates. Our average debt balance increased 10% in 2005 compared to 2004,
partly due to incremental borrowings made in connection with both internal
capital spending and external acquisitions, and partly due to the net increase
of $300 million in principal amount of senior notes in March 2005. The weighted
average interest rate on all of our borrowings increased 19% in 2005 compared to
2004, reflecting a general rise in interest rates since the end of 2004.
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 $15.0 million in 2006, $7.3 million in 2005 and $9.7 million in
2004. The overall $7.7 million (105%) increase in 2006 compared to 2005 included
a $3.1 million increase attributable to the 33 1/3% minority interest in the IMT
Partnership's hurricane related income and expense items, as described above in
"--Terminals," and a $1.6 million increase attributable to higher net income
from overall net operating partnership income. The overall $2.4 million (25%)
decrease in minority interest in 2005 compared to 2004 was chiefly due to lower
net income allocated to the minority interest in the IMT Partnership in 2005,
due to business interruption caused by Hurricane Katrina.
Liquidity and Capital Resources
Capital Structure
We attempt to maintain a conservative overall capital structure, with a
long-term target mix of approximately 50% equity and 50% debt. In addition to
our results of operations, our debt and capital balances are affected by our
financing activities, as discussed below in "--Financing Activities." The
following table illustrates the sources of our invested capital (dollars in
thousands):
88
December 31,
-----------------------------------------
2006 2005 2004
------------ ------------ ------------
Long-term debt, excluding market value of interest rate swaps.... $ 4,384,332 $ 5,220,887 $ 4,722,410
Minority interest................................................ 50,599 42,331 45,646
Partners' capital, excluding accumulated other
comprehensive loss............................................. 4,863,207 4,693,414 4,353,863
------------ ------------ ------------
Total capitalization........................................... 9,298,138 9,956,632 9,121,919
Short-term debt, less cash and cash equivalents.................. 1,345,084 (12,108) -
------------ ------------ ------------
Total invested capital......................................... $ 10,643,222 $ 9,944,524 $ 9,121,919
============ ============ ============
Capitalization:
Long-term debt, excluding market value of interest rate swaps.. 47.2% 52.4% 51.8%
Minority interest.............................................. 0.5% 0.4% 0.5%
Partners' capital, excluding accumulated other comprehensive
loss......................................................... 52.3% 47.2% 47.7%
------------ ------------ ------------
100.0% 100.0% 100.0%
============ ============ ============
Invested Capital:
Total debt, less cash and cash equivalents and excluding market
value of interest rate swaps................................. 53.8% 52.4% 51.8%
Partners' capital and minority interest, excluding accumulated
other comprehensive loss .................................... 46.2% 47.6% 48.2%
------------ ------------ ------------
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 for expansion capital
expenditures 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:
o cash distributions and sustaining capital expenditures with existing
cash and cash flows from operating activities;
o expansion capital expenditures and working capital deficits with
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;
o interest payments with cash flows from operating activities; and
o debt principal payments with additional borrowings, as such debt
principal payments become due, or by the issuance of additional common
units or the proceeds from purchases of additional i-units to KMR.
As a publicly traded limited partnership, our common units are attractive
primarily to individual investors, although such investors represent a small
segment of the total equity capital market. We believe 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.
As part of our financial strategy, we try to maintain an investment-grade
credit rating, which involves, among other things, the issuance of additional
limited partner units in connection with our acquisitions and internal growth
activities in order to maintain acceptable financial ratios. On May 30, 2006,
S&P and Moody's each placed our ratings on credit watch pending resolution of a
management buyout proposal for all of the outstanding shares of KMI. On January
5, 2007, in anticipation of the buyout closing, S&P downgraded us one level to
BBB and removed our rating from credit watch with negative implications. Our
debt credit ratings are currently rated BBB by Standard & Poor's Rating
Services, and Baa1 by Moody's Investors Service. As noted by Moody's in its
credit opinion dated November 15, 2006, our rating is expected to be downgraded
from Baa1 to Baa2 at the time Moody's
89
finalizes its ratings for KMI. Additionally, as noted by Fitch in its press
release dated August 28, 2006, our rating is expected to be downgraded from BBB+
to BBB at the time Fitch finalizes its ratings for KMI. At this time, neither
Moody's nor Fitch have changed their ratings on KMI or us. We are not able to
predict with certainty the final outcome of the pending buyout proposal.
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; provided, however, that our cash and the cash of
our subsidiaries is not concentrated into accounts of KMI or any company not in
our consolidated group of companies, and KMI has no rights with respect to our
cash except as permitted pursuant to our partnership agreement.
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:
o our $1.85 billion five-year senior unsecured revolving credit facility
that matures August 18, 2010;
o our $1.85 billion short-term commercial paper program (which is
supported by our bank credit facility, with the amount available for
borrowing under our credit facility being reduced by our outstanding
commercial paper borrowings); and
o cash from operations (discussed following).
Borrowings under our credit facility can be used for general corporate
purposes and as a backup for our commercial paper program. Effective August 28,
2006, we terminated our $250 million unsecured nine-month bank credit facility
due November 21, 2006, and we increased our existing five-year bank credit
facility from $1.60 billion to $1.85 billion. The five-year unsecured bank
credit facility remains due August 18, 2010; however, the bank facility can now
be amended to allow for borrowings up to $2.1 billion. There were no borrowings
under our bank credit facility as of December 31, 2005 or as of December 31,
2006. As of December 31, 2006, we had $1,098.2 million of commercial paper
outstanding.
We provide for additional liquidity by maintaining a sizable amount of
excess borrowing capacity related to our commercial paper program and long-term
revolving credit facility. After inclusion of our outstanding commercial paper
borrowings and letters of credit, the remaining available borrowing capacity
under our bank credit facility was $367.1 million as of December 31, 2006. As of
December 31, 2006, our outstanding short-term debt was $1,359.1 million.
Currently, we believe our liquidity to be adequate. For more information on our
commercial paper program and our credit facility, see Note 9 to our consolidated
financial statements included elsewhere in this report.
Long-term Financing
In addition to our principal sources of short-term liquidity listed above,
we could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through issuing 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.
We are subject, however, to changes in the equity and debt markets for our
limited partner units and long-term notes, and there can be no assurance we will
be able or willing to access the public or private markets for our limited
partner units and/or long-term notes in the future. If we were unable or
unwilling to issue additional limited partner
90
units, we would be required to either restrict potential future acquisitions or
pursue other debt financing alternatives, some of which could involve higher
costs or negatively affect our credit ratings. Our ability to access the public
and private debt markets is affected by our credit ratings. See "--Capital
Structure" above for a discussion of our credit ratings.
In August 2006, we issued, in a public offering, 5,750,000 of our common
units, including common units sold pursuant to the underwriters' over-allotment
option, at a price of $44.80 per unit, less commissions and underwriting
expenses. We received net proceeds of approximately $248.0 million for the
issuance of these 5,750,000 common units.
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 long-term
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.
As of December 31, 2006, our total liability balance due on the various
series of our senior notes was $4,490.7 million, and the total liability balance
due on the various borrowings of our operating partnerships and subsidiaries was
$154.5 million.
In addition, on January 30, 2007, we completed a public offering of senior
notes. We issued a total of $1.0 billion in principal amount of senior notes,
consisting of $600 million of 6.00% notes due February 1, 2017 and $400 million
of 6.50% notes due February 1, 2037. We received proceeds from the issuance of
the notes, after underwriting discounts and commissions, of approximately $992.8
million, and we used the proceeds to reduce the borrowings under our commercial
paper program. For additional information regarding our debt securities, see
Note 9 to our consolidated financial statements included elsewhere in this
report.
Capital Requirements for Recent Transactions
During 2006, our cash outlays for the acquisition of assets totaled $397.4
million. We utilized our commercial paper program to fund our 2006 acquisitions.
We then reduced our short-term borrowings with the proceeds from our August
issuance of common units. We intend to refinance the remainder of our current
short-term debt and any additional short-term debt incurred during 2007 through
a combination of long-term debt, equity and the issuance of additional
commercial paper to replace maturing commercial paper borrowings.
We are committed to maintaining a cost effective capital structure and we
intend to finance new acquisitions using a mix of approximately 50% equity
financing and 50% debt financing. For more information on our capital
requirements during 2006 in regard to our acquisition expenditures, see Note 3
to our consolidated financial statements included elsewhere in this report.
Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial
statements. As of December 31, 2006, our obligations with respect to these
investments, as well as our obligations with respect to a letter of credit, are
summarized below (dollars in millions):
91
Our
Our Remaining Total Total Contingent
Investment Ownership Interest(s) Entity Entity Share of
Entity Type Interest Ownership Assets(5) Debt Entity Debt(6)
------------------------------ ---------- --------- ------------ --------- ------ -------------
General
Cortez Pipeline Company........ Partner 50% (1) $73.7 $148.9 $74.5(2)
Red Cedar Gathering General Southern Ute
Company.................... Partner 49% Indian Tribe $247.5 $31.4 $15.4
ConocoPhillips
Limited and
West2East Pipeline LLC(3)...... Liability 51% Sempra Energy $850.5 $790.1 $403.0
Nassau County,
Nassau County, Florida Ocean
Florida Ocean Highway Highway and
and Port Authority (4)..... N/A N/A Port Authority N/A N/A $23.9
- ---------
(1) The remaining general partner interests are owned by ExxonMobil Cortez
Pipeline, Inc., an indirect wholly-owned subsidiary of ExxonMobil
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 (50%) of the
Cortez Pipeline Company debt. 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.
Accordingly, in December 2006 and January 2007 we entered into two separate
letters of credit, each in the amount of $37.5 million issued by JP Morgan
Chase, in order to secure our indemnification obligations to Shell for 50%
of the Cortez debt balance of $148.9 million.
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) West2East Pipeline LLC is a limited liability company and is the sole owner
of Rockies Express Pipeline LLC. As of December 31, 2006, the remaining
limited liability member interests in West2East Pipeline LLC are owned by
ConocoPhillips (24%) and Sempra Energy (25%). We owned a 66 2/3% ownership
interest in West2East Pipeline LLC from October 21, 2005 until June 30,
2006, and we included its results in our consolidated financial statements
until June 30, 2006. On June 30, 2006, our ownership interest was reduced
to 51%, West2East Pipeline LLC was deconsolidated, and we subsequently
accounted for our investment under the equity method of accounting.
(4) 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, 2006, the
value of this letter of credit outstanding under our credit facility was
$23.9 million. Principal payments on the bonds are made on the first of
December each year and reductions are made to the letter of credit.
(5) Principally property, plant and equipment.
(6) 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 Cortez Pipeline Company, Red Cedar
Gathering Company and West2East Pipeline LLC under the equity method of
accounting. For the year ended December 31, 2006, our share of earnings, based
on our ownership percentage and before amortization of excess investment cost
was $19.2 million from
92
Cortez Pipeline Company, $36.3 million from Red Cedar Gathering Company, and
$1.9 million from West2East Pipeline LLC. Additional information regarding the
nature and business purpose of these investments is included in Notes 7 and 9 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............... $1,098,192 $1,098,192 $ -- $ -- $ --
Other debt borrowings-principal payments... 4,654,476 260,899 267,763 969,494 3,156,320
Interest payments(a)....................... 3,922,682 349,792 547,492 469,117 2,556,281
Lease obligations(b)....................... 157,668 47,882 50,578 30,339 28,869
Post-retirement welfare plans(c)........... 3,709 363 729 727 1,890
Other obligations(d)....................... 155,184 47,391 60,770 39,972 7,051
---------- ---------- ---------- ---------- -----------
Total...................................... $9,991,911 $1,804,519 $ 927,332 $1,509,649 $ 5,750,411
========== ========== ========== ========== ===========
Other commercial commitments:
Standby letters of credit(e)............... $ 445,793 $ 387,579 $ 20,224 $ 490 $ 37,500
========== ========== ========== ========== ==========
Capital expenditures(f).................... $ 85,955 $ 85,955 - - -
========== ========== ========== ========== ===========
- -------------
(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, 2006.
(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 1 Year or Less column only, our purchase and sale agreement with
Trans-Global Solutions, Inc. for the acquisition of our Texas Petcoke
terminal assets.
(e) The $445.8 million in letters of credit outstanding as of December 31 2006
consisted of the following: (i) a combined $243 million in three letters of
credit supporting our hedging of commodity price risks; (ii) a combined
$39.7 million in two letters of credit supporting the construction of our
Kinder Morgan Louisiana Pipeline; (iii) a $37.5 million letter of credit
supporting our indemnification obligations on the Series D note borrowings
of Cortez Capital Corporation; (iv) our $30.3 million guarantee under
letters of credit supporting our International Marine Terminals Partnership
Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a
$25.4 million letter of credit supporting our Kinder Morgan Liquids
Terminals LLC New Jersey Economic Development Revenue Bonds; (vi) a $24.1
million letter of credit supporting our Kinder Morgan Operating L.P. "B"
tax-exempt bonds; (vii) a $23.9 million letter of credit supporting Nassau
County, Florida Ocean Highway and Port Authority tax-exempt bonds; (viii) a
$5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois
Development Revenue Bonds; and (ix) a combined $16.5 million in seven
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, 2006.
Operating Activities
Net cash provided by operating activities was $1,257.4 million in 2006,
versus $1,289.4 million in 2005. The year-to-year decrease of $32.0 million (2%)
in cash flow from operations primarily consisted of the following:
o a $125.0 million decrease in cash inflows relative to net changes in
working capital items, mainly due to timing differences that resulted
in higher net cash payments of $159.2 million with regard to the
collection and payment of both trade and related party receivables and
payables;
o a $19.1 million decrease in cash related to payments made in June 2006
to certain shippers on our Pacific operations' pipelines. The payment
related to a settlement agreement reached in May 2006 that resolved
certain challenges by complainants with regard to delivery tariffs and
gathering enhancement fees at our
93
Pacific operations' Watson Station, located in Carson, California. The
agreement called for estimated refunds to be paid into an escrow
account pending final approval by the FERC, which was made in the
third quarter of 2006;
o a $104.4 million increase in cash from overall higher partnership
income--net of non-cash items including depreciation charges,
undistributed earnings from equity investments, non-cash pipeline
transportation rate case expenses, and gains from both the sale of
assets and property casualty settlements. The higher partnership
income reflects an increase in cash earnings from our four reportable
business segments in 2006, as discussed above in "-Results of
Operations." The components of this overall $104.4 million increase in
operating cash inflows in 2006 compared to 2005 consisted of the
following:
o a $159.9 million increase from higher overall net income;
o a $63.9 million increase from higher non-cash depreciation, depletion
and amortization expenses;
o a $15.5 million increase from higher non-cash earnings from our
unconsolidated investees accounted for under the equity method of
accounting;
o a $105.0 million decrease from the 2005 non-cash operating expense
attributable to an increase in our reserves related to our Pacific
operations' rate case liability; and
o a $29.9 million decrease from non-cash property-related gains and
losses-- primarily consisting of the $15.1 million gain from the
combined sale of our Douglas natural gas gathering system and Painter
Unit fractionation facility and the $15.2 million gain from property
casualty indemnifications, both recognized in 2006;
o a $4.8 million increase related to higher distributions received from
equity investments--chiefly due to higher distributions received from
Red Cedar Gathering Company in 2006, when compared to 2005. The
overall increase in distributions was partially offset by lower
distributions from Plantation Pipe Line Company, due to lower overall
partnership net income in 2006 versus 2005. The increase in
distributions received from Red Cedar was due primarily to higher
year-over-year net income in 2006 versus 2005, and also from the fact
that Red Cedar had higher capital expansion spending in 2005, and
funded a large portion of the expenditures with retained cash; and
o a $2.9 million increase in cash inflows relative to changes in
non-current assets and liabilities--which represent offsetting changes
in cash from various long-term assets and liability accounts.
Investing Activities
Net cash used in investing activities was $1,388.2 million for the year
ended December 31, 2006, compared to $1,181.1 million for the prior year. The
$207.1 million (18%) overall increase in funds utilized in investing activities
was mainly attributable to:
o a $195.2 million (23%) increase in capital expenditures--driven by a
$168.7 million increase in capital spending from our Natural Gas
Pipelines business segment, largely due to the inclusion of Rockies
Express Pipeline LLC's capital expenditures for the first six months
of 2006, and by incremental expenditures for both asset infrastructure
expansions and hurricane repair and replacement costs. We continue to
make significant investments for both strategic acquisitions and
internal growth projects, and including all expansion and maintenance
projects, our capital expenditures were $1,058.3 million in 2006,
compared to $863.1 million in 2005.
Our sustaining capital expenditures totaled $125.4 million in 2006 and
$140.8 million in 2005. Sustaining capital expenditures are defined as
capital expenditures which do not increase the capacity of an asset.
Beginning in the third quarter of 2006, our Products Pipelines and CO2
business segments and our Texas intrastate natural gas pipeline group
began recognizing certain costs incurred as part of their pipeline
integrity management program as maintenance expense in the period
incurred, and in addition, recorded an expense for
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costs previously capitalized as sustaining capital expenditures during
the first six months of 2006. This change primarily affected our
Products Pipelines business segment, reducing its earnings before
depreciation, depletion and amortization expenses by $24.2 million and
reducing its sustaining capital expenditures by $19.8 million, when
compared to 2005.
Additionally, our forecasted expenditures for sustaining capital
expenditures for 2007 are approximately $156.5 million. This amount
has been forecasted primarily for the purchase of plant and equipment.
All of our capital expenditures, with the exception of sustaining
capital expenditures, are discretionary;
o an $89.6 million (29%) increase due to higher expenditures made for
strategic business acquisitions--in 2006, our acquisition outlays
totaled $397.4 million, which primarily consisted of $244.6 million
for the acquisition of Entrega Gas Pipeline LLC and $89.1 million for
the acquisition of bulk, liquids and refined products terminal
operations and related assets. In 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. Both our 2006 and 2005 acquisition
expenditures are discussed more fully in Note 3 to our consolidated
financial statements included elsewhere in this report;
o a $74.0 million decrease in cash used due to higher net proceeds of
$60.9 million received from both the sales of property, plant and
equipment and other net assets, net of salvage and removal costs, and
$13.1 million from property insurance indemnities received in 2006 for
damaged or destroyed property as a result of the 2005 hurricane
season. The increase from sales proceeds in 2006 versus 2005 was
driven by (i) the $42.5 million we received from Momentum Energy
Group, LLC for the combined sale of our Douglas natural gas gathering
system and Painter Unit fractionation facility; and (ii) the $27.1
million we received from the sale of certain oil and gas properties
originally acquired from Journey Acquisition - I, L.P. and Journey
2000, L.P.; and
o a $5.9 million (31%) decrease due to lower payments for natural gas
stored underground and natural gas liquids pipeline line-fill--largely
related to lower investments in underground natural gas storage
volumes in 2006 compared to 2005.
Financing Activities
Net cash provided by financing activities was $132.4 million in 2006; while
in the prior year, our financing activities used net cash of $96.0 million. The
$228.4 million overall increase in cash inflows provided by financing activities
was primarily due to:
o a $499.1 million increase from overall debt financing
activities--which include our issuances and payments of debt and our
debt issuance costs. The increase was primarily due to a $795.2
million increase from higher net commercial paper borrowings in 2006,
partially offset by a $294.4 million decrease due to both issuances
and payments of senior notes during 2005.
During each of the years 2006 and 2005, 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 issuing additional common
units and, in 2005 only, completing public offerings of senior notes.
We used the proceeds from these debt and equity issuances to reduce
our borrowings under our commercial paper program. Furthermore, the
increase in our commercial paper debt includes net borrowings of
$412.5 million under the commercial paper program of Rockies Express
Pipeline LLC. We held a 66 2/3% ownership interest in Rockies Express
Pipeline LLC until June 30, 2006, and according to the provisions of
generally accepted accounting principles, we included its cash inflows
and outflows in our consolidated statement of cash flows for the first
six months of 2006.
On June 30, 2006, following ConocoPhillips' acquisition of a 24%
ownership interest in West2East Pipeline LLC (and its subsidiary
Rockies Express Pipeline LLC), we deconsolidated West2East Pipeline
LLC and we have subsequently accounted for our investment under the
equity method of accounting. Following the change to the equity method
on June 30, 2006, Rockies Express' debt balances were no longer
included in our
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consolidated balance sheet and its cash inflows and outflows for all
periods subsequent to June 2006 were not included in our consolidated
statement of cash flows.
The decrease in cash inflows from changes in our senior notes related
to debt activities occurring on March 15, 2005. On that date, we both
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 to repay the 8.0% senior notes and to reduce our
commercial paper debt;
o a $102.0 million increase from contributions from minority
interests--principally due to contributions of $104.2 million received
in 2006 from Sempra Energy with regard to its ownership interest in
Rockies Express Pipeline LLC. The contribution from Sempra included an
amount of $80 million, contributed in the first quarter of 2006, for
Sempra's original 33 1/3% share of the purchase price of Entrega Gas
Pipeline LLC. In April 2006, Rockies Express Pipeline LLC merged with
and into Entrega Gas Pipeline LLC, and the surviving entity was
renamed Rockies Express Pipeline LLC;
o a $15.3 million increase from net changes in cash book
overdrafts--which represent checks issued but not yet endorsed. The
increase reflects a higher amount of outstanding checks in 2006, due
to timing differences in the payments of year-end accruals and
outstanding vendor invoices in 2006 versus 2005;
o a $221.6 million decrease from higher partnership
distributions--distributions to all partners, consisting of our common
and Class B unitholders, our general partner and minority interests,
totaled $1,171.5 million in 2006, compared to $949.9 million in 2005.
The overall increase in period-to-period distributions included
minority interest distributions of $105.2 million paid from our
Rockies Express Pipeline LLC subsidiary to Sempra Energy in the first
half of 2006. The distributions to Sempra (and distributions to us for
our proportionate ownership interest) were made in conjunction with
Rockies Express' establishment of and subsequent borrowings under its
commercial paper program during the second quarter of 2006, as
discussed above. During the second quarter of 2006, Rockies Express
both issued a net amount of $412.5 million of commercial paper and
distributed $315.5 million to its member owners. Prior to the
establishment of its commercial paper program (supported by its
five-year unsecured revolving credit agreement), Rockies Express
funded its acquisition of Entrega Gas Pipeline LLC and its Rockies
Express Pipeline construction costs with contributions from both us
and Sempra.
Excluding the minority interest distributions to Sempra, overall
distributions increased $116.4 million in 2006, when compared to 2005.
The increase primarily resulted from higher distributions of
"Available Cash," as described below in "--Partnership Distributions."
The increase in "Available Cash" distributions in 2006 versus 2005 was
due to an increase in the per unit cash distributions paid, an
increase in the number of units outstanding and an increase in our
general partner incentive distributions. We paid distributions of
$3.23 per unit in 2006 compared to $3.07 per unit in 2005. The 5%
increase in distributions paid per unit principally resulted from
favorable operating results in 2006. 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.
We also distributed 4,383,303 and 3,760,732 i-units in quarterly
distributions during 2006 and 2005, 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 2006 and 2005. 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; and
o a $167.2 million decrease in cash inflows from common unit equity
issuances--primarily related to the incremental cash we received from
our two separate 2005 common unit issuances over the cash received
from
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our single 2006 common unit issuance. In both 2006 and 2005, we used
the proceeds from each of these issuances to reduce the borrowings
under our commercial paper program.
In an August 2006 public offering, we issued an additional 5,750,000
of our common units at a price of $44.80, less commissions and
underwriting expenses. After all fees, we received net proceeds of
$248.0 million for the issuance of these common units. In 2005, we
received aggregate proceeds of $413.7 million from two separate common
unit equity issuances, consisting of the following (amounts are net of
all commissions and underwriting expenses):
o $283.6 million received from our issuance of 5,750,000 common
units in an August 2005 public offering; and
o $130.1 million received from our issuance of 2,600,000 common
units in a November 2005 public offering.
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 2006,
2005 and 2004, we distributed approximately 103%, 101% and 96%, respectively, of
the total of cash receipts less cash disbursements (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.
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to provide
for incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to
our general partner until the owners of all classes of units have
received a total of $0.15125 per unit in cash or equivalent i-units
for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the
owners of all classes of units have received a total of $0.17875 per
unit in cash or equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the
owners of all classes of units have received a total of $0.23375 per
unit in cash or equivalent i-units for such quarter; and
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o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units
in cash and to owners of i-units in the equivalent number of i-units,
and 50% to our general partner.
Incentive distributions are generally defined as all cash distributions
paid to our general partner that are in excess of 2% of the aggregate value of
cash and i-units being distributed. Our general partner's incentive distribution
that we declared for 2006 was $508.3 million, while the incentive distribution
paid to our general partner during 2006 was $515.9 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.
Under the terms of our partnership agreement, our distributions to
unitholders for 2006 required incentive distributions to our general partner in
the amount of $528.4 million; however, due to the fact that we did not meet our
2006 budget target, we had no obligation to fund our 2006 bonus plan for the
executive officers of our general partner and KMR, and for the employees of KMGP
Services Company, Inc. and KMI who operate our businesses. The board of
directors of KMI determined that it was in KMI's long-term interest to fund a
partial payout of our bonuses through a reduction in the general partner's
incentive distribution and accordingly, our general partner, with the approval
of the compensation committees and boards of KMI and KMR, waived $20.1 million
of its 2006 incentive distribution for the fourth quarter of 2006. The waived
amount approximates an amount equal to our actual bonus payout for 2006, which
is approximately 75% of our budgeted full bonus payout for 2006 of $26.5
million. Including the effect of this waiver, our distributions to unitholders
for 2006 resulted in payments of incentive distributions to our general partner
in the amount of $508.3 million.
On February 14, 2007, we paid a quarterly distribution of $0.83 per unit
for the fourth quarter of 2006. This distribution was 4% greater than the $0.80
distribution per unit we paid for the fourth quarter of 2005 and 2% greater than
the $0.81 distribution per unit we paid for the first quarter of 2006. 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 $0.83 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
As of December 31, 2006, we have recorded a total reserve for environmental
claims, without discounting and without regard to anticipated insurance
recoveries, in the amount of $61.6 million. In addition, we have recorded a
receivable of $27.0 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 or accidental spills or releases at facilities that we own.
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.
Additionally, as of December 31, 2006, we have recorded a total reserve for
legal fees, transportation rate cases and other litigation liabilities in the
amount of $112.0 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. As of December 31, 2005, our total
reserve for legal fees, transportation rate cases and other litigation
liabilities amounted to $136.5 million.
Though no assurance can be given, 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 adverse impact on
our business, cash flows, financial position or results of operations.
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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.
Please refer to Notes 16 and 17, respectively, to our consolidated
financial statements included elsewhere in this report for additional
information regarding pending litigation, environmental and asset integrity
matters.
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 2007 associated with the Pipeline Safety Improvement Act of 2002 and
the integrity management of our products pipelines in our 2007 budget and
capital expenditure plan.
Please refer to Note17 to our consolidated financial statements included
elsewhere in this report for additional information regarding regulatory
matters.
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:
o price trends and overall demand for natural gas liquids, refined
petroleum products, oil, carbon dioxide, natural gas, coal and other
bulk materials and chemicals in North America;
o economic activity, weather, alternative energy sources, conservation
and technological advances that may affect price trends and demand;
o changes in our tariff rates implemented by the Federal Energy
Regulatory Commission or the California Public Utilities Commission;
o our ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as our ability to
make expansions to our facilities;
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o difficulties or delays experienced by railroads, barges, trucks, ships
or pipelines in delivering products to or from our terminals or
pipelines;
o our ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
o shut-downs or cutbacks at major refineries, petrochemical or chemical
plants, ports, utilities, military bases or other businesses that use
our services or provide services or products to us;
o crude oil and natural gas production from exploration and production
areas that we serve, including, among others, the Permian Basin area
of West Texas;
o changes in laws or regulations, third-party relations and approvals,
decisions of courts, regulators and governmental bodies that may
adversely affect our business or our ability to compete;
o 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;
o our ability to offer and sell equity securities and debt securities or
obtain debt financing in sufficient amounts to implement that portion
of our business plan that contemplates growth through acquisitions of
operating businesses and assets and expansions of our facilities;
o our indebtedness could make us vulnerable to general adverse economic
and industry conditions, limit our ability to borrow additional funds,
and/or place us at competitive disadvantages compared to our
competitors that have less debt or have other adverse consequences;
o interruptions of electric power supply to our facilities due to
natural disasters, power shortages, strikes, riots, terrorism, war or
other causes;
o our ability to obtain insurance coverage without significant levels of
self-retention of risk;
o acts of nature, sabotage, terrorism or other similar acts causing
damage greater than our insurance coverage limits;
o capital markets conditions;
o the political and economic stability of the oil producing nations of
the world;
o national, international, regional and local economic, competitive and
regulatory conditions and developments;
o the ability to achieve cost savings and revenue growth;
o inflation;
o interest rates;
o the pace of deregulation of retail natural gas and electricity;
o foreign exchange fluctuations;
o the timing and extent of changes in commodity prices for oil, natural
gas, electricity and certain agricultural products;
o 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;
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o engineering and mechanical or technological difficulties with
operational equipment, in well completions and workovers, and in
drilling new wells;
o the uncertainty inherent in estimating future oil and natural gas
production or reserves;
o the ability to complete expansion projects on time and on budget;
o the timing and success of business development efforts; and
o unfavorable results of litigation and the fruition of contingencies
referred to in Note 3 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. Other
than as required by applicable law, 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 commodity prices or interest rates and the timing of transactions.
Energy Commodity Market Risk
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 commodity derivative contracts to reduce and minimize the
risks associated with unfavorable changes in the market price of natural gas,
natural gas liquids and crude oil. The derivative contracts 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
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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
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 commodity derivative contracts are as follows:
Credit Rating
-------------
Morgan Stanley................................. A+
J. Aron & Company / Goldman Sachs.............. AA-
BNP Paribas.................................... AA
We account for our energy commodity risk management derivative contracts
according to the provisions of 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 commodity derivative contracts
is to mitigate the market price risk associated with anticipated transactions
for the purchase and sale of natural gas, natural gas liquids and crude oil.
Using derivative contracts 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.
SFAS No. 133 categorizes such use of energy commodity derivative contracts
as cash flow hedges because the derivative contract is used to hedge the
anticipated future cash flow of a transaction that is expected to occur but
whose value is uncertain. Cash flow hedges are defined as hedges made with the
intention of decreasing the variability in cash flows related to future
transactions, as opposed to the value of an asset, liability or firm commitment,
and SFAS No. 133 prescribes special hedge accounting treatment for such
derivatives.
In accounting for cash flow hedges, gains and losses on the derivative
contracts are reported in other comprehensive income, outside "Net Income"
reported in our consolidated statements of income, but only to the extent that
the gains and losses from the change in value of the derivative contracts 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 derivative contracts'
gains and losses goes to other comprehensive income, pending occurrence of the
expected transaction. Other comprehensive income consists of those financial
items that are included in "Accumulated other comprehensive loss" in our
accompanying consolidated balance sheets but not included in our net income.
Thus, in highly effective cash flow hedges, where there is no ineffectiveness,
other comprehensive income changes by exactly as much as the derivative
contracts and there is no impact on earnings.
All remaining gains and losses on the derivative contracts (the ineffective
portion) are included in current net income. The ineffective portion of the gain
or loss on the derivative contracts is the difference between the gain or loss
from the change in value of the derivative contract and the effective portion of
that gain or loss. In addition, when the hedged forecasted transaction does take
place and affects earnings, the effective part of the hedge is also recognized
in the income statement, and the earlier recognized effective amounts are
removed from "Accumulated other comprehensive loss." If the forecasted
transaction results in an asset or liability, amounts in "Accumulated other
comprehensive loss" should be reclassified into earnings when the asset or
liability affects earnings through cost of sales, depreciation, interest
expense, etc.
Under current accounting rules, the accumulated components of other
comprehensive income 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 $838.7 million and $1,079.4 million being included within
"Accumulated other comprehensive loss" in the Partners' Capital section of our
accompanying balance sheets as of December 31, 2006 and December 31, 2005,
respectively.
For us, the gains and losses that are included in "Accumulated other
comprehensive loss" in our accompanying consolidated balance sheets are
primarily related to the derivative contracts associated with our hedging of
anticipated future cash flows from the sales and purchases of natural gas,
natural gas liquids and crude oil and represent the effective portion of the
gain or loss on these derivative contacts. In future periods, as the hedged cash
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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 and crude oil 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 is 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. Derivative contracts 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, 2006 and 2005, value-at-risk
reached a high of $2.6 million and $21.5 million, respectively, and a low of
$0.5 million and $7.6 million, respectively. Value-at-risk as of December 31,
2006, was $0.6 million and averaged $1.1 million for 2006. Value-at-risk as of
December 31, 2005, was $9.1 million and averaged $12.7 million for 2005.
Our calculated value-at-risk exposure represents an estimate of the
reasonably possible net losses that would be recognized on our portfolio of
derivative contracts 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 derivative contracts 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 derivative contracts, 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
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. 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.
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, 2006 and 2005, the carrying values of our fixed rate
debt were approximately $4,551.2 million and $4,560.7 million, respectively.
These amounts compare to, as of December 31, 2006 and 2005, fair values of
$4,672.7 million and $4,805.0 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 (approximately 62 basis points) in the average interest rates applicable
to such debt for 2006 and 2005, respectively, would result in changes of
approximately $183.4 million and $193.8 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 $1,195.6 million as of December 31, 2006 and $655.9 million as of December
31, 2005. 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, 2006 and 2005, respectively, including adjustments for
notional swap amounts, would result in changes of approximately $20.3 million
and $13.9 million, respectively, in our 2006 and 2005 annual pre-tax earnings.
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As of both December 31, 2006 and 2005, we were a party to interest rate
swap agreements with notional principal amounts of $2.1 billion. 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.
We entered into our interest rate swap agreements for the purposes of:
o hedging the interest rate risk associated with our fixed rate debt
obligations; and
o transforming 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.
Since the fair value of our fixed rate debt varies with changes in the
market rate of interest, we enter into swap agreements to receive a fixed and
pay a variable rate of interest. Such swap agreements result in future cash
flows that vary with the market rate of interest, and therefore hedge against
changes in the fair value of our fixed rate debt due to market rate changes. As
of December 31, 2006, all of our interest rate swap agreements 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 with
fixed rate debt (or vice versa) or by entering into interest rate swap
agreements 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.
As of December 31, 2006, 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.
See Note 9 to our consolidated financial statements included elsewhere in
this report for additional information related to our debt instruments; for more
information on our interest rate swap agreements, see Note 14.
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 134.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
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Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2006, 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 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, 2006.
Our management's assessment of the effectiveness of our internal control
over financial reporting as of December 31, 2006 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as
stated in their attestation report which is included elsewhere in this report.
Certain businesses we acquired during 2006 were excluded from the scope of
our management's assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2006. The excluded businesses consisted
of the following:
o the various oil and gas properties acquired from Journey Acquisition -
I, L.P. and Journey 2000, L.P. on April 5, 2006. The acquisition was
made effective March 1, 2006;
o three terminal operations acquired separately in April 2006: terminal
equipment and infrastructure located on the Houston Ship Channel, a
rail terminal located at the Port of Houston, and all of the
membership interests in Lomita Rail Terminal LLC;
o all of the membership interests of Transload Services, LLC, acquired
November 20, 2006;
o all of the membership interests of Devco USA L.L.C., acquired December
1, 2006; and
o the refined petroleum products terminal located in Roanoke, Virginia,
acquired from Motiva Enterprises, LLC effective December 15, 2006.
These businesses, in the aggregate, constituted 0.4% of our total operating
revenues for 2006 and 1.2% of our total assets as of December 31, 2006.
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Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting
during the fourth quarter of 2006 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance.
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............ 62 Director, Chairman and Chief Executive Officer
C. Park Shaper............... 38 Director and President
Steven J. Kean............... 45 Executive Vice President and Chief Operating Officer
Edward O. Gaylord............ 75 Director
Gary L. Hultquist............ 63 Director
Perry M. Waughtal............ 71 Director
Kimberly A. Dang............. 37 Vice President, Investor Relations and Chief Financial Officer
Jeffrey R. Armstrong......... 38 Vice President (President, Terminals)
Thomas A. Bannigan........... 53 Vice President (President, Products Pipelines)
Richard T. Bradley........... 51 Vice President (President, CO2)
David D. Kinder.............. 32 Vice President, Corporate Development and Treasurer
Joseph Listengart............ 38 Vice President, General Counsel and Secretary
Scott E. Parker.............. 46 Vice President (President, Natural Gas Pipelines)
James E. Street.............. 50 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
107
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 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 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
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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 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
We have a separately designated standing audit committee established in
accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934
comprised of Messrs. Gaylord, Hultquist and Waughtal. Mr. Gaylord is the
chairman of the audit committee and has been determined by the board to be an
"audit committee financial expert." The 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 $1.0 million or 2% of such tax-exempt
organization's consolidated gross revenues.
On April 11, 2006, 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 April 11, 2006, 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.
