Knight
Inc. Form 10-K
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
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þ
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
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For
the fiscal year ended December
31, 2008
or
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o
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
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For
the transition period from _____to_____
Commission
File Number 1-06446
Knight
Inc.
(Exact
name of registrant as specified in its charter)
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Kansas
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48-0290000
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(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification No.)
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500
Dallas Street, Suite 1000, Houston, Texas 77002
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(Address
of principal executive offices, including zip
code)
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Registrant’s
telephone number, including area code (713)
369-9000
Securities
registered pursuant to Section 12(b) of the Act:
None
Securities
registered pursuant to section 12(g) of the Act:
None
Indicate
by checkmark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act:
Yeso No þ
Indicate
by checkmark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act:
Yes
þ No
o
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 o No þ
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. þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (Check
one): Large accelerated filer o Accelerated
filer o Non-accelerated
filer þ Smaller
reporting company o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes o No þ
The
aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant was $0 at June 30, 2008.
The
number of shares outstanding of the registrant’s common stock, $0.01 par value,
as of January 30, 2009 was 100 shares.
Knight
Inc. Form 10-K
CONTENTS
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2
Knight
Inc. Form 10-K
KNIGHT
INC. AND SUBSIDIARIES
CONTENTS
(Continued)
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184-185
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186-194
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____________
Note: Individual
financial statements of the parent company are omitted pursuant to the
provisions of Accounting Series Release No. 302.
3
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Knight
Form 10-K
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In
this report, unless the context requires otherwise, references to “we,” “us,”
“our,” or the “Company” are intended to mean Knight Inc. (a private Kansas
corporation incorporated on May 18, 1927, formerly known as Kinder Morgan, Inc.)
and its consolidated subsidiaries. All dollars are United States dollars, except
where stated otherwise. Canadian dollars are designated as C$. Unless otherwise
indicated, all volumes of natural gas are stated at a pressure base of 14.73
pounds per square inch absolute and at 60 degrees Fahrenheit and, in most
instances, are rounded to the nearest major multiple. In this report, the term
“MMcf” means million cubic feet, the term “Bcf” means billion cubic feet, the
term “MBbl/d” means million barrels per day, the term “Bbl” means barrels, the
term “bpd” means barrels per day and the terms “Dth” (dekatherms) and “MMBtus”
mean million British Thermal Units (“Btus”). Natural gas liquids consist of
ethane, propane, butane, iso-butane and natural gasoline. The following
discussion should be read in conjunction with the accompanying Consolidated
Financial Statements and related Notes.
(A)
General Development of Business
We
are a large energy transportation and storage company, operating or owning an
interest in approximately 36,000 miles of pipelines and approximately 170
terminals. Our pipelines transport natural gas, gasoline, crude oil, carbon
dioxide and other products, and our terminals store petroleum products and
chemicals and handle bulk materials like coal and petroleum coke. We are also
the leading provider of carbon dioxide, commonly called “CO2,” for
enhanced oil recovery projects in North America. We have both regulated and
nonregulated operations. Our executive offices are located at 500 Dallas Street,
Suite 1000, Houston, Texas 77002 and our telephone number is (713)
369-9000.
Kinder
Morgan Management, LLC, referred to in this report as “Kinder Morgan Management”
is a publicly traded Delaware limited liability company that was formed on
February 14, 2001. Kinder Morgan G.P., Inc., of which we indirectly own all of
the outstanding common equity, owns all of Kinder Morgan Management’s voting
shares. Kinder Morgan Management, pursuant to a delegation of control agreement,
has been delegated, to the fullest extent permitted under Delaware law, all of
Kinder Morgan G.P., Inc.’s power and authority to manage and control the
business and affairs of Kinder Morgan Energy Partners, L.P., (“Kinder Morgan
Energy Partners”) subject to Kinder Morgan G.P., Inc.’s right to approve certain
transactions. Kinder Morgan Management also owns all of the i-units of Kinder
Morgan Energy Partners. The i-units are a class of Kinder Morgan Energy
Partners’ limited partner interests that have been, and will be, issued only to
Kinder Morgan Management. We have certain rights and obligations with respect to
these securities.
Kinder
Morgan Energy Partners is a publicly traded pipeline limited partnership whose
limited partnership units are traded on the New York Stock Exchange under the
ticker symbol “KMP.” Kinder Morgan Management’s shares (other than the voting
shares held by Kinder Morgan G.P., Inc.) are traded on the New York Stock
Exchange under the ticker symbol “KMR.”