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Interested parties 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, Texas 77002, Attention: General Counsel, or by e-mail within the
"Contact Us" section of our Internet website, at www.kindermorgan.com. Any
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 2006.
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 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; consequently, in this Item 11., "we," "our" or "us" refers to Kinder
Morgan G.P., Inc., KMR and, where appropriate, KMI.
Compensation Discussion and Analysis
Program Objectives
We are a publicly traded master limited partnership, and our businesses
consist of a diversified portfolio of energy transportation, storage and
production assets. We seek to attract and retain executives who will help us
achieve our primary business strategy objective of growing the value of our
portfolio of businesses for the benefit of our unitholders. To help accomplish
this goal, we have designed an executive compensation program that rewards
individuals with competitive compensation that consists of a mix of cash,
benefit plans and long-term compensation, with a majority of executive
compensation tied to the "at risk" portions of the annual cash bonus and
long-term equity compensation.
The key objectives of our executive compensation program are to attract,
motivate and retain executives who will advance our overall business strategies
and objectives to create and return value to our unitholders. We believe that an
effective executive compensation program should link total compensation to
financial performance and to the attainment of short and long term strategic,
operational, and financial objectives. We also believe it should provide
competitive total compensation opportunities at a reasonable cost. In designing
our executive compensation program, we have recognized that our executives have
a much greater portion of their overall compensation at-risk than do our other
employees; consequently, we have tried to establish the at-risk portions of our
executive total compensation at levels that recognize their much increased level
of responsibility and their ability to influence business results.
Our executive compensation program is principally comprised of the
following three elements:
o base cash salary;
o possible annual cash bonus (reflected in the Summary Compensation
Table below as Non-Equity Incentive Plan Compensation); and
110
o possible long-term equity awards, namely grants of restricted KMI
stock and, in previous years, grants of options to acquire shares of
KMI common stock.
It is our current philosophy to pay our executive officers a base salary
not to exceed $200,000 per year, which is below base salaries for comparable
positions in the marketplace. In addition, we believe that the compensation of
our Chief Executive Officer, Chief Financial Officer and the executives named
below, collectively referred to in this Item 11 as our named executive officers,
should be directly and materially tied to the financial performance of KMI and
us, and should be aligned with the interests of KMI stockholders and our
unitholders. Therefore, the majority of our named executive officers'
compensation is allocated to the "at risk" portions of our compensation
program--the annual cash bonus and the long-term equity compensation. For 2006,
our executive compensation was weighted toward the cash bonus, payable on the
basis of achieving (i) an earnings per share target by KMI; and (ii) a cash
distribution per common unit target by us. Prior to 2003, we used both KMI stock
options and restricted KMI stock as the principal components of long-term
executive compensation, and beginning in 2003, we used grants of restricted
stock exclusively as the principal component of long-term executive
compensation.
Grants of restricted KMI stock are made to encourage our executive officers
to manage from the perspective of owners with an equity stake, and our approach
to equity compensation is designed to balance the business objective of fair and
reasonable executive pay with the business objectives of equityholder interests.
We are very sensitive to making large awards of KMI restricted stock or KMI
stock options to our executive officers because such large awards dilute the
ownership of KMI's stockholders. Therefore, we seek to balance the dilutive
effect of such stock awards to KMI's existing stockholders with our need to
attract and retain key employees.
Additionally, we periodically compare our executive compensation components
with market information. The purpose of this comparison is to ensure that our
total compensation package operates effectively, remains both reasonable and
competitive with the energy industry, and is generally comparable to the
compensation offered by companies of similar size and scope as us. We also keep
abreast of current trends, developments, and emerging issues in executive
compensation, and if appropriate, will obtain advice and assistance from outside
legal, compensation or other advisors.
We have endeavored to design our executive compensation program and
practices with appropriate consideration of all tax, accounting, legal and
regulatory requirements. Section 162(m) of the Internal Revenue Code limits the
deductibility of certain compensation for our executive officers to $1,000,000
of compensation per year; however, if specified conditions are met, certain
compensation may be excluded from consideration of the $1,000,000 limit. Since
the bonuses we pay to our executive officers are paid under KMI's
stockholder-approved 2005 Annual Incentive Plan as a result of reaching
designated financial targets established by KMI's compensation committee, we
expect that all compensation paid to our executives will be deductible by KMI.
Behaviors Designed to Reward
Our executive compensation program is designed to reward individuals for
advancing our business strategies and the interests of our stakeholders, and we
prohibit engaging in any detrimental activities, such as performing services for
a competitor, disclosing confidential information or violating appropriate
business conduct standards. Each executive is held accountable to uphold and
comply with company guidelines, which require the individual to maintain a
discrimination-free workplace, to comply with orders of regulatory bodies, and
to maintain high standards of operating safety and environmental protection.
Unlike many companies, we have no executive perquisites and, with respect
to our United States-based executives, we have no supplemental executive
retirement, non-qualified supplemental defined benefit/contribution, deferred
compensation or split dollar life insurance programs. We have no executive
company cars or executive car allowances nor do we offer or pay for financial
planning services. Additionally, we do not own any corporate aircraft and we do
not pay for executives to fly first class. We are currently below competitive
levels for comparable companies in this area of our compensation package;
however, we have no current plans to change our policy of not offering such
executive benefits or perquisite programs.
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At his request, Mr. Kinder, our Chairman and Chief Executive Officer,
receives $1 of base salary per year. Additionally, Mr. Kinder has requested that
he receive no annual bonus, stock or unit grants, or other compensation. Mr.
Kinder does not have any deferred compensation, supplemental retirement or any
other special benefit, compensation or perquisite arrangement. He wishes to be
rewarded strictly on the basis of stock performance which impacts the value of
his holdings of KMI common stock, KMP common units and KMR shares. Each year Mr.
Kinder reimburses us for his portion of health care premiums and parking
expenses.
Elements of Compensation
As outlined above, our executive compensation program is principally
comprised of the following three elements: a base cash salary; a possible annual
cash bonus; and a possible long-term equity award. With regard to our executive
officers other than our Chief Executive Officer, KMI's and KMR's compensation
committees review and approve annually the financial goals and objectives of
both KMI and us that are relevant to the compensation of our executive officers.
Generally following the regularly scheduled fourth quarter board meetings in
each year, the committees solicit information from other directors, the Chief
Executive Officer and other relevant members of senior management regarding the
performance of our executive officers other than our Chief Executive Officer
during that year. Our Chief Executive Officer makes compensation recommendations
to the committees with respect to our executive officers, other than himself.
The committees obtain the information and the recommendations prior to the
regularly scheduled first quarter board meetings.
Annually, at KMI's and our regularly scheduled first quarter board
meetings, the committees evaluate the performance of our executive officers
other than our Chief Executive Officer and make determinations regarding the
terms of their continued employment and compensation for that year. If the
committees deem it advisable, they may, rather than determine the terms of
continued employment and compensation for executive officers (other than the
Chief Executive Officer), make a recommendation with respect thereto to the
independent members of the board, who make the determination at the first
quarter board meetings. The committees also determine bonuses for the prior year
based on the performance targets set therefore, and set performance targets for
the present year for bonus and other relevant purposes.
If any executive officer of KMI is also an executive officer of KMR or our
General Partner, the committees' compensation determination or recommendation
(i) may be with respect to the aggregate compensation to be received by such
officer from KMI, KMR, and our General Partner that is to be allocated among
them in accordance with procedures approved by the committees, if such aggregate
compensation set by the committee or the board of KMI and that set by the
committee or the board of KMR are the same, or alternatively (ii) may be with
respect to the compensation to be received by such executive officers from KMI,
KMR or our General Partner, as the case may be, in which case such compensation
will not be allocated among KMI, on the one hand, and KMR, our General Partner
and us, on the other. Further, if any executive officer of KMI is also an
executive officer of KMR, the committees may, to the extent they believe
necessary or desirable, exchange information with respect to evaluation and
compensation recommendations with each other. Thereafter, the committees or the
Chief Executive Officer will discuss the committees' evaluation and the
determination as to compensation with the executive officers.
In addition, the compensation committees have the sole authority to retain
(and terminate as necessary) and compensate any compensation consultants,
counsel and other firms of experts to advise them as they determine necessary or
appropriate. The committees have the sole authority to approve any such firm's
fees and other retention terms, and we and KMI, as applicable, will make
adequate provision for the payment of all fees and other compensation, approved
by the committees, to any such firm employed by the committees. The committees
also have sole authority to determine if any compensation consultant is to be
used to assist in the evaluation of director, Chief Executive Officer or senior
executive compensation and will have sole authority to retain and terminate any
such compensation consultant and to approve the consultant's fees and other
retention terms.
Base Salary
This includes base salary, which is paid in cash. All of our executive
officers, with the exception of our Chairman and Chief Executive Officer who
receives $1 of base salary per year as described above, earn a base salary not
to exceed $200,000 per year. Generally, we believe that our executive officers'
base salaries are below
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base salaries for executives in similar positions and with similar
responsibilities at comparable companies of corresponding size and scope.
Possible Annual Cash Bonus (Non-Equity Cash Incentive)
Our possible annual cash bonuses are provided for under KMI's 2005 Annual
Incentive Plan, which became effective January 18, 2005 and which is referred to
in this report as the KMI Annual Incentive Plan. The overall purpose of the KMI
Annual Incentive Plan is to increase our executive officers' and our employees'
personal stake in the continued success of KMI and us by providing them
additional incentives through the possible payment of annual cash bonuses. Under
the plan, annual cash bonuses may be paid to our executive officers and other
employees depending on a variety of factors, including their individual
performance, KMI's financial performance, the financial performance of KMI's
subsidiaries (including us), and safety and environmental goals.
The plan is administered by the compensation committee of KMI's board of
directors, which consists of three or more directors, each of whom qualifies as
an "outside director" for purposes of the Internal Revenue Code. The
compensation committee is authorized to grant awards under the plan, interpret
the plan, adopt rules and regulations for carrying out the plan, and make all
determinations necessary or advisable for the administration of the plan.
All of the employees of KMI and its subsidiaries, including KMGP Services
Company, Inc., are eligible to participate in the plan, except employees who are
included in a unit of employees covered by a collective bargaining agreement
unless such agreement expressly provides for eligibility under the plan.
However, only eligible employees who are selected by the KMI compensation
committee will actually participate in the plan and receive bonuses.
The plan consists of two components: the executive plan component and the
non-executive plan component. Our Chairman and Chief Executive Officer and all
employees who report directly to the Chairman are eligible for the executive
plan component; however, as stated elsewhere in this report, Mr. Richard D.
Kinder, our Chairman and Chief Executive Officer, does not participate under the
plan. As of January 31, 2007, excluding Mr. Richard D. Kinder, 13 of our current
executive officers were eligible to participate in the executive plan component.
All other U.S. eligible employees were eligible for the non-executive plan
component.
The KMI compensation committee determines which of the eligible employees
will be eligible to participate under the executive plan component of the KMI
Annual Incentive Plan for any given year. At or before the start of each
calendar year (or later, to the extent allowed under Internal Revenue Code
regulations), performance objectives for that year are identified. The
performance objectives are based on one or more of the criteria set forth in the
plan. The KMI compensation committee establishes a bonus opportunity for each
executive officer, which is the amount of the bonus the executive officer will
earn if the performance objectives are fully satisfied. 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 compensation committee may set additional levels above the
minimum (which may also be above the targeted performance objective), with a
formula to determine the percentage of the bonus opportunity to be earned at
each level of achievement above the minimum. Performance at a level above the
targeted performance objective may entitle the executive officer to earn a bonus
in excess of 100% of the bonus opportunity. However, the maximum payout to any
individual under the KMI Annual Incentive Plan for any year is $2.0 million, and
the KMI compensation committee has the discretion to reduce the bonus amount in
any performance period.
Performance objectives may be based on one or more of the following
criteria:
o KMI's earnings per share;
o KMI cash dividends to its stockholders;
o KMI's earnings before interest and taxes or earnings before interest,
taxes and corporate charges, or the earnings before interest and taxes
or earnings before interest, taxes and corporate charges of one of its
subsidiaries or business units;
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o KMI's net income or the net income of one of its subsidiaries or
business units;
o KMI's revenues or the revenues of one of its subsidiaries or business
units;
o KMI's unit revenues minus unit variable costs or the unit revenues
minus unit variable costs of one of its subsidiaries or business
units;
o KMI's return on capital, return on equity, return on assets, or return
on invested capital, or the return on capital, return on equity,
return on assets, or return on invested capital of one of its
subsidiaries or business units;
o KMI's cash flow return on assets or cash flows from operating
activities, or the cash flow return on assets or cash flows from
operating activities of one of its subsidiaries or business units;
o KMI's capital expenditures or the capital expenditures of one of its
subsidiaries or business units;
o KMI's operations and maintenance expense or general and administrative
expense, or the operations and maintenance expense or general and
administrative expense of one of its subsidiaries or business units;
o KMI's debt-equity ratios and key profitability ratios, or the
debt-equity ratios and key profitability ratios of one of its
subsidiaries or business units; or
o KMI's stock price.
The KMI compensation committee set two performance objectives for 2006
under both the executive plan component and the non-executive plan component.
The 2006 performance objectives were $3.28 in cash distributions per common unit
at KMP, and $5.00 in earnings per share at KMI. These targets were the same as
our and KMI's previously disclosed 2006 budget expectations. At the end of 2006,
the KMI compensation committee determined and certified in writing the extent to
which the performance objectives had been attained and the extent to which the
bonus opportunity had been earned under the formula previously established by
the KMI compensation committee. Because payments under the plan for our
executive officers are determined by comparing actual performance to the
performance objectives established by the compensation committee each year for
eligible executive officers chosen to participate for that year, it is not
possible to accurately predict any amounts that will actually be paid under the
executive plan portion of the plan over the life of the plan.
The below table sets forth the bonus opportunities that would have been
payable to our executive officers if the performance objectives established by
the KMI compensation committee for 2006 had been 100% achieved. The KMI
compensation committee may, at its sole discretion, reduce the amount of the
bonus actually paid to any executive officer under the plan from the amount of
any bonus opportunity open to such executive officer.
KMI Annual Incentive Plan
Bonus Opportunities for 2006(1)
Name and Principal Position Dollar Value
--------------------------- ------------
Richard D. Kinder, Chairman and Chief Executive Officer............... $ --(2)
Kimberly A. Dang, Vice President and Chief Financial Officer.......... 1,000,000(3)
Jeffrey R. Armstrong, Vice President (President, Terminals)........... 1,000,000(3)
David D. Kinder, Vice President, Corporate Development and Treasurer.. 1,000,000(3)
Steven J. Kean, Executive Vice President and Chief Operating Officer.. 1,500,000(4)
Joseph Listengart, Vice President, General Counsel and Secretary...... 1,000,000(3)
Scott E. Parker, Vice President (President, Natural Gas Pipelines).... 1,000,000(3)
C. Park Shaper, Director and President................................ 1,500,000(4)
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(1) No stock, stock options, stock appreciation rights, restricted stock or
similar awards are payable under the plan.
(2) Declined to participate.
(3) Under the plan, for 2006, if neither of the targets was met, no bonus
opportunities would have been provided; if one of the targets was met,
$500,000 in bonus opportunities would have been open; if both of the
targets had been exceeded by 10%, $1,500,000 in bonus opportunities would
have been open. The KMI compensation committee may, in its sole discretion,
reduce the award payable to any participant for any reason.
(4) Under the plan, for 2006, if neither of the targets was met, no bonus
opportunities would have been provided; if one of the targets was met,
$750,000 in bonus opportunities would have been open; if both of the
targets had been exceeded by 10%, $2,000,000 in bonus opportunities would
have been open. The KMI compensation committee may, in its sole discretion,
reduce the award payable to any participant for any reason.
In 2006, excluding the impairment charge resulting from KMI entering into a
definitive agreement to sell its Terasen Gas business segment, KMI exceeded its
established target, but we (KMP) did not achieve our established target.
Excluding Mr. Richard D. Kinder, who does not participate in the plan, our top
three executive officers (Messrs. Shaper, Kean and Listengart) voluntarily
elected to take zero bonuses for work done in 2006. The KMI compensation
committee agreed to the executives' request for zero bonuses, but wanted to make
note that it was no reflection on any of the executives' personal performance
for the year. It was also noted and reflected that each of our other executive
officers' bonus was reduced in accordance with past practice and in light of the
making of just one target. Mr. Parker's bonus was paid $500,000 from the plan
according to the plan terms, and $350,000 from outside the plan as a
discretionary bonus.
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 by us for tax purposes.
The tax deduction available with respect to compensation paid to executive
officers is limited, unless the compensation qualifies as performance-based
under the Internal Revenue Code. The requirements for performance-based
compensation include the following:
o the compensation must be paid based solely on the attainment of
objective performance measures established by a committee of outside
directors, and
o the plan providing for such compensation must be approved by KMI
stockholders.
The KMI Annual Incentive Plan is a bonus plan that enables the portion of
an officer or employee's annual bonus based on objective performance criteria to
qualify as performance-based. Accordingly, that amount is deductible without
regard to the deduction limit otherwise imposed by the Internal Revenue Code. If
a bonus paid under the plan to an individual is in excess of the bonus
opportunity set by the compensation committee, Section 162(m) of the Internal
Revenue Code could limit the deductibility of the bonus paid. Consequently, the
compensation committee set bonus opportunities under the plan for 2006 for the
executive officers at dollar amounts in excess of that which were expected to
actually be paid under the plan.
KMI's Board of Directors may amend the plan from time to time without KMI
stockholder approval except as required to satisfy the Internal Revenue Code or
any applicable securities exchange rules. Awards may be granted under the plan
for calendar years 2007 through 2009, unless the plan is terminated earlier by
the KMI Board. However, the plan will remain in effect until payment has been
completed with respect to all awards granted under the plan prior to its
termination.
Restricted KMI Stock Awards
This includes grants of restricted KMI stock under KMI's Amended and
Restated 1999 Stock Plan, referred to in this report as the KMI stock plan. The
KMI stock plan allows for grants of restricted KMI stock and non-qualified KMI
stock options. We believe the plan permits us to keep pace with changing
developments in compensation and benefit programs, making us competitive with
those companies that offer incentives to attract and retain employees.
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The purposes of the KMI stock plan are to:
o enable the employees of KMI and the employees of its subsidiaries to
develop a sense of proprietorship and personal involvement in KMI's
financial success and the financial success of its subsidiaries,
including us; and
o encourage those employees to remain with and devote their best efforts
to KMI's business and the business of its subsidiaries, including us.
Officers and other employees of KMI and other entities in which they have a
direct or indirect interest are eligible to participate in the plan. KMI's
compensation committee, which administers the plan, has the sole discretion to
select participants from among eligible persons. Directors who are not employees
are not eligible to participate in the plan. The aggregate number of shares of
KMI common stock which may be issued under the plan with respect to options,
restricted stock and restricted stock units may not exceed 10,500,000, subject
to adjustment for certain transactions affecting the common stock. Lapsed,
forfeited or canceled options, and shares subject to forfeited restricted stock
units, will not count against this limit and can be regranted under the plan.
Options with respect to more than 1,000,000 shares of KMI common stock,
restricted stock with respect to more than 500,000 shares of KMI common stock
and restricted stock units with respect to more than 100,000 shares of KMI
common stock may not be granted to any one employee during any five year period.
The shares issued under the plan may be issued from shares held in treasury or
from authorized but unissued shares.
The KMI stock plan provides for the grant of:
o nonqualified stock options;
o stock appreciation rights in tandem with stock options;
o restricted stock; and
o restricted stock units.
Awards may be granted individually, in combination, or in tandem as
determined by the KMI compensation committee. KMI's Board of Directors may amend
the plan without KMI stockholder approval, unless that approval is required by
applicable law, rules, regulations or stock exchange requirements; however,
KMI's Board of Directors may not amend the plan in such a way that would impair
the rights of a participant under an award without the consent of such
participant, or that would decrease any authority granted to the KMI
compensation committee in contravention of Rule 16b-3 under the Securities
Exchange Act of 1934, as amended. In addition, KMI's Board of Directors may
terminate the plan at any time.
The KMI compensation committee establishes the form and terms of each grant
of restricted stock, and each grant is evidenced by a written agreement. Shares
of restricted stock are subject to "forfeiture restrictions" that restrict the
transferability of the shares and obligate the participant to forfeit and
surrender the shares under certain circumstances, such as termination of
employment. The KMI compensation committee may decide that forfeiture
restrictions on restricted stock will lapse upon the restricted stock holder's
continued employment for a specified period of time, the attainment of one or
more performance targets established by the KMI compensation committee, the
occurrence of any event or the satisfaction of any condition specified by the
KMI compensation committee, or a combination of any of these. The performance
targets may be based on:
o the price of a share of KMI stock or of the equity of one of its
subsidiaries or business units;
o KMI's earnings per share or the earnings per share of one of its
subsidiaries or business units;
o KMI's total stockholder value or the total stockholder value of one of
its subsidiaries or business units;
o KMI's dividends or distributions or the dividends or distributions of
one of its subsidiaries or business units;
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o KMI's revenues or the revenues of one of its subsidiaries or business
units;
o KMI's debt/equity ratio, interest coverage ratio or
indebtedness/earnings before or after interest, taxes, depreciation
and amortization ratio, or such ratios with respect to one of its
subsidiaries or business units;
o KMI's cash coverage ratio or the cash coverage ratio with respect to
one of its subsidiaries or business units;
o KMI's net income (before or after taxes) or the net income (before or
after taxes) of one of its subsidiaries or business units;
o KMI's cash flow or cash flow return on investments or the cash flow or
cash flow return on investments of one of its subsidiaries or business
units;
o KMI's earnings before or after interest, taxes, depreciation, and/or
amortization or earnings before or after interest, taxes,
depreciation, and/or amortization of one of its subsidiaries or
business units;
o KMI's economic value added or the economic value added of one of its
subsidiaries or business units;
o KMI's return on stockholders' equity or the return on stockholders'
equity of one of its subsidiaries or business units; or
o the payment of a bonus under the KMI Annual Incentive Plan as a result
of the attainment of performance goals based on one or more of the
criteria set forth above.
Each grant of restricted stock may have different forfeiture restrictions,
in the discretion of the KMI compensation committee. The KMI compensation
committee may, in its sole discretion, prescribe additional terms, conditions or
restrictions relating to restricted stock, including, but not limited to, rules
pertaining to the termination of employment (by retirement, disability, death or
otherwise) of a participant prior to the lapse of the forfeiture restrictions,
and terms related to tax matters.
Unless otherwise provided for in a written agreement, a participant will
have the right to receive dividends with respect to restricted stock, to vote
the stock and to enjoy all other stockholder rights, except that:
o the participant will not be entitled to delivery of the stock
certificate unless and until the forfeiture restrictions have lapsed;
o KMI will retain custody of the stock unless and until the forfeiture
restrictions have lapsed;
o the participant may not sell, transfer, pledge, exchange, hypothecate
or otherwise dispose of the stock unless and until the forfeiture
restrictions have lapsed; and
o a breach by a participant of the terms and conditions established by
the KMI compensation committee pursuant to the restricted stock
agreement will cause a forfeiture of the restricted stock by the
participant.
Unless otherwise provided for in a written agreement, dividends payable
with respect to restricted stock will be paid to a participant in cash on the
day on which the corresponding dividend on shares is paid to KMI stockholders,
or as soon as administratively feasible thereafter, but no later than the
fifteenth day of the third calendar month following the day on which the
corresponding dividend is paid to KMI stockholders. The KMI compensation
committee may, in its sole discretion, decide that a participant's right to
receive dividends on restricted stock is subject to the attainment of one or
more performance targets based on the criteria listed above.
The KMI compensation committee at any time may accelerate the time or
conditions under which the forfeiture restrictions lapse. However, except in the
event of a corporate change (as defined in the plan), the KMI compensation
committee may not take any such action with respect to "covered employees"
(within the meaning of Treasury Regulation ss. 1.162-27(c)(2)) if such
restricted stock has been designed to meet the exception for
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performance-based compensation under Section 162(m) of the Internal Revenue Code
unless the performance targets with respect to the restricted stock have been
attained.
For the year ended December 31, 2006, no restricted stock or options to
purchase shares of KMI were granted to any of our executive officers.
Other Compensation
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., including the named executive
officers, 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 special discretionary contributions. Certain employees'
contributions are based on collective bargaining agreements. The mandatory
contributions are made each pay period on behalf of each eligible employee. 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 business 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 service between two and five years, and 4% for
service of five years or more. All employer contributions for employees of our
Terminals business segment hired after October 1, 2005 will vest on the fifth
anniversary of the date of hire.
At its July 2006 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 2006 and continuing through the
last pay period of July 2007. 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 it will vest according to the same vesting schedule described in
the preceding paragraph. Since this additional 1% company contribution is
discretionary, KMI compensation committee approval will be required annually for
each additional contribution. During the first quarter of 2007, excluding the 1%
additional contribution described above, we will not make any additional
discretionary contributions to individual accounts for 2006.
Additionally, in 2006, an option to make after-tax "Roth" contributions
(Roth 401(k) option) to a separate participant account was added to the Savings
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. The employer contribution will still be considered taxable
income at the time of withdrawal.
Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and
KMI, including the named executive officers, 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. Under the plan, we make contributions on behalf of
participating employees equal to 3% of eligible compensation every pay period.
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
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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 actuarial present value of
each named executive officer's accumulated pension benefit as of December 31,
2006, under the provisions of the Kinder Morgan Cash Balance Retirement Plan.
With respect to our executive officers, the benefits were computed using the
same assumptions used for financial statement purposes, assuming current
remuneration levels without any salary projection, and assuming participation
until normal retirement at age sixty-five. 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.
Pension Benefits
Current Present Value
Credited Yrs of Accumulated Contributions
Name Plan Name of Service Benefit(1) During 2006
---- --------- ---------- -------------- -------------
Richard D. Kinder.........Cash Balance 6 $ -- $ --
Kimberly A. Dang..........Cash Balance 5 24,114 6,968
Jeffrey R. Armstrong......Cash Balance 6 40,534 7,726
David D. Kinder...........Cash Balance 6 32,114 7,337
Steven J. Kean............Cash Balance 5 33,957 7,422
Joseph Listengart.........Cash Balance 6 42,885 7,835
Scott E. Parker...........Cash Balance 8 62,385 8,735
C. Park Shaper............Cash Balance 6 42,885 7,835
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(1) The present values in the Pension Benefits table are based on certain
assumptions-including a 6% discount rate, RP 2000 mortality
(post-retirement only), 5% cash balance interest crediting rate, and lump
sums calculated using a 5% interest rate and IRS mortality. We assumed
benefits would commence at normal retirement date or unreduced retirement
date, if earlier. No death or turnover was assumed prior to retirement
date.
Other Potential Post-Employment Benefits. On October 7, 1999, Mr. Richard
D. Kinder entered into an employment agreement with KMI pursuant to which he
agreed to serve as its Chairman and Chief Executive Officer. His employment
agreement provides for a term of three years and one year extensions on each
anniversary of October 7th. Mr. Kinder, at his initiative, accepted an annual
salary of $1 to demonstrate his belief in our and KMI's long term viability. Mr.
Kinder continues to accept an annual salary of $1, and he receives no other
compensation. Mr. Kinder's employment agreement is extended annually at the
request of KMI's Board of Directors.
KMI's Board of Directors believes that Mr. Kinder's employment agreement
contains provisions that are beneficial to KMI, its subsidiaries and its
stockholders. For example, with limited exceptions, Mr. Kinder is prevented from
competing in any manner with KMI or any of its subsidiaries, while he is
employed by KMI and for 12 months following the termination of his employment
with KMI. The agreement contains provisions that address termination with and
without cause, termination as a result of change in duties or disability, and
death. At his current compensation level, the maximum amount that would be paid
to Mr. Kinder or his estate in the event of his termination is three times
$750,000, or $2.25 million. This payment would be made if Mr. Kinder were
terminated by KMI without cause or if Mr. Kinder terminated his employment with
KMI as a result of change in duties (as defined in the employment agreement).
There are no employment agreements or change-in-control arrangements with any of
our other executive officers.
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. KMR's compensation committee will determine
the duration and vesting of the options to employees at the time of grant, and
no individual employee may be granted options for more than 20,000 common units
in any year. The option plan also granted to each of our non-employee directors
an
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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.
For the year ended December 31, 2006, no options to purchase common units
were granted to or exercised by any of our executive officers, and as of
December 31, 2006, none of our executive officers owned unexercised common unit
options. For the year ended December 31, 2006, no options to purchase common
units were granted to our non-employee directors; however, one non-employee
director held and exercised 10,000 common unit options during 2006. As of
December 31, 2006, no options to purchase common units were outstanding under
the plan.
Summary Compensation Table
The following table shows compensation paid for services rendered to us
during fiscal year 2006 by (i) our principal executive officer, (ii) our
principal financial officer, (iii) the three most highly compensated executive
officers serving at fiscal year end, and (iv) our three other highest ranking
executive officers (collectively referred to as the "named executive officers"):
(1) (2) (3) (4) (5)
Non-Equity Change
Name and Stock Option Incentive Plan in Pension All Other
Principal Position Year Salary Bonus Awards Awards Compensation Value Compensation Total
------------------ ---- -------- -------- ---------- -------- -------------- ---------- ------------ ----------
Richard D. Kinder.......2006 $ 1 $ -- $ -- $ -- $ -- $ -- $ -- $ 1
Director, Chairman and
Chief Executive
Officer
Kimberly A. Dang........2006 200,000 -- 139,296 37,023 270,000 6,968 46,253 699,540
Vice President and
Chief Financial Officer
Jeffrey R. Armstrong....2006 200,000 -- 412,467 -- 450,000 7,726 132,878 1,203,071
Vice President
(President,
Terminals)
Steven J. Kean..........2006 200,000 -- 1,591,192 147,943 -- 7,422 284,919 2,231,476
Executive Vice
President and
Chief Operating Officer
David D. Kinder.........2006 200,000 -- 235,207 63,586 315,000 7,337 164,630 985,760
Vice President,
Corporate Development
and Treasurer
Joseph Listengart.......2006 200,000 -- 721,817 -- -- 7,835 224,753 1,154,405
Vice President,
General Counsel and
Secretary
Scott E. Parker.........2006 200,000 350,000 881,317 29,490 500,000 8,735 164,630 2,134,172
Vice President
(President,
Natural Gas Pipelines)
C. Park Shaper..........2006 200,000 -- 1,134,283 24,952 -- 7,835 348,542 1,715,612
Director and President
---------------------
(1) None of the restricted KMI stock awards were granted in 2006. Table
amounts only represent the calendar year 2006 expense attributable to
KMI restricted stock awarded in 2003, 2004 and 2005, and these awards
were reflected in compensation tables previously filed by us with the
Securities and Exchange Commission. The restricted shares were awarded
according to the provisions of the KMI Stock Plan, and the computed
value earned equaled the SFAS No. 123R
120
expense accumulated during the 2006 calendar year. For grants of
restricted stock, we take the value of the award at time of grant and
accrue the expense over the vesting period according to SFAS No. 123R.
For grants made July 16, 2003--KMI closing price was $53.80,
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. For grants made July 20, 2004--KMI closing
price was $60.79, 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. For
grants made July 20, 2005--KMI closing price was $89.48, 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.
(2) None of the options to purchase KMI shares were granted in 2006. Table
amounts only represent the calendar year 2006 expense attributable to
options to purchase KMI shares granted in 2002 and 2003, and these
awards were reflected in compensation tables previously filed by us
with the Securities and Exchange Commission. The options were granted
according to the provisions of the KMI Stock Plan, and the computed
value earned equaled the SFAS No. 123R expense accumulated on unvested
options during the 2006 calendar year. For options granted in
2002--volatility of 0.3912 using a 6 year term, 4.01% five year risk
free interest rate return, and a 0.71% expected annual dividend rate.
For options granted in 2003--volatility of 0.3853 using a 6.25 year
term, 3.37% treasury strip quote at time of grant, and a 2.973%
expected annual dividend rate.
(3) Represents amounts paid according to the provisions of the KMI Annual
Incentive Plan--except in the case of Mr. Parker, where $500,000 was
paid under the plan and $350,000 was paid outside of the plan. Amounts
were earned in 2006 but paid in 2007.
(4) Represents the 2006 change in the actuarial present value of
accumulated defined pension benefit (including unvested benefits)
according to the provisions of KMI's Cash Balance Retirement Plan.
(5) Amounts represent value of contributions to the Kinder Morgan Savings
Plan (a 401(k) plan), value of group-term life insurance exceeding
$50,000, taxable parking subsidy and dividends paid on unvested
restricted stock awards. For each individual excluding Mr. Richard D.
Kinder, amounts include $10,000 representing the value of
contributions to the Kinder Morgan Savings Plan. Amounts representing
the value of dividends paid on unvested restricted stock awards are as
follows: for Ms. Dang $35,875; for Mr. Armstrong $122,500; for Mr.
Kean $273,000; for Mr. David D. Kinder $69,563; for Mr. Listengart
$214,375; for Mr. Parker $154,000; and for Mr. Shaper $336,875.
The following supplemental compensation table shows compensation details on
the value of all non-guaranteed and non-discretionary incentive awards granted
during 2006 to our named executive officers. The table includes grant awards
made during 2006 and discloses estimated future payouts for both equity and
non-equity incentive plans.
Grants of Plan-Based Awards
Estimated Future Payouts Under
Non-Equity Incentive Plan Awards(1)
-----------------------------------
Name Threshold Target Maximum
---- --------- ------ -------
Richard D. Kinder........... $ -- $ -- $ --
Kimberly A. Dang............ 500,000 1,000,000 1,500,000
Jeffrey R. Armstrong........ 500,000 1,000,000 1,500,000
Steven J. Kean.............. 750,000 1,500,000 2,000,000
David D. Kinder............. 500,000 1,000,000 1,500,000
Joseph Listengart........... 500,000 1,000,000 1,500,000
Scott E. Parker............. 500,000 1,000,000 1,500,000
C. Park Shaper.............. 750,000 1,500,000 2,000,000
- ----------
(1) Represents grants under the KMI Annual Incentive Plan for 2006. See
"Elements of Compensation--Possible Annual Cash Bonus (Non-Equity Cash
Incentive)" for a discussion of these awards.
121
The following tables set forth certain information at December 31, 2006
with respect to all outstanding KMI equity awards granted to our named
executive officers.
Outstanding KMI Equity Awards at 2006 Year-End
Option Awards Stock Awards
--------------------------------------------------------- ------------------------------------
No. of Shares Underlying
Unexercised Options Option Option No. of Shares Market Value
------------------------------- Exercise Expiration that have of Shares that
Name Exercisable Unexercisable Price Date not vested(1) have not vested(2)
---- ----------- ------------- -------- ------------- ------------- ------------------
Richard D. Kinder.............. -- -- $ -- -- -- $ --
Kimberly A. Dang............... 10,250 -- 56.99 Jan. 16, 2012 8,000 846,000
10,000 -- 39.12 July 17, 2012
4,500 -- 53.80 July 16, 2010
Jeffrey R. Armstrong........... 22,000 -- 53.20 Mar. 30, 2011 30,000 3,172,500
Steven J. Kean................. 12,500 -- 56.99 Jan. 16, 2012 78,000 8,248,500
13,500 -- 39.12 July 12, 2012
10,000 -- 53.80 July 16, 2010
David D. Kinder................ 12,500 -- 49.875 Jan. 17, 2011 15,750 1,665,563
100 -- 49.875 Jan. 17, 2011
8,000 -- 39.12 July 12, 2012
Joseph Listengart.............. 50,000 -- 23.8125 Oct. 8, 2009 52,500 5,551,875
6,300 -- 49.875 Jan. 17, 2011
Scott E. Parker................ 10,000 -- 53.80 July 16, 2010 44,000 4,653,000
C. Park Shaper................. 95,000 -- 24.75 Jan. 20, 2010 82,500 8,724,375
25,000 -- 49.875 Jan. 17, 2011
100,000 -- 56.99 Jan. 16, 2012
- ----------------
(1) For Ms. Dang, 2,000 shares vest July 20, 2007, 1,500 shares vest July 20,
2009, and 4,500 shares vest July 20, 2010; for Mr. Armstrong 30,000 shares
vest July 16, 2008; for Mr. Kean 4,000 shares vest July 20, 2007, 17,500
shares vest July 20, 2008, 4,000 shares vest July 20, 2009, and 52,500
shares vest July 20, 2010; for Mr. David D. Kinder 11,250 shares vest July
16, 2008, and 4,500 shares vest July 20, 2010; for Mr. Listengart 52,500
shares vest July 16, 2008; for Mr. Parker 4,000 shares vest July 20, 2007,
9,000 shares vest July 20, 2008, 4,000 shares vest July 20, 2009, and
27,000 shares vest July 20, 2010; and for Mr. Shaper 82,500 shares vest
July 16, 2008. Upon closing of the proposed merger agreement providing for
the acquisition of KMI by investors, including Mr. Richard D. Kinder and
other senior members of KMI management, all restricted stock vesting dates
would be accelerated.