The
equity interests in Kinder Morgan Energy Partners and Kinder Morgan Management
(which are both consolidated in our financial statements) owned by the public
are reflected within “minority interest” on our consolidated balance sheet. The
earnings recorded by Kinder Morgan Energy Partners and Kinder Morgan Management
that are attributed to their units and shares, respectively, held by the public
are reported as “minority interest” in the accompanying Consolidated Statements
of Operations.
On
May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of
Knight Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal
entity and subsequently renamed Knight Inc. Knight Holdco LLC is a private
company owned by Richard D. Kinder, our Chairman and Chief Executive Officer;
our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez
Sarofim and Michael C. Morgan; other members of our senior management, most of
whom are also senior officers of Kinder Morgan G.P., Inc. and Kinder Morgan
Management; and affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar
Capital, (iii) The Carlyle Group and (iv) Riverstone Holdings LLC. This
transaction is referred to in this report as “the Going Private transaction.” As
a result of the Going Private transaction, we are now privately owned, our stock
is no longer traded on the New York Stock Exchange and we have adopted a new
basis of accounting for our assets and liabilities.
Additional
information concerning the business of, and our investment in and obligations
to, Kinder Morgan Energy Partners and Kinder Morgan Management is contained in
Notes 2 and 9 of the accompanying Notes to Consolidated Financial Statements and
in Kinder Morgan Energy Partners’ and Kinder Morgan Management’s Annual Reports
on Form 10-K for the year ended December 31, 2008.
The
following is a brief listing of significant developments since December 31,
2007. We begin with developments pertaining to our seven reportable business
segments, described more fully below in “(C) Narrative Description
of
4
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Items 1. and
2. Business and Properties.
(continued)
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Knight
Form 10-K
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Business—Business
Segments.” Additional information regarding most of these items may be found
elsewhere in this report.
Natural
Gas Pipeline Company of America (“NGPL”)
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·
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On
February 15, 2008, we sold an 80% ownership interest in our NGPL business
segment to Myria Acquisition Inc. (“Myria”) for approximately $5.9
billion. The $5.9 billion of proceeds from this sale, along with cash on
hand, were used to: (i) payoff the outstanding $4.2 billion balance on our
senior secured credit facility’s Tranche A and Tranche B term loans that
had been incurred to help finance the Going Private transaction discussed
above, (ii) repurchase $1.67 billion of outstanding debt securities and
(iii) reduce the outstanding debt under our $1.0 billion revolving credit
facility. We continue to operate NGPL’s assets pursuant to a 15-year
operating agreement. Myria is owned by a syndicate of investors led by
Babcock & Brown, an international investment and specialized fund and
asset management group.
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Power
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·
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Effective
January 1, 2008, we sold our interests in three natural gas-fired power
plants in Colorado to Bear Stearns and we received net proceeds of $63.1
million.
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Products
Pipelines–KMP
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·
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In
October 2008, Kinder Morgan Energy Partners successfully completed a
series of tests demonstrating the commercial feasibility of transporting
batched denatured ethanol on our 16-inch diameter gasoline pipeline that
extends between Tampa and Orlando, Florida. After making certain
mechanical modifications to the pipeline in late-November, Kinder Morgan
Energy Partners began batching denatured ethanol shipments along with
gasoline shipments for its customers, making our Central Florida Pipeline
the first gasoline pipeline in the U.S. capable of also handling ethanol
in commercial movements.
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In
addition to the Central Florida Pipeline ethanol project, Kinder Morgan Energy
Partners has approved over $90 million in ethanol and biofuel related capital
expenditure projects, including modifications to tanks, truck racks and related
infrastructure for new or expanded ethanol and biodiesel service at various
owned, operated and/or third party terminal facilities located in the Southeast
and the Pacific Northwest. Kinder Morgan Energy Partners plans on offering
ethanol blending capabilities in twelve of fifteen markets served by its
Southeast terminals by the end of 2009.
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·
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In
October 2008, Plantation Pipe Line Company successfully shipped a 20,000
barrel batch of blended biodiesel (a 5% blend commonly referred to as B5).
The shipment originated at Collins, Mississippi and was delivered to a
customer terminal located in Spartanburg, South Carolina. Plantation is
currently developing plans to expand its capability to deliver biodiesel
to at least ten markets served by its pipeline system in the Southeast.
Assuming sufficient commercial support, Plantation Pipe Line Company
expects to be moving forward with investments to provide this service
during the second quarter of 2009.