(2) Calculated on the basis of the fair market value of the underlying shares
at December 31, 2006 ($105.75).
The following tables set forth certain information for the fiscal year
ended December 31, 2006 with respect to all outstanding KMI equity awards vested
to our named executive officers during 2006 and all exercises of KMI stock
options during 2006.
KMI Option Exercises and KMI Stock Vested in 2006
Option Awards Stock Awards
------------------------------------ -----------------------------------
Shares Acquired Value Realized Shares Acquired Value Realized
Name on Exercise on Exercise(1) on Vesting on Vesting(2)
---- --------------- -------------- --------------- -------------
Richard D. Kinder.............. -- $ -- -- $ --
Kimberly A. Dang............... -- -- -- --
Jeffrey R. Armstrong........... 10,000 522,642 11,000 1,098,980
Steven J. Kean................. 11,500 757,165 5,000 483,850
David D. Kinder................ -- -- 4,000 399,193
Joseph Listengart.............. -- -- 20,000 1,991,925
Scott E. Parker................ -- -- 625 60,481
C. Park Shaper................. -- -- 30,000 2,991,925
- -------
(1) Calculated on the basis of the fair market value of the underlying shares
at exercise date, minus the exercise price.
(2) Calculated on the basis of the fair market value of underlying shares at
the vesting date.
122
Director Compensation
Compensation Committee Interlocks and Insider Participation. 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, Mr. James E. Street, and Messrs. Shaper and Kean, who are executive
officers of KMR, participate in the deliberations of the KMR compensation
committee concerning executive officer compensation. None of the members of
KMR's compensation committee is or has been one of our officers or employees,
and none of our executive officers served during 2006 on a board of directors of
another entity which has employed any of the members of KMR's compensation
committee.
Directors Fees. Beginning in 2005, our Common Unit Compensation Plan for
Non-Employee Directors, as discussed following, 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 (Messrs. Richard D. Kinder and C. Park Shaper) do not
receive compensation in their capacity as directors.
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 for Non-Employee Directors. 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.
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 payable in cash. Pursuant to the plan, in lieu of receiving cash
compensation, each non-employee director may elect to receive common units. Each
election will 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
election for 2006 was made effective January 17, 2006, and the election for 2007
was made effective January 16, 2007. 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 will 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 will, 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 will 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 will 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 cash compensation in the form of common units will equal the
amount of such 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 cash
compensation in the form of common units will receive cash equal to the
difference between (i) the 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
will be payable in four equal installments
123
generally around March 31, June 30, September 30 and December 31 of the calendar
year in which such cash compensation is awarded.
On January 17, 2006, each of KMR's three non-employee directors was awarded
cash compensation of $160,000 for board service during 2006. Effective January
17, 2006, each non-employee director elected to receive 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 remaining $72,220 cash compensation was paid to each of the
non-employee directors as described above. No other compensation was paid to the
non-employee directors during 2006.
On January 17, 2007, each of KMR's three non-employee directors was awarded
cash compensation of $160,000 for board service during 2007. Effective January
17, 2007, each non-employee director elected to receive certain amounts of cash
compensation in the form of our common units and each was issued common units
pursuant to the plan and its agreements (based on the $48.44 closing market
price of our common units on January 17, 2007, as reported on the New York Stock
Exchange). Mr. Gaylord elected to receive cash compensation of $95,911.20 in the
form of our common units and was issued 1,980 common units; Mr. Waughtal elected
to receive cash compensation of $159,852.00 in the form of our common units and
was issued 3,300 common units; and Mr. Hultquist elected to receive cash
compensation of $96,880.00 in the form of our common units and was issued 2,000
common units. All remaining cash compensation ($64,088.80 to Mr. Gaylord;
$148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) will be paid to each
of the non-employee directors as described above, and no other compensation will
be paid to the non-employee directors during 2007.
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 2006, and
as of December 31, 2006, 52,500 unit appreciation rights had been granted,
vested and remained outstanding.
The following table discloses the compensation earned by each of KMR's
three non-employee directors for board service during 2006. 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.
124
Non-Employee Director Compensation for Fiscal Year 2006
Fees Earned or Common Unit All Other
Name Paid in Cash Awards(1) Compensation(2) Total
---- ------------ --------- --------------- -----
Edward O. Gaylord.......... $72,220 $87,780 $3,418 $163,418
Gary L. Hultquist.......... 72,220 87,780 3,418 163,418
Perry M. Waughtal.......... 72,220 87,780 3,418 163,418
- ----------
(1) Represents the value of cash compensation received in the form of our
common units according to the provisions of our Common Unit Compensation
Plan for Non-Employee Directors. Value computed as the number of common
units elected to be received in lieu of cash (1,750 on January 17, 2006)
times the closing price on date of election ($50.16 at January 17, 2006).
(2) For each, represents the value of common unit appreciation rights earned
during 2006 according to the provisions of our Directors' Unit Appreciation
Rights Plan for Non-Employee Directors. For grants of common unit
appreciation rights, compensation cost is determined according to the
provisions of SFAS No. 123R--for each common unit appreciation right, equal
to the increase in value of each common unit over its grant-date fair
value. Value of $600 computed as the number of common unit appreciation
rights increasing in value during 2006 (7,500) times the increase in common
unit closing price from December 31, 2005 to December 31, 2006 ($0.08;
equal to $47.90 at December 31, 2006 less $47.82 at December 31, 2005).
Also for each, includes $2,818 for distributions paid on unvested common
units awarded according to the provisions of our Common Unit Compensation
Plan for Non-Employee Directors.
Compensation Committee Report
Throughout fiscal 2006, the compensation committee of KMR's board of
directors was comprised of three directors, each of which the KMR board of
directors has determined meets the criteria for independence under KMR's
governance guidelines and the New York Stock Exchange rules.
The KMR compensation committee has discussed and reviewed the above
Compensation Discussion and Analysis for fiscal year 2006 with management. Based
on this review and discussion, the KMR compensation committee recommended to its
board of directors, that this Compensation Discussion and Analysis be included
in this annual report on Form 10-K for the fiscal year 2006.
KMR Compensation Committee:
- ---------------------------
Edward O. Gaylord
Gary L. Hultquist
Perry M. Waughtal
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
The following table sets forth information as of January 31, 2007,
regarding (a) the beneficial ownership of (i) our common and Class B units, (ii)
the common stock of KMI, the parent company of our general partner, and (iii)
KMR shares by all directors of our general partner and KMR, its delegate, by
each of the named executive officers identified in Item 11. and by all directors
and executive officers as a group and (b) the beneficial ownership of our
125
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 of Percent Number of Percent
of Units(2) of Class Of Units(3) Of Class Shares(4) of Class Shares(5) of Class
----------- -------- ----------- -------- ---------- --------- ---------- ---------
Richard D. Kinder(6)................. 315,979 * -- -- 59,910 * 24,000,000 17.90%
C. Park Shaper(7).................... 4,000 * -- -- 2,913 * 352,070 *
Edward O. Gaylord(8)................. 38,480 * -- -- -- -- 2,000 *
Gary L. Hultquist(9)................. 16,500 * -- -- -- -- 500 --
Perry M. Waughtal(10)................ 44,100 * -- -- 43,243 * 70,030 *
Steven J. Kean(11)................... -- -- -- -- -- -- 124,754 *
Joseph Listengart(12)................ 4,198 * -- -- -- -- 140,368 *
Scott E. Parker(13).................. -- -- -- -- -- -- 55,431 *
Kimberly A. Dang(14)................. 121 * -- -- 412 * 33,915 *
David D. Kinder(15).................. 2,186 * -- -- 1,408 * 42,307 *
Jeffrey R. Armstrong(16)............. 1,093 * -- -- -- * 64,417 *
Directors and Executive Officers
as a group (14 persons)(17)....... 436,657 * -- -- 111,174 * 25,101,200 18.61%
Kinder Morgan, Inc.(18).............. 14,355,735 8.90% 5,313,400 100.00% 9,676,909 15.53% -- --
Kayne Anderson Capital Advisors,
L.P.(19).......................... -- -- -- -- 6,250,520 10.79% -- --
OppenheimerFunds, Inc.(20)........... -- -- -- -- 5,230,737 8.40% -- --
Tortoise Capital Advisors, L.L.C.(21) -- -- -- -- 4,047,052 6.50% -- --
----------
* 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, 2007, we had 162,823,583 common units issued and
outstanding.
(3) As of January 31, 2007, we had 5,313,400 Class B units issued and
outstanding.
(4) Represent the limited liability company shares of KMR. As of January
31, 2007, there were 62,301,674 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, 2007, KMI had a total of 134,188,793 shares of
issued and outstanding voting common stock, which excludes 15,023,351
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, 2007, and includes 82,500 shares of restricted KMI
stock.
(8) Includes 1,980 restricted common units.
(9) Includes 2,000 restricted common units.
(10) Includes 3,300 restricted common units.
(11) Includes options to purchase 36,000 KMI shares exercisable within 60
days of January 31, 2007, and 78,000 shares of restricted KMI stock.
126
(12) Includes options to purchase 56,300 KMI shares exercisable within 60
days of January 31, 2007, and includes 52,500 shares of restricted KMI
stock.
(13) Includes options to purchase 10,000 KMI shares exercisable within 60
days of January 31, 2007, and includes 44,000 shares of restricted KMI
stock.
(14) Includes options to purchase 24,750 KMI shares exercisable within 60
days of January 31, 2007, and includes 8,000 shares of restricted KMI
stock.
(15) Includes 1,211 common units owned by Mr. Kinder's spouse, 240 KMR
shares purchased in November 2004 for Mr. Kinder's son (and nominal
share distributions thereon), options to purchase 20,600 KMI shares
exercisable within 60 days of January 31, 2007, and includes 15,750
shares of restricted KMI stock. Mr. Kinder's son holds 250 shares of
KMI stock, which shares are not included in the number of shares Mr.
Kinder beneficially owns. Mr. Kinder disclaims any and all beneficial
ownership in the KMP common units owned by his wife, and the KMR
shares and the KMI stock owned by his sons.
(16) Includes options to purchase 22,000 KMI shares exercisable within 60
days of January 31, 2007, and includes 30,000 shares of restricted KMI
stock.
(17) Includes options to purchase 458,050 KMI shares exercisable within 60
days of January 31, 2007, and includes 7,280 restricted common units
and 400,750 shares of restricted KMI stock.
(18) Includes common units owned by KMI and its consolidated subsidiaries,
including 1,724,000 common units owned by Kinder Morgan G.P., Inc.
(19) As reported on the Schedule 13G/A filed February 5, 2007 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 6,978,859
shares, sole disposition power over 0 shares and shared disposition
power over 6,978,859 shares. Mr. Kayne reports that in regard to KMR
shares, he had sole voting power over 1,060 shares, shared voting
power over 6,978,859 shares, sole disposition power over 1,060 shares
and shared disposition power over 6,978,859 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.
(20) As reported on the Schedule 13G/A filed February 6, 2007 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 5,230,737
shares, sole disposition power over 0 shares and shared disposition
power over 5,230,737 shares. Of those 5,230,737 KMR shares,
Oppenheimer Capital Income Fund had sole voting power over 0 shares,
shared voting power over 3,657,500 shares, sole disposition power over
0 shares and shared disposition power over 3,657,500 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.
(21) As reported on the Schedule 13G/A filed February 13, 2007 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 3,960,233 shares, sole disposition power over
0 shares and shared disposition power over 4,047,052 shares. Tortoise
Capital Advisors, L.L.C.'s address is 10801 Mastin Blvd., Suite 222,
Overland Park, Kansas 66210.
Equity Compensation Plan Information
The following table sets forth information regarding our equity
compensation plans as of December 31, 2006. Specifically, the table provides
information regarding our Common Unit Option Plan and our Common Unit
Compensation Plan for Non-Employee Directors, both described in Item 11,
"Executive Compensation."
127
Number of securities Weighted average Number of securities
to be issued upon exercise exercise price remaining available for
of outstanding options, of outstanding options, future issuance under equity
warrants and rights warrants and rights compensation plans
Plan category (a) (b) (c)
- ----------------------------------- --------------------------- ----------------------- ----------------------------
Equity compensation plans
approved by security holders - - -
Equity compensation plans
not approved by security holders - - 149,100
-------
Total - - 149,100
=======
Item 13. Certain Relationships and Related Transactions, and Director
Independence.
For information regarding related transactions, see Note 12 of the notes to
our consolidated financial statements included elsewhere in this report.
Except for transactions through the retail division of KMI, employees must
obtain authorization from the appropriate business unit president of the
relevant company or head of corporate function; and directors, business unit
presidents, executive officers and heads of corporate functions must obtain
authorization from the non-interested members of the audit committee of the
applicable board of directors for any business relationship or proposed business
transaction in which they or an immediate family member has a direct or indirect
interest, or from which they or an immediate family member may derive a personal
benefit (a "related party transaction"). The maximum dollar amount of related
party transactions that may be approved as described above in this paragraph in
any calendar year will be $1.0 million. Any related party transactions that
would bring the total value of such transactions to greater than $1.0 million
will be referred to the audit committee of the appropriate board of directors
for approval or to determine the procedure for approval.
Director Independence
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, the committee charters and rules, respectively. Copies of
the guidelines and committee charters are available on our internet website at
www.kindermorgan.com. To assist in making determinations of independence, the
board has determined that the following categories of relationships are not
material relationships that would cause the affected director not to be
independent:
o If the director was an employee, or had an immediate family member who
was an executive officer, of KMR or us or any of its or our
affiliates, but the employment relationship ended more than three
years prior to the date of determination (or, in the case of
employment of a director as an interim chairman, interim chief
executive officer or interim executive officer, such employment
relationship ended by the date of determination);
128
o 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 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);
o 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 $1.0
million or 2% of such other company's annual consolidated gross
revenues. Contributions to tax-exempt organizations are not considered
payments for purposes of this determination;
o If the director is also a director, but is not an employee or
executive officer, of our general partner or another affiliate or
affiliates of KMR or us, so long as such director is otherwise
independent; and
o If the director beneficially owns less than 10% of each class of
voting securities of us, our general partner, KMR or Kinder Morgan,
Inc.
The board has affirmatively determined that Messrs. Gaylord, Hultquist and
Waughtal, who constitute a majority of the directors, are independent as
described in our governance guidelines and the New York Stock Exchange rules.
Each of them meets the standards above and has no other relationship with us. In
conjunction with all regular quarterly and certain special board meetings, these
three non-management directors also meet in executive session without members of
management. In January 2007, Mr. Waughtal was elected for a one year term to
serve as lead director to develop the agendas for and preside at these executive
sessions of independent directors.
The governance guidelines and our audit committee charter, as well as the
rules of the New York Stock Exchange and the Securities and Exchange Commission,
require that members of the audit committee satisfy independence requirements in
addition to those above. The board has determined that all of the members of the
audit committee are independent as described under the relevant standards.
Item 14. Principal Accounting Fees and Services
The following sets forth fees billed for the audit and other services
provided by PricewaterhouseCoopers LLP for the fiscal years ended December 31,
2006 and 2005 (in dollars):
Year Ended December 31,
---------------------------
2006 2005
------------ ------------
Audit fees(1).................$ 2,038,215 $ 2,085,800
Audit-Related fees(2)......... -- 34,000
Tax fees(3)................... 1,470,466 1,479,344
------------ ------------
Total.......................$ 3,508,681 $ 3,599,144
============ ============
- ----------
(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. 2005 amount represents fees for audit related services
associated with Plantation Pipe Line Company. We account for our investment
in Plantation under the equity method of accounting.
(3) For 2006 and 2005, amounts include fees of $1,356,399 and $1,355,194,
respectively, billed for professional services rendered for tax processing
and preparation of Forms K-1 for our unitholders. Amounts also include fees
of $114,067 and $124,150, respectively, billed for professional services
rendered for tax return review services and for general state, local and
foreign tax compliance and consulting services.
129
All services rendered by PricewaterhouseCoopers LLP are permissible under
applicable laws and regulations, and were pre-approved by the audit committee of
KMR and our general partner. Pursuant to the charter of the audit committee of
KMR, the delegate of our general partner, the committee's primary purposes
include the following:
o to select, appoint, engage, oversee, retain, evaluate and terminate
our external auditors;
o to pre-approve all audit and non-audit services, including tax
services, to be provided, consistent with all applicable laws, to us
by our external auditors; and
o to establish the fees and other compensation to be paid to our
external auditors.
The audit committee has reviewed the external auditors' fees for audit and
non audit services for fiscal year 2006. The audit committee considered whether
such non audit services are compatible with maintaining the external auditors'
independence and has concluded that they are compatible at this time.
Furthermore, the audit committee will review the external auditors'
proposed audit scope and approach as well as the performance of the external
auditors. It also has direct responsibility for and sole authority to resolve
any disagreements between our management and our external auditors regarding
financial reporting, will regularly review with the external auditors any
problems or difficulties the auditors encountered in the course of their audit
work, and will, at least annually, use its reasonable efforts to obtain and
review a report from the external auditors addressing the following (among other
items):
o the auditors' internal quality-control procedures;
o any material issues raised by the most recent internal quality-control
review, or peer review, of the external auditors;
o the independence of the external auditors; and
o the aggregate fees billed by our external auditors for each of the
previous two fiscal years.
130
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 134.
(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 (File No. 1-11234) 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 (File No. 1-11234)).
*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 (File No. 1-11234) 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
(File No. 1-11234)).
*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 (File No. 1-11234) 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 (File
No. 1-11234) 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 (File No. 1-11234) 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 (File No.
1-11234), 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
(File No. 1-11234), 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
(File No. 1-11234), filed on March 14, 2001).
131
<Page>
*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
(File No. 1-11234) 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
(File No. 1-11234) 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
(File No. 1-11234) 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 -- Certificate of Vice President and Chief Financial Officer 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
6.00% Senior Notes due 2017 and 6.50% Senior Notes due 2037.
4.29 -- Specimen of 6.00% Senior Notes due 2017 in book-entry form.
4.30 -- Specimen of 6.50% Senior Notes due 2037 in book-entry form.
4.31 -- 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.
132
<Page>
*10.1 -- Kinder Morgan Energy Partners, L.P. Common Unit Option Plan (filed
as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. 1997 Form
10-K, File No. 1-11234).
*10.2 -- 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 -- First Amendment, dated October 28, 2005, to 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 Form 10-Q for the quarter ended
September 30, 2006).
*10.10 -- Second Amendment, dated April 13, 2006, to 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 10.2 to Kinder
Morgan Energy Partners, L.P.'s Form 10-Q for the quarter ended
September 30, 2006).
*10.11 -- Third Amendment, dated October 6, 2006, to 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 10.3 to Kinder
Morgan Energy Partners, L.P.'s Form 10-Q for the quarter ended
September 30, 2006).
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.
133
<Page>
INDEX TO FINANCIAL STATEMENTS
Page
Number
-------
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
Report of Independent Registered Public Accounting Firm.................... 135
Consolidated Statements of Income for the years ended December 31, 2006,
2005, and 2004............................................................. 137
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2006, 2005, and 2004.......................................... 138
Consolidated Balance Sheets as of December 31, 2006 and 2005............... 139
Consolidated Statements of Cash Flows for the years ended December 31,
2006, 2005, and 2004....................................................... 140
Consolidated Statements of Partners' Capital for the years ended
December 31, 2006, 2005, and 2004.......................................... 141
Notes to Consolidated Financial Statements................................. 142
134
<Page>
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
consolidated financial statements and of its internal control over financial
reporting as of December 31, 2006, 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, 2006 and 2005, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2006 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.
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, 2006 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, 2006, 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 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
135
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:
o the various oil and gas properties acquired from Journey Acquisition -
I, L.P. and Journey 2000, L.P. on April 5, 2006. The acquisition was
made effective March 1, 2006;
o three terminal operations acquired separately in April 2006: terminal
equipment and infrastructure located on the Houston Ship Channel, a
rail terminal located at the Port of Houston, and all of the
membership interests in Lomita Rail Terminal LLC;
o all of the membership interests of Transload Services, LLC, acquired
November 20, 2006;
o all of the membership interests of Devco USA L.L.C., acquired December
1, 2006; and
o the refined petroleum products terminal located in Roanoke, Virginia,
acquired from Motiva Enterprises, LLC effective December 15, 2006,
(the "Acquired Businesses"), each acquired in separate transactions, from its
assessment of internal control over financial reporting as of December 31, 2006
because these businesses were acquired by the Partnership in purchase business
combinations during 2006. We have also excluded these Acquired Businesses from
our audit of internal control over financial reporting. These Acquired
Businesses', in the aggregate, constituted 1.2% and 0.4%, respectively, of total
assets and total revenues of the related consolidated financial statement
amounts as of and for the year ended December 31, 2006.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
March 1, 2007
136
<Page>
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
2006 2005 2004
----------- ----------- -----------
(In thousands except per unit amounts)
Revenues
Natural gas sales....................................... $ 6,039,866 $ 7,198,499 $ 5,803,065
Services................................................ 2,084,119 1,851,699 1,571,504
Product sales and other................................. 830,598 736,930 558,292
----------- ----------- -----------
8,954,583 9,787,128 7,932,861
----------- ----------- -----------
Costs, Expenses and Other
Gas purchases and other costs of sales.................. 5,990,963 7,167,414 5,767,169
Operations and maintenance.............................. 769,514 747,363 499,714
Fuel and power.......................................... 216,222 183,458 151,480
Depreciation, depletion and amortization................ 413,725 349,827 288,626
General and administrative.............................. 219,575 216,706 170,507
Taxes, other than income taxes.......................... 118,756 108,838 81,369
Other expense (income).................................. (30,306) -- --
----------- ----------- -----------
7,698,449 8,773,606 6,958,865
----------- ----------- -----------
Operating Income.......................................... 1,256,134 1,013,522 973,996
Other Income (Expense)
Earnings from equity investments........................ 76,170 91,660 83,190
Amortization of excess cost of equity investments....... (5,664) (5,644) (5,575)
Interest, net........................................... (331,499) (258,861) (192,882)
Other, net.............................................. 11,065 3,273 2,254
Minority Interest......................................... (15,015) (7,262) (9,679)
----------- ----------- -----------
Income Before Income Taxes................................ 991,191 836,688 851,304
Income Taxes.............................................. (19,048) (24,461) (19,726)
----------- ----------- -----------
Net Income................................................ $ 972,143 $ 812,227 $ 831,578
=========== =========== ===========
General Partner's interest in Net Income.................. $ 512,967 $ 477,300 $ 395,092
Limited Partners' interest in Net Income.................. 459,176 334,927 436,486
----------- ----------- -----------
Net Income................................................ $ 972,143 $ 812,227 $ 831,578
=========== =========== ===========
Basic and Diluted Limited Partners' Net Income per Unit... $ 2.04 $ 1.58 $ 2.22
=========== =========== ===========
Weighted average number of units used in computation
of Limited Partners' Net Income per Unit:
Basic..................................................... 224,585 212,197 196,956
=========== =========== ===========
Diluted................................................... 224,914 212,429 197,038
=========== =========== ===========
Per unit cash distribution declared....................... $ 3.26 $ 3.13 $ 2.87
=========== =========== ===========
The accompanying notes are an integral part of these
consolidated financial statements.
137
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
------------------------------------
2006 2005 2004
---------- ---------- ---------
(In thousands)
Net Income........................................... $ 972,143 $ 812,227 $ 831,578
Change in fair value of derivatives used for
hedging purposes................................... (187,525) (1,045,615) (494,212)
Reclassification of change in fair value of
derivatives to net income......................... 428,137 423,983 192,304
Foreign currency translation adjustments............. 722 (699) 375
---------- ---------- ---------
Total other comprehensive income................... 241,334 (622,331) (301,533)
---------- ---------- ---------
Comprehensive Income................................. $1,213,477 $ 189,896 $ 530,045
========== ========== =========
The accompanying notes are an integral part of these consolidated
financial statements.
138
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
-------------------------
2006 2005
----------- -----------
ASSETS (Dollars in thousands)
Current Assets
Cash and cash equivalents................................ $ 13,985 $ 12,108
Accounts, notes and interest receivable, net
Trade................................................. 840,755 1,011,716
Related parties....................................... 18,802 2,543
Inventories
Products.............................................. 20,419 18,820
Materials and supplies................................ 13,825 13,292
Gas imbalances
Trade................................................. 7,835 18,220
Related parties....................................... 11,640 -
Gas in underground storage............................... 8,373 7,074
Other current assets..................................... 101,111 131,451
----------- -----------
1,036,745 1,215,224
Property, Plant and Equipment, net......................... 9,445,471 8,864,584
Investments................................................ 425,600 419,313
Notes receivable
Trade.................................................... 1,241 1,468
Related parties.......................................... 89,713 109,006
Goodwill................................................... 828,970 798,959
Other intangibles, net..................................... 213,208 217,020
Deferred charges and other assets.......................... 205,446 297,888
----------- -----------
Total Assets............................................... $12,246,394 $11,923,462
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Accounts payable
Cash book overdrafts.................................. $ 46,215 $ 30,408
Trade................................................. 758,294 996,174
Related parties....................................... 2 16,676
Current portion of long-term debt........................ 1,359,069 -
Accrued interest......................................... 82,444 74,886
Accrued taxes............................................ 37,047 23,536
Deferred revenues........................................ 19,972 10,523
Gas imbalances
Trade................................................. 15,849 22,948
Related parties....................................... -- 1,646
Accrued other current liabilities........................ 566,807 632,088
----------- -----------
2,885,699 1,808,885
Long-Term Liabilities and Deferred Credits
Long-term debt
Outstanding........................................... 4,384,332 5,220,887
Market value of interest rate swaps................... 42,630 98,469
----------- -----------
4,426,962 5,319,356
Deferred revenues........................................ 18,786 6,735
Deferred income taxes.................................... 75,541 70,343
Asset retirement obligations............................. 48,880 42,417
Other long-term liabilities and deferred credits......... 718,274 1,019,655
----------- -----------
5,288,443 6,458,506
Commitments and Contingencies (Notes 13 and 16)
Minority Interest.......................................... 50,599 42,331
----------- -----------
Partners' Capital
Common Units (162,816,303 and 157,005,326 units issued and
outstanding as of December 31, 2006 and 2005,
respectively).......................................... 2,743,786 2,680,352
Class B Units (5,313,400 and 5,313,400 units issued and
Outstanding as of December 31, 2006 and 2005,
respectively).......................................... 103,305 109,594
i-Units (62,301,676 and 57,918,373 units issued and
outstanding as of December 31, 2006 and 2005,
respectively).......................................... 1,906,449 1,783,570
General Partner.......................................... 109,667 119,898
Accumulated other comprehensive loss..................... (841,554) (1,079,674)
----------- -----------
4,021,653 3,613,740
Total Liabilities and Partners' Capital.................... $12,246,394 $11,923,462
=========== ===========
The accompanying notes are an integral part of these consolidated
financial statements.
139
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------------
2006 2005 2004
----------- ----------- -----------
(In thousands)
Cash Flows From Operating Activities
Net income................................................................. $ 972,143 $ 812,227 $ 831,578
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization................................. 413,725 349,827 288,626
Amortization of excess cost of equity investments........................ 5,664 5,644 5,575
Gains and other non-cash income from the sale of property, plant and
equipment.............................................................. (15,235) (521) 659
Gains from property casualty indemnifications............................ (15,193) -- --
Earnings from equity investments......................................... (76,170) (91,660) (83,190)
Distributions from equity investments...................................... 67,865 63,098 65,248
Changes in components of working capital:
Accounts receivable...................................................... 162,419 (240,751) (172,393)
Other current assets..................................................... 15,430 (14,129) 26,175
Inventories.............................................................. 661 (13,560) (7,353)
Accounts payable......................................................... (267,479) 294,907 222,377
Accrued interest......................................................... 7,558 17,943 4,568
Accrued liabilities...................................................... (10,766) 4,501 (23,050)
Accrued taxes............................................................ 13,823 (2,301) 3,444
FERC rate reparations, refunds and reserve adjustments..................... (19,079) 105,000 --
Other, net................................................................. 2,049 (795) (7,156)
----------- ----------- -----------
Net Cash Provided by Operating Activities.................................... 1,257,415 1,289,430 1,155,108
----------- ----------- -----------
Cash Flows From Investing Activities
Acquisitions of assets..................................................... (397,412) (307,832) (478,830)
Additions to property, plant and equip. for expansion and maintenance
projects................................................................. (1,058,265) (863,056) (747,262)
Sale of property, plant and equipment, and other net assets net of removal
costs.................................................................... 70,811 9,874 1,069
Property casualty indemnifications......................................... 13,093 -- --
Net proceeds from margin deposits.......................................... 2,298 -- --
Contributions to equity investments........................................ (2,449) (1,168) (7,010)
Natural gas stored underground and natural gas liquids line-fill........... (12,863) (18,735) (19,189)
Other...................................................................... (3,401) (211) 712
----------- ----------- -----------
Net Cash Used in Investing Activities........................................ (1,388,188) (1,181,128) (1,250,510)
----------- ----------- -----------
Cash Flows From Financing Activities
Issuance of debt........................................................... 4,632,562 4,900,936 6,016,670
Payment of debt............................................................ (3,698,749) (4,463,162) (5,657,566)
Repayments from (Loans to) related party................................... 1,097 2,083 (96,271)
Debt issue costs........................................................... (2,032) (6,058) (5,843)
Increase in cash book overdrafts........................................... 15,807 542 29,866
Proceeds from issuance of common units..................................... 248,420 415,574 506,520
Proceeds from issuance of i-units.......................................... -- -- 67,528
Contributions from minority interest....................................... 109,820 7,839 7,956
Distributions to partners:
Common units............................................................. (512,097) (460,620) (389,912)
Class B units............................................................ (17,162) (16,312) (14,931)
General Partner.......................................................... (523,198) (460,869) (376,005)
Minority interest........................................................ (119,025) (12,065) (10,117)
Other, net................................................................. (3,005) (3,866) (5,822)
----------- ----------- -----------
Net Cash Provided by (Used in) Financing Activities.......................... 132,438 (95,978) 72,073
----------- ----------- -----------
Effect of exchange rate changes on cash and cash equivalents................. 212 (216) --
----------- ----------- -----------
Increase (Decrease) in Cash and Cash Equivalents............................. 1,877 12,108 (23,329)
Cash and Cash Equivalents, beginning of period............................... 12,108 -- 23,329
----------- ----------- -----------
Cash and Cash Equivalents, end of period..................................... $ 13,985 $ 12,108 $ --
=========== =========== ===========
Noncash Investing and Financing Activities:
Contribution of net assets to partnership investments...................... $ 17,003 $ -- $ --
Assets acquired by the issuance of units................................... 1,650 49,635 64,050
Assets acquired by the assumption or incurrence of liabilities............. 6,051 76,574 81,403
Supplemental disclosures of cash flow information:
Cash paid during the year for interest (net of capitalized interest)....... 323,709 245,623 186,870
Cash paid (received) during the year for income taxes...................... 7,607 7,345 (752)
The accompanying notes are an integral part of these consolidated
financial statements.
140
KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
2006 2005 2004
------------------------- ------------------------- -------------------------
Units Amount Units Amount Units Amount
----------- ----------- ----------- ----------- ----------- ----------
(Dollars in thousands)
Common Units:
Beginning Balance..................... 157,005,326 $ 2,680,352 147,537,908 $ 2,438,011 134,729,258 $1,946,116
Net income............................ -- 325,390 -- 237,779 -- 311,237
Units issued as consideration pursuant
to common unit compensation plan for
non-employee directors.............. 5,250 263 5,250 239 -- --
Units issued as consideration in the
acquisition of assets............... 34,627 1,650 1,022,068 49,635 1,400,000 64,050
Units issued for cash................. 5,771,100 248,228 8,440,100 415,308 11,408,650 506,520
Distributions......................... -- (512,097) -- (460,620) -- (389,912)
----------- ----------- ----------- ----------- ----------- ----------
Ending Balance........................ 162,816,303 2,743,786 157,005,326 2,680,352 147,537,908 2,438,011
Class B Units:
Beginning Balance..................... 5,313,400 109,594 5,313,400 117,414 5,313,400 120,582
Net income............................ -- 10,873 -- 8,492 -- 11,763
Distributions......................... -- (17,162) -- (16,312) -- (14,931)
----------- ----------- ----------- ------------ ----------- ----------
Ending Balance........................ 5,313,400 103,305 5,313,400 109,594 5,313,400 117,414
i-Units:
Beginning Balance..................... 57,918,373 1,783,570 54,157,641 1,694,971 48,996,465 1,515,659
Net income............................ -- 122,913 -- 88,656 -- 113,486
Units issued for cash................. -- (34) -- (57) 1,660,664 65,826
Distributions......................... 4,383,303 -- 3,760,732 -- 3,500,512 --
----------- ----------- ----------- ------------ ----------- ----------
Ending Balance........................ 62,301,676 1,906,449 57,918,373 1,783,570 54,157,641 1,694,971
General Partner:
Beginning Balance..................... -- 119,898 -- 103,467 -- 84,380
Net income............................ -- 512,967 -- 477,300 -- 395,092
Distributions......................... -- (523,198) -- (460,869) -- (376,005)
----------- ----------- ----------- ------------ ----------- ----------
Ending Balance........................ -- 109,667 -- 119,898 -- 103,467
Accum. other comprehensive income (loss):
Beginning Balance..................... -- (1,079,674) -- (457,343) -- (155,810)
Change in fair value of derivatives
used for hedging purposes........... -- (187,525) -- (1,045,615) -- (494,212)
Reclassification of change in fair
value of derivatives to net income.. -- 428,137 -- 423,983 -- 192,304
Foreign currency translation adjustments -- 722 -- (699) -- 375
Adj. to initially apply SFAS No. 158
-other post-retirement benefit acctg.
changes -- (3,214) -- -- -- --
----------- ----------- ----------- ----------- ----------- ----------
Ending Balance........................ -- (841,554) -- (1,079,674) -- (457,343)
Total Partners' Capital................. 230,431,379 $ 4,021,653 220,237,099 $ 3,613,740 207,008,949 $3,896,520
=========== =========== =========== =========== =========== ==========
The accompanying notes are an integral part of
these consolidated financial statements.
141
<Page>
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:
o Products Pipelines - transporting, storing and processing refined
petroleum products;
o Natural Gas Pipelines - transporting, storing, selling and processing
natural gas;
o CO2 - producing, transporting and selling carbon dioxide, commonly
called CO2, for use in, and selling crude oil produced from, enhanced
oil recovery operations; and
o 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:
o Kinder Morgan Operating L.P. "A" (OLP-A);
o Kinder Morgan Operating L.P. "B" (OLP-B);
o Kinder Morgan Operating L.P. "C" (OLP-C);
o Kinder Morgan Operating L.P. "D" (OLP-D); and
o 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, storage and distribution companies in North America. It
operates or owns an interest in, either for itself or on our behalf,
approximately 43,000 miles of pipelines that transport primarily natural gas,
crude oil, petroleum products and carbon dioxide; more than 155
142
terminals that store transfer and handle products like gasoline and coal; and
provides natural gas distribution service to over 1.1 million customers. At
December 31, 2006, KMI and its consolidated subsidiaries owned, through its
general and limited partner interests, an approximate 14.7% 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 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,
2006, KMR owned approximately 27.0% 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
operating partnerships and their majority-owned and controlled 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. We believe,
however, that certain accounting policies are of more significance in our
financial statement preparation process than others. Also, certain amounts
included in or affecting our financial statements and related disclosures must
be estimated, requiring us to make certain assumptions with respect to values or
conditions which cannot be known with certainty at the time the financial
statements are prepared. These estimates and assumptions affect the amounts we
report for assets and liabilities, our revenues and expenses during the
reporting period, and our disclosure of contingent assets and liabilities at the
date of our financial statements.
In preparing our consolidated financial statements and related disclosures,
examples of certain areas that require more judgment relative to others include
our use of estimates in determining:
o the economic useful lives of our assets;
o the fair values used to determine possible asset impairment charges;
o reserves for environmental claims, legal fees, transportation rate
cases and other litigation liabilities;
o provisions for uncollectible accounts receivables;
o volumetric receivable (assets) and payable (liabilities) valuations;
o exposures under contractual indemnifications; and
o various other recorded or disclosed amounts.
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
143
from revisions to these estimates are recorded in the period in which the facts
that give rise to the revision become known.
Cash Equivalents
We define cash equivalents as all highly liquid short-term investments with
original maturities of three months or less.
Accounts Receivables
Our policy for determining an appropriate allowance for doubtful accounts
varies according to the type of business being conducted and the customers being
served. An allowance for doubtful accounts is charged to expense monthly,
generally using a percentage of revenue or receivables, based on a historical
analysis of uncollected amounts, adjusted as necessary for changed circumstances
and customer-specific information. When specific receivables are determined to
be uncollectible, the reserve and receivable are relieved. The following tables
show the balance in the allowance for doubtful accounts and activity for the
years ended December 31, 2006, 2005 and 2004.
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, 2006..... $6,542 $ 259 $ 285 $ (267) $6,819
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
- ----------
(1) Amount for 2006 represents the allowance recognized when we acquired Devco
USA L.L.C. ($155) and Transload Services, LLC ($130). 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 $10.8 million as of December 31, 2006 and $8.2
million as of December 31, 2005.
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. The value of natural gas in our
underground storage facilities under the weighted-average cost method was $8.4
million as of December 31, 2006, and $7.1 million as of December 31, 2005. We
also maintain gas in our underground storage facilities on behalf of certain
third parties. We receive a fee from our storage service customers but do not
reflect the value of their gas stored in our facilities in our accompanying
consolidated balance sheets.
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
144
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.
Depreciation estimates are based on various factors, including age (in the case
of acquired assets), manufacturing specifications, technological advances and
historical data concerning useful lives of similar assets. Uncertainties that
impact these estimates included changes in laws and regulations relating to
restoration and abandonment requirements, economic conditions, and supply and
demand in the area. When assets are put into service, we make estimates with
respect to useful lives (and salvage values where appropriate) that we believe
are reasonable. However, subsequent events could cause us to change our
estimates, thus impacting the future calculation of depreciation and
amortization expense. Historically, adjustments to useful lives have not had a
material impact on our aggregate depreciation levels from year to year.
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 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 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. 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.
145
As discussed in "--Inventories" above, we maintain natural gas in
underground storage as part of our inventory. This component of our inventory
represents the portion of gas stored in an underground storage facility
generally known as "working gas," and represents an estimate of the portion of
gas in these facilities available for routine injection and withdrawal to meet
demand. In addition to this working gas, underground gas storage reservoirs
contain injected gas which is not routinely cycled but, instead, serves the
function of maintaining the necessary pressure to allow efficient operation of
the facility. This gas, generally known as "cushion gas," is divided into the
categories of "recoverable cushion gas" and "unrecoverable cushion gas," based
on an engineering analysis of whether the gas can be economically removed from
the storage facility at any point during its life. The portion of the cushion
gas that is determined to be unrecoverable is considered to be a permanent part
of the facility itself (thus, part of our "Property, Plant and Equipment, net"
balance in our accompanying consolidated balance sheets), and this unrecoverable
portion is depreciated over the facility's estimated useful life. The portion of
the cushion gas that is determined to be recoverable is also considered a
component of the facility but is not depreciated because it is expected to
ultimately be recovered and sold.
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 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, 2007.
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 $829.0 million as of December 31, 2006 and $799.0
million as of December 31, 2005. 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 both December 31, 2006 and December 31, 2005. 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.
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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 $177.1 million and $181.7 million as of
December 31, 2006 and 2005, 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, 2006, this excess
investment cost is being amortized over a weighted average life of approximately
31.7 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, 2006, 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 as services are rendered or goods are delivered and,
if applicable, title has passed. We generally sell natural gas under long-term
agreements, with periodic price adjustments. In some cases, we sell natural gas
under short-term agreements at prevailing market prices. In all cases, we
recognize natural gas sales revenues when the natural gas is sold to a purchaser
at a fixed or determinable price, delivery has occurred and title has
transferred, and collectibility of the revenue is reasonably assured. The
natural gas we market is primarily purchased gas produced by third parties, and
we market this gas to power generators, local distribution companies, industrial
end-users and national marketing companies. We recognize gas gathering and
marketing revenues in the month of delivery based on customer nominations and
generally, our natural gas marketing revenues are recorded gross, not net of
cost of gas sold.
We provide various types of natural gas storage and transportation services
to customers. The natural gas remains the property of these customers at all
times. In many cases (generally described as "firm service"), the customer pays
a two-part rate that includes (i) a fixed fee reserving the right to transport
or store natural gas in our facilities and (ii) a per-unit rate for volumes
actually transported or injected into/withdrawn from storage. The fixed-fee
component of the overall rate is recognized as revenue in the period the service
is provided. The per-unit charge is recognized as revenue when the volumes are
delivered to the customers' agreed upon delivery point, or when the volumes are
injected into/withdrawn from our storage facilities. In other cases (generally
described as "interruptible service"), there is no fixed fee associated with the
services because the customer accepts the possibility that service may be
interrupted at our discretion in order to serve customers who have purchased
firm service. In the case of interruptible service, revenue is recognized in the
same manner utilized for the per-unit rate for volumes actually transported
under firm service agreements.
We provide crude oil transportation services and refined petroleum products
transportation and storage services to customers. Revenues are recorded when
products are delivered and services have been provided, and adjusted according
to terms prescribed by the toll settlements with shippers and approved by
regulatory authorities.
We recognize bulk terminal transfer service revenues based on volumes
loaded and unloaded. We recognize liquids terminal tank rental revenue ratably
over the contract period. We recognize liquids terminal throughput revenue based
on volumes received and volumes delivered. 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.
147
Revenues from the sale of oil, natural gas liquids and natural gas
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. 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 2006, 2005 and 2004 was $18.4
million, $9.8 million and $6.4 million, respectively.
Unit-Based Compensation
We account for common unit options granted under our common unit option
plan according to the provisions of SFAS No. 123R (revised 2004), "Share-Based
Payment," which became effective for us January 1, 2006. 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. According to
the provisions of SFAS No. 123R, 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. Companies will recognize
compensation cost for share-based payment awards as they vest, including the
related tax effects, and compensation cost for awards that vest would not be
reversed if the awards expire without being exercised.
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.
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 routinely conduct reviews of potential environmental issues and claims
that could impact our assets or operations, and we utilize both internal staff
and external experts to assist us in identifying environmental issues and in
estimating the costs and timing of remediation efforts. Often, as the
remediation evaluation and effort progresses, additional information is
obtained, requiring revisions to estimated costs. These revisions are reflected
in our income in the period in which they are reasonably determinable.
In 2006, we made quarterly adjustments to our environmental liabilities to
reflect changes in previous estimates. In making these liability estimations, we
considered the material effect of environmental compliance, pending legal
actions against us, and potential third-party liability claims. As a result, in
2006, we recorded a combined $35.4 million increase in environmental expense
associated with environmental liability adjustments. We recorded a $32.4 million
increase in expense within "Operations and maintenance," a $4.9 million increase
in expense within "Earnings from equity investments," and a $1.9 million
reduction in expense within "Income Taxes" in our accompanying consolidated
statement of income for 2006. The $35.4 million increase in environmental
expense resulted in a $31.8 million increase in expense to our Products
Pipelines business segment, a $2.2 million increase in expense to our Terminals
business segment, a $1.6 million increase in expense to our Natural Gas
Pipelines business segment, and a $0.2 million decrease in expense to our CO2
business segment. The environmental expense adjustment (including our share of
environmental expense associated with liability adjustments recognized by
148
Plantation Pipe Line Company) included a $4.1 million increase in our estimated
environmental receivables and reimbursables, a $3.5 million decrease in our
equity investments, a $34.5 million increase in our overall accrued
environmental and related claim liabilities, and a $1.5 million increase in our
accrued expense liabilities.
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 $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.
Pensions and Other Post-retirement Benefits
Effective December 31, 2006, we adopted SFAS No. 158, "Employers'
Accounting for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statement Nos. 87, 88, 106 and 132(R)." This Statement
requires us to fully recognize the overfunded or underfunded status of our SFPP,
L.P. post-retirement benefit plan as an asset or liability in our statement of
financial position. Accordingly, as of December 31, 2006, we recognized a
liability of $5.5 million for the unfunded portion of this post-retirement
benefit plan. We included $0.2 million of this amount within "Accrued other
current liabilities" and the remaining $5.3 million within "Other long-term
liabilities and deferred credits" on our accompanying consolidated balance
sheet. We consider our overall pension and post-retirement benefit liability
exposure to be minimal in relation to the value of our total consolidated assets
and net income. For more information on our pension and post-retirement benefit
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, 2006, minority interest consisted of the following:
149
o the 1.0101% general partner interest in each of our five operating
partnerships;
o the 0.5% special limited partner interest in SFPP, L.P.;
o the 50% interest in Globalplex Partners, a Louisiana joint venture
owned 50% and controlled by Kinder Morgan Bulk Terminals, Inc.;
o the 33 1/3% interest in International Marine Terminals Partnership, a
Louisiana partnership owned 66 2/3% and controlled by Kinder Morgan
Operating L.P. "C";
o the approximate 31% interest in the Pecos Carbon Dioxide Company, a
Texas general partnership owned approximately 69% and controlled by
Kinder Morgan CO2 Company, L.P. and its consolidated subsidiaries;
o the 1% interest in River Terminals Properties, L.P., a Tennessee
partnership owned 99% and controlled by Kinder Morgan River Terminals
LLC; and
o the 25% interest in Guilford County Terminal Company, LLC, a limited
liability company owned 75% and controlled by Kinder Morgan Southeast
Terminals 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
On April 26, 2006, we incorporated Kinder Morgan Canada Terminals ULC, an
Alberta, Canada unlimited liability corporation. Kinder Morgan Canada Terminals
ULC, located in Edmonton, Alberta, is currently constructing a crude oil tank
farm which will have a storage capacity of approximately 2.2 million barrels and
serve as a blending and storage hub for Canadian crude oil. We expect Kinder
Morgan Canada Terminals ULC to begin operations sometime in the third quarter of
2007.
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 three 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 consolidated balance
150
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, 2006, 2005 and
2004, the difference between our net income and our comprehensive income
resulted from unrealized gains or losses on derivatives utilized for energy
commodity price risk hedging purposes and from foreign currency translation
adjustments. For more information on our risk management activities, see Note
14.
Cumulative revenues, expenses, gains and losses that under generally
accepted accounting principals are included within comprehensive income but
excluded from earnings are reported as accumulated other comprehensive
income/(loss) within Partners' Capital in our consolidated balance sheets. In
addition, pursuant to our initial application of SFAS No. 158 "Employers'
Accounting for Defined Benefit Pension and Other Postretirement Plans" on
December 31, 2006, we also recognized prior service credits and actuarial gains
that had not yet been included in net periodic benefit cost as of the end of the
fiscal year as a component of our ending balance of accumulated other
comprehensive income. The following table summarizes changes in the amount of
our "Accumulated other comprehensive loss" in our accompanying consolidated
balance sheets for each of the two years ended December 31, 2005 and 2006 (in
thousands):
Net unrealized Foreign Other Total
gains/(losses) currency Post-retirement Accumulated other
on cash flow translation benefit comprehensive
hedge derivatives adjustments acctg. changes income/(loss)
----------------- ----------- --------------- -----------------
December 31, 2004.......$ (457,718) $ 375 $ -- $ (457,343)
Change for period....... (621,632) (699) -- (622,331)
----------------- ----------- --------------- -----------------
December 31, 2005....... (1,079,350) (324) -- (1,079,674)
Change for period....... 240,612 722 (3,214) 238,120
----------------- ----------- --------------- -----------------
December 31, 2006.......$ (838,738) $ 398 $ (3,214) $ (841,554)
================= =========== =============== =================
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 commodity derivative contracts for the purpose of
mitigating our risk resulting from fluctuations in the market price of natural
gas, natural gas liquids and crude oil. In addition, we enter into interest rate
swap agreements for the purpose of hedging the interest rate risk associated
with our debt obligations.
Our derivative contracts 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 contract
(including certain derivative contracts embedded in other contracts) be
151
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 contract's fair
value be recognized currently in earnings unless specific hedge accounting
criteria are met. If a derivative contract meets those criteria, SFAS No. 133
allows a derivative contract'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 contract as a hedge and document and assess the
effectiveness of derivative contracts 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 derivative contracts that hedge our commodity price risks
involve our normal business activities, which include the sale of natural gas,
natural gas liquids and crude oil, and these derivative contracts have been
designated as cash flow hedges as defined by SFAS No. 133. SFAS No. 133
designates derivative contracts that hedge exposure to variable cash flows of
forecasted transactions as cash flow hedges and the effective portion of the
derivative contract'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.
Accounting for Regulatory Activities
Our regulated utility operations are accounted for in accordance with the
provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation," which prescribes the circumstances in which the application of
generally accepted accounting principles is affected by the economic effects of
regulation. Regulatory assets and liabilities represent probable future revenues
or expenses associated with certain charges and credits that will be recovered
from or refunded to customers through the ratemaking process.
The following regulatory assets and liabilities are reflected within
"Deferred charges and other assets" and "Other long-term liabilities and
deferred credits," respectively, in our accompanying consolidated balance sheets
as of December 31, 2006 and December 31, 2005 (in thousands):
As of December 31,
2006 2005
----------- ---------
Regulated Assets:
Employee benefit costs........... $ 373 $ 328
Fuel Tracker..................... 1,594 --
Deferred regulatory expenses..... 3,238 3,363
----------- ---------
Total regulatory assets.......... 5,205 3,691
Regulated Liabilities:
Deferred income taxes............ 925 1,883
Fuel Tracker..................... -- (1,275)
----------- ---------
Total regulatory liabilities..... 925 608
Net regulatory assets............ $ 4,280 $ 3,083
=========== =========
As of December 31, 2006, all of our regulatory assets and regulatory
liabilities were being recovered from or refunded to customers through rates
over periods ranging from one to five years.
3. Aquisitions, Joint Ventures and Divestitures
During 2006, 2005 and 2004, 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 any liabilities assumed) may be adjusted
to reflect the final determined amounts during a short period of time following
the acquisition. Although the time that is required to identify and measure the
fair value of the assets acquired and the liabilities assumed in a business
combination will vary with circumstances, generally our allocation period ends
when we no longer are waiting for information that is known to be available or
obtainable. The results of operations from these acquisitions are included in
our consolidated financial statements from the acquisition date.
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Acquisitions and Joint Ventures
Allocation of Purchase Price
---------------------------------------------------------------
(in millions)
---------------------------------------------------------------
Property Deferred
Purchase Current Plant & Charges Minority
Ref. Date Acquisition Price Assets Equipment & Other Goodwill Interest
--- ------ ------------------------------------------ --------- ------- --------- -------- -------- --------
(1) 3/04 ExxonMobil Products Terminals............. $ 50.9 $ - $ 50.9 $ - $ - $ -
(2) 8/04 Kinder Morgan Wink Pipeline, L.P.......... 100.3 0.1 77.4 22.8 - -
(3) 10/04 Interest in Cochin Pipeline System........ 10.9 - 10.9 - - -
(4) 10/04 Kinder Morgan River Terminals LLC......... 87.9 9.9 43.2 14.6 20.2 -
(5) 11/04 Charter Products Terminals................ 75.2 0.5 70.9 4.9 - (1.1)
(6) 11/04 TransColorado Gas Transmission Company.... 284.5 2.0 280.6 1.9 - -
(7) 12/04 Kinder Morgan Fairless Hills Terminal..... 7.5 0.3 5.9 1.3 - -
(8) 1/05 Claytonville Oil Field Unit .............. 6.5 - 6.5 - - -
(9) 4/05 Texas Petcoke Terminal Region ............ 247.2 - 72.5 161.4 13.3 -
(10) 7/05 Terminal Assets .......................... 36.2 0.5 35.7 - - -
(11) 7/05 General Stevedores, L.P. ................. 10.4 0.6 5.2 0.2 4.4 -
(12) 8/05 North Dayton Natural Gas Storage Facility 109.4 - 71.7 11.7 26.0 -
(13) 8-9/05 Terminal Assets .......................... 4.3 0.4 3.9 - - -
(14) 11/05 Allied Terminal Assets ................... 13.3 0.2 12.6 0.5 - -
(15) 2/06 Entrega Gas Pipeline LLC.................. 244.6 - 244.6 - - -
(16) 4/06 Oil and Gas Properties.................... 63.9 0.2 63.7 - - -
(17) 4/06 Terminal Assets .......................... 61.9 0.5 43.6 - 17.8 -
(18) 11/06 Transload Services, LLC................... 16.8 1.6 6.6 - 8.6 -
(19) 12/06 Devco USA L.L.C........................... 7.3 0.8 - 6.5 - -
(20) 12/06 Roanoke, Virginia Products Terminal....... $ 6.4 $ - $ 6.4 $ - $ - $ -
(1) ExxonMobil Products Terminals
Effective March 9, 2004, we acquired seven refined petroleum products
terminals in the southeastern United States from ExxonMobil 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 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.
(2) 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 130,000 barrels of crude oil per day (with the use of a drag reducing agent).
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
120,000 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.
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(3) 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.
(4) 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 $87.9 million, consisting of $31.8 million in cash and $56.1
million of assumed liabilities, including debt of $33.7 million. 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 evaluation of acquired income tax
assets and liabilities.
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.
The $20.2 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 $14.6 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.
(5) 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 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
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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.
(6) 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.
(7) 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.
(8) 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 we include the acquired
operations as part of our CO2 business segment. Currently, we are performing
technical evaluations to confirm the carbon dioxide enhanced oil recovery
potential and generate definitive plans to develop this potential, if proven to
be economic.
(9) 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
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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.
(10) 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.
(11) 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 $10.4
million, consisting of $2.0 million in cash, $3.4 million in common units, and
$5.0 million in assumed liabilities, including debt of $3.0 million. In August
2005, we paid the $3.0 million
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outstanding debt balance, and in 2006, we made our final purchase price
adjustments and the final allocation of our purchase price to assets acquired
and liabilities assumed. The adjustments included minor revisions to acquired
working capital items, and, pursuant to an appraisal of acquired fixed asset and
land values, adjustments to property, plant and equipment, goodwill, and
deferred tax liabilities.
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. The $4.4
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.
(12) 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 was based on an appraisal of fair market values, which was completed in
the fourth quarter of 2005. 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.
(13) 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.
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(14) 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 acquired assets are counted as an
external addition to our Shipyard River terminal and are included as part of our
Terminals business segment.
(15) Entrega Gas Pipeline LLC
Effective February 23, 2006, Rockies Express Pipeline LLC acquired Entrega
Gas Pipeline LLC from EnCana Corporation for $244.6 million in cash. West2East
Pipeline LLC is a limited liability company and is the sole owner of Rockies
Express Pipeline LLC. We contributed 66 2/3% of the consideration for this
purchase, which corresponded to our percentage ownership of West2East Pipeline
LLC at that time. At the time of acquisition, Sempra Energy held the remaining
33 1/3% ownership interest and contributed this same proportional amount of the
total consideration.
On the acquisition date, Entrega Gas Pipeline LLC owned the Entrega
Pipeline, an interstate natural gas pipeline that will, when fully constructed,
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, an
interstate natural gas pipeline that is currently being developed by Rockies
Express Pipeline LLC. The acquired operations are included as part of our
Natural Gas Pipelines business segment.
In the first quarter of 2006, EnCana Corporation completed construction of
the pipeline segment that extends from the Meeker Hub to the Wamsutter Hub, and
interim service began on that portion of the pipeline on February 24, 2006.
Under the terms of the purchase and sale agreement, Rockies Express Pipeline LLC
will construct the segment that extends from the Wamsutter Hub to the Cheyenne
Hub. Construction on this pipeline segment began in the second quarter of 2006,
and both pipeline segments were placed into service on February 14, 2007.
In April 2006, Rockies Express Pipeline LLC merged with and into Entrega
Gas Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline
LLC. Going forward, the entire pipeline system (including the lines currently
being developed) will be known as the Rockies Express Pipeline. The combined
1,663-mile pipeline system will be one of the largest natural gas pipelines ever
constructed in North America. The approximately $4.4 billion project will have
the capability to transport 1.8 billion cubic feet per day of natural gas, and
binding firm commitments have been secured for virtually all of the pipeline
capacity.
On June 30, 2006, ConocoPhillips exercised its option to acquire a 25%
ownership interest in West2East Pipeline LLC (and its subsidiary Rockies Express
Pipeline LLC). On that date, a 24% ownership interest was transferred to
ConocoPhillips, and an additional 1% interest will be transferred once
construction of the entire project is completed. Through our subsidiary Kinder
Morgan W2E Pipeline LLC, we will continue to operate the project but our
ownership interest decreased to 51% of the equity in the project (down from 66
2/3%). Sempra's ownership interest in West2East Pipeline LLC decreased to 25%
(down from 33 1/3%). When construction of the entire project is completed, our
ownership interest will be reduced to 50% at which time the capital accounts of
West2East Pipeline LLC will be trued up to reflect our 50% economics in the
project. We do not anticipate any additional changes in the ownership structure
of the Rockies Express Pipeline project.
West2East Pipeline LLC qualifies as a variable interest entity as defined
by Financial Accounting Standards Board Interpretation No. 46 (Revised December
2003) (FIN 46R), "Consolidation of Variable Interest Entities-An Interpretation
of ARB No. 51," due to the fact that the total equity at risk is not sufficient
to permit the entity to finance its activities without additional subordinated
financial support provided by any parties, including equity holders.
Furthermore, following ConocoPhillips' acquisition of its ownership interest in
West2East Pipeline LLC
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on June 30, 2006, we receive 50% of the economics of the Rockies Express project
on an ongoing basis, and thus, effective June 30, 2006, we were no longer
considered the primary beneficiary of this entity as defined by FIN 46R.
Accordingly, on that date, we made the change in accounting for our investment
in West2East Pipeline LLC from full consolidation to the equity method following
the decrease in our ownership percentage.
Under the equity method, we record the costs of our investment within the
"Investments" line on our consolidated balance sheet and as changes in the net
assets of West2East Pipeline LLC occur (for example, earnings and dividends), we
recognize our proportional share of that change in the "Investment" account. We
also record our proportional share of any accumulated other comprehensive income
or loss within the "Accumulated other comprehensive loss" line on our
consolidated balance sheet.
Summary financial information as of December 31, 2006, for West2East
Pipeline LLC, which is accounted for under the equity method, is as follows (in
thousands; amounts represent 100% of investee information):
December 31,
Balance Sheet 2006
--------------------- ----------------
Current assets............................ $ 3,456
Non-current assets........................ 847,000
Current liabilities....................... 68,486
Non-current liabilities................... 790,050
Accumulated other comprehensive income.... $ (8,080)
In addition, we have guaranteed our proportionate share of West2East
Pipeline LLC's debt borrowings under a $2 billion credit facility entered into
by Rockies Express Pipeline LLC. For more information on our contingent debt,
see Note 7.
(16) April 2006 Oil and Gas Properties
On April 5, 2006, Kinder Morgan Production Company L.P. purchased various
oil and gas properties from Journey Acquisition - I, L.P. and Journey 2000, L.P.
for an aggregate consideration of approximately $63.9 million, consisting of
$60.3 million in cash and $3.6 million in assumed liabilities. The acquisition
was effective March 1, 2006. However, we divested certain acquired properties
that are not considered candidates for carbon dioxide enhanced oil recovery,
thus reducing our total investment. We received proceeds of approximately $27.1
million from the sale of these properties.
The properties are primarily located in the Permian Basin area of West
Texas and New Mexico, produce approximately 430 barrels of oil equivalent per
day, and include some fields with potential for enhanced oil recovery
development near our current carbon dioxide operations. The acquired operations
are included as part of our CO2 business segment. Currently, we are performing
technical evaluations to confirm the carbon dioxide enhanced oil recovery
potential and generate definitive plans to develop this potential, if proven to
be economic.
(17) April 2006 Terminal Assets
In April 2006, we acquired terminal assets and operations from A&L
Trucking, L.P. and U.S. Development Group in three separate transactions for an
aggregate consideration of approximately $61.9 million, consisting of $61.6
million in cash and $0.3 million in assumed liabilities.
The first transaction included the acquisition of equipment and
infrastructure on the Houston Ship Channel that loads and stores steel products.
The acquired assets complement our nearby bulk terminal facility purchased from
General Stevedores, L.P. in July 2005. The second acquisition included the
purchase of a rail terminal at the Port of Houston that handles both bulk and
liquids products. The rail terminal complements our existing Texas petroleum
coke terminal operations and maximizes the value of our existing deepwater
terminal by providing customers with both rail and vessel transportation options
for bulk products. Thirdly, we acquired the entire membership interest of Lomita
Rail Terminal LLC, a limited liability company that owns a high-volume rail
ethanol terminal in Carson, California. The terminal serves approximately 80% of
the Southern California demand for reformulated fuel blend ethanol with
expandable offloading/distribution capacity, and the acquisition expanded our
existing rail transloading operations. All of the acquired assets are included
in our Terminals business segment. The $17.8 million of
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goodwill was assigned to our Terminals business segment and the entire amount is
expected to be deductible for tax purposes.
(18) Transload Services, LLC
Effective November 20, 2006, we acquired all of the membership interests of
Transload Services, LLC from Lanigan Holdings, LLC for an aggregate
consideration of approximately $16.8 million, consisting of $15.4 million in
cash, an obligation to pay $0.9 million currently held as security for the
collection of certain accounts receivable and for the perfection of certain real
property title rights, and $0.5 million of assumed liabilities. Transload
Services, LLC is a leading provider of innovative, high quality material
handling and steel processing services, operating 14 steel-related terminal
facilities located in the Chicago metropolitan area and various cities in the
United States. Its operations include transloading services, steel fabricating
and processing, warehousing and distribution, and project staging. Specializing
in steel processing and handling, Transload Services can inventory product,
schedule shipments and provide customers cost-effective modes of transportation.
The combined operations include over 92 acres of outside storage and 445,000
square feet of covered storage that offers customers environmentally controlled
warehouses with indoor rail and truck loading facilities for handling
temperature and humidity sensitive products. The acquired assets are included in
our Terminals business segment, and the acquisition further expanded and
diversified our existing terminals' materials services (rail transloading)
operations.
The $8.6 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 it establishes a business presence in several key markets,
taking advantage of the non-residential and highway construction demand for
steel that contributed to the fair value of acquired identifiable net assets and
liabilities exceeding our acquisition price--in the aggregate, these factors
represented goodwill. 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 2007.
(19) Devco USA L.L.C.
Effective December 1, 2006, we acquired all of the membership interests in
Devco USA L.L.C., an Oklahoma limited liability company, for an aggregate
consideration of approximately $7.3 million, consisting of $4.8 million in cash,
$1.6 million in common units, and $0.9 million of assumed liabilities. The
primary asset acquired was a technology based identifiable intangible asset, a
proprietary process that transforms molten sulfur into premium solid formed
pellets that are environmentally friendly, easy to handle and store, and safe to
transport. The process was developed internally by Devco's engineers and
employees. Devco, a Tulsa, Oklahoma based company, has more than 20 years of
sulfur handling expertise and we believe the acquisition and subsequent
application of this acquired technology complements our existing dry-bulk
terminal operations. We allocated $6.5 million of our total purchase price to
the value of this intangible asset, and we have included the acquisition as part
of our Terminals business segment.
(20) Roanoke, Virginia Products Terminal
Effective December 15, 2006, we acquired a refined petroleum products
terminal located in Roanoke, Virginia from Motiva Enterprises, LLC for
approximately $6.4 million in cash. The terminal has storage capacity of
approximately 180,000 barrels per day for refined petroleum products like
gasoline and diesel fuel. The terminal is served exclusively by the Plantation
Pipeline and Motiva has entered into a long-term contract to use the terminal.
The acquisition complemented the other refined products terminals we own in the
southeast region of the United States, and the acquired terminal is included as
part our Products Pipelines business segment.
Pro Forma Information
The following summarized unaudited pro forma consolidated income statement
information for the years ended December 31, 2006 and 2005, assumes that all of
the acquisitions we have made and joint ventures we have entered into since
January 1, 2005, including the ones listed above, had occurred as of January 1,
2005. We have prepared these unaudited pro forma financial results for
comparative purposes only. These unaudited pro forma financial
160
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, 2005 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,
----------------------------
2006 2005
------------ ------------
(Unaudited)
Revenues............................................. $ 8,979,852 $ 9,882,437
Operating Income..................................... 1,262,480 1,040,753
Net Income........................................... $ 974,501 $ 823,029
Basic Limited Partners' Net Income per unit.......... $ 2.05 $ 1.63
Diluted Limited Partners' Net Income per unit........ $ 2.05 $ 1.62
Acquisitions Subsequent to December 31, 2006
On January 15, 2007, we announced that we had entered into an agreement
with affiliates of BP to increase our ownership interest in the Cochin pipeline
system to 100%. We purchased our original undivided 32.5% ownership interest in
the Cochin pipeline system in November 2000, and currently, we own a 49.8%
ownership interest. BP Canada Energy Company owns the remaining 50.2% ownership
interest and is the operator of the pipeline. The agreement is subject to due
diligence, regulatory clearance and other standard closing conditions. The
transaction is expected to close in the first quarter of 2007, and upon closing,
we will become the operator of the pipeline.
Divestitures
Effective April 1, 2006, we sold our Douglas natural gas gathering system
and our Painter Unit fractionation facility to Momentum Energy Group, LLC for
approximately $42.5 million in cash. Our investment in net assets, including all
transaction related accruals, was approximately $24.5 million, most of which
represented property, plant and equipment, and we recognized approximately $18.0
million of gain on the sale of these net assets. We used the proceeds from these
asset sales to reduce the outstanding balance on our commercial paper
borrowings.
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 approximately 650 active receipt points. Gathered
volumes are processed at our Douglas plant (which we retained), located in
Douglas, Wyoming. As part of the transaction, we executed a long-term processing
agreement with Momentum Energy Group, LLC which dedicates volumes from the
Douglas gathering system to our Douglas processing plant. The Painter Unit,
located near Evanston, Wyoming, consists of a natural gas processing plant and
fractionator, a nitrogen rejection unit, a natural gas liquids terminal, and
interconnecting pipelines with truck and rail loading facilities. Prior to the
sale, we leased the plant to BP, which operates the fractionator and the
associated Millis terminal and storage facilities for its own account.
Additionally, with regard to the natural gas operating activities of our
Douglas gathering system, we utilized certain derivative financial contracts to
offset our exposure to fluctuating expected future cash flows caused by periodic
changes in the price of natural gas and natural gas liquids. According to the
provisions of current accounting principles, changes in the fair value of
derivative contracts that are designated and effective as cash flow hedges of
forecasted transactions are reported in other comprehensive income (not net
income) and recognized directly in equity (included within accumulated other
comprehensive income/(loss)). Amounts deferred in this way are reclassified to
net income in the same period in which the forecast transactions are recognized
in net income. However, if a hedged transaction is no longer expected to occur
by the end of the originally specified time period, because, for example, the
asset generating the hedged transaction is disposed of prior to the occurrence
of the transaction, then the net cumulative gain or loss recognized in equity
should be transferred to net income in the current period.
Accordingly, upon the sale of our Douglas gathering system, we reclassified
a net loss of $2.9 million from "Accumulated other comprehensive loss" into net
income on those derivative contracts that effectively hedged uncertain future
cash flows associated with forecasted Douglas gathering transactions. We
included the net amount of the gain, $15.1 million, within the caption "Other
expense (income)" in our accompanying consolidated statement
161
of income for the year ended December 31, 2006. For more information on our
accounting for derivative contracts, see Note 14.
4. Asset Retirement Obligations
We account for our legal obligations associated with the retirement of
long-lived assets pursuant to Statement of Financial Accounting Standards 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.
SFAS No. 143 requires companies to record a liability relating to the
retirement and removal of assets used in their businesses. 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.
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, 2006 and 2005, we have recognized
asset retirement obligations relating to these requirements at existing sites
within our CO2 segment in the aggregate amounts of $47.2 million and $41.5
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, 2006 and
2005, we have recognized asset retirement obligations relating to the businesses
within our Natural Gas Pipelines segment in the aggregate amounts of $3.1
million and $1.7 million, respectively.
We have included $1.4 million and $0.8 million, respectively, of our total
asset retirement obligations as of December 31, 2006 and December 31, 2005
within "Accrued other current liabilities" in our accompanying consolidated
balance sheets. The remaining $48.9 million obligation as of December 31, 2006
and $42.4 million obligation as of December 31, 2005 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 the years ended December
31, 2006 and 2005 is as follows (in thousands):
Year Ended December 31,
------------------------------
2006 2005
--------- ----------
Balance at beginning of period............... $ 43,227 $ 38,274
Liabilities incurred....................... 6,763 5,926
Liabilities settled........................ (2,233) (1,778)
Accretion expense.......................... 2,518 1,327
Revisions in estimated cash flows.......... -- (522)
--------- ----------
Balance at end of period..................... $ 50,275 $ 43,227
========= ==========
5. Income Taxes
Components of the income tax provision applicable to continuing operations
for federal, foreign and state taxes are as follows (in thousands):
162
Year Ended December 31,
------------------------------------
2006 2005 2004
-------- -------- --------
Taxes currently payable:
Federal................................. $ 12,822 $ 9,604 $ 7,515
State................................... 2,339 2,112 1,497
Foreign................................. 458 322 70
-------- -------- --------
Total................................... 15,619 12,038 9,082
Taxes deferred:
Federa.................................. 1,568 8,159 5,694
State................................... 260 769 883
Foreign................................. 1,601 3,495 4,067
-------- -------- --------
Total................................... 3,429 12,423 10,644
-------- -------- --------
Total tax provision....................... $ 19,048 $ 24,461 $ 19,726
======== ======== ========
Effective tax rate........................ 1.9% 2.9% 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,
-----------------------------
2006 2005 2004
------- ------- -------
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....................... 1.0% 1.1% 0.5%
Income tax expense attributable to corporate equity earnings....... 0.5% 1.1% 1.2%
Income tax expense attributable to foreign corporate earnings...... 0.2% 0.5% 0.5%
State taxes........................................................ 0.2% 0.2% 0.1%
------- ------- -------
Effective tax rate.................................................. 1.9% 2.9% 2.3%
======= ======= =======
Our deferred tax assets and liabilities as of December 31, 2006 and 2005
result from the following (in thousands):
December 31,
----------------------
2006 2005
-------- --------
Deferred tax assets:
Book accruals............................................. $ 1,431 $ 1,112
Net Operating Loss/Alternative minimum tax credits........ 2,982 1,548
Other..................................................... 1,310 1,445
-------- --------
Total deferred tax assets................................... 5,723 4,105
Deferred tax liabilities:
Property, plant and equipment............................. 69,964 63,562
Other..................................................... 11,300 10,886
-------- --------
Total deferred tax liabilities.............................. 81,264 74,448
-------- --------
Net deferred tax liabilities................................ $ 75,541 $ 70,343
======== ========
We had available, at December 31, 2006, approximately $0.112 million of
foreign minimum tax credit carryforwards, which are available through 2015, and
$2.9 million of foreign and state net operating loss carryforwards, which will
expire between the years 2008 and 2025. 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
Classes and Depreciation
As of December 31, 2006 and 2005, our property, plant and equipment
consisted of the following (in thousands):
163
December 31,
----------------------------
2006 2005
----------- -----------
Natural gas, liquids and carbon dioxide pipelines..................................... $ 4,309,501 $ 4,005,612
Natural gas, liquids, carbon dioxide pipeline, and terminals station equipment........ 4,508,757 4,146,328
Coal and bulk tonnage transfer, storage and services.................................. 5,946 131,265
Natural gas, liquids (including linefill), and transmix processing.................... 172,720 187,061
Other................................................................................. 844,897 625,615
Accumulated depreciation and depletion................................................ (1,604,614) (1,242,304)
----------- -----------
8,237,207 7,853,577
Land and land right-of-way............................................................ 487,123 440,497
Construction work in process.......................................................... 721,141 570,510
----------- -----------
Property, Plant and Equipment, net.................................................... $ 9,445,471 $ 8,864,584
=========== ===========
Depreciation and depletion expense charged against property, plant and
equipment consists of the following (in thousands):
2006 2005 2004
-------- -------- --------
Depreciation and depletion expense.. $397,525 $339,580 $285,351
Casualty Gain
On August 29, 2005, Hurricane Katrina made landfall in the United States'
Gulf Coast causing widespread damage to residential and commercial real and
personal property. In addition, on September 23, 2005, Hurricane Rita struck the
Texas-Louisiana Gulf Coast causing additional damage to insured interests. The
primary assets we operate that were impacted by these storms included several
bulk and liquids terminal facilities located in the states of Louisiana and
Mississippi, and certain of our Gulf Coast liquids terminals facilities, which
are located along the Houston Ship Channel. Specifically, with regard to
physical property damage, our International Marine Terminals facility suffered
extensive property damage and a general loss of business due to the effects of
Hurricane Katrina. IMT is a Louisiana partnership owned 66 2/3% by us. It
operates a multi-purpose bulk commodity transfer terminal facility located in
Port Sulphur, Louisiana.
All of our terminal facilities affected by these storms are currently open,
and all of the facilities are covered by property casualty insurance. Some of
the facilities are also covered by business interruption insurance. To account
for our property casualty damage, we recognized repair expense related to
hurricane damage as incurred. We also transferred off our books the net book
value of the assets that were damaged or destroyed, and we offset the book value
of all damaged and destroyed assets with indemnity proceeds received (and
receivable in the future) according to the provisions of the insurance policies
in force. We also incurred capital expenditures related to the repair and
replacement of damaged assets.