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·
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In
November 2008, Kinder Morgan Energy Partners’ West Coast Products
Pipelines completed an approximate $25 million expansion project that
included the construction of four 80,000 barrel tanks and ancillary
facilities that provide military jet fuel and marine diesel fuel service
to the U.S. Marine Corps Naval Air Station in Miramar, California and the
Naval Air Station in Point Loma,
California.
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·
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On
December 10, 2008, Kinder Morgan Energy Partners’ West Coast Products
Pipelines operations purchased a 200,000 barrel refined petroleum products
terminal located in Phoenix, Arizona from ConocoPhillips for approximately
$27.5 million in cash.
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Natural
Gas Pipelines–KMP
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·
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Effective
April 1, 2008, Kinder Morgan Energy Partners sold its 25% equity ownership
interest in Thunder Creek Gas Services, LLC to PVR Midstream LLC, a
subsidiary of Penn Virginia Corporation, for approximately $50.7 million
in cash.
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·
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On
May 20, 2008, transportation service on the final 210 miles of the Rockies
Express-West pipeline segment commenced. Interim service for up to 1.4
billion cubic feet per day of natural gas on the segment’s first 503 miles
of pipe began on January 12, 2008. The Rockies Express-West pipeline
segment is the second phase of the Rockies Express Pipeline and consists
of a 713-mile, 42-inch diameter pipeline that extends from the Cheyenne
Hub in Weld County, Colorado to an interconnect with Panhandle Eastern
Pipeline Company in Audrain County, Missouri. Now fully operational,
Rockies Express-West has the capacity to transport up to 1.5 billion cubic
feet of natural gas per day and can make deliveries to interconnects with
Kinder Morgan Interstate Gas Transmission Pipeline
LLC,
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5
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Items 1. and
2. Business and Properties.
(continued)
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Knight
Form 10-K
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Northern
Natural Gas Company, Natural Gas Pipeline Company of America LLC, ANR
Pipeline Company and Panhandle Eastern Pipeline
Company.
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·
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On
May 30, 2008, the Federal Energy Regulatory Commission (“FERC”) issued an
order authorizing construction of the Rockies Express-East pipeline
segment, the third phase of the Rockies Express Pipeline. Rockies
Express-East is a 639-mile, 42-inch diameter pipeline that will extend
from Audrain County, Missouri to Clarington, Ohio. When fully completed,
the 1,679-mile Rockies Express Pipeline will have the capability to
transport 1.8 billion cubic feet per day of natural gas and binding firm
commitments from creditworthy shippers have been secured for all of the
pipeline capacity. Kinder Morgan Energy Partners is a 51% owner in the
Rockies Express Pipeline, which is estimated to cost approximately $6.3
billion including expansion when completed (consistent with Kinder Morgan
Energy Partners’ January 21, 2009 fourth quarter earnings
release).
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Construction
of the Rockies Express-East pipeline segment is in progress and subject to the
receipt of regulatory approvals, initial service on the pipeline is projected to
commence April 1, 2009. The initial service will provide for capacity of up to
1.6 billion cubic feet per day to interconnects upstream of Lebanon, Ohio,
followed by service to the Lebanon Hub in Warren County, Ohio beginning June 15,
2009. Final pipeline completions and fully powered deliveries to Clarington,
Ohio are expected to commence by November 1, 2009.
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·
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Rockies
Express Pipeline LLC is requesting authorization to construct and operate
certain facilities that upon completion will comprise its Meeker, Colorado
to Cheyenne, Wyoming expansion project. The proposed expansion will
consist of additional natural gas compression at its Big Hole compressor
station located in Moffat County, Colorado and its Arlington compressor
station located in Carbon County, Wyoming. Upon completion, the additional
compression will permit the transportation of an additional 200 million
cubic feet per day of natural gas from (i) the Meeker Hub located in Rio
Blanco County, Colorado northward to the Wamsutter Hub located in
Sweetwater County, Wyoming; and (ii) from the Wamsutter Hub eastward to
the Cheyenne Hub located in Weld County, Colorado. The expansion is fully
supported by long-term contracts and is expected to be operational in
April 2010. The total estimated cost for the proposed project is
approximately $78 million. Rockies Express Pipeline LLC submitted an
application to the FERC seeking approval to construct and operate this
expansion on February 3, 2009.