When an insured asset is damaged or destroyed, the relevant accounts must
be adjusted to the date of the casualty, and settlement with the insurance
companies must be completed. The maximum amount recoverable from property damage
is the fair market value of the property at the date of loss (the replacement
value), or the amount stipulated in the insurance contract. Although net book
values are irrelevant in determining indemnifications from insurers, under
current accounting provisions, asset book values are used for accounting
purposes to measure the gain or loss resulting from casualty settlements. Also,
because indemnifications under insurance policies are based upon fair market
values, indemnifications often exceed the book value of the assets destroyed or
damaged, and any excess of insurance indemnifications over the book value of
damaged assets represents a book casualty gain.
In the fourth quarter of 2006, we reached settlements with our insurance
carriers on all of our property damage claims related to the 2005 hurricane
season, including IMT's claims. As a result of these settlements, we recognized
a property casualty gain of $15.2 million, excluding all hurricane repair and
clean-up expenses. This casualty gain represented the excess of indemnity
proceeds received or recoverable over the book value of damaged or destroyed
assets. We also collected, in 2006, property insurance indemnities of $13.1
million, and we disclosed these cash receipts separately as "Property casualty
indemnifications" within investing activities on our accompanying consolidated
statement of cash flows. In addition, as of December 31, 2006, we signed proofs
of loss totaling $8.0 million for expected future property damage proceeds, and
we received these indemnity proceeds in January 2007. With the settlement of
these claims, we released all remaining estimated property insurance receivables
and estimated property insurance-related damage claim amounts, as these
hurricane property damage claims are now
164
closed; however, we will recognize additional casualty gains of approximately
$2.0 million in the first quarter of 2007 (before minority interest
allocations), based upon our final determination of the book value of the fixed
assets destroyed or damaged, and upon expected future indemnities pursuant to
flood insurance coverage.
In addition to this casualty gain, 2006 income and expense items related to
hurricane activity included the following: (i) a $2.8 million increase in
operating and maintenance expenses from hurricane repair and clean-up
activities, (ii) a $1.1 million increase in income tax expense associated with
overall hurricane income and expense items, (iii) a $0.4 million decrease in
general and administrative expenses from the allocation of overhead expenses to
hurricane related capital projects, and (iv) a $3.1 million increase in minority
interest expense related to the allocation of IMT's earnings from hurricane
income and expense items to minority interest. Combined, the hurricane income
and expense items, including the casualty gain, resulted in a total increase in
net income of $8.6 million in 2006. For the year 2006, we spent $1,058.3 million
in total capital expenditures for our continuing operations, which included
approximately $12.2 million for hurricane repair and replacement costs
(including accruals, sustaining capital expenditures for hurricane repair and
replacement costs totaled $14.2 million).
7. Investments
Our significant equity investments as of December 31, 2006 consisted of:
o Plantation Pipe Line Company (51%);
o West2East Pipeline LLC (51%);
o Red Cedar Gathering Company (49%);
o Thunder Creek Gas Services, LLC (25%);
o Cortez Pipeline Company (50%); and
o Heartland Pipeline Company (50%).
We operate and own an approximate 51% ownership interest in Plantation Pipe
Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49%
interest. 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.
Similarly, as of December 31, 2006, we operate and own a 51% ownership
interest in West2East Pipeline LLC, a limited liability company that is the sole
owner of Rockies Express Pipeline LLC. ConocoPhillips owns a 24% ownership
interest in West2East Pipeline LLC and Sempra Energy holds the remaining 25%
interest. As discussed in Note 2, when construction of the entire Rockies
Express Pipeline project is completed, our ownership interest will be reduced to
50% at which time the capital accounts of West2East Pipeline LLC will be trued
up to reflect our 50% economics in the project. According to the provisions of
current accounting standards, due to the fact that we will receive 50% of the
economics of the Rockies Express project on an ongoing basis, we are not
considered the primary beneficiary of West2East Pipeline LLC and thus, effective
June 30, 2006, we deconsolidated this entity and began accounting for our
investment under the equity method of accounting. As of December 31, 2006, we
had no material investment in the net assets of West2East Pipeline LLC due to
the fact that the amount of its assets, primarily property, plant and equipment,
was largely offset by the amount of its liabilities, primarily debt.
In addition, prior to the contribution of our ownership interest in Coyote
Gas Treating, LLC to Red Cedar Gathering on September 1, 2006, discussed in Note
12, we were the managing partner and owned a 50% equity interest in Coyote Gas
Treating, LLC.
Our total investments consisted of the following (in thousands):
165
December 31,
-----------------------
2006 2005
-------- --------
Plantation Pipe Line Company................................. $199,555 $213,072
Red Cedar Gathering Company.................................. 160,647 139,852
Thunder Creek Gas Services, LLC.............................. 37,229 37,254
Cortez Pipeline Company...................................... 16,168 17,938
Heartland Pipeline Company................................... 5,733 5,205
All Others................................................... 6,268 5,992
-------- --------
Total Equity Investments..................................... $425,600 $419,313
======== ========
Our earnings from equity investments were as follows (in thousands):
Year Ended December 31,
2006 2005 2004
---------- ---------- ----------
Red Cedar Gathering Company......... $ 36,310 $ 32,000 $ 14,679
Cortez Pipeline Company............. 19,173 26,319 34,179
Plantation Pipe Line Company........ 12,775 24,926 25,879
Thunder Creek Gas Services, LLC..... 2,461 2,741 2,828
Heartland Pipeline Company.......... 2,177 2,122 1,369
Coyote Gas Treating, LLC............ 1,676 2,071 2,453
All Others.......................... 1,598 1,481 1,803
-------- -------- --------
Total............................... $ 76,170 $ 91,660 $ 83,190
======== ======== ========
Amortization of excess costs........ $ (5,664) $ (5,644) $ (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 2006 2005 2004
------------------------------- ---------- ---------- ---------
Revenues..................................................... $ 449,669 $ 448,382 $ 418,186
Costs and expenses........................................... 303,339 282,317 265,819
--------- --------- ---------
Earnings before extraordinary items and cumulative
effect of a change in accounting principle................. 146,330 166,065 152,367
========= ========= =========
Net income................................................... $ 146,330 $ 166,065 $152,367
========= ========= =========
December 31,
------------------------
Balance Sheet 2006 2005
--------------------- ---------- ---------
Current assets...................... $ 99,523 $ 107,975
Non-current assets.................. 1,514,214 680,330
Current liabilities................. 213,610 182,549
Non-current liabilities............. 1,127,240 345,227
Partners'/owners' equity............ $ 272,887 $ 260,529
Equity Investee Natural Gas Pipeline Expansion Filings
Rockies Express Pipeline-Currently Certificated Facilities
On August 9, 2005, the FERC approved the application of Rockies Express
Pipeline LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles
of pipeline facilities in two phases. For phase I (consisting of two segments),
Rockies Express was granted authorization to construct and operate approximately
136 miles of pipeline extending northward from Rio Blanco County, Colorado to
the Wamsutter Hub in Sweetwater County, Wyoming (segment 1), and then construct
approximately 191 miles of pipeline eastward to the Cheyenne Hub in Weld County,
Colorado (segment 2). Construction of segment 1 has been completed and went into
interim service on February 24, 2006. Construction of segment 2 commenced in
mid-summer 2006, and went into service on February 14, 2007. For Phase II, which
will follow the construction of Segment 2, Rockies Express was authorized to
construct three compressor stations referred to as the Meeker, Big Hole and
Wamsutter compressor stations.
166
Rockies Express Pipeline-West Project
On May 31, 2006, in FERC Docket No. CP06-354-000, Rockies Express Pipeline
LLC filed an application for authorization to construct and operate certain
facilities comprising its proposed "Rockies Express-West Project." This project
is the first planned segment extension of the Rockies Express' currently
certificated facilities, which includes (i) a 136-mile pipeline segment
currently in operation from the Meeker Hub in Colorado to the Wamsutter Hub in
Wyoming, and (ii) a 191-mile segment that went into service in February 2007
from Wamsutter to the Cheyenne Hub located in Weld County, Colorado. The Rockies
Express-West Project will be comprised of approximately 713 miles of 42-inch
diameter pipeline extending from the Cheyenne Hub to an interconnection with
Panhandle Eastern Pipe Line located in Audrain County, Missouri. The segment
extension proposes to transport approximately 1.5 billion cubic feet per day of
natural gas across the following five states: Wyoming, Colorado, Nebraska,
Kansas and Missouri. The project will also include certain improvements to
existing Rockies Express facilities located to the west of the Cheyenne Hub.
On September 21, 2006, the FERC issued a favorable preliminary
determination on all non-environmental issues of the project, approving Rockies
Express' application (i) to construct and operate the 713 miles of new natural
gas transmission facilities from the Cheyenne Hub and (ii) to lease capacity
from Questar Overthrust Pipeline Company, which will extend the Rockies Express
system 140 miles west from Wamsutter to the Opal Hub in Wyoming. We expect the
FERC will complete its environmental review and issue its certificate by the end
of March 2007, and the project is expected to begin service in January 2008.
Rockies Express Pipeline-East Project
On June 13, 2006, the FERC agreed with Rockies Express' participation in
the pre-filing process for development of the "Rockies Express-East Project."
The Rockies Express-East Project will comprise approximately 635 miles of
42-inch diameter pipeline commencing from the terminus of the Rockies
Express-West pipeline to a terminus near the town of Clarington in Monroe
County, Ohio. The segment proposes to transport approximately 1.8 billion cubic
feet per day of natural gas. On August 13, 2006, the FERC issued its notice of
intent to prepare an environmental impact statement for the proposed project and
hosted nine scoping meetings from September 11 through September 15, 2006 in
various locations along the route. During this pre-filing process, Rockies
Express has encountered opposition from certain landowners in the states of
Indiana and Ohio. Rockies Express is actively participating in community
outreach meetings with landowners and agencies located in these states to
resolve any differences they may have with the project. Rockies Express is
confident that a mutual agreement and/or understanding will be reached with
these parties, and that the project is on track for a certificate application to
be filed in April 2007. The application will request that a FERC order be issued
by February 1, 2008 in order to meet both a December 31, 2008 project in-service
date for the proposed pipeline and partial compression and a June 30, 2009
in-service date for the remaining compression.
8. Intangibles
Our intangible assets include goodwill, lease value, contracts, customer
relationships and agreements.
Goodwill and Excess Investment Cost
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. Following is information related to
our goodwill as of December 31, 2006 and 2005 (in thousands):
167
December 30, December 31,
------------ ------------
2006 2005
---------- ----------
Goodwill
Gross carrying amount........ $ 843,112 $ 813,101
Accumulated amortization..... (14,142) (14,142)
---------- ----------
Net carrying amount.......... 828,970 798,959
========== ==========
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. Changes in the carrying amount
of our goodwill for each of the two years ended December 31, 2005 and 2006 are
summarized as follows (in thousands):
Products Natural Gas
Pipelines Pipelines CO2 Terminals Total
--------- ----------- --------- --------- ---------
Balance as of December 31, 2004............. $ 263,182 $ 250,318 $ 46,101 $ 173,237 $ 732,838
Acquisitions and purchase price adjs...... - 38,117 - 28,004 66,121
Disposals................................. - - - - -
Impairments............................... - - - - -
--------- ---------- --------- --------- ---------
Balance as of December 31, 2005............. $ 263,182 $ 288,435 $ 46,101 $ 201,241 $ 798,959
Acquisitions and purchase price adjs...... - - - 30,011 30,011
Disposals................................. - - - - -
Impairments............................... - - - - -
Balance as of December 31, 2006............. $ 263,182 $ 288,435 $ 46,101 $ 231,252 $ 828,970
========= ========== ========= ========= =========
For our investments in entities that are not fully consolidated but instead
are included in our financial statements under the equity method of accounting,
the premium we pay that represents excess cost over underlying fair value of net
assets is referred to as equity method goodwill, and under SFAS No. 142, this
excess cost 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. As of both December 31,
2006 and 2005, we have reported $138.2 million in equity method goodwill within
the caption "Investments" in our accompanying consolidated balance sheets.
We also periodically reevaluate the difference between the fair value of
net assets accounted for under the equity method and our proportionate share of
the underlying book value (that is, the investee's net assets per its financial
statements) of the investee at date of acquisition. In almost all instances,
this differential, relating to the discrepancy between our share of the
investee's recognized net assets at book values and at current fair values,
represents our share of undervalued depreciable assets, and since those assets
(other than land) are subject to depreciation, we amortize this portion of our
investment cost against our share of investee earnings. We reevaluate this
differential, as well as the amortization period for such undervalued
depreciable 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 excess fair value of net
assets over book value costs of $177.1 million as of December 31, 2006 and
$181.7 million as of December 31, 2005.
Other Intangibles
Excluding goodwill, our other intangible assets include lease value,
contracts, customer relationships, technology-based assets 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. Following is
information related to our intangible assets subject to amortization (in
thousands):
168
December 31,
------------------------
2006 2005
---------- ----------
Lease value
Gross carrying amount............. $ 6,592 $ 6,592
Accumulated amortization.......... (1,309) (1,168)
--------- ---------
Net carrying amount............... 5,283 5,424
--------- ---------
Contracts and other
Gross carrying amount............. 231,097 221,250
Accumulated amortization.......... (23,172) (9,654)
--------- ---------
Net carrying amount............... 207,925 211,596
--------- ---------
Total Other intangibles, net........ $ 213,208 $ 217,020
========= =========
Amortization expense on our intangibles consisted of the following (in
thousands):
Year Ended December 31,
-------------------------------
2006 2005 2004
-------- -------- --------
Lease value...................... $ 141 $ 140 $ 140
Contracts and other.............. 13,518 8,599 752
-------- ------- --------
Total amortization............... $ 13,659 $ 8,739 $ 892
======== ======= ========
As of December 31, 2006, our weighted average amortization period for our
intangible assets was approximately 18.76 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$13.6 million, $13.6 million, $12.4 million, $12.2 million and $12.1 million,
respectively.
9. Debt
Short-Term Debt
Our outstanding short-term debt as of December 31, 2006 was $1,359.1
million. The balance consisted of:
o $1,098.2 million of commercial paper borrowings;
o $250.0 million in principal amount of 5.35% senior notes due August
15, 2007;
o a $5.9 million portion of 5.23% senior notes (our subsidiary, Kinder
Morgan Texas Pipeline, L.P., is the obligor on the notes); and
o a $5.0 million portion of 7.84% senior notes (our subsidiary, Central
Florida Pipe Line LLC, is the obligor on the notes).
Our outstanding short-term debt as of December 31, 2005 was $575.6 million,
which primarily consisted of $566.2 million in outstanding commercial paper
borrowings; however, 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, this debt balance was classified as long-term debt in our
accompanying consolidated balance sheet. As of December 31, 2006 we did not
intend to refinance all of our short-term debt on a long-term basis under our
unsecured long-term credit facility. The weighted average interest rate on all
of our borrowings was approximately 6.1779% during 2006 and 5.3019% during 2005.
Long-Term Debt
Our outstanding long-term debt, excluding market value of interest rate
swaps, as of December 31, 2006 and 2005 was $4,384.3 million and $5,220.9
million, respectively. The balances consisted of the following (in thousands):
169
December 31,
---------------------------
2006 2005
------------ ------------
Kinder Morgan Energy Partners, L.P. borrowings:
5.35% senior notes due August 15, 2007..................................................... $ 250,000 $ 250,000
6.30% senior notes due February 1, 2009..................................................... 250,000 250,000
7.50% senior notes due November 1, 2010..................................................... 250,000 250,000
6.75% senior notes due March 15, 2011....................................................... 700,000 700,000
7.125% senior notes due March 15, 2012...................................................... 450,000 450,000
5.00% senior notes due December 15, 2013.................................................... 500,000 500,000
5.125% senior notes due November 15, 2014................................................... 500,000 500,000
7.400% senior notes due March 15, 2031...................................................... 300,000 300,000
7.75% senior notes due March 15, 2032....................................................... 300,000 300,000
7.30% senior notes due August 15, 2033...................................................... 500,000 500,000
5.80% senior notes due March 15, 2035....................................................... 500,000 500,000
Commercial paper borrowings................................................................. 1,098,192 566,200
Subsidiary borrowings:
Central Florida Pipe Line LLC-7.840% senior notes due July 23, 2008......................... 10,000 15,000
Arrow Terminals L.P.-IL Development Revenue Bonds due January 1, 2010....................... 5,325 5,325
Kinder Morgan Texas Pipeline, L.P.-5.23% Senior Notes, due January 2, 2014.................. 49,102 54,683
Kinder Morgan Liquids Terminals LLC-N.J. Development Revenue Bonds due Jan. 15, 2018........ 25,000 25,000
Kinder Morgan Operating L.P. "B"-Jackson-Union Cos. IL Revenue Bonds due April 1, 2024...... 23,700 23,700
International Marine Terminals-Plaquemines, LA Revenue Bonds due March 15, 2025............. 40,000 40,000
Other miscellaneous subsidiary debt......................................................... 1,349 1,447
Unamortized debt discount on senior notes....................................................... (9,26) (10,46)
Current portion of long-term debt............................................................... (1,359,06) --
------------ ------------
Total Long-term debt............................................................................ $ 4,384,332 $ 5,220,887
============ ============
Credit Facilities
On August 5, 2005, we increased our existing five-year unsecured bank
credit facility from $1.25 billion to $1.6 billion, and we extended the maturity
one year to August 18, 2010. 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.
On February 22, 2006, we entered into a second unsecured credit facility,
in the amount of $250 million, expiring on November 21, 2006. This facility
contained borrowing rates and restrictive financial covenants that were similar
to the borrowing rates and covenants under our $1.6 billion bank facility.
Effective August 28, 2006, we terminated our $250 million unsecured
nine-month bank credit facility and we increased our existing five-year bank
credit facility from $1.6 billion to $1.85 billion. The five-year unsecured bank
credit facility remains due August 18, 2010; however, the bank facility can now
be amended to allow for borrowings up to $2.1 billion. There were no borrowings
under our five-year credit facility as of December 31, 2006 or as of December
31, 2005.
Similar to our previous bank credit facilities, our current five-year
credit facility is with a syndicate of financial institutions and Wachovia Bank,
National Association is the administrative agent. The amount available for
borrowing under our credit facility as of December 31, 2006 was reduced by:
o our outstanding commercial paper borrowings ($1,098.2 million as of
December 31, 2006);
o a combined $243 million in three letters of credit that support our
hedging of commodity price risks associated with the sale of natural
gas, natural gas liquids and crude oil;
o a combined $48 million in two letters of credit that support
tax-exempt bonds;
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o a combined $39.7 million in two letters of credit that support the
construction of our Kinder Morgan Louisiana Pipeline (a natural gas
pipeline);
o a $37.5 million letter of credit that supports our indemnification
obligations on the Series D note borrowings of Cortez Capital
Corporation; and
o a combined $16.5 million in 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:
o the administrative agent's base rate (but not less than the Federal
Funds Rate, plus 0.5%); or
o LIBOR, plus a margin, which varies depending upon the credit rating of
our long-term senior unsecured debt.
Our credit facility included the following restrictive covenants as of
December 31, 2006:
o total debt divided by earnings before interest, income taxes,
depreciation and amortization for the preceding four quarters may not
exceed:
o 5.5, in the case of any such period ended on the last day of (i)
a fiscal quarter in which we make any Specified Acquisition, or
(ii) the first or second fiscal quarter next succeeding such a
fiscal quarter; or
o 5.0, in the case of any such period ended on the last day of any
other fiscal quarter;
o certain limitations on entering into mergers, consolidations and sales
of assets;
o limitations on granting liens; and
o prohibitions on making any distribution to holders of units if an
event of default exists or would exist upon making such distribution.
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:
o 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;
o 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;
o 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
o 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 we will pay with respect to borrowings and the facility fee that we
will pay on the total commitment will vary based
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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.
Interest Rate Swaps
Information on our interest rate swaps is contained in Note 14.
Commercial Paper Program
On August 5, 2005, we increased our commercial paper program by $350
million to provide for the issuance of up to $1.6 billion. In April 2006, we
increased our commercial paper program by $250 million to provide for the
issuance of up to $1.85 billion. Our $1.85 billion unsecured five-year bank
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, 2006, we had $1,098.2 million of commercial paper
outstanding with an average interest rate of 5.4164%. The borrowings under our
commercial paper program were used principally to finance the acquisitions and
capital expansions we made during 2006 and 2005.
Senior Notes
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, 2006, the outstanding principal balance on the various
series of our senior notes (excluding unamortized debt discount) was $4,490.7
million. For a listing of the various outstanding series of our senior notes,
see the table above included in "--Long-term Debt."
On January 30, 2007, we completed a public offering of senior notes. We
issued a total of $1.0 billion in principal amount of senior notes, consisting
of $600 million of 6.00% notes due February 1, 2017, and $400 million of 6.50%
notes due February 1, 2037. We received proceeds from the issuance of the notes,
after underwriting discounts and commissions, of approximately $992.8 million,
and we used the proceeds to reduce the borrowings under our commercial paper
program.
Subsidiary Debt
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 2006 and July 2005, we made an annual
repayment of $5.0 million and as of December 31, 2006, Central Florida's
outstanding balance under the senior notes was $10.0 million.
Arrow Terminals L.P.
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
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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, 2006, the interest rate
was 4.089%. 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 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, 2006, KMTP's outstanding balance under the senior notes was
$49.1 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:
o $4.1 million of 7.30% New Jersey Industrial Revenue Bonds due
September 1, 2019;
o $59.5 million of 6.95% Texas Industrial Revenue Bonds due February 1,
2022;
o $7.4 million of 6.65% New Jersey Industrial Revenue Bonds due
September 1, 2022;
o $13.3 million of 7.00% Louisiana Industrial Revenue Bonds due March 1,
2023; and
o $3.6 million of 6.625% Texas Industrial Revenue Bonds due February 1,
2024.
In 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
173
of December 31, 2006, the interest rate was 3.87%. 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, 2006, the
interest rate on these bonds was 3.90%. Also, as of December 31, 2006, 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.
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, 2006, the interest rate on these bonds was 3.50%.
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.
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, 2006, are summarized as follows (in
thousands):
2007.......... $1,359,069
2008.......... 11,215
2009.......... 256,377
2010.......... 261,618
2011.......... 706,410
Thereafter.... 3,148,712
----------
Total......... $5,743,401
==========
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.
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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 ExxonMobil 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.
As of December 31, 2006, the debt facilities of Cortez Capital Corporation
consisted of:
o $75 million of Series D notes due May 15, 2013;
o a $125 million short-term commercial paper program; and
o 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, 2006, Cortez Capital Corporation had $73.9 million of
commercial paper outstanding with an average interest rate of 5.3846%, the
average interest rate on the Series D notes was 7.14%, and there were no
borrowings under the credit facility.
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 was released of its guaranty
obligations on December 31, 2006; with respect to Cortez's Series D notes, in
December 2006, we entered into a letter of credit issued by JP Morgan Chase in
the amount of $37.5 million to secure our indemnification obligations to Shell
for 50% of the $75 million in principal amount of Series D notes outstanding as
of December 31, 2006; and with respect to Cortez's short-term commercial paper
borrowings, in January 2007, we entered into an additional letter of credit
issued by JP Morgan Chase in the amount of $37.5 million to secure our
indemnification obligations to Shell for 50% of the outstanding commercial paper
borrowings as of December 31, 2006.
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 installments beginning on October 31, 2004 and ending
on October 31, 2010. As of December 31, 2006, $31.4 million in principal amount
of notes were outstanding.
In the first quarter of 2007, Red Cedar plans to refinance the outstanding
balance of its existing Senior Notes through a private placement of $100 million
in principal amount of ten year fixed rate notes. Bids for the new notes were
due February 15, 2007, and the placement is expected to close on March 15, 2007.
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
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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
corresponding reductions are made to the letter of credit. As of December 31,
2006, this letter of credit had an outstanding balance under our credit facility
of $23.9 million.
Rockies Express Pipeline LLC Debt
On April 28, 2006, Rockies Express Pipeline LLC entered into a $2.0 billion
five-year, unsecured revolving credit facility due April 28, 2011. This credit
facility supports a $2.0 billion commercial paper program that was established
in May 2006, and borrowings under the commercial paper program reduce the
borrowings allowed under the credit facility; this facility can be amended to
allow for borrowings up to $2.5 billion. Borrowings under the Rockies Express
credit facility and commercial paper program will be primarily used to finance
the construction of the Rockies Express interstate natural gas pipeline and to
pay related expenses, and the borrowings will not reduce the borrowings allowed
under our credit facility described in Note 9.
In addition, pursuant to certain guaranty agreements, all three member
owners of West2East Pipeline LLC (and its subsidiary Rockies Express Pipeline,
LLC) have agreed to guarantee borrowings under the Rockies Express credit
facility and under the Rockies Express commercial paper program severally in the
same proportion as their percentage ownership of the member interests in Rockies
Express Pipeline LLC. The three member owners and their respective ownership
interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline
LLC - 51%, Sempra Energy - 25%, and ConocoPhillips - 24%. As of December 31,
2006, Rockies Express Pipeline LLC had $790.1 million of commercial paper
outstanding, and there were no borrowings under its five-year credit facility.
Accordingly, as of December 31, 2006, our contingent share of Rockies Express'
debt was $403.0 million (51% of total commercial paper borrowings).
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, including its current portion and excluding market
value of interest rate swaps, is based upon prevailing interest rates available
to us as of December 31, 2006 and December 31, 2005 and is disclosed below.
December 31, 2006 December 31, 2005
------------------------- -------------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
---------- ---------- ---------- ----------
(In thousands)
Total Debt $5,743,401 $5,864,966 $5,220,887 $5,465,215
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.
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Our net periodic benefit cost for the SFPP post-retirement benefit plan were
credits of $0.3 million in 2006, $0.3 million in 2005, and $0.6 million in 2004.
The credits resulted in increases to income, largely due to amortizations of an
actuarial gain and a negative prior service cost, primarily related to the
following:
o there have been changes to the plan for both 2004 and 2005 which
reduced liabilities, creating a negative prior service cost that is
being amortized each year; and
o there was a significant drop in 2004 in the number of retired
participants reported as pipeline retirees by Burlington Northern
Santa Fe, which holds a 0.5% special limited partner interest in SFPP,
L.P.
As of December 31, 2006, we estimate our overall net periodic
post-retirement benefit cost for the year 2007 will be a credit of approximately
$0.3 million, including amortization of approximately $0.5 million of combined
prior service credits and actuarial gains from accumulated other comprehensive
income. This amount could change if there is a significant event, such as a plan
amendment or a plan curtailment, which would require a remeasurement of
liabilities. In addition, we expect to contribute approximately $0.4 million to
our post-retirement benefit plans in 2007.
On September 29, 2006, the FASB issued SFAS No. 158, "Employers' Accounting
for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB
Statement Nos. 87, 88, 106 and 132(R)." One of the provisions of this Statement
requires an employer with publicly traded equity securities to recognize the
overfunded or underfunded status of a defined benefit pension plan or
post-retirement benefit plan (other than a multiemployer plan) as an asset or
liability in its statement of financial position and to provide the required
disclosures as of the end of the fiscal year ending after December 15, 2006.
Following adoption of SFAS No. 158, entities will report as part of the net
benefit liability on their balance sheets amounts that have not yet been
recognized as a component of benefit expense (for example, unrecognized prior
service costs or credits, net (actuarial) gain or loss, and transition
obligation or asset) with a corresponding adjustment to accumulated other
comprehensive income.
We adopted this provision on December 31, 2006, and the primary impact on
us from adopting SFAS No. 158 was to require us to fully recognize, in our
consolidated balance sheet, both the funded status of the SFPP post-retirement
benefit plan obligation and previously unrecognized prior service credits and
actuarial gains. Both the funded status and the recorded value of our benefit
obligation for the SFPP post-retirement benefit plan as of December 31, 2006 was
$5.5 million. The following table discloses the incremental effect on our
consolidated balance sheet of applying SFAS No. 158 on December 31, 2006 (in
thousands):
Before After
Application Adjustments Application
----------- ----------- -----------
Prepaid benefit cost........................ $ - $ - $ -
Accrued benefit liability................... 10,967 (5,510) 5,457
Intangible asset............................ - - -
Minority interest........................... - 28 28
Accumulated other comprehensive income...... - 5,482 5,482
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 each of the
years ended December 31, 2006 and 2005.
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
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base compensation per year for most plan participants, our general partner may
make special discretionary contributions. Certain employees' contributions are
based on collective bargaining agreements. The mandatory contributions are made
each pay period on behalf of each eligible employee. 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. The total amount charged to expense for our Savings Plan was $10.2
million during 2006 and $7.9 million during 2005. All employee 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.
At its July 2006 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 2006 and continuing through the
last pay period of July 2007. 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 it will vest according to the same vesting schedule described in
the preceding paragraph. Since this additional 1% company contribution is
discretionary, compensation committee approval will be required annually for
each additional contribution. During the first quarter of 2007, excluding the 1%
additional contribution described above, we will not make any additional
discretionary contributions to individual accounts for 2006.
Additionally, in 2006, an option to make after-tax "Roth" contributions
(Roth 401(k) option) to a separate participant account was added to the Savings
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. The employer contribution will still be considered taxable
income at the time of withdrawal.
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. Under the plan, we make
contributions on behalf of participating employees equal to 3% of eligible
compensation every pay period. 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, 2006 and 2005, our partners' capital consisted of the
following limited partner units:
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December 31, December 31,
2006 2005
----------- ------------
Common units.................. 162,816,303 157,005,326
Class B units................. 5,313,400 5,313,400
i-units....................... 62,301,676 57,918,373
---------- ----------
Total limited partner units. 230,431,379 220,237,099
=========== ===========
The total limited partner units represent our limited partners' interest
and an effective 98% economic interest in us, exclusive of our general partner's
incentive distribution rights. Our general partner has an effective 2% interest
in us, excluding its incentive distribution rights.
As of December 31, 2006, our common unit total consisted of 148,460,568
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. 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.
On both December 31, 2006 and December 31, 2005, all of our 5,313,400 Class
B units were held entirely by a wholly-owned subsidiary of 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. All of our Class B units were issued to
a wholly-owned subsidiary of KMI in December 2000.
On both December 31, 2006 and December 31, 2005, all of our i-units were
held entirely by KMR. Our i-units are a separate class of limited partner
interests in us 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 to 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 1,160,520 i-units on November 14,
2006. These additional i-units distributed were based on the $0.81 per unit
distributed to our common unitholders on that date. During the year ended
December 31, 2006, KMR received distributions of 4,383,303 i-units. These
additional i-units distributed were based on the $3.23 per unit distributed to
our common unitholders during 2006.
Equity Issuances
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 the 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.
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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.
In August 2006, we issued, in a public offering, 5,750,000 of our common
units, including common units sold pursuant to the underwriters' over-allotment
option, at a price of $44.80 per unit, less commissions and underwriting
expenses. We received net proceeds of approximately $248.0 million for the
issuance of these 5,750,000 common units.
We used the proceeds from each of these three issuances to reduce the
borrowings under our commercial paper program.
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, 2006, 2005 and 2004, we declared
distributions of $3.26, $3.13 and $2.87 per unit, respectively. Under the terms
of our partnership agreement, our distributions to unitholders for 2006 required
incentive distributions to our general partner in the amount of $528.4 million.
According to the provisions of the KMI Annual Incentive Plan, in order for the
executive officers of our general partner and KMR, and for the employees of KMGP
Services Company, Inc. and KMI who operate our business to earn a non-equity
cash incentive (bonus) for 2006, both we and KMI were required to meet
pre-established financial performance targets. The target for us was $3.28 in
cash distributions per common unit for 2006. Due to the fact that we did not
meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan;
however, the board of directors of KMI determined that it was in KMI's long-term
interest to fund a partial payout of our bonuses through a reduction in the
general partner's incentive distribution.
Accordingly, our general partner, with the approval of the compensation
committees and boards of KMI and KMR, waived $20.1 million of its 2006 incentive
distribution for the fourth quarter of 2006. The waived amount approximates an
amount equal to our actual bonus payout for 2006, which is approximately 75% of
our budgeted full bonus payout for 2006 of $26.5 million. Including the effect
of this waiver, our distributions to unitholders for 2006 resulted in payments
of incentive distributions to our general partner in the amount of $508.3
million. The waiver of $20.1 million of incentive payment in the fourth quarter
of 2006 reduced our general partner's equity earnings by $19.9 million.
Our total distributions to unitholders for 2005 and 2004 required incentive
distributions to our general partner in the amount of $473.9 million and $390.7
million, respectively. The increased incentive distributions paid for 2006 over
2005 and 2005 over 2004 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 17, 2007, we declared a cash distribution of $0.83 per unit for
the quarterly period ended December 31, 2006. This distribution was paid on
February 14, 2007, to unitholders of record as of January 31, 2007. 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 $0.83
distribution per common unit. The number of i-units distributed was 1,054,082.
For each outstanding i-unit that KMR held, a fraction of an i-unit (0.016919)
was issued. The fraction was determined by dividing:
o $0.83, the cash amount distributed per common unit
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by
o $49.057, the average of KMR's limited liability shares' closing market
prices from January 12-26, 2007, 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, 2007 distribution included an incentive distribution to
our general partner in the amount of $118.0 million--including the effect of the
$20.1 million waiver, described above. Since this distribution was declared
after the end of the quarter, no amount is shown in our December 31, 2006
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 Kinder Morgan Services LLC
for their allocated shares of these direct costs. There is no profit or margin
charged by Kinder Morgan Services LLC to the members of the Group. The
administrative support necessary to implement these payroll and benefits
services is provided by the human resource department of KMI, and the related
administrative costs are allocated to members of the Group in accordance with
existing expense allocation procedures. The effect of these arrangements is that
each member of the Group bears the direct compensation and employee benefits
costs of its assigned or partially assigned employees, as the case may be, while
also bearing its allocable share of administrative costs. Pursuant to our
limited partnership agreement, we provide reimbursement for our share of these
administrative costs and such reimbursements will be accounted for as described
above. Additionally, we reimburse KMR with respect to costs incurred or
allocated to KMR in accordance with our limited partnership agreement, the
delegation of control agreement among our general partner, KMR, us and others,
and KMR's limited liability company agreement.
The named executive officers of our general partner and KMR and other
employees that provide management or services to both KMI and the Group are
employed by KMI. Additionally, other KMI employees assist in the operation of
our Natural Gas Pipeline assets. These KMI employees' expenses are allocated
without a profit component between KMI and the appropriate members of the Group.
Partnership 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:
o its 1.0101% direct general partner ownership interest (accounted for
as minority interest in our consolidated financial statements); and
o its 0.9899% ownership interest indirectly owned via its 1% ownership
interest in us.
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As of December 31, 2006, our general partner owned 1,724,000 common units,
representing approximately 0.75% 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. 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.
Available cash is initially distributed 98% to our limited partners and 2%
to our general partner. These distribution percentages are modified to provide
for incentive distributions to be paid to our general partner in the event that
quarterly distributions to unitholders exceed certain specified targets.
Available cash for each quarter is distributed:
o first, 98% to the owners of all classes of units pro rata and 2% to
our general partner until the owners of all classes of units have
received a total of $0.15125 per unit in cash or equivalent i-units
for such quarter;
o second, 85% of any available cash then remaining to the owners of all
classes of units pro rata and 15% to our general partner until the
owners of all classes of units have received a total of $0.17875 per
unit in cash or equivalent i-units for such quarter;
o third, 75% of any available cash then remaining to the owners of all
classes of units pro rata and 25% to our general partner until the
owners of all classes of units have received a total of $0.23375 per
unit in cash or equivalent i-units for such quarter; and
o fourth, 50% of any available cash then remaining to the owners of all
classes of units pro rata, to owners of common units and Class B units
in cash and to owners of i-units in the equivalent number of i-units,
and 50% to our general partner.
Incentive distributions are generally defined as all cash distributions
paid to our general partner that are in excess of 2% of the aggregate value of
cash and i-units being distributed. Our general partner's declared incentive
distributions for the years ended December 31, 2006, 2005 and 2004 were $508.3
million, $473.9 million and $390.7 million, respectively.
Kinder Morgan, Inc.
KMI, through its subsidiary Kinder Morgan (Delaware), Inc., remains the
sole stockholder of our general partner. As of December 31, 2006, KMI directly
owned 8,838,095 common units, indirectly owned 5,313,400 Class B units and
5,517,640 common units through its consolidated affiliates, including our
general partner, and owned 10,305,553 KMR shares, representing an indirect
ownership interest of 10,305,553 i-units. Together, these units
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represented approximately 13.0% of our outstanding limited partner units.
Including both its general and limited partner interests in us, at the 2006
distribution level, KMI received approximately 49% of all quarterly
distributions from us, of which approximately 42% was attributable to its
general partner interest and 7% was attributable to its limited partner
interest. The actual level of distributions KMI will receive in the future will
vary with the level of distributions to the limited partners determined in
accordance with our partnership agreement.
Kinder Morgan Management, LLC
As of December 31, 2006, KMR, our general partner's delegate, remained the
sole owner of our 62,301,676 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.