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·
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In
June 2008, Kinder Morgan Energy Partners’ Texas intrastate group began gas
injections into a fifth cavern at its salt dome storage facility located
near Markham, Texas as part of an $84 million expansion. After final
developments were completed in January 2009, the project added 7.5 billion
cubic feet of natural gas working storage capacity, and gas injection
capacity will increase by approximately 110 million cubic feet per day
upon completion of compression installation in spring 2009. In addition,
the Texas intrastate pipeline group’s approximately $13 million Texas Hill
Country natural gas compression project was completed in January 2009,
resulting in 45 million cubic feet of incremental pipeline capacity out of
West Texas, primarily serving the Austin, Texas
market.
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·
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On
July 25, 2008, the FERC approved the application made by Midcontinent
Express Pipeline LLC to construct and operate the approximately 500-mile
Midcontinent Express Pipeline natural gas transmission system and to lease
272 million cubic feet of capacity on the Oklahoma intrastate system of
Enogex Inc. Kinder Morgan Energy Partners and Energy Transfer Partners,
L.P. each own a 50% interest in Midcontinent Express Pipeline LLC, the
sole owner of the Midcontinent Express
Pipeline.
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The
project is expected to cost approximately $2.2 billion, including previously
announced expansions. This is an increase from the $1.9 billion previous
forecast. Much of the increase is attributable to increased construction cost.
Midcontinent Express Pipeline LLC is currently finalizing negotiations with
contractors for construction of the final segment. Those contracts will fix the
per unit prices, providing greater cost certainty on that portion of the project
and those construction costs are incorporated into the current
forecast.
Interim
service on the first portion of the pipeline from Bryan County, Oklahoma to an
interconnection with Columbia Gulf Transmission Corporation near Perryville,
Louisiana is expected commence in April 2009. The second construction phase, to
the Transco Pipeline near Butler, Alabama, is expected to be completed by August
1, 2009. The Midcontinent Express Pipeline’s capacity is fully subscribed with
long-term binding commitments from creditworthy shippers.
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·
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Construction
continues on the fully-owned Kinder Morgan Louisiana Pipeline and the
current cost estimate for this natural gas transmission system is
approximately $950 million. The project is supported by fully subscribed
capacity and long-term customer
commitments with Chevron and Total and it is anticipated that the pipeline
will become fully operational during the second quarter of
2009.
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6
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Items 1. and
2. Business and Properties.
(continued)
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Knight
Form 10-K
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·
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In
September 2008, Kinder Morgan Energy Partners completed construction of an
approximately $75 million natural gas pipeline that transports additional
East Texas natural gas supplies to markets in the Houston and Beaumont,
Texas areas. The new pipeline connects the Kinder Morgan Tejas system in
Houston County, Texas to the Kinder Morgan Texas Pipeline system in Polk
County near Goodrich, Texas. Kinder Morgan Energy Partners entered into a
long-term binding agreement with CenterPoint Energy Services, Inc. to
provide firm transportation for a significant portion of the initial
project capacity, which consists of approximately 225 million cubic feet
per day of natural gas.
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·
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On
October 1, 2008, Kinder Morgan Energy Partners and Energy Transfer
Partners, L.P. announced a joint venture to build and develop the
Fayetteville Express Pipeline, a new $1.2 billion natural gas pipeline
that will provide shippers in the Arkansas Fayetteville Shale area with
takeaway natural gas capacity and further access to growing markets. The
project is expected to be in service in 2010 or early 2011 and has secured
binding 10-year commitments totaling 1.85 billion cubic feet per
day.
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·
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In
October 2008, Kinder Morgan Energy Partners completed construction of an
approximately $22 million expansion project on the Kinder Morgan
Interstate Gas Transmission LLC pipeline system that provides for the
delivery of natural gas to five separate industrial plants (four of which
produce ethanol) located near Grand Island, Nebraska. The project is fully
subscribed with long-term customer
contracts.
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·
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On
November 24, 2008, Kinder Morgan Interstate Gas Transmission LLC completed
construction and placed into service its previously announced Colorado
Lateral Pipeline. The approximately $39 million expansion project extends
from the Cheyenne Hub to interconnects with Atmos Energy’s pipeline near
Greeley, Colorado. The pipeline provides firm natural gas transportation
of up to 74 million cubic feet per day to local distribution companies and
to industrial end users.
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CO2–KMP
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·
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As
of February 1, 2009, the CO2–KMP
business segment was nearing completion of its previously announced
southwest Colorado carbon dioxide expansion project. Combined, the
expansion will cost its owners approximately $290 million and includes
developing a new carbon dioxide source field (named the Doe Canyon Deep
Unit), drilling new wells and expanding infrastructure at both the McElmo
Dome Unit and the Cortez pipeline. The entire expansion increases carbon
dioxide supplies by approximately 300 million cubic feet per day to its
customers.