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 feet 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, 2006. 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
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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 $1.0 million of
fixed costs and $37.9 million of actual costs incurred for 2006, $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 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
approximately half 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 expiring in June 2010. 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 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 amounts
paid to KMI in 2006 and 2005 for operating and maintaining the power plant was
$2.9 million and $0.8 million, respectively. We estimate the total reimbursement
to be paid to KMI for operating and maintaining the plant for 2007 will be
approximately $3.3 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 and crude oil.
We also have exposure to interest rate risk as a result of the issuance of our
fixed rate debt obligations. Pursuant to our management's approved risk
management policy, we use derivative contracts to hedge or reduce our exposure
to these risks and protect our profit margins.
Our risk management policies prohibit us from engaging in speculative
trading. Our commodity-related risk management activities are monitored by our
risk management committee, which is a separately designated standing committee
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 charged with the review and enforcement of
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our management's risk management policy. The committee is comprised of 19
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. The committee is chaired by
our President and is charged with the following three responsibilities:
o establish and review risk limits consistent with our risk tolerance
philosophy;
o recommend to the audit committee of our general partner's delegate any
changes, modifications, or amendments to our risk management policy;
and
o address and resolve any other high-level risk management issues.
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 and which
totaled approximately $5.8 million in 2006.
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.
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."
In 2006, Plantation paid to us $1.1 million in principal amount under the
note, and as of December 31, 2006, the principal amount receivable from this
note was $93.1 million. We included $3.4 million of this balance within
"Accounts, notes and interest receivable, net-Related parties" on our
consolidated balance sheet as of December 31, 2006, and we included the
remaining $89.7 million balance within "Notes receivable-Related parties."
Coyote Gas Treating, LLC
Coyote Gas Treating, LLC is a joint venture that was organized in December
1996. It is referred to as Coyote Gulch in this report. The sole asset owned by
Coyote Gulch is a 250 million cubic feet per day natural gas treating facility
located in La Plata County, Colorado. Prior to the contribution of our ownership
interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006, discussed
below, we were the managing partner and owned a 50% equity interest in Coyote
Gulch.
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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 corresponded 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, and as of December 31, 2005, we included the
principal amount of $17.0 million related to this note within "Notes
Receivable-Related Parties" on our consolidated balance sheet.
In March 2006, the owners of Coyote Gulch agreed to transfer Coyote Gulch's
notes payable to members' equity. Accordingly, we contributed the principal
amount of $17.0 million related to our note receivable to our equity investment
in Coyote Gulch.
In the third quarter of 2006, the Southern Ute Indian Tribe acquired the
remaining 50% ownership interest in Coyote Gulch from Enterprise Field Services
LLC. The acquisition was made effective March 1, 2006. On September 1, 2006, we
and the Southern Ute Tribe agreed to transfer all of the members' equity in
Coyote Gulch to the members' equity of Red Cedar Gathering, a joint venture
organized in August 1994 and referred to in this report as Red Cedar. Red Cedar
owns and operates natural gas gathering, compression and treating facilities in
the Ignacio Blanco Field in La Plata County, Colorado, and is owned 49% by us
and 51% by the Southern Ute Tribe. Under the terms of a five-year operating
lease agreement that became effective January 1, 2002, Red Cedar also operates
the gas treating facility owned by Coyote Gulch and is responsible for all
operating and maintenance expenses and capital costs.
Accordingly, on September 1, 2006, we and the Southern Ute Tribe
contributed the value of our respective 50% ownership interests in Coyote Gulch
to Red Cedar, and as a result, Coyote Gulch became a wholly owned subsidiary of
Red Cedar. The value of our 50% equity contribution from Coyote Gulch to Red
Cedar on September 1, 2006 was $16.7 million, and this amount remains included
within "Investments" on our consolidated balance sheet as of December 31, 2006.
Red Cedar Gathering Company
As described above in "--Coyote Gas Treating, LLC," we own a 49% equity
interest in the Red Cedar Gathering Company 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 agreed to 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
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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.
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 two
equipment leases accounted for as capital leases and each of these leases expire
in 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,
2006
------------
Leasehold improvements........... $ 4,089
Machinery and equipment.......... 25
---------
4,114
Less: Accumulated amortization... (2,997)
---------
$ 1,117
Future commitments under capital lease obligations as of December 31, 2006
are as follows (in thousands):
Year Commitment
---- ----------
2007....................................... $ 173
2008....................................... 168
2009....................................... 168
2010....................................... 168
2011....................................... 168
Thereafter................................. 991
----------
Subtotal..................................... 1,836
Less: Amount representing interest......... (720)
----------
Present value of minimum capital lease
payments................................... $ 1,116
==========
Operating Leases
Including probable elections to exercise renewal options, the remaining
terms on our operating leases range from one to 62 years. Future commitments
related to these leases as of December 31, 2006 are as follows (in thousands):
Year Commitment
---- ----------
2007.................... $ 47,709
2008.................... 30,050
2009.................... 20,192
2010.................... 16,877
2011.................... 13,126
Thereafter.............. 27,878
----------
Total minimum payments.... $ 155,832
==========
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The largest of these lease commitments, in terms of total obligations
payable by December 31, 2008, include commitments supporting:
o crude oil drilling rig operations for the oil and gas activities of
our CO2 business segment;
o natural gas liquids pipeline capacity and storage for our North System
natural gas liquids pipeline;
o marine port terminal operations at our Nassau bulk product terminal,
located in Fernandina Beach, Florida; and
o natural gas storage in underground salt dome caverns for our Texas
intrastate natural gas pipeline group.
We have not reduced our total minimum payments for future minimum sublease
rentals aggregating approximately $6.2 million. Total lease and rental expenses
were $54.1 million for 2006, $47.3 million for 2005 and $39.3 million for 2004.
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.
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.
During 2006, 4,200 options to purchase common units were cancelled or
forfeited, and 21,100 options to purchase common units were exercised at an
average price of $19.67 per unit. The common units underlying these options had
an average fair market value of $46.43 per unit. As of December 31, 2006, there
were no outstanding options.
We account for common unit options granted under our common unit option
plan according to the provisions of SFAS No. 123R (revised 2004), "Share-Based
Payment," which became effective for us January 1, 2006. 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. According to
the provisions of SFAS No. 123R, 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. Companies will recognize
compensation cost for share-based payment awards as they vest, including the
related tax effects, and compensation cost for awards that vest would not be
reversed if the awards expire without being exercised.
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.
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
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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, discussed following. All unexercised awards made under
our Directors' Unit Appreciation Rights Plan remain outstanding. No unit
appreciation rights were exercised during 2006, and as of December 31, 2006,
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.
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 payable in cash. Pursuant to the plan, in lieu of receiving 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, and the
election for 2007 was made effective January 17, 2007. 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 cash compensation in the form of common units will equal the
amount of such cash compensation awarded, divided by the closing price
189
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 cash compensation in the form of common units will receive cash equal to the
difference between (i) the 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 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 cash compensation of $119,750 for board
service during 2005. Effective January 20, 2005, each non-employee director
elected to receive 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
remaining $40,000 cash compensation and the $37.50 of 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
cash compensation of $160,000 for board service during 2006. Effective January
17, 2006, each non-employee director elected to receive 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 remaining $72,220 cash compensation was paid to each of the
non-employee directors as described above. No other compensation was paid to the
non-employee directors during 2006.
On January 17, 2007, each of KMR's three non-employee directors was awarded
cash compensation of $160,000 for board service during 2007. Effective January
17, 2007, each non-employee director elected to receive certain amounts of cash
compensation in the form of our common units and each were issued common units
pursuant to the plan and its agreements (based on the $48.44 closing market
price of our common units on January 17, 2007, as reported on the New York Stock
Exchange). Mr. Gaylord elected to receive cash compensation of $95,911.20 in the
form of our common units and was issued 1,980 common units; Mr. Waughtal elected
to receive cash compensation of $159,852.00 in the form of our common units and
was issued 3,300 common units; and Mr. Hultquist elected to receive cash
compensation of $96,880.00 in the form of our common units and was issued 2,000
common units. All remaining cash compensation ($64,088.80 to Mr. Gaylord;
$148.00 to Mr. Waughtal; and $63,120.00 to Mr. Hultquist) will be paid to each
of the non-employee directors as described above, and no other compensation will
be paid to the non-employee directors during 2007.
14. Risk Management
Certain of our business activities expose us to risks associated with
unfavorable changes in the market price of natural gas, natural gas liquids and
crude oil. We also have exposure to interest rate risk as a result of the
issuance of our fixed rate debt obligations. Pursuant to our management's
approved risk management policy, we use derivative contracts to hedge or reduce
our exposure to these risks, and we account for these hedging transactions
according to the provisions of SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" and associated amendments, collectively,
SFAS No. 133.
Energy Commodity Price Risk Management
We are exposed to risks associated with unfavorable changes in the market
price of natural gas, natural gas liquids and crude oil as a result of the
forecasted purchase or sale of these products. Specifically, these risks are
associated with unfavorable price volatility related to:
o pre-existing or anticipated physical natural gas, natural gas liquids
and crude oil sales;
190
o natural gas purchases; and
o natural gas system use and storage.
The unfavorable price changes are often caused by shifts in the supply and
demand for these commodities, as well as their locations. Our energy commodity
derivative contracts act as a hedging (offset) mechanism against the volatility
of energy commodity prices by allowing us to transfer this price risk to
counterparties who are able and willing to bear it.
Hedging effectiveness and ineffectiveness
These derivative contracts are used to offset the risk associated with an
anticipated future cash flow of a transaction that is expected to occur but
whose value is uncertain, therefore the resulting hedges are designated and
qualified as cash flow hedges in accordance with SFAS No. 133. For cash flow
hedges, the portion of the change in the value of derivative contracts that is
effective in offsetting undesired changes in expected cash flows (the effective
portion) is reported as a component of other comprehensive income (outside
current earnings, net income), but only to the extent that they can later offset
the undesired changes in expected cash flows during the period in which the
hedged cash flows affect earnings. Other comprehensive income consists of those
financial items that are included in "accumulated other comprehensive
income/loss" on the balance sheet but not included within net income on the
statement of income. Thus, in highly effective cash flow hedges, where there is
no ineffectiveness, other comprehensive income changes by exactly as much as the
change in the value of the derivative contacts and there is no impact on
earnings.
To the contrary, the portion of the change in the value of derivative
contracts that is not effective in offsetting undesired changes in expected cash
flows (the ineffective portion), as well as any component excluded from the
computation of the effectiveness of the derivative contracts, is required to be
recognized currently in earnings. Accordingly, as a result of ineffective
hedges, we recognized a loss of $1.3 million during 2006, a loss of $0.6 million
during 2005 and a gain of $0.1 million during 2004. All of the gains and losses
we recognized as a result of ineffective hedges are reported within the captions
"Natural gas sales," "Gas purchases and other costs of sales," and "Product
sales and other" in our accompanying consolidated statements of income, and for
each of the years ended December 31, 2006, 2005 and 2004, we did not exclude any
component of the derivative contracts' gain or loss from the assessment of hedge
effectiveness.
When the hedged sales and purchases take place and we record them into
earnings, or when a determination is made that a forecasted transaction will no
longer occur by the end of the originally specified time period or within an
additional two-month period of time thereafter, the gains and losses from the
effective portion of the change in the value of the derivative contracts are
removed from "accumulated other comprehensive income/loss" on the balance sheet
and reclassified into earnings. During the years 2006, 2005 and 2004, we
reclassified $428.1 million, $424.0 million and $192.3 million, respectively, of
"Accumulated other comprehensive loss" into earnings.
With the exception of the $2.9 million loss resulting from the
discontinuance of cash flow hedges related to the sale of our Douglas gathering
assets (described in Note 2), none of the reclassification of Accumulated other
comprehensive loss into earnings during 2006, 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 or within an additional two-month period of time thereafter, but rather
resulted from the hedged forecasted transactions actually affecting earnings
(for example, when the forecasted sales and purchases actually occurred).
Our consolidated "Accumulated other comprehensive loss" balance reported on
our accompanying consolidated balance sheets was $841.6 million as of December
31, 2006 and $1,079.7 million as of December 31, 2005. Included in these
consolidated totals were "Accumulated other comprehensive loss" amounts
associated with our commodity price risk management activities of $838.7 million
as of December 31, 2006 and $1,079.4 million as of December 31, 2005.
Approximately $344.3 million of our $838.7 million "Accumulated other
comprehensive loss" amount associated with our commodity price risk management
activities as of December 31, 2006 is expected to be reclassified into earnings
during the next twelve months.
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Fair Value of Energy Commodity Derivative Contracts
Derivative contracts represent rights or obligations that meet the
definitions of assets or liabilities and should be reported in financial
statements. Furthermore, SFAS No. 133 requires derivative contracts to be
reflected as assets or liabilities at their fair market values and current
market values should be used to track changes in derivative holdings; that is,
mark-to-market valuation should be employed. The fair value of our energy
commodity derivative contracts reflect 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 energy commodity derivative
contracts that we use, including: commodity futures and options contracts, fixed
price swaps, and basis swaps.
The fair values of our energy commodity derivative contracts are included
in our accompanying consolidated balance sheets within "Other current assets,"
"Deferred charges and other assets," "Accrued other current liabilities," "Other
long-term liabilities and deferred credits," and, as of December 31, 2005 only,
"Accounts payable-Related parties." The following table summarizes the fair
values of our energy commodity derivative contracts associated with our
commodity price risk management activities and included on our accompanying
consolidated balance sheets as of December 31, 2006 and December 31, 2005 (in
thousands):
December 31, December 31,
2006 2005
------------ ------------
Derivatives-net asset/(liability)
Other current assets..................................... $ 91,939 $ 109,437
Deferred charges and other assets........................ 12,729 47,682
Accounts payable-Related parties......................... -- (16,057)
Accrued other current liabilities........................ (431,365) (507,306)
Other long-term liabilities and deferred credits......... $ (510,203) $ (727,929)
Given our portfolio of businesses as of December 31, 2006, our principal
use of energy commodity derivative contracts 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, 2006, 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, 2006, our energy commodity derivative contracts and
over-the-counter swaps and options (in thousands) consisted of the following:
Over the
Counter
Swaps and
Commodity Options
Contracts Contracts Total
--------- ----------- ---------
(Number of contracts(1))
Natural Gas
Notional Volumetric Positions: Long................... 143 1,904 2,047
Notional Volumetric Positions: Short.................. (216) (1,616) (1,832)
Net Notional Totals to Occur in 2007.................. (73) 208 135
Net Notional Totals to Occur in 2008 and Beyond....... -- 80 80
Crude Oil
Notional Volumetric Positions: Long................... -- 2,985 2,985
Notional Volumetric Positions: Short.................. -- (55,835) (55,835)
Net Notional Totals to Occur in 2007.................. -- (11,963) (11,963)
Net Notional Totals to Occur in 2008 and Beyond....... -- (40,887) (40,887)
Natural Gas Liquids
Notional Volumetric Positions: Long................... -- 10 10
Notional Volumetric Positions: Short.................. -- (360) (360)
Net Notional Totals to Occur in 2007.................. -- (350) (350)
Net Notional Totals to Occur in 2008 and Beyond....... -- -- --
192
- ----------
(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 contracts we entered into with
counterparties outside centralized trading facilities such as a futures, options
or stock exchange. These contracts are with a number of parties, all of which
had investment grade credit ratings as of December 31, 2006. We both owe money
and are owed money under these derivative contracts. 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 contracts 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.
In addition, in conjunction with the purchase of exchange-traded derivative
contracts or when the market value of our derivative contracts 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, 2006, we had three outstanding
letters of credit totaling $243.0 million in support of our hedging of commodity
price risks associated with the sale of natural gas, natural gas liquids and
crude oil. As of December 31, 2005, we had five outstanding letters of credit
totaling $534 million in support of our hedging of commodity price risks.
As of December 31, 2006, we had no cash margin deposits associated with our
commodity contract positions and over-the-counter swap partners; however, our
counterparties associated with our commodity contract positions and
over-the-counter swap agreements had margin deposits with us totaling $2.3
million, and we reported this amount within "Accrued other liabilities" in our
accompanying consolidated balance sheet as of December 31, 2006. As of December
31, 2005, we had no cash margin deposits associated with our commodity contract
positions and over-the-counter swap partners.
Interest Rate Risk Management
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
both December 31, 2006 and December 31, 2005, we were a party to interest rate
swap agreements with notional principal amounts of $2.1 billion. We entered into
these agreements for the purposes of:
o hedging the interest rate risk associated with our fixed rate debt
obligations; and
o transforming 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.
Since the fair value of fixed rate debt varies with changes in the market
rate of interest, we enter into swap agreements to receive a fixed and pay a
variable rate of interest. Such swaps result in future cash flows that vary with
the market rate of interest, and therefore hedge against changes in the fair
value of our fixed rate debt due to market rate changes. As of December 31,
2006, 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:
o $200 million principal amount of our 5.35% senior notes due August 15,
2007;
o $250 million principal amount of our 6.30% senior notes due February
1, 2009;
o $200 million principal amount of our 7.125% senior notes due March 15,
2012;
o $250 million principal amount of our 5.0% senior notes due December
15, 2013;
193
o $200 million principal amount of our 5.125% senior notes due November
15, 2014;
o $300 million principal amount of our 7.40% senior notes due March 15,
2031;
o $200 million principal amount of our 7.75% senior notes due March 15,
2032;
o $400 million principal amount of our 7.30% senior notes due August 15,
2033; and
o $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, 2006, 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.
The swap agreements related to our 7.40% senior notes contain mutual
cash-out provisions at the then-current economic value every seven years. The
swap agreements related to our 7.125% senior notes contain cash-out provisions
at the then-current economic value 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.
Hedging effectiveness and ineffectiveness
Our interest rate swap contracts have been designated as fair value hedges
as defined by SFAS No. 133. According to the provisions of SFAS No. 133, when
derivative contracts are used to hedge the fair value of an asset, liability, or
firm commitment, then reporting changes in the fair value of the hedged item as
well as in the value of the derivative contract is appropriate, 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.
Our interest rate swap contracts meet the conditions required to assume no
ineffectiveness under SFAS No. 133 and, therefore, we have accounted for them
using the "shortcut" method prescribed by SFAS No. 133 for fair value hedges of
a fixed rate asset or liability using an interest rate swap contract.
Accordingly, we adjust the carrying value of each swap contract 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 under the swap contracts. Interest expense
is accrued monthly and paid semi-annually. When there is no ineffectiveness in
the hedging relationship, employing the shortcut method results in the same net
effect on earnings, accrual and payment of interest, net effect of changes in
interest rates, and level-yield amortization of hedge accounting adjustments as
produced by explicitly amortizing the hedge accounting adjustments on the debt.
Fair Value of Interest Rate Swap Agreements
The differences between the fair value and the original carrying value
associated with our interest rate swap agreements, that is, the derivative
contracts' changes in fair value, 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, 2006
and December 31, 2005 (in thousands):
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December 31, December 31,
2006 2005
------------ ------------
Derivatives-net asset/(liability)
Deferred charges and other assets..................... $ 65,183 $ 112,386
Other long-term liabilities and deferred credits...... (22,553) (13,917)
----------- -----------
Market value of interest rate swaps................. $ 42,630 $ 98,469
=========== ===========
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 contracts 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. As of December 31, 2006, all
of our interest rate swap agreements were with counterparties with investment
grade credit ratings.
Other
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.
15. Reportable Segments
We divide our operations into four reportable business segments:
o Products Pipelines;
o Natural Gas Pipelines;
o CO2; and
o Terminals.
Each segment uses the same accounting policies as those described in the
summary of significant accounting policies (see Note 2). We evaluate performance
principally based on each segments' earnings 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 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.
195
Financial information by segment follows (in thousands):
2006 2005 2004
------------- ------------- -------------
Revenues(a)
Products Pipelines
Revenues from external customers............. $ 776,268 $ 711,886 $ 645,249
Intersegment revenues........................ -- -- --
Natural Gas Pipelines
Revenues from external customers............. 6,577,661 7,718,384 6,252,921
Intersegment revenues........................ -- -- --
CO2
Revenues from external customers............. 736,524 657,594 492,834
Intersegment revenues........................ -- -- --
Terminals
Revenues from external customers............. 864,130 699,264 541,857
Intersegment revenues........................ 714 -- --
------------- ------------- -------------
Total segment revenues......................... 8,955,297 9,787,128 7,932,861
Less: Total intersegment revenues.............. (714) -- --
------------- ------------- -------------
Total consolidated revenues.................... $ 8,954,583 $ 9,787,128 $ 7,932,861
============= ============= =============
Operating expenses(b)
Products Pipelines............................. $ 308,296 $ 366,048 $ 191,425
Natural Gas Pipelines.......................... 6,057,753 7,254,979 5,862,159
CO2............................................ 268,111 212,636 173,382
Terminals...................................... 462,009 373,410 272,766
------------- ------------- -------------
Total segment operating expenses............... 7,096,169 8,207,073 6,499,732
Less: Total intersegment operating expenses.... (714) -- --
------------- ------------- -------------
Total consolidated operating expenses........ $ 7,095,455 $ 8,207,073 $ 6,499,732
============= ============= =============
Other expense (income)(c)
Products Pipelines............................. $ -- $ -- $ --
Natural Gas Pipelines.......................... (15,114) -- --
CO2............................................ -- -- --
Terminals...................................... (15,192) -- --
------------- ------------- -------------
Total consolidated other expense (income).... $ (30,306) $ -- $ --
============= ============= =============
Depreciation, depletion and amortization
Products Pipelines............................. $ 82,888 $ 79,199 $ 71,263
Natural Gas Pipelines.......................... 65,374 61,661 53,112
CO2............................................ 190,922 149,890 121,361
Terminals...................................... 74,541 59,077 42,890
------------- ------------- -------------
Total consol. depreciation, depletion and
amortization............................... $ 413,725 $ 349,827 $ 288,626
============= ============= =============
Earnings from equity investments(d)
Products Pipelines............................. $ 16,336 $ 28,446 $ 29,050
Natural Gas Pipelines.......................... 40,447 36,812 19,960
CO2............................................ 19,173 26,319 34,179
Terminals...................................... 214 83 1
------------- ------------- -------------
Total consolidated equity earnings........... $ 76,170 $ 91,660 $ 83,190
============= ============= =============
Amortization of excess cost of equity investments
Products Pipelines............................. $ 3,362 $ 3,350 $ 3,281
Natural Gas Pipelines.......................... 285 277 277
CO2............................................ 2,017 2,017 2,017
Terminals...................................... -- -- --
------------- ------------- -------------
Total consol. amortization of excess cost of
investments................................. $ 5,664 $ 5,644 $ 5,575
============= ============= =============
196
2006 2005 2004
------------- ------------- -------------
Interest income
Products Pipelines............................. $ 4,481 $ 4,595 $ 2,091
Natural Gas Pipelines.......................... 150 747 --
CO2............................................ -- -- --
Terminals...................................... -- -- --
------------- ------------- -------------
Total segment interest income................ 4,631 5,342 2,091
Unallocated interest income.................... 1,867 4,155 1,199
------------- ------------- -------------
Total consolidated interest income........... $ 6,498 $ 9,497 $ 3,290
============= ============= =============
Other, net-income (expense)(e)
Products Pipelines............................. $ 7,536 $ 1,516 $ (28,025)
Natural Gas Pipelines.......................... 603 1,982 9,434
CO2............................................ 808 (5) 4,152
Terminals...................................... 2,118 (220) 18,255
------------- ------------- -------------
Total segment other, net-income (expense).... 11,065 3,273 3,816
Loss from early extinguishment of debt......... -- -- (1,562)
------------- ------------- -------------
Total consolidated other, net-income (expense) $ 11,065 $ 3,273 $ 2,254
============= ============= =============
Income tax benefit (expense)(f)
Products Pipelines............................. $ (5,175) $ (10,343) $ (12,075)
Natural Gas Pipelines.......................... (1,423) (2,622) (1,895)
CO2............................................ (224) (385) (147)
Terminals...................................... (12,226) (11,111) (5,609)
------------- ------------- -------------
Total consolidated income tax benefit
(expense).................................. $ (19,048) $ (24,461) $ (19,726)
============= ============= =============
Segment earnings(g)
Products Pipelines............................. $ 404,900 $ 287,503 $ 370,321
Natural Gas Pipelines.......................... 509,140 438,386 364,872
CO2............................................ 295,231 318,980 234,258
Terminals...................................... 333,592 255,529 238,848
------------- ------------- -------------
Total segment earnings....................... 1,542,863 1,300,398 1,208,299
Interest and corporate administrative
expenses(h).................................. (570,720) (488,171) (376,721)
Total consolidated net income................ $ 972,143 $ 812,227 $ 831,578
============= ============= =============
Segment earnings before depreciation, depletion,
amortization and amortization of excess cost of
equity investments(i)
Products Pipelines............................. $ 491,150 $ 370,052 $ 444,865
Natural Gas Pipelines.......................... 574,799 500,324 418,261
CO2............................................ 488,170 470,887 357,636
Terminals...................................... 408,133 314,606 281,738
------------- ------------- -------------
Total segment earnings before DD&A........... 1,962,252 1,655,869 1,502,500
Consolidated depreciation and amortization..... (413,725) (349,827) (288,626)
Consolidated amortization of excess cost of
investments.................................. (5,664) (5,644) (5,575)
Interest and corporate administrative expenses. (570,720) (488,171) (376,721)
------------- ------------- -------------
Total consolidated net income................ $ 972,143 $ 812,227 $ 831,578
============= ============= =============
Capital expenditures(j)
Products Pipelines............................. $ 195,949 $ 271,506 $ 213,746
Natural Gas Pipelines.......................... 271,624 102,914 106,358
CO2............................................ 283,014 302,032 302,935
Terminals...................................... 307,678 186,604 124,223
------------- ------------- -------------
Total consolidated capital expenditures...... $ 1,058,265 $ 863,056 $ 747,262
============= ============= =============
Investments at December 31
Products Pipelines............................. $ 211,076 $ 223,729 $ 223,196
Natural Gas Pipelines.......................... 197,876 177,105 174,296
CO2............................................ 16,168 17,938 15,503
Terminals...................................... 480 541 260
------------- ------------- -------------
Total consolidated investments............... $ 425,600 $ 419,313 $ 413,255
============= ============= =============
197
2006 2005 2004
------------- ------------- -------------
Assets at December 31
Products Pipelines............................. $ 3,910,612 $ 3,873,939 $ 3,651,657
Natural Gas Pipelines.......................... 3,942,786 4,139,969 3,691,457
CO2............................................ 1,838,223 1,772,756 1,527,810
Terminals...................................... 2,364,001 2,052,457 1,576,333
------------- ------------- -------------
Total segment assets......................... 12,055,622 11,839,121 10,447,257
Corporate assets(k)............................ 190,772 84,341 105,685
------------- ------------- -------------
Total consolidated assets.................... $ 12,246,394 $ 11,923,462 $ 10,552,942
============= ============= =============
(a) 2006 amounts include a reduction of $1,819 to our CO2 business segment from
a loss on derivative contracts used to hedge forecasted crude oil sales.
(b) Includes natural gas purchases and other costs of sales, operations and
maintenance expenses, fuel and power expenses and taxes, other than income
taxes. 2006 amounts include expenses of $13,458 to our Products Pipelines
business segment and $1,500 to our Natural Gas Pipelines business segment
associated with environmental liability adjustments. 2006 amounts also
include a $6,244 reduction in expense to our natural Gas Pipelines business
segment due to the release of a reserve related to a natural gas
purchase/sales contract, and a $2,792 increase in expense to our Terminals
business segment related to hurricane clean-up and repair activities. 2005
amounts include a rate case liability adjustment resulting in a $105,000
expense to our Products Pipelines business segment, a North System liquids
inventory reconciliation adjustment resulting in a $13,691 expense to our
Products Pipelines business segment, and 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 expense to our CO2 business segment and a $3,535
expense to our Terminals business segment.
(c) 2006 amounts include a $15,114 gain to our Natural Gas Pipelines business
segment from the combined sale of our Douglas natural gas gathering system
and our Painter Unit fractionation facility, and a $15,192 gain to our
Terminals business segment from property casualty indemnifications.
(d) 2006 amounts include a $4,861 increase in expense to our Products Pipelines
business segment associated with environmental liability adjustments on
Plantation Pipe Line Company.
(e) 2006 amounts include a $5,700 increase in income to our Products Pipelines
business segment from the settlement of transmix processing contracts. 2004
amounts include environmental liability adjustments resulting in a $30,611
expense to our Products Pipelines business segment, a $7,602 earnings
increase to our Natural Gas Pipelines business segment, a $4,126 earnings
increase to our CO2 business segment and an $18,651 earnings increase to
our Terminals business segment.
(f) 2006 amounts include a $1,871 decrease in expense to our Products Pipelines
business segment associated with the tax effect on expenses from
environmental liability adjustments made by Plantation Pipe Line Company
and described in footnote (c), and a $1,125 increase in expense to our
Terminals business segment associated with hurricane expenses and casualty
gain. 2004 amounts include an $80 increase in expense to our Terminals
business segment related to environmental expense adjustments described in
footnote (d).
(g) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses, other
expense (income), depreciation, depletion and amortization, and
amortization of excess cost of equity investments.
(h) Includes unallocated interest income, interest and debt expense, general
and administrative expenses, minority interest expense and loss from early
extinguishment of debt (2004 only).
(i) Includes revenues, earnings from equity investments, income taxes,
allocable interest income and other, net, less operating expenses and other
expense (income).
(j) Includes sustaining capital expenditures of $125,360 in 2006, $140,805 in
2005 and $119,244 in 2004. Sustaining capital expenditures are defined as
capital expenditures which do not increase the capacity of an asset.
(k) Includes cash, cash equivalents, certain unallocable deferred charges, and
risk management assets related to the market value of interest rate swaps.
We do not attribute interest and debt expense to any of our reportable
business segments. For each of the years ended December 31, 2006, 2005 and 2004,
we reported (in thousands) total consolidated interest expense of $337,997,
$268,358 and $196,172, respectively.
198
Our total operating revenues are derived from a wide customer base. For
each of the years ended December 31, 2006 and 2005, no revenues from
transactions with a single external customer amounted to 10% or more of our
total consolidated revenues. For the year ended December 31, 2004, 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% of our total consolidated revenues during 2004.
16. Litigation, Environmental and Other Contingencies
Federal Energy Regulatory Commission Proceedings
SFPP, L.P.
SFPP, L.P. is the subsidiary limited partnership that owns our Pacific
operations, excluding CALNEV Pipe Line LLC and related terminals acquired from
GATX Corporation. Tariffs charged by SFPP are subject to certain proceedings at
the FERC, including shippers' complaints and protests 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 part of ConocoPhillips Company). The FERC has ruled that the
complainants have the burden of proof in this proceeding.
In this Note, we refer to SFPP, L.P. as SFPP; CALNEV Pipe Line LLC as
Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as
Navajo; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP;
Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as
Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as
ExxonMobil; Tosco Corporation as Tosco; and ConocoPhillips Company as
ConocoPhillips.
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
199
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 Court of
Appeals for the District of Columbia Circuit, referred to in this report as D.C.
Circuit. Certain of those petitions were dismissed by the D.C. Circuit as
premature, and the remaining petitions were held in abeyance pending completion
of agency action. However, in December 2002, the D.C. Circuit 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. In this Note, we refer to
Ultramar Diamond Shamrock Corporation as Ultramar and we refer to Valero Energy
Corporation as Valero.
Briefing in the D.C. Circuit was completed in August 2003, and oral
argument took place on November 12, 2003. On July 20, 2004, the D.C. Circuit
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 (BP West Coast Products, LLC v. FERC), addressing in part
the tariffs of SFPP. 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 D.C. Circuit 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 and
was based on the record in that case.
The D.C. Circuit 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
200
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 D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit 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
FERC'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."
The D.C. Circuit 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 D.C. Circuit also rejected:
o Navajo's argument that its prior settlement with SFPP's predecessor
did not limit its right to seek reparations;
o 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;
o 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
o 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.
201
On September 2, 2004, BP WCP, Chevron, ConocoPhillips and ExxonMobil filed
a petition for rehearing and rehearing en banc asking the D.C. Circuit 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 D.C. Circuit denied both petitions without
further comment.
On November 2, 2004, the D.C. Circuit 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 D.C.
Circuit'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.
The FERC's decision in Docket No. PL05-5 has been appealed to the D.C. Circuit
(discussed further below in relation to the OR96-2 proceedings). Oral argument
was held on December 12, 2006, but the D.C. Circuit has not yet issued an
opinion.
On December 17, 2004, the D.C. Circuit 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 D.C. Circuit 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 D.C. Circuit's 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 WCP
and ExxonMobil also filed a petition for certiorari, on December 30, 2004,
seeking review of the D.C. Circuit's ruling that there was no pending
investigation of West Line rates at the time of enactment of the Energy Policy
Act (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 WCP and ExxonMobil.
On June 1, 2005, the FERC issued its Order on Remand and Rehearing,
referred to in this report as the June 2005 Order, which addressed issues in
both the OR92-8 and OR96-2 proceedings (discussed following).
With respect to the OR92-8 proceedings, the June 2005 Order ruled on
several issues that had been remanded by the D.C. Circuit in BP West Coast
Products, LLC v. FERC. 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
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further proceedings on the non-grandfathered West Line turbine fuel rate until
completion of its review of the initial decision in Phase II 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 discussed further below.
Petitions for review of the June 2005 Order by the D.C. Circuit have been
filed by SFPP, Navajo, Western Refining, BP WCP, ExxonMobil, Chevron,
ConocoPhillips, Ultramar, Inc. and Valero. SFPP moved to intervene in the review
proceedings brought by the other parties. The proceedings before the D.C.
Circuit are addressed further below.
On December 16, 2005, the FERC issued its Order on Initial Decision and on
Certain Remanded Cost Issues, referred to in this report as the December 2005
Order, 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 2005 Order required SFPP to submit a
revised East Line cost of service filing following FERC's rulings regarding the
income tax allowance and the ruling in the June 2005 Order regarding the
allocation of litigation costs. SFPP filed 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
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 2005 Order.
Watson Station proceedings. The FERC's June 2005 Order initiated a separate
proceeding regarding the reasonableness of the Watson Station charge. All
Watson-related issues in Docket No. OR92-8, Docket No. OR96-2 and other dockets
were also consolidated in that proceeding. After discovery and the filing of
prepared direct testimony, the procedural schedule was suspended while the
parties pursued settlement negotiations.
On May 17, 2006, the parties entered into a settlement agreement and filed
an offer of settlement with the FERC. On August 2, 2006, the FERC approved the
settlement without modification and directed that it be implemented. Pursuant to
the settlement, SFPP filed a new tariff, which took effect September 1, 2006,
lowering SFPP's going-forward rate to $0.003 per barrel and including certain
volumetric pumping rates. SFPP also paid refunds to all shippers for the period
from April 1, 1999 through August 31, 2006. Those refunds were based upon the
difference between the Watson Station charge as filed in SFPP's prior tariffs
and the reduced charges set forth in the agreement.
On September 28, 2006, SFPP filed a refund report with the FERC, setting
forth the refunds that had been paid and describing how the refund calculations
were made. ExxonMobil protested the refund report (BP WCP also originally
protested the report, but later withdrew its protest). On December 5, 2006, the
FERC approved SFPP's refund report with respect to all shippers except
ExxonMobil. On December 5, 2006, the FERC remanded the ExxonMobil refund issue
to the administrative law judge for a determination as to whether additional
funds were due ExxonMobil; the FERC accepted the refund report as to all other
amounts and the recipients contained in the report. In February 2007, SFPP and
ExxonMobil reached agreement regarding ExxonMobil's protest of the refund
report, and the protest was withdrawn. As of December 31, 2006, SFPP had made
aggregate payments, including accrued interest, of $19.1 million.
For the period prior to April 1, 1999, the parties agreed to reserve for
briefing issues related to whether shippers are entitled to reparations. To the
extent any reparations are owed, the parties agreed on how reparations would be
calculated. Initial briefs regarding the reserved legal issues were filed on
November 15, 2006. Reply briefs were due on February 8, 2007, with oral
argument, if convened, to occur on March 1, 2007. The scheduled issuance date
for the initial decision is March 29, 2007.
On January 16, 2007, SFPP and ExxonMobil informed the presiding judge that
they had reached a settlement in principle regarding the ExxonMobil refund
issue.
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
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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.
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.
On December 8, 2006, the FERC issued its order on the initial decision in
the Sepulveda proceeding. The FERC affirmed the administrative law judge's
decision that the Sepulveda rate should have been lower but disagreed with the
administrative law judge's rulings on some aspects of the equity
cost-of-capital, income tax allowances, and the recovery of SFPP's litigation
costs. The December 8 order directed SFPP to file revised Sepulveda rates for
1995 and 1996 and to submit a compliance filing estimating reparations and
refunds. The compliance filing, related tariff adjustments, and requests for
rehearing were made on February 7, 2007.
OR96-2; OR97-2; OR98-1. et al. proceedings. In October 1996, Ultramar, Inc.
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 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 Refining
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
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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 I initial
decision, referred to in this report as the March 2004 Order. The March 2004
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 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 March 2004
Order. The March 2004 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 2005 Order on Phase II issues. The March 2004
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 D.C. Circuit
in its review of the FERC's Opinion No. 435 orders; as noted above, the FERC
held in its June 2005 Order that the Watson Station fee is not grandfathered.
Several of the participants in the proceeding requested rehearing of the March
2004 Order. The FERC denied those requests in its June 2005 Order. In addition,
several participants, including SFPP, filed petitions with the D.C. Circuit for
review of the March 2004 Order. In August 2005, the FERC and SFPP jointly moved
that the D.C. Circuit hold the petitions for review of the March 2004 and June
2005 Orders in abeyance due to the pendency of further action before the FERC on
income tax allowance issues. In December 2005, the D.C. Circuit denied this
motion and placed the petitions seeking review of the two orders on the active
docket. Initial briefs to the Court were filed May 30, 2006, and final briefs
were filed October 19, 2006. Oral argument was held on December 12, 2006.
On July 24, 2006, the FERC filed with the D.C. Circuit a motion for
voluntary partial remand, requesting that the portion of the March 2004 and June
2005 Orders in which the FERC removed grandfathering protection from SFPP's West
Line rates and affirmed such protection for the North Line and Oregon Line rates
be returned to the FERC for reconsideration in light of arguments presented by
SFPP and other parties in their initial briefs. In response to the FERC's remand
motion, SFPP filed on August 1, 2006 to reinstate its West Line rates at the
previous, grandfathered level effective August 2, 2006, and asked for FERC
approval of such reinstatement on the ground that, pending the FERC's
reconsideration of its grandfathering rulings, the prior grandfathered rate
level is the lawful rate. On August 17, 2006, the D.C. Circuit denied without
prejudice the FERC's motion for voluntary partial remand. In light of this
denial, on August 31, 2006, the FERC issued an order rejecting SFPP's August 1,
2006 filing seeking reinstatement of SFPP's grandfathered West Line rates.
In the June 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 that the FERC's policy statement
and its decision in these cases have been appealed to the federal courts.
On September 9, 2004, the presiding administrative law judge in OR96-2
issued his initial decision in the Phase II 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.
In the December 2005 Order, the FERC addressed issues remanded by the D.C.
Circuit in the Docket No. OR92-8 proceeding (discussed above) and the cost of
service issues arising from the initial decision in Phase II of OR96-2,
including income tax allowance issues arising from the briefing directed by the
FERC's June 2005 Order. The FERC directed SFPP to submit compliance filings and
revised tariffs by February 28, 2006 (as extended to March 7, 2006) which were
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
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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 2005
Order. ExxonMobil, BP WCP, Chevron, Ultramar, Inc. and ConocoPhillips have filed
petitions for review of the December 2005 Order with the D.C. Circuit. On
February 13, 2006, the FERC issued an order, referred to in this report as the
February 2006 Order, addressing the pending rehearing requests, granting the
majority of SFPP's requested changes regarding reparations and methodological
issues. SFPP, Navajo, and other parties have filed petitions for review of the
December 2005 and February 2006 Orders with the D.C. Circuit. On July 31, 2006,
the D.C. Circuit held the appeals of these orders in abeyance pending further
FERC action.
On March 7, 2006, SFPP filed its compliance filings and revised tariffs.
Various shippers filed protests of the tariffs. On April 21, 2006, various
parties submitted comments challenging aspects of the costs of service and rates
reflected in the compliance filings and tariffs. On April 28, 2006, the FERC
issued an order accepting SFPP's tariffs lowering its West Line and East Line
rates in conformity with the FERC's December 2005 and February 2006 Orders. On
May 1, 2006, these lower tariff rates became effective. The FERC indicated that
a subsequent order would address the issues raised in the comments. On May 1,
2006, SFPP filed reply comments.
In accordance with the FERC's December 2005 Order, rate reductions were
implemented on May 1, 2006. We assume that reparations and accrued interest
thereon will be paid no earlier than the second 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, OR96-2, and IS05-230 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 December
2005 Order and February 2006 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. We estimate that the actual, partial year impact on 2006 distributable
cash flow was approximately $15.7 million.
We are not able to predict with certainty the final outcome of the pending
FERC proceedings involving SFPP, should they be carried through to their
conclusion, or whether we can reach a settlement with some or all of the
complainants. 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.
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 D.C. Circuit.
On July 2, 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 D.C. Circuit.
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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 D.C. Circuit, 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 D.C.
Circuit 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 WCP and ExxonMobil,
ConocoPhillips, Navajo and Chevron all filed timely motions to intervene in this
proceeding. Valero Marketing and Supply Company, referred to in this Note as
Valero Marketing, 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 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 WCP and ExxonMobil
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, Navajo, and Western Refining 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 WCP and ExxonMobil, Navajo, and
Western Refining 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 WCP 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.
Consolidated Complaints. On February 13, 2006, the FERC consolidated the
complaints in Docket Nos. OR03-5, 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. A procedural
schedule was established in that consolidated proceeding. The FERC also
indicated in its 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. On September 5, 2006, the presiding administrative
law judge suspended the procedural
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schedule in Docket No. OR03-5 pending a decision by the D.C. Circuit regarding
various issues before the court that directly impact the Docket No. OR03-5
proceeding.
Docket No. OR07-1. On December 1, 2006, Tesoro Refining and Marketing
Company, referred to in this Note as Tesoro, filed a complaint against SFPP
challenging the rate that SFPP charges for interstate transportation on its
North Line. Tesoro seeks rate reductions and reparations for two years prior to
the filing of the complaint. SFPP filed an answer to the complaint on January 2,
2007. The FERC has not yet issued a ruling in Docket No. OR07-1.
Docket No. OR07-2. On December 12, 2006, Tesoro filed a complaint against
SFPP alleging that SFPP's interstate West Line rates are unjust and
unreasonable. Tesoro seeks rate reductions and reparations for two years prior
to the filing of the complaint. SFPP filed an answer to the complaint on January
11, 2007. The FERC has not yet issued a ruling in Docket No. OR07-2.
Docket No. OR07-3. BP WCP, Chevron, ExxonMobil, Tesoro, and Valero
Marketing filed a complaint and motion for summary disposition on December 20,
2006 in Docket No. OR07-3 that challenged the justness and reasonableness of
SFPP's North Line index rate increase in Docket No. IS05-327. The complaint
requests refunds and reparations for shipments made under the indexed rates from
July 1, 2005. SFPP filed an answer to this complaint on January 9, 2007. The
FERC has not yet issued a ruling in Docket No. OR07-3.
Docket No. OR07-4. On January 5, 2007, BP WCP, ExxonMobil, and Chevron
filed a complaint against SFPP, Kinder Morgan GP, Inc., and Kinder Morgan, Inc.
alleging that none of SFPP's current rates or terms of service are just and
reasonable under the Interstate Commerce Act. Complainants seek reparations with
interest for the two years prior to the filing of this complaint. The answer to
this complaint was due on February 5, 2007.
Docket No. OR07-6. ConocoPhillips filed a complaint on January 9, 2007 that
challenged the justness and reasonableness of SFPP's North Line index rate
increases in Docket Nos. IS05-327 and IS06-356. The complaint requests refunds
and reparations for shipments made under the indexed rates from July 1, 2005.
SFPP filed an answer to ConocoPhillips' complaint, and the FERC has not yet
issued a ruling in Docket No. OR07-6.
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, referred to in this Note as the Concord to Sacramento segment. 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. A hearing was held in January and
February 2006, and the presiding administrative law judge issued his initial
decision on September 25, 2006.
The initial decision held that SFPP should be allowed to include in its
rate base all costs associated with relocating the Concord to Sacramento
Segment, but to include only 14/20ths of the cost of constructing the new line;
it further held that the FERC's policy statement on income tax allowance is
inconsistent with the D.C. Circuit's decision in BP West Coast Products, LLC v.
FERC and that, therefore, SFPP should be allowed no income tax allowance. While
the initial decision held that SFPP could recover its litigation costs, it
otherwise made rulings generally adverse to SFPP on cost of service issues.
These issues included the capital structure to be used in computing SFPP's
"starting rate base," treatment of SFPP's accumulated deferred income tax
account, costs of debt and equity, as well as allocation of overhead. Briefs on
exceptions were filed on October 25, 2006, and briefs opposing exceptions were
filed on November 14, 2006. The FERC has not yet reviewed the initial decision,
and it is not possible to predict the outcome of FERC or appellate review.
East Line rate case, IS06-283 proceeding. In May 2006, SFPP filed to
increase its East Line interstate rates to reflect increased costs, principally
due to the installation of replacement pipe between El Paso, Texas and Tucson,
Arizona, significantly increasing the East Line's capacity. Under FERC
regulations, SFPP was required to demonstrate that there was a substantial
divergence between the revenues generated by its existing East Line rates and
its increased costs. SFPP's rate increase was protested by various shippers and
accepted subject to refund by the FERC. FERC established an investigation and
hearing before an administrative law judge. On November 22, 2006, the chief
judge suspended the procedural schedule in this docket pending resolution of
certain issues pending before the D.C. Circuit.
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Index Increases, IS06-356, IS05-327. On May 27, 2005, SFPP filed to
increase certain rates pursuant to the FERC's indexing methodology. Various
shippers protested, and the FERC accepted and suspended all but one of the filed
tariffs, subject to SFPP's filing of a revised Page 700 of its FERC Form 6 and
subject to the outcome of various proceedings involving SFPP at the FERC. BP WCP
and ExxonMobil filed for rehearing and challenged the revised Page 700 filed by
SFPP. On December 12, 2005, the FERC denied the request for rehearing; this
decision is currently on appeal before the D.C. Circuit. Initial and final
briefs have been filed, and oral argument was held on February 15, 2007.
On May 30, 2006, SFPP also filed to increase certain interstate rates
pursuant to the FERC's indexing methodology. This filing was protested, but the
FERC determined that SFPP's tariff filing was consistent with the FERC's
regulations. Certain shippers requested rehearing, which the FERC granted for
further consideration on August 21, 2006. The FERC's order has been appealed to
the D.C. Circuit. On August 31, 2006, the FERC filed a motion with the D.C.
Circuit to hold the case in abeyance, and SFPP and BP WCP subsequently
intervened. The Court has not yet issued a ruling on the motions filed by the
FERC, SFPP, and BP WCP. On December 6, 2006, the FERC rescinded the July 1, 2006
index increase to SFPP's East Line rates and ordered SFPP to refund the East
Line index increase to shippers back to the effective date of July 1, 2006. On
January 5, 2007, SFPP filed a request for rehearing of the FERC's December 6,
2006 order, but the FERC has not yet ruled on the request for rehearing.
ULSD Surcharge, IS06-508. On August 11, 2006, SFPP filed tariffs to include
a per barrel Ultra Low Sulfur Diesel (referred to in this Note as ULSD) recovery
fee on all diesel products. Various shippers protested the filing, and, on
September 8, 2006, the FERC accepted the tariffs, subject to refund, and
established hearing procedures. SFPP has withdrawn the tariffs containing the
ULSD surcharge, and the FERC vacated the procedural schedule in this docket on
October 17, 2006.
Motions to Compel Payment of Interim Damages. On November 21, 2006, a
number of SFPP shippers filed a motion with the FERC to compel SFPP and/or
Kinder Morgan GP, Inc. and/or Kinder Morgan, Inc. to pay interim damages to
shippers or alternatively to put such damages in escrow pending FERC resolution
of the various complaint and protest proceedings pending against SFPP. SFPP
filed its response to this motion on December 6, 2006. Also on December 6, 2006,
the complainants in Docket No. OR04-3 filed their own motion for interim damages
and/or escrow, and SFPP filed a response to this second motion on December 21,
2006. The FERC has not yet taken any action with respect to these pending
motions.
Calnev Pipe Line LLC
Docket No. IS06-296. On May 22, 2006, Calnev filed to increase its
interstate rates pursuant to the FERC's indexing methodology applicable to oil
pipelines. Calnev's filing was protested by ExxonMobil, claiming that Calnev was
not entitled to an indexing increase in its rates based on its cost of service.
Calnev answered the protest. On June 29, 2006, the FERC accepted and suspended
the filing, subject to refund, permitting the increased rates to go into effect
on July 1, 2006. The FERC found that Calnev's indexed rates exceeded its change
in costs to a degree that warranted establishing an investigation and hearing.
However, the FERC initially directed the parties to attempt to reach a
settlement of the dispute before a FERC settlement judge. The settlement process
is proceeding.
Docket No. OR07-5. On January 8, 2007, ExxonMobil filed a complaint against
Calnev, Kinder Morgan GP, Inc., and Kinder Morgan, Inc. In the Calnev complaint,
ExxonMobil alleges that none of Calnev's current rates or terms of service are
just and reasonable under the Interstate Commerce Act. ExxonMobil seeks
reparations with interest for the two years prior to the filing of the Calnev
complaint. Calnev filed an answer to the Calnev complaint on February 7, 2007.
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 Oil Company, referred to in
this Note as Marathon, requested that the FERC require Trailblazer Pipeline
Company to refund all amounts paid by Marathon above Trailblazer Pipeline
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Company'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 Pipeline Company to bill Marathon the Expansion 2002 recourse rate
for future billings. Marathon estimated that the amount of Trailblazer Pipeline
Company's refund obligation at the time of the filing was over $15 million.
Trailblazer Pipeline Company 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 Pipeline Company 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.
California Public Utilities Commission Proceeding
ARCO, Mobil and Texaco filed a complaint against SFPP with the California
Public Utilities Commission, referred to in this Note as the CPUC, 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 at any time.
In October, 2002, the CPUC issued a resolution, referred to in this report
as the Power Surcharge 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, Ultramar Inc., BP
WCP, ExxonMobil and Chevron. 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 at any time.
With regard to the CPUC complaints and the Power Surcharge Resolution, we
currently believe the complainants/protestants seek approximately $31 million in
prospective annual tariff reductions. Based upon CPUC practice and procedure
which precludes refunds or reparations in complaints in which the complainants
challenge the reasonableness of rates previously found reasonable by the CPUC
(as is the case with the two pending complaints contesting the reasonableness of
SFPP's rates) except for matters which have been expressly reserved by the CPUC
for further consideration (as is the case with respect to the reasonableness of
the rate charged for use of the Watson Station gathering enhancement
facilities), we currently believe that complainants/protestants are seeking
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approximately $15 million in refunds/reparations. We are not able to quantify
the potential extent to which the CPUC could determine that SFPP's existing
California rates are unreasonable.
SFPP also has various, pending ratemaking matters before the CPUC that are
unrelated to the above-referenced complaints and the Power Surcharge Resolution.
On November 22, 2004, SFPP filed an application with the CPUC requesting a $9
million annual 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, Ultramar Inc., BP WCP, ExxonMobil and Chevron. Because no
schedule has been established by the CPUC for addressing the issues raised by
the contested rate increase application nor does any record exist upon which the
CPUC could base a decision, SFPP has no basis for estimating either the
prospective rate reductions or the potential refunds at issue or for
establishing a date by which the CPUC is likely to render a decision regarding
the application.
On January 26, 2006, SFPP filed a request for a rate increase of
approximately $5.4 million annually with the CPUC, to be effective as of March
2, 2006. Protests to SFPP's rate increase application have been filed by Tesoro,
BP WCP, ExxonMobil, Southwest Airlines Company, Valero Marketing, Ultramar Inc.
and Chevron, asserting that the requested rate increase is unreasonable. As a
consequence of the protests, the related rate increases are being collected
subject to refund. Because no schedule has been established by the CPUC for
addressing the issues raised by the contested rate increase application nor does
any record exist upon which the CPUC could base a decision, SFPP has no basis
for estimating either the prospective rate reductions or the potential refunds
at issue or for establishing a date by which the CPUC is likely to render a
decision regarding the application.
On August 25, 2006, SFPP filed an application to increase rates by
approximately $0.5 million annually to recover costs incurred to comply with
revised ULSD regulations and to offset the revenue loss associated with
reduction of the Watson Station Volume Deficiency Charge (intrastate) by
increasing rates on a system-wide basis by approximately $3.1 million annually
to be effective as of October 5, 2006. Protests to SFPP's rate increase
application have been filed by Tesoro, BP WCP, ExxonMobil, Southwest Airlines
Company, Valero Marketing, Ultramar Inc. and Chevron, asserting that the
requested rate increase is unreasonable. As a consequence of the protests, the
related rate increases are being collected subject to refund. Because no
schedule has been established by the CPUC for addressing the issues raised by
the contested rate increase application, nor does any record exist upon which
the CPUC could base a decision, SFPP has no basis for estimating either the
prospective rate reductions, or the potential refunds at issue, or for
establishing a date by which the CPUC is likely to render a decision regarding
the application.
All of the referenced pending matters before the CPUC have been
consolidated and assigned to a single Administrative Law Judge. The
Administrative Law Judge has referred the matters to mediation, and the
mediation process is pending.
With regard to the Power Surcharge Resolution, the November 2004 rate
increase application, the January 2006 rate increase application, and the August
2006 rate increase application, 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 rate
reductions or 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.
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Carbon Dioxide Litigation
Shores and First State Bank of Denton Lawsuits
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).
Armor/Reddy Lawsuit
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. The case is currently set for trial on June 11, 2007.
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 case is currently set for trial on June 11,
2007.
Bailey and Bridwell Oil Company Harris County/Southern District of Texas
Lawsuit
Shell CO2 Company, Ltd., predecessor to Kinder Morgan CO2 Company, L.P., is
among the named counter-claim defendants in the case originally filed as 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 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
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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 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
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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
U.S. Supreme Court denied Bailey's petition for writ of certiorari. The Houston
federal district court subsequently realigned the parties in the Bailey Houston
Federal Court Action, and the case is now styled Gerald O. Bailey et al. v.
Shell Oil Company et al. 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. The Shell and Kinder Morgan defendants,
along with Cortez Pipeline Company and ExxonMobil defendants, have filed motions
for summary judgment on all claims. No current trial date is set.
Bridwell Oil Company Wichita County Lawsuit
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 that are virtually identical to the 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.
Ptasynski Colorado Federal District Court Lawsuit
On April 7, 2006, Harry Ptasynski, one of the plaintiffs in the Colorado
federal action filed by Bailey under the False Claims Act (which was transferred
to the Bailey Houston Federal Court Action as described above), filed suit
against Kinder Morgan G.P., Inc. in Colorado federal district court. Harry
Ptasynski v. Kinder Morgan G.P., Inc., No. 06-CV-00651 (LTB) (U.S. District
Court for the District of Colorado). Ptasynski, who holds an overriding royalty
interest at McElmo Dome, asserted claims for civil conspiracy, violation of the
Colorado Organized Crime Control Act, violation of Colorado antitrust laws,
violation of the Colorado Unfair Practices Act, breach of fiduciary duty and
confidential relationship, violation of the Colorado Payment of Proceeds Act,
fraudulent concealment, breach of contract and implied duties to market and good
faith and fair dealing, and civil theft and conversion. Ptasynski sought actual
damages, treble damages, forfeiture, disgorgement, and declaratory and
injunctive relief. The Colorado court transferred the case to Houston federal
district court, and Ptasynski subsequently sought to non-suit (voluntarily
dismiss) the case. The Houston federal district court granted Ptasynski's
request to non-suit. Ptasynski also filed an appeal in the Tenth Circuit seeking
to overturn the Colorado court's order transferring the case to Houston federal
district court. Harry Ptasynski v. Kinder Morgan G.P., Inc., No. 06-1231 (10th
Cir.). Briefing in the appeal was completed on November 27, 2005. No oral
argument has been set.
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Grynberg Lawsuit
Kinder Morgan CO2 Company, L.P. and Cortez Pipeline Company were 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
involved 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 claimed breaches of contractual and potential fiduciary
duties owed by the defendants and also alleged other theories of 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 sought 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. In August
2006, plaintiffs and defendants reached a settlement of all claims. Pursuant to
the settlement, the case was dismissed with prejudice on September 27, 2006.
CO2 Claims Arbitration
Cortez Pipeline Company and Kinder Morgan CO2 Company, L.P., successor to
Shell CO2 Company, Ltd., were among the named defendants in CO2 Committee, Inc.
v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005. The
arbitration arose 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 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 alleged 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 $12 million.
The plaintiff also alleged 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 $0.5 million.
Defendants denied that there was any breach of the settlement agreement. The
arbitration hearing took place in Albuquerque, New Mexico on June 26-30, 2006.
On August 7, 2006, the arbitration panel issued its opinion finding that
defendants did not breach the settlement agreement. On October 25, 2006,
defendants in the arbitration filed an application to confirm the arbitration
decision in New Mexico federal district court. On November 6, 2006, the
plaintiff in the arbitration filed a motion to vacate the arbitration award in
Colorado federal district court. On that same day, the plaintiff in the
arbitration filed a motion to dismiss the New Mexico federal district court
application for lack of jurisdiction or, alternatively, asked the New Mexico
court to stay consideration of the application in favor of its motion to vacate
filed in the Colorado federal district court. On January 24, 2007, the Colorado
federal district court denied the plaintiff's motion to vacate the arbitration
award as moot in light of the pending application to confirm filed by defendants
in New Mexico federal district court. On January 29, 2007, the New Mexico
federal district court denied the plaintiff's motion to dismiss the New Mexico
application to confirm or to stay the New Mexico application.
MMS Notice of Noncompliance and Civil Penalty
On December 20, 2006, Kinder Morgan CO2 Company, L.P. received a "Notice of
Noncompliance and Civil Penalty: Knowing or Willful Submission of False,
Inaccurate, or Misleading Information--Kinder Morgan CO2 Company, L.P., Case No.
CP07-001" from the U.S. Department of the Interior, Minerals Management Service.
This Notice, and the MMS' position that Kinder Morgan CO2 Company, L.P. has
violated certain reporting obligations, relates to a disagreement between the
MMS and Kinder Morgan CO2 Company, L.P. concerning the approved transportation
allowance to be used in valuing McElmo Dome carbon dioxide for purposes of
calculating federal royalties. In the Notice of Noncompliance and Civil Penalty,
the MMS assesses civil penalties under section 109(d) of the Federal Oil and Gas
Royalty Management Act of 1982, which provides that "[a]ny person who - (1)
knowingly or willfully prepares, maintains, or submits false, inaccurate, or
misleading reports, notices, affidavits,
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records, data or other written information...shall be liable for a penalty of up
to $25,000.00 per violation for each day such violation continues." The Notice
of Noncompliance and Civil Penalty assesses a civil penalty of approximately
$2.2 million as of December 15, 2006 (based on a penalty of $500.00 per day for
each of seventeen alleged violations) for Kinder Morgan CO2 Company, L.P.'s
alleged submission of false, inaccurate, or misleading information relating to
the transportation allowance, and federal royalties for CO2 produced at McElmo
Dome, during the period from June 2005 through October 2006. The MMS contends
that false, inaccurate, or misleading information was submitted in the seventeen
monthly Form 2014s containing remittance advice reflecting the royalty payments
for the referenced period. The MMS contends that the 2014s were false,
inaccurate or misleading because they reflected Kinder Morgan CO2 Company,
L.P.'s use of the Cortez Pipeline tariff as the transportation allowance. The
MMS claims that the Cortez Pipeline tariff is not the proper transportation
allowance and that Kinder Morgan CO2 Company, L.P. should have used its
"reasonable actual costs" calculated in accordance with certain federal product
valuation regulations as amended effective June 1, 2005. The MMS has not,
however, identified any royalty underpayment amount due or otherwise issued an
appealable order directing that Kinder Morgan CO2 Company, L.P. pay additional
royalties or calculate the federal government's royalties in a different manner.
The MMS also stated that although it considers each line of each 2014 to
constitute a separate "violation," it is limiting the violation count to the
seventeen monthly 2014s submitted during the June 2005 through October 2006
period. The MMS stated that civil penalties will continue to accrue at the same
rate until the alleged violations are corrected. The MMS set a due date of
January 20, 2007 for Kinder Morgan CO2 Company, L.P.'s payment of the
$2,234.500.00 in civil penalties, with interest to accrue daily on that amount
in the event payment is not made by such date. Kinder Morgan CO2 Company, L.P.
has not paid the penalty. On January 2, 2007, Kinder Morgan CO2 Company, L.P.
submitted a response to the Notice of Noncompliance and Civil Penalty
challenging the assessment in the Office of Hearings and Appeals of the
Department of the Interior. On February 1, 2007, Kinder Morgan CO2 Company, L.P.
filed a petition to stay the accrual of penalties until the dispute is resolved.
On February 22, 2007, an administrative law judge of the U.S. Department of the
Interior issued an order denying Kinder Morgan CO2 Company, L.P.'s petition to
stay the accrual of penalties. Kinder Morgan CO2 Company, L.P. is reviewing the
order of the administrative law judge and evaluating potential appellate
options.
Kinder Morgan CO2 Company, L.P. disputes the Notice of Noncompliance and
Civil Penalty for a number of reasons. Kinder Morgan CO2 Company, L.P. contends
that use of the Cortez pipeline tariff as the transportation allowance for
purposes of calculating federal royalties was approved by the MMS in 1984. This
approval was later affirmed as open-ended by the Interior Board of Land Appeals
in the 1990s. Accordingly, Kinder Morgan CO2 Company, L.P. has stated to the MMS
that its use of the Cortez tariff as the approved federal transportation
allowance is authorized and proper. Kinder Morgan CO2 Company, L.P. also
disputes the allegation that it has knowingly or willfully submitted false,
inaccurate, or misleading information to the MMS. Kinder Morgan CO2 Company,
L.P.'s use of the Cortez Pipeline tariff as the approved federal transportation
allowance has been the subject of extensive discussion between the parties. The
MMS was, and is, fully apprised of that fact and of the royalty valuation and
payment process followed by Kinder Morgan CO2 Company, L.P. generally.
As noted, the Notice of Noncompliance and Civil Penalty does not purport to
identify a royalty underpayment. If, however, the MMS were to assert such a
claim, the difference between the federal royalties actually paid in the June
2005 through October 2006 period and those it is thought that the government
would urge as due is estimated at approximately $2.7 million. No pre-hearing
hearing date or pre-hearing schedule has been set in this matter.
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)
This case 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-
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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 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. Kinder Morgan appealed that ruling to the New Mexico Court of
Appeals. Oral arguments took place before the New Mexico Court of Appeals on
March 23, 2006, and the New Mexico Court of Appeals affirmed the district
court's order on August 8, 2006. Kinder Morgan filed a petition for writ of
certiorari in the New Mexico Supreme Court. The New Mexico Supreme Court granted
the petition on October 11, 2006. Kinder Morgan filed its Brief in Chief in the
New Mexico Supreme Court on December 12, 2006. No oral argument has been set.
In addition to the matters listed above, audits and administrative
inquiries concerning Kinder Morgan CO2 Company L.P.'s payments on carbon dioxide
produced from the McElmo Dome Unit are currently ongoing. These audits and
inquiries involve federal agencies and the State of Colorado.
Commercial Litigation Matters
Union Pacific Railroad Company Easements
SFPP, L.P. and Union Pacific Railroad Company (the successor to Southern
Pacific Transportation Company and referred to in this report as UPRR) 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).
With regard to the first proceeding, covering the ten year period beginning
January 1, 1994, the trial court, on July 16, 2003, 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.
In April 2006, we paid UPRR $15.3 million in satisfaction of our rental
obligations through December 31, 2003. However, we do not believe that the
assessment of interest awarded to Southern Pacific Transportation Company on
rental amounts owing as of May 7, 1997 was proper, and we sought appellate
review of the interest award. In July 2006, the Court of Appeals disallowed the
award of interest.
In addition, SFPP, L.P. and UPRR are engaged in a second 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. The trial
in this matter has commenced and is ongoing.
SFPP and UPRR are also engaged in multiple disputes over the circumstances
under which SFPP must pay for a relocation of its pipeline within the UPRR right
of way and the safety standards that govern relocations. SFPP believes that it
must pay for relocation of the pipeline only when so required by the railroad's
common carrier operations, and in doing so, it need only comply with standards
set forth in the federal Pipeline Safety Act in conducting relocations. In July
2006, a trial before a judge regarding the circumstances under which we must pay
for relocations concluded, and the judge determined in a preliminary statement
of decision that we must pay for any relocations resulting from any legitimate
business purpose of the UPRR. We expect to appeal any final statement of
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decision to this effect. In addition, UPRR contends that it has complete
discretion to cause the pipeline to be relocated at SFPP's expense at any time
and for any reason, and that SFPP must comply with the more expensive American
Railway Engineering and Maintenance-of-Way standards. Each party is seeking
declaratory relief with respect to its positions regarding relocations.
It is difficult to quantify the effects of the outcome of these cases on
SFPP because SFPP does not know UPRR's plans for projects or other activities
that would cause pipeline relocations. Even if SFPP is successful in advancing
its positions, significant relocations for which SFPP must nonetheless bear the
expense (i.e. for railroad purposes, with the standards in the federal Pipeline
Safety Act applying) would have an adverse effect on our financial position and
results of operations. These effects would be even greater in the event SFPP is
unsuccessful in one or more of these litigations.
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. On December 18, 2006, Plaintiff filed a Notice of
Non-Suit with the Zapata County District Court Clerk. With the filing of the
non-suit, this matter is concluded.
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.
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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.
On May 9, 2006, the Kinder Morgan defendants filed a Motion to Dismiss and
a Motion for Sanctions. On October 20, 2006, the United States District Court,
for the District of Wyoming, issued its Order on Report and Recommendations of
Special Master. In its Order, the Court upheld the dismissal of the claims
against the Kinder Morgan defendants on jurisdictional grounds, finding that the
Grynberg's claims are based upon public disclosures and that Grynberg does not
qualify as an original source. Grynberg has appealed this Order to the Tenth
Circuit Court of Appeals. The mediation office for the Tenth Circuit Court of
Appeals is involved and is consulting with the parties regarding possible
settlement negotiations and will not issue a procedural schedule until these
negotiations are complete. The Coordinated Defendants, which include the Kinder
Morgan defendants, filed a Motion for Authorization of Taxation of Costs on
December 18, 2006, and a Motion for Fees and Expenses on January 8, 2007.
Grynberg filed his response brief to the Kinder Morgan Defendants' Motion to
Dismiss and Motion for Sanctions on January 5, 2007. A hearing regarding the
Motion for Authorization of Taxation of Costs, Motion for Fees and Expenses, and
the Kinder Morgan Defendants' Motion to Dismiss and Motion for Sanctions is
scheduled for April 24, 2007.
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 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 parties have recently
concluded jurisdictional discovery and various defendants have filed motions
arguing that the Arkansas courts lack personal jurisdiction over them. The Court
denied these motions. 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.
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., referred to in this report as KMTP, 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 was claiming
approximately $13 million in damages. In May 2006, the parties entered into a
confidential settlement that resolved all claims in this matter. The case has
been dismissed.
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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. In September 2005 and subsequent thereto, we
responded to a subpoena in this matter by producing a large volume of documents,
which, we understand, are being reviewed by the FBI and auditors from the
Tennessee Valley Authority, which is a customer of the Cora and Grand Rivers
terminals. We believe that the federal authorities are also investigating coal
inventory practices at one or more of our other terminals. While we have no
indication of the direction of this additional investigation, our records do not
reflect any sales of excess coal from our other terminals, and we are not aware
of any wrongdoing or improper activities at our terminals. We are cooperating
fully with federal law enforcement authorities in this investigation, and expect
several of our officers and employees to be interviewed formally by federal
authorities. We do not believe there is any basis for criminal charges, and we
are engaged in discussions to resolve any possible criminal charges. 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
Claims asserted by residents and businesses. 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, referred to in this report as 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 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
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of time to respond to plaintiffs' motion for class certification in order to
conduct discovery regarding class certification. On February 10, 2006, the court
granted our motion for additional time to conduct class discovery.
In June 2006, the parties reached an agreement to partially settle the
class action suit. On June 29, 2006, the plaintiffs filed an unopposed motion
for conditional certification of a settlement class. The settlement provides for
a fund of $2.0 million to distribute to residents within the evacuation zone
("Zone 1") and residents immediately adjacent to the evacuation zone ("Zone 2").
Persons in Zones 1 and 2 reside within approximately one mile from the site of
the incident. Kinder Morgan Energy Partners agreed to participate in and fund a
minor percentage of the settlement. A fairness hearing occurred on August 18,
2006 for the purpose of establishing final approval of the partial settlement.
The court approved the settlement, entered final judgment, and certified a
settlement class for Zones 1 and 2.
One member of the Zone 1 and 2 settlement class, the Estate of George W.
Dameron, opted out of the settlement, and the Adminstratrix of the Dameron
Estate filed a wrongful death lawsuit on November 15, 2006 in the Hamilton
County Court of Common Pleas, Case No. A0609990. The complaint alleges that
styrene exposure caused the death of Mr. Dameron. Kinder Morgan is not a named
defendant in such lawsuit, but it is likely that Kinder Morgan will be joined as
a defendant, in which case Kinder Morgan intends on vigorously defending against
the estate's claim.
Certain claims by other residents and businesses remain pending.
Specifically, the Zone 1 and 2 settlement and final judgment does not apply to
purported class action claims by residents in outlying geographic zones more
than one mile from the site of the incident. Settlement discussions are
proceeding with such residents in outlying geographic zones. In addition, the
non-Kinder Morgan defendants have agreed to settle remaining claims asserted by
businesses and will obtain a release of such claims favoring all defendants,
including Kinder Morgan and its affiliates, subject to the retention by all
defendants of their claims against each other for contribution and indemnity.
Kinder Morgan expects that a claim will be asserted by other defendants against
Kinder Morgan seeking contribution or indemnity for any settlements funded
exclusively by other defendants, and Kinder Morgan expects to vigorously defend
against any such claims.
Claims asserted by the city of Cincinnati. 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. 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, the Kinder Morgan defendants filed a motion for
summary judgment seeking dismissal of the remaining aspects of the city's
complaint. Oral argument on Kinder Morgan's motions was scheduled for December
8, 2006. At the hearing, the court referred the parties to mediation. The
parties agreed to stay discovery until after the mediation, if necessary. No
trial date has been established.
Leukemia Cluster Litigation
We are a party to two wrongful death 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.
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, 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
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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 filed
motions to dismiss all causes of action excluding plaintiffs' cause of action
for negligence. Defendants also filed motions to strike portions of the
complaint. By order dated May 5, 2006, the court granted defendants' motions to
dismiss as to the counts purporting to assert claims for fraud, but denied
defendants' motions to dismiss as to the remaining counts, as well as
defendants' motions to strike. Defendant Kennametal, Inc. has filed a
third-party complaint naming the United States and the United States Navy (the
"United States") as additional defendants. In response, the United States
removed the case to the United States District Court for the District of Nevada
and filed a motion to dismiss the third-party complaint, which motion is
currently pending. Plaintiff has also filed a motion to dismiss the United
States and/or to remand the case back to state court. Briefing on these motions
has been completed and the motions remain pending.
Floyd Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326
(Second Judicial District Court, State of Nevada, County of Washoe) ("Sands").
On August 28, 2003, a separate group of plaintiffs, represented by the
counsel for the plaintiffs in the Jernee matter, individually and on behalf of
Stephanie Suzanne Sands, filed a civil action in the Nevada State trial court
against us and several Kinder Morgan related entities and individuals and
additional unrelated defendants. 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 third amended complaint and all defendants filed
motions to dismiss all causes of action excluding plaintiffs' cause of action
for negligence. Defendants also filed motions to strike portions of the
complaint. By order dated May 5, 2006, the court granted defendants' motions to
dismiss as to the counts purporting to assert claims for fraud, but denied
defendants' motions to dismiss as to the remaining counts, as well as
defendants' motions to strike. Defendant Kennametal, Inc. has filed a
third-party complaint naming the United States and the United States Navy (the
"United States") as additional defendants. In response, the United States
removed the case to the United States District Court for the District of Nevada
and filed a motion to dismiss the third-party complaint, which motion is
currently pending. Plaintiff has also filed a motion to dismiss the United
States and/or to remand the case back to state court. Briefing on these motions
has been completed and the motions remain pending.
Pipeline Integrity and Releases
Walnut Creek, California Pipeline Rupture
On November 9, 2004, excavation equipment operated by Mountain Cascade,
Inc., a third-party contractor on a water main installation project hired by
East Bay Municipal Utility District ("EBMUD"), struck and ruptured an
underground petroleum pipeline owned and operated by SFPP, L.P. 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 property damage.
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. On June 27, 2005, the Office of the California State Fire Marshal,
Pipeline Safety Division, referred to in this report as the CSFM, issued a
notice of violation against us which also alleged 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 $0.5 million. The
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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.
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. We have been notified by the Contra
Costa District Attorney's office that it intends to pursue criminal charges
against us in connection with the Walnut Creek pipeline rupture. We have
responded by reiterating our belief that the facts and circumstances do not
warrant criminal charges. We are currently engaged in discussions with the
Contra Costa District Attorney's office in an effort to resolve any possible
criminal charges. In the event that we are not able to reach a resolution, we
anticipate that the Contra Costa District Attorney will pursue criminal charges,
and we intend to defend such charges vigorously.
As a result of the accident, nineteen separate lawsuits have been filed.
Each of these lawsuits is currently coordinated in Contra Costa County Superior
Court. There are also several cross-complaints for indemnity between the
co-defendants in the coordinated lawsuits. The majority of the cases 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); Fuentes et al. v. Kinder Morgan, et al. (Contra Costa
County Superior Court Case No. C05-02286); Berry et al. v. Kinder Morgan, et al.
(Contra Costa County Superior Court Case No. C06-010524); Pena et al. v. Kinder
Morgan, et al. (Contra Costa County Superior Court Case No. C06-01051); Bower et
al. v. Kinder Morgan, et al. (Contra Costa County Superior Court Case No.
MSC06-02129 (unserved)); and Ross et al. v. Kinder Morgan, et al. (Contra Costa
County Superior Court Case No. MSC06-02299 (unserved)). These complaints all
allege, among other things, that SFPP/Kinder Morgan failed to properly field
mark the area where the accident occurred. All of these plaintiffs sought
compensatory and punitive damages. These complaints also alleged 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 named 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 named 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 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, among other things, 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.
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Following court ordered mediation, the Kinder Morgan defendants have
settled with plaintiffs in all of the wrongful death cases and many of the
personal injury and property damages cases. These settlements have either become
final by order of the court or are awaiting court approval. The cases which
remain unsettled at present are the Bower, Ross, Chabot, Matamoros, and Mountain
Cascade cases, as well as certain cross-claims for contribution and indemnity by
and between various defendants. The parties are currently continuing discovery
and court ordered mediation on the remaining cases.
Cordelia, California
On April 28, 2004, SFPP, L.P. discovered a spill of diesel fuel into a
marsh near Cordelia, California from a section of SFPP's 14-inch Concord to
Sacramento, California 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 SFPP. The damaged section of the pipeline was
removed and replaced, and the pipeline resumed operations on May 2, 2004. SFPP
has completed recovery of diesel from the marsh and has 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.
SFPP is 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. Since the April 2004 release in the Suisun Marsh area near
Cordelia, California, SFPP has cooperated fully with federal and state agencies
and has worked diligently to remediate the affected areas. As of December 31,
2005, the remediation was substantially complete.
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 and the Oakland estuary. 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.
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 asserting civil penalty claims with
respect to this release. We are currently in settlement negotiations with these
agencies. We will vigorously contest any unsupported, duplicative or excessive
civil penalty claims, but hope to be able to 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 received
civil penalty claims on behalf of the United States Environmental Protection
Agency, the California Department of Fish and Game, and the Lahontan Regional
Water Quality Control Board. We are currently in settlement negotiations with
these agencies. We will vigorously contest any unsupported, duplicative or
excessive civil penalty claims, but hope to be able to resolve the demands by
each governmental entity through out-of-court settlements.
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Baker, California
In November 2004, near Baker, California, our CALNEV Pipeline experienced a
failure in its pipeline 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. The State of California Department of Fish &
Game has alleged a small natural resource damage claim that is currently under
review. CALNEV expects to work cooperatively with the Department of Fish & Game
to resolve this claim.
Henrico County, Virginia
On April 17, 2006, Plantation Pipe Line Company, which transports refined
petroleum products across the southeastern United States and which is 51.17%
owned and operated by us, experienced a pipeline release of turbine fuel from
its 12-inch pipeline. The release occurred in a residential area and impacted
adjacent homes, yards and common areas, as well as a nearby stream. The released
product did not ignite and there were no deaths or injuries. Plantation
estimates the amount of product released to be approximately 553 barrels.
Immediately following the release, the pipeline was shut down and emergency
remediation activities were initiated. Remediation and monitoring activities are
ongoing under the supervision of the United States Environmental Protection
Agency, referred to in this report as the EPA, and the Virginia Department of
Environmental Quality, referred to in this report as the VDEQ. In February 2007,
the VDEQ proposed a civil penalty of approximately $0.8 million in this matter,
and is also seeking reimbursement for oversight costs in amounts less than $0.1
million. Plantation is evaluating the VDEQ's penalty proposal and will engage
the VDEQ in settlement discussions.
Repairs to the pipeline were completed on April 19, 2006 with the approval
of the United States Department of Transportation, Pipeline and Hazardous
Materials Safety Administration, referred to in this report as the PHMSA, and
pipeline service resumed on April 20, 2006. On April 20, 2006, the PHMSA issued
a corrective action order which, among other things, requires that Plantation
maintain a 20% reduction in the operating pressure along the pipeline between
the Richmond and Newington, Virginia pump stations while the cause is
investigated and a remediation plan is proposed and approved by PHMSA. The cause
of the release is related to an original pipe manufacturing seam defect.
Dublin, California
In June 2006, near Dublin, California, our SFPP pipeline, which transports
refined petroleum products to San Jose, California, experienced a leak,
resulting in a release of product that affected a limited area along a
recreation path known as the Iron Horse Trail. Product impacts were primarily
limited to backfill of utilities crossing the pipeline. The release was located
on land administered by Alameda County, California. Remediation and monitoring
activities are ongoing under the supervision of The State of California
Department of Fish & Game. The cause of the release was outside force damage. We
are currently investigating potential recovery against third parties.
Soda Springs, California
In August 2006, our SFPP pipeline, which transports refined petroleum
products to Reno, Nevada, experienced a failure near Soda Springs, California,
resulting in a release of product that affected a limited area along Interstate
Highway 80. Product impacts were primarily limited to soil in an area between
the pipeline and Interstate Highway 80. The release was located on land
administered by Nevada County, California. Remediation and monitoring activities
are ongoing under the supervision of The State of California Department of Fish
& Game and Nevada County. The cause of the release is currently under
investigation.
Rockies Express Pipeline LLC Wyoming Construction Incident
On November 11, 2006, a bulldozer operated by an employee of Associated
Pipeline Contractors, Inc, (a third-party contractor to Rockies Express Pipeline
LLC, referred to in this report as REX, for construction of this segment of the
new REX pipeline), struck an existing subsurface natural gas pipeline owned by
Wyoming Interstate
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Company and operated by Colorado Interstate Gas Company, both subsidiaries of El
Paso Pipeline Group. The Wyoming Interstate Company pipeline was ruptured,
resulting in an explosion and fire. The incident occurred in a rural area
approximately nine miles southwest of Cheyenne, Wyoming. The incident resulted
in one fatality (the operator of the bulldozer) and there were no other reported
injuries.
The cause of the incident is under investigation by the PHMSA, as well as
the Wyoming Occupational Safety and Health Administration. We are cooperating
with both agencies. Immediately following the incident, REX and El Paso Pipeline
Group reached an agreement on a set of additional enhanced safety protocols
designed to prevent the reoccurrence of such an incident. We have been contacted
by attorneys representing the estate and the family of the deceased bulldozer
operator regarding potential claims related to the incident. Although the
internal and external investigations are currently ongoing, based upon presently
available information, we believe that REX acted appropriately and in compliance
with all applicable laws and regulations.
Charlotte, North Carolina
On November 27, 2006, the Plantation Pipeline experienced a release of
approximately four thousand gallons of gasoline from a Plantation Pipe Line
Company block valve on a delivery line into a terminal owned by a third party
company. Upon discovery of the release, Plantation immediately locked out the
delivery of gasoline through that pipe to prevent further releases. Product had
flowed onto the surface and into a nearby stream, which is a tributary of Paw
Creek, and resulted in loss of fish and other biota. Product recovery and
remediation efforts were implemented immediately, including removal of product
from the stream. Remediation efforts are continuing under the direction of the
North Carolina Department of Environment and Natural Resources, referred to in
this report as the NCDENR, which issued a Notice of Violation and Recommendation
of Enforcement against Plantation on January 8, 2007. Plantation continues to
cooperate fully with the NCDENR, but does not believe that a penalty is
warranted given the quality of Plantation's response efforts. The line was
repaired and put back into service within a few days.
Proposed Office of Pipeline Safety Civil Penalty and Compliance Order
On July 15, 2004, the U.S. Department of Transportation's Pipeline and
Hazardous Materials Safety Administration (PHMSA) 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. PHMSA sought to have us implement a number of
changes to our integrity management program and also to impose a proposed civil
penalty of approximately $0.3 million. An administrative hearing was held on
April 11 and 12, 2005, and a final order was issued on June 26, 2006. We have
already addressed most of the concerns identified by PHMSA and continue to work
with them to ensure that our integrity management program satisfies all
applicable regulations. However, we are seeking clarification for portions of
this order and have received an extension of time to allow for discussions.
Along with the extension, we reserved our right to seek reconsideration if
needed. We have established a reserve for the $0.3 million proposed civil
penalty. Subsequent to the 2004 inspection and order, most if not all findings
have been addressed. We are currently waiting for the final report from PHMSA's
2006 reinspection of our Integrity Management Plan and we expect positive
findings. This matter is not expected to have a material impact on our business,
financial position, results of operations or cash flows.
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 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 reached an agreement in principle on the terms
of a consent agreement with the PHMSA, subject to the PHMSA's
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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 closed on March 26, 2006.
On April 10, 2006, we announced the final consent agreement, which 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 expect to spend
approximately $90 million on pipeline integrity activities for our Pacific
operations' pipelines over the next five years. Of that amount, approximately
$26 million is related to this consent agreement. Currently, we have made all
submittals required by the agreement schedule and all submittals have been found
to be acceptable. We do not expect that our compliance with the consent
agreement will have a material adverse effect on our business, financial
position, results of operations or cash flows.
Maricopa County, Arizona Order of Abatement by Consent
On December 29, 2006, we received and executed an order of abatement by
consent and settlement in the amount of $0.2 million with Maricopa County Air
Quality Department relating to a several notices of violations associated with
our Pacific operations' pipeline terminal in Phoenix, Arizona.
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
ExxonMobil Corporation v. GATX Corporation, Kinder Morgan Liquids
Terminals, Inc. and ST Services, Inc.
On April 23, 2003, ExxonMobil 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 to participate in mandatory
mediation. The parties participated in a mediation session on November 2, 2005
but no resolution was reached regarding the claims set out in the lawsuit. At
this time, the mediation judge is working with a technical consultant and
reviewing reports of scientific studies conducted at the site. We anticipate
that there will be another mediation session during the second quarter of 2007.
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The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.; Kinder
Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC;
Continental Oil Company; Chevron Corporation, California Superior Court, County
of Los Angeles, Case No. NC041463.
We are and some of our subsidiaries are defendants in a lawsuit filed in
2005 captioned The City of Los Angeles v. Kinder Morgan Energy Partners, L.P.;
Kinder Morgan Liquids Terminals LLC; Kinder Morgan Tank Storage Terminals LLC;
Continental Oil Company; Chevron Corporation, California Superior Court, County
of Los Angeles, Case No. NC041463. The suit involves claims for environmental
cleanup costs and rent at the former Los Angeles Marine Terminal in the Port of
Los Angeles. Plaintiff alleges that terminal cleanup costs could approach $18
million; however, Kinder Morgan believes that the clean up costs should be
substantially less and that cleanup costs must be apportioned among all the
parties to the litigation. Plaintiff also alleges that it is owed approximately
$2.8 million in past rent and an unspecified amount for future rent; however, we
believe that previously paid rents will offset some of the plaintiff's rent
claim and that we have certain defenses to the payment of rent allegedly owed.
The lawsuit is set for trial in October 2007.
Currently, this lawsuit is still in a preliminary stage of discovery, and
the parties to the lawsuit have engaged environmental consultants to investigate
environmental conditions at the terminal and to consider remedial options for
those conditions. The California Regional Water Quality Control Board is the
regulatory agency overseeing the environmental investigation and expected
remedial work at the terminal, having issued formal directives to Kinder Morgan,
plaintiff and the other defendants in the lawsuit to investigate terminal
contamination and to propose a remedial action plan to address that
contamination. We are supporting a lower cost cleanup that will meet state and
federal regulatory requirements. We will vigorously defend these matters and
believe that the outcome will not have a material adverse effect on us.
Other Environmental
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.
We are subject to environmental cleanup and enforcement actions from time
to time. In particular, the federal Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) generally imposes joint and several
liability for cleanup and enforcement costs on current or predecessor owners and
operators of a site, 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 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 several governmental proceedings involving
air, water and waste violations issued by various governmental authorities
related to compliance with environmental regulations. As we receive notices of
non-compliance, we negotiate and settle these matters. We do not believe that
these violations will have a material adverse affect on our business.
We are also currently involved in several governmental proceedings
involving groundwater and soil remediation efforts under administrative orders
or related state remediation programs issued by various regulatory authorities
related to compliance with environmental regulations associated with our assets.
We have established a reserve to address the costs associated with the cleanup.
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In addition, we are 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.
See "--Pipeline Integrity and Ruptures" above for information with respect
to the environmental impact of recent ruptures of some of our pipelines.
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,
2006, we have accrued an environmental reserve of $61.6 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 the FERC, under the Interstate
Commerce Act. The Interstate Commerce Act requires, among other things, that
interstate petroleum products pipeline rates be just and reasonable and
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, 2006, 2005 and 2004, 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 was 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 were 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.
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, and provided further clarification in several areas.
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On February 19, 2004, Kinder Morgan Interstate Gas Transmission LLC and
Trailblazer Pipeline Company and the affiliated interstate pipelines owned by
KMI filed exemption requests with the FERC so that affiliated Hinshaw and
intrastate pipelines would not be considered energy affiliates. On July 21,
2004, Kinder Morgan Interstate Gas Transmission LLC and Trailblazer Pipeline
Company filed an alternative approach with respect to its exemption requests,
seeking relief from the independent functioning and information disclosure
requirements of Order 2004, subject to the separation of the commodity related
functions of the intrastate pipelines and KMI's retail operations from the
transportation functions of the intrastate pipelines/retail operations and the
interstate pipelines that were shared. The exemption requests proposed to treat
as energy affiliates, within the meaning of Order 2004, two groups of employees:
o individuals in the Choice Gas Commodity Group within KMI's retail
operations; and
o 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 discrete
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.
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.
We have implemented compliance with the Standards of Conduct as of
September 22, 2004, subject to the exemptions described above. 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 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 clarification as
to the intrastate group in three areas:
o 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;
o additional posting of organizational information about the commodity
sales and purchase personnel within our Texas intrastate natural gas
operations; and
o 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.
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The Kinder Morgan interstate pipelines made a compliance filing on May 18,
2005. On July 20, 2006, the FERC accepted our May 19, 2005 compliance filing
under Order No. 2004. On November 17, 2006, the United States Court of Appeals
for the District of Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders
2004, 2004-A, 2004-B, 2004-C, and 2004-D as applied to natural gas pipelines,
and remanded these same orders back to the FERC.
On January 9, 2007, the FERC issued an Interim Rule, effective January 9,
2007, in response to the court's action. In the Interim Rule, the FERC readopted
the Standards of Conduct, but revised or clarified with respect to issues which
had been appealed to the court. Specifically, the following changes were made:
o the Standards of Conduct apply only to the relationship between
interstate gas transmission pipelines and their marketing affiliates,
not their energy affiliates;
o all risk management personnel can be shared;
o the requirement to post discretionary tariff actions was eliminated
(but interstate gas pipelines must still maintain a log of
discretionary tariff waivers);
o lawyers providing legal advice may be shared employees; and
o new interstate gas transmission pipelines are not subject to the
Standards of Conduct until they commence service.
The FERC clarified that all exemptions and waivers issued under Order 2004
remain in effect. On January 18, 2007, the FERC issued a notice of proposed
rulemaking seeking comments regarding whether or not the Interim Rule should be
made permanent for natural gas transmission providers.
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. On March 23, 2006, the FERC dismissed rehearing requests
and denied requests for clarification--all related to the January 19, 2006
order.
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.
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 as incurred include those to:
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o prepare a plan to implement the program;
o identify high consequence areas;
o develop and maintain a record keeping system; and
o 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, referred to in this
report as INGAA, 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. On May 10, 2006,
the court issued an order establishing a briefing schedule. Under the schedule,
INGAA filed its initial brief on June 23, 2006. Both the FERC's and INGAA's
reply briefs have been filed. Oral argument at the Court of Appeals was held
January 16, 2007.
Due to the implementation of this FERC order on January 1, 2006, our
FERC-regulated natural gas pipelines expensed certain pipeline integrity
management program costs that would have been capitalized. Also, beginning in
the third quarter of 2006, our Texas intrastate natural gas pipeline group and
the operations included in our Products Pipelines and CO2 business segments
began recognizing certain costs incurred as part of their pipeline integrity
management program as operating expense in the period incurred, and in addition,
recorded an expense for costs previously capitalized during the first six months
of 2006. For the year 2006 compared to 2005, this change resulted in operating
expense increases of approximately $4.4 million for our Texas intrastate gas
group, $20.1 million for our Products Pipelines business segment, and $1.7
million for our CO2 business segment. Combined, this change did not have a
material impact on our financial position, results of operations, or cash flows
for the 2006 annual period and did not have any material effect to prior
periods. In addition, due to the fact that these amounts were not capitalized,
but instead charged to expense, our 2006 sustaining capital expenditures were
reduced by similar amounts.
Selective Discounting
On November 22, 2004, the FERC issued a notice of inquiry seeking comments
on its policy of selective discounting. Specifically, the FERC requested 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. 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
231
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 proposed 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 proposed 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.
On June 19, 2006, FERC issued Order No. 678 allowing for broader
market-based pricing of storage services. The rule expands the alternatives that
can be considered in evaluating competition, provides that market-based pricing
may be available even when market power is present (if market-based pricing is
needed to stimulate development), and treats expansions of existing storage
facilities similar to new storage facilities. The order became effective July
27, 2006.
On November 16, 2006, the FERC issued its order on rehearing, clarifying
that it would consider whether additional reporting is appropriate on a
case-by-case basis to ensure that customer protections remain adequate over
time, but denying rehearing in all other respects.
Notice of Inquiry - Financial Reporting
On February 15, 2007, the FERC issued a notice of inquiry seeking comment
on the need for changes or revisions to the FERC's reporting requirements
contained in the financial forms for gas and oil pipelines and electric
utilities.
Natural Gas Pipeline Expansion Filings
TransColorado Pipeline
On June 23, 2006, in FERC Docket No. CP06-401-000, TransColorado Gas
Transmission Company filed an application for authorization to construct and
operate certain facilities comprising its proposed "Blanco-Meeker Expansion
Project." Upon implementation, this project will facilitate the transportation
of up to approximately 250 million cubic feet per day of natural gas from the
Blanco Hub area in San Juan County, New Mexico through TransColorado's existing
interstate pipeline for delivery to the Rockies Express Pipeline at an existing
point of interconnection located in the Meeker Hub in Rio Blanco County,
Colorado.
Kinder Morgan Louisiana Pipeline
On September 8, 2006, in FERC Docket No. CP06-449-000, we filed an
application with the FERC requesting approval to construct and operate our
Kinder Morgan Louisiana Pipeline. The pipeline will extend approximately 135
miles from Cheniere's Sabine Pass liquefied natural gas terminal in Cameron
Parish, Louisiana, to various delivery points in Louisiana and will provide
interconnects with many other natural gas pipelines, including KMI's Natural Gas
Pipeline Company of America. The project is supported by fully subscribed
capacity and long-term customer commitments with Chevron and Total. The entire
approximately $500 million project is expected to be in service in the second
quarter of 2009.
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18. Recent Accounting Pronouncements
SFAS No. 123R
On December 16, 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:
o 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;
o when measuring fair value, companies can choose an option-pricing
model that appropriately reflects their specific circumstances and the
economics of their transactions;
o 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
o 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 December 31, 2005, for us, and the adoption of this
Interpretation had no effect on our consolidated financial statements.
SFAS No. 154
On June 1, 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
233
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 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). 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 did 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.
Nonetheless, as a result of EITF 04-5, as of January 1, 2006, our financial
statements are consolidated into the consolidated financial statements of KMI.
Notwithstanding the consolidation of our financial statements into the
consolidated financial statements of KMI pursuant to EITF 04-5, KMI is not
liable for, and its assets are not available to satisfy, the obligations of us
and/or our subsidiaries and vice versa. Responsibility for payments of
obligations reflected in our or KMI's financial statements is a legal
determination based on the entity that incurs the liability. The determination
of responsibility for payment among entities in our consolidated group of
subsidiaries was not impacted by the adoption of EITF 04-5.
SFAS No. 155
On February 16, 2006, the FASB issued SFAS No. 155, "Accounting for Certain
Hybrid Financial Instruments." This Statement amends SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" and SFAS No. 140, "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities." The Statement improves the financial reporting of certain hybrid
financial instruments by requiring more consistent accounting that eliminates
exemptions and provides a means to simplify the accounting for these
instruments. Specifically, it allows financial instruments that have embedded
derivatives to be accounted for as a whole (eliminating the need to bifurcate
the derivative from its host) if the holder elects to account for the whole
instrument on a fair value basis.
The provisions of this Statement are effective for all financial
instruments acquired or issued after the beginning of an entity's first fiscal
year that begins after September 15, 2006 (January 1, 2007 for us). Adoption of
this Statement did not have an effect on our consolidated financial statements.
SFAS No. 156
On March 17, 2006, the FASB issued SFAS No. 156, "Accounting for Servicing
of Financial Assets." This Statement amends SFAS No. 140 and simplifies the
accounting for servicing assets and liabilities, such as those common with
mortgage securitization activities. Specifically, this Statement addresses the
recognition and measurement of separately recognized servicing assets and
liabilities, and provides an approach to simplify efforts to obtain hedge-like
(offset) accounting by permitting a servicer that uses derivative financial
instruments to offset risks on servicing to report both the derivative financial
instrument and related servicing asset or liability by using a consistent
measurement attribute--fair value. For us, this Statement became effective
January 1, 2007. Adoption of this Statement did not have an effect on our
consolidated financial statements.
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EITF 06-3
On June 28, 2006, the FASB ratified the consensuses reached by the Emerging
Issues Task Force on EITF 06-3, "How Taxes Collected from Customers and Remitted
to Governmental Authorities Should Be Presented in the Income Statement (That
is, Gross versus Net Presentation)." According to the provisions of EITF 06-3:
o taxes assessed by a governmental authority that are directly imposed
on a revenue-producing transaction between a seller and a customer may
include, but are not limited to, sales, use, value added, and some
excise taxes; and
o that the presentation of such taxes on either a gross (included in
revenues and costs) or a net (excluded from revenues) basis is an
accounting policy decision that should be disclosed pursuant to
Accounting Principles Board Opinion No. 22 (as amended) "Disclosure of
Accounting Policies." In addition, for any such taxes that are
reported on a gross basis, a company should disclose the amounts of
those taxes in interim and annual financial statements for each period
for which an income statement is presented if those amounts are
significant. The disclosure of those taxes can be done on an aggregate
basis.
EITF 06-3 should be applied to financial reports for interim and annual
reporting periods beginning after December 15, 2006 (January 1, 2007 for us).
Because the provisions of EITF 06-3 require only the presentation of additional
disclosures on a prospective basis, the adoption of EITF 06-3 did not have an
effect on our consolidated financial statements.
FIN 48
In June 2006, the FASB issued Interpretation (FIN) No. 48, "Accounting for
Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109." This
interpretation clarifies the accounting for uncertainty in income taxes
recognized in an enterprise's financial statements in accordance with SFAS No.
109, "Accounting for Income Taxes." This Interpretation prescribes a recognition
threshold and measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return. It
also provides guidance on derecognition, classification, interest and penalties,
accounting in interim periods, disclosure, and transition. For us, this
Interpretation was effective January 1, 2007, and the adoption of this
Interpretation had no effect on our consolidated financial statements.
SAB 108
In September 2006, the Securities and Exchange Commission issued Staff
Accounting Bulletin No. 108. This Bulletin requires a "dual approach" for
quantifications of errors using both a method that focuses on the income
statement impact, including the cumulative effect of prior years' misstatements,
and a method that focuses on the period-end balance sheet. For us, SAB No. 108
was effective January 1, 2007. The adoption of this Bulletin did not have a
material impact on our consolidated financial statements, and we will apply this
guidance prospectively.
SFAS No. 157
On September 15, 2006, the FASB issued SFAS No. 157, "Fair Value
Measurements." This Statement defines fair value in generally accepted
accounting principles, and expands disclosures about fair value measurements. It
addresses how companies should measure fair value when they are required to use
a fair value measure for recognition or disclosure purposes under generally
accepted accounting principles and, as a result, there is now a common
definition of fair value to be used throughout generally accepted accounting
principles.
This Statement applies to other accounting pronouncements that require or
permit fair value measurements; the Board having previously concluded in those
accounting pronouncements that fair value is the relevant measurement attribute.
Accordingly, this Statement does not require any new fair value measurements;
however, for some entities the application of this Statement will change current
practice. The changes to current practice resulting from the application of this
Statement relate to the definition of fair value, the methods used to measure
fair value, and the expanded disclosures about fair value measurements.
235
This Statement is effective for financial statements issued for fiscal
years beginning after November 15, 2007 (January 1, 2008 for us), and interim
periods within those fiscal years. This Statement is to be applied prospectively
as of the beginning of the fiscal year in which this Statement is initially
applied, with certain exceptions. The disclosure requirements of this Statement
are to be applied in the first interim period of the fiscal year in which this
Statement is initially applied. We are currently reviewing the effects of this
Statement.
SFAS No. 158
On September 29, 2006, the FASB issued SFAS No. 158, "Employers' Accounting
for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB
Statement Nos. 87, 88, 106 and 132(R)." This Statement requires an employer to:
o recognize the overfunded or underfunded status of a defined benefit
pension plan or postretirement benefit plan (other than a
multiemployer plan) as an asset or liability in its statement of
financial position;
o measure a plan's assets and its obligations that determine its funded
status as of the end of the employer's fiscal year (with limited
exceptions), and to disclose in the notes to financial statements
additional information about certain effects on net periodic benefit
cost for the next fiscal year that arise from delayed recognition of
the gains or losses, prior service costs or credits, and transition
assets or obligations; and
o recognize changes in the funded status of a plan in the year in which
the changes occur through comprehensive income.
Past accounting standards only required an employer to disclose the
complete funded status of its plans in the notes to the financial statements.
Recognizing the funded status of a company's benefit plans as a net liability or
asset on its balance sheet will require an offsetting adjustment to "Accumulated
other comprehensive income/loss" in shareholders' equity ("Partners' Capital"
for us). SFAS No. 158 does not change how pensions and other postretirement
benefits are accounted for and reported in the income statement--companies will
continue to follow the existing guidance in previous accounting standards.
Accordingly, the amounts to be recognized in "Accumulated other comprehensive
income/loss" representing unrecognized gains/losses, prior service
costs/credits, and transition assets/obligations will continue to be amortized
under the existing guidance. Those amortized amounts will continue to be
reported as net periodic benefit cost in the income statement. Prior to SFAS No.
158, those unrecognized amounts were only disclosed in the notes to the
financial statements.
According to the provisions of this Statement, an employer with publicly
traded equity securities is required to initially recognize the funded status of
a defined benefit pension plan or postretirement benefit plan and to provide the
required disclosures as of the end of the fiscal year ending after December 15,
2006 (December 31, 2006 for us). In the year that the recognition provisions of
this Statement are initially applied, an employer is required to disclose, in
the notes to the annual financial statements, the incremental effect of applying
this Statement on individual line items in the year-end statement of financial
position. For us, the adoption of this part of SFAS No. 158 did not have a
material effect on our statement of financial position as of December 31, 2006.
For more information on our pensions and other post-retirement benefit plans,
and our disclosures regarding the provisions of this Statement, please see Note
10.
In addition, the requirement to measure plan assets and benefit obligations
as of the date of the employer's fiscal year-end statement of financial position
is effective for fiscal years ending after December 15, 2008 (December 31, 2008
for us). In the year that the measurement date provisions of this Statement are
initially applied, a business entity is required to disclose the separate
adjustments of retained earnings ("Partners' Capital" for us) and "Accumulated
other comprehensive income/loss" from applying this Statement. While earlier
application of the recognition of measurement date provisions is allowed, we
have opted not to adopt this part of the Statement early.
SFAS No. 159
On February 15, 2007, the FASB issued SFAS No. 159, "The Fair Value Option
for Financial Assets and Financial Liabilities." This Statement provides
companies with an option to report selected financial assets and
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liabilities at fair value. The Statement's objective is to reduce both
complexity in accounting for financial instruments and the volatility in
earnings caused by measuring related assets and liabilities differently. The
Statement also establishes presentation and disclosure requirements designed to
facilitate comparisons between companies that choose different measurement
attributes for similar types of assets and liabilities.
SFAS No. 159 requires companies to provide additional information that will
help investors and other users of financial statements to more easily understand
the effect of the company's choice to use fair value on its earnings. It also
requires entities to display the fair value of those assets and liabilities for
which the company has chosen to use fair value on the face of the balance sheet.
The Statement does not eliminate disclosure requirements included in other
accounting standards, including requirements for disclosures about fair value
measurements included in SFAS No. 157, discussed above, and SFAS No. 107
"Disclosures about Fair Value of Financial Instruments."
This Statement is effective as of the beginning of an entity's first fiscal
year beginning after November 15, 2007 (January 1, 2008 for us). Early adoption
is permitted as of the beginning of the previous fiscal year provided that the
entity makes that choice in the first 120 days of that fiscal year and also
elects to apply the provisions of SFAS No. 157. We are currently reviewing the
effects of this Statement.
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)
2006
First Quarter...... $2,391,601 $ 305,194 $ 246,709 $ 0.53 $ 0.53
Second Quarter..... 2,196,488 311,839 247,061 0.53 0.53
Third Quarter...... 2,273,433 302,227 223,818 0.40 0.40
Fourth Quarter..... 2,093,061 336,874 254,555 0.59 0.59
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(a).. 3,057,587 170,805 121,393 (0.02) (0.02)
- ---------------
(a) 2005 fourth quarter includes an expense of $105.0 million attributable
to an increase in our reserves related to our Pacific operations' rate
case liability.
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.
Our capitalized costs consisted of the following (in thousands):
Capitalized Costs Related to Oil and Gas Producing Activities
December 31,
----------------------------------
Consolidated Companies(a) 2006 2005 2004
---------- ---------- ----------
Wells and equipment, facilities and other. $1,369,534 $1,097,863 $ 815,311
Leasehold................................. 347,394 320,702 315,100
---------- ---------- ----------
Total proved oil and gas properties....... 1,716,928 1,418,565 1,130,411
Accumulated depreciation and depletion.... (470,245) (303,284) (174,802)
---------- ---------- ----------
Net capitalized costs..................... $1,246,683 $1,115,281 $ 955,609
========== ========== ==========
- --------------
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(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) 2006 2005 2004
---------- ---------- ----------
Property Acquisition
Proved oil and gas properties........... $ 36,585 $ 6,426 $ -
Development............................... 261,777 281,728 293,671
- ----------
(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.
Our results of operations from oil and gas producing activities for each of
the years 2006, 2005 and 2004 are shown in the following table (in thousands):
Results of Operations for Oil and Gas Producing Activities
Year Ended December 31,
---------------------------------
Consolidated Companies(a) 2006 2005 2004
--------- --------- ---------
Revenues(b)................................ $ 524,745 $ 469,149 $ 361,809
Expenses:
Production costs........................... 208,868 159,640 131,501
Other operating expenses(c)................ 66,411 58,978 44,043
Depreciation, depletion and
amortization expenses.................. 169,439 130,485 104,147
--------- --------- ---------
Total expenses........................... 444,718 349,103 279,691
--------- --------- ---------
Results of operations for oil
and gas producing activities........... $ 80,027 $ 120,046 $ 82,118
========= ========= =========
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) Revenues include losses attributable to our hedging contracts of $441.7
million, $374.3 million and $181.8 million for the years ended December 31,
2006, 2005 and 2004, respectively.
(c) Consists primarily of carbon dioxide expense.
The table below represents estimates, as of December 31, 2006, of proved
crude oil, natural gas liquids and natural gas reserves prepared by Netherland,
Sewell and Associates, Inc. (independent oil and gas consultants) of Kinder
Morgan CO2 Company, L.P. and its consolidated subsidiaries' interests in oil and
gas properties, all of which are located in the State of Texas. This data has
been prepared using constant prices and costs, as discussed in subsequent
paragraphs of this document. The estimates of reserves and future revenue in
this document conforms to the guidelines of the United States Securities and
Exchange Commission.
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 becomes 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 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
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infrastructure under current operating conditions. Proved undeveloped reserves
require additional investments in wells and related infrastructure in order to
recover the production.
During 2006, we filed estimates of our oil and gas reserves for the year
2005 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)(b)
--------- -------- --------
Proved developed and undeveloped reserves:
As of December 31, 2003.................... 116,608 16,263 3,293
Revisions of previous estimates.......... 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
Revisions of previous estimates.......... (4,615) (6,858) (1,408)
Production............................... (13,811) (1,817) (461)
Purchases of reserves in place........... 453 25 7
--------- -------- --------
As of December 31, 2006.................... 123,978 10,333 291
========= ======== ========
Proved developed reserves:
As of December 31, 2003.................... 64,879 8,160 2,551
As of December 31, 2004.................... 71,307 8,873 1,357
As of December 31, 2005.................... 78,755 9,918 1,650
As of December 31, 2006.................... 69,073 5,877 291
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) Natural gas reserves are computed at 14.65 pounds per square inch absolute
and 60 degrees 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:
o 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;
o pricing is applied based upon year-end market prices adjusted for
fixed or determinable contracts that are in existence at year-end;
o future development and production costs are determined based upon
actual cost at year-end;
o the standardized measure includes projections of future abandonment
costs based upon actual costs at year-end; and
o 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):
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Standardized Measure of Discounted Future Net Cash Flows From
Proved Oil and Gas Reserves
As of December 31,
----------------------------------------
Consolidated Companies(a) 2006 2005 2004
----------- ----------- -----------
Future cash inflows from production............ $ 7,534,688 $ 9,150,576 $ 5,799,658
Future production costs........................ (2,617,904) (2,756,535) (1,935,597)
Future development costs(b).................... (1,256,730) (869,034) (502,172)
----------- ----------- -----------
Undiscounted future net cash flows........... 3,660,054 5,525,007 3,361,889
10% annual discount............................ (1,452,215) (2,450,002) (1,316,923)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows...................... $ 2,207,839 $ 3,075,005 $ 2,044,966
=========== =========== ===========
- ----------
(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) 2006 2005 2004
------------ ----------- -----------
Present value as of January 1......................... $ 3,075,005 $ 2,044,966 $ 1,407,815
Changes during the year:
Revenues less production and other costs(b)....... (689,984) (624,413) (368,083)
Net changes in prices, production and other
costs(b)....................................... (123,009) 1,013,448 506,078
Development costs incurred........................ 261,777 281,728 293,671
Net changes in future development costs........... (445,955) (492,307) (270,114)
Purchases of reserves in place.................... 3,175 9,413 --
Revisions of previous quantity estimates.......... (179,462) 51,063 396,946
Improved Recovery................................. -- 587,537 --
Accretion of discount............................. 307,391 204,412 136,939
Timing differences and other...................... (1,099) (842) (58,286)
------------ ----------- -----------
Net change for the year............................. (867,166) 1,030,039 637,151
------------ ----------- -----------
Present value as of December 31....................... $ 2,207,839 $ 3,075,005 $ 2,044,966
=========== =========== ===========
- ----------
(a) Amounts relate to Kinder Morgan CO2 Company, L.P. and its consolidated
subsidaries.
(b) Excludes the effect of losses attributable to our hedging contracts of
$441.7 million, $374.3 million and $181.8 million for the years ended
December 31, 2006, 2005 and 2004, respectively.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
KINDER MORGAN ENERGY PARTNERS, L.P.
(A Delaware Limited Partnership)
By: KINDER MORGAN G.P., INC.,
its sole General Partner
By: KINDER MORGAN MANAGEMENT, LLC,
the Delegate of Kinder Morgan
G.P., Inc.
By: /s/ KIMBERLY A. DANG
---------------------------------
Kimberly A. Dang,
Vice President and Chief Financial
Officer
Date: March 1, 2007
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 1, 2007
- -------------------- 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 1, 2007
- --------------------- 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 1, 2007
- --------------------- Management, LLC, Delegate of
Edward O. Gaylord Kinder Morgan G.P., Inc.
/s/ GARY L. HULTQUIST Director of Kinder Morgan March 1, 2007
- --------------------- Management, LLC, Delegate of
Gary L. Hultquist Kinder Morgan G.P., Inc.
/s/ PERRY M. WAUGHTAL Director of Kinder Morgan March 1, 2007
- --------------------- Management, LLC, Delegate of
Perry M. Waughtal Kinder Morgan G.P., Inc.
/s/ C. PARK SHAPER Director and President of March 1, 2007
- ------------------ Kinder Morgan Management, LLC,
C. Park Shaper Delegate of Kinder Morgan G.P.,
Inc.
241