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The
Doe Canyon source field began operations in January 2008 and is currently
delivering 120 million cubic feet per day of carbon dioxide. The first
compression train of the Goodman Point expansion at the McElmo Dome source field
was placed in service in June 2008 at a rate of 108 million cubic feet per day
of carbon dioxide. The second compression train was brought on in October 2008
(after the activation of the Blanco pump station on the Cortez Pipeline) and
increased the production rate to 207 million cubic feet per day of carbon
dioxide. In 2009, the Goodman Point plant has averaged 232 million cubic feet
per day of carbon dioxide. In October of 2008, Kinder Morgan Energy Partners
activated the Blanco pump station on the Cortez Pipeline utilizing power from
diesel generators and in January 2009, it began construction on a new power line
that will connect the Blanco pumps to the power grid. The new power line is
expected to be in service by the end of the third quarter of 2009. Kinder Morgan
Energy Partners owns a 50% interest in the Cortez pipeline, which currently
delivers approximately 1.3 billion cubic feet per day of carbon
dioxide.
Terminals–KMP
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·
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On
January 16, 2008, Kinder Morgan Energy Partners announced plans to invest
approximately $56 million to construct a petroleum coke terminal at the BP
refinery located in Whiting, Indiana. Kinder Morgan Energy Partners has
entered into a long-term contract to build and operate the facility, which
will handle approximately 2.2 million tons of petroleum coke per year from
a coker unit BP plans to construct to process heavy crude oil from Canada.
The facility is expected to be in service in mid-year
2011.
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|
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·
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On
March 20, 2008, Kinder Morgan Energy Partners announced the completion of
several expansion projects representing total investment of more than $500
million at various bulk and liquids terminal facilities. The primary
investment projects included (i) an approximately $195 million expansion
for additional tankage at the combined Galena Park/Pasadena, Texas liquids
terminal facilities located on the Houston, Texas Ship Channel; (ii) an
approximately $170 million investment to construct the Kinder Morgan North
40 terminal, a crude oil tank farm situated on approximately 24 acres near
Edmonton, Alberta, Canada; (iii) an approximately $70 million capital
improvement project at the Pier IX bulk terminal located in Newport News,
Virginia; and (iv) an approximately $68 million for the construction of
nine new liquid storage tanks at the Perth Amboy, New Jersey liquids
terminal located on the New York
Harbor.
|
7
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Items 1. and
2. Business and Properties.
(continued)
|
Knight
Form 10-K
|
|
|
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The
storage expansion at the Galena Park/Pasadena terminals brings total
capacity of the combined complex to approximately 25 million barrels. As
previously announced, the building of the Kinder Morgan North 40 terminal
included the construction of nine storage tanks with a combined capacity
of approximately 2.15 million barrels for crude oil, all of which is
subscribed by shippers under long-term contracts. The Pier IX project
involved the construction of a new ship dock and the installation of a new
import coal facility that is expected to increase terminal throughput by
30% to about nine million tons a year. The expansion at Perth Amboy
included the building of nine new liquid storage tanks, which increased
capacity for refined petroleum products and chemicals by 1.4 million
barrels, bringing total terminal capacity to approximately 3.7 million
barrels.
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·
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Effective
August 5, 2008, Kinder Morgan Energy Partners acquired certain terminal
assets from Chemserv, Inc. for an aggregate consideration of approximately
$12.7 million, consisting of $11.8 million in cash and $0.9 million in
assumed liabilities. The acquired assets are primarily involved in the
storage of petroleum products and
chemicals.
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·
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In
December 2008, Kinder Morgan Energy Partners began operations at its
approximately $47 million terminal, which offers liquids, storage,
transfer and packaging facilities at the Rubicon Plant site located in
Geismar, Louisiana. The newly constructed terminal has liquids storage
capacity of approximately 123,500 barrels and has approximately 144,000
square feet of warehouse space.
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·
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Construction
continues on an approximately $13 million expansion at Kinder Morgan
Energy Partners’ Cora coal terminal, located in Rockwood, Illinois along
the upper Mississippi River. The project will increase terminal storage
capacity by approximately 250,000 tons (to 1.25 million tons) and will
expand maximum throughput at the terminal to approximately 13 million tons
annually. It is expected that the Cora expansion project will be completed
in the second quarter of 2009.
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Kinder
Morgan Canada–KMP
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·
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Effective
August 28, 2008, we sold our one-third equity ownership interest in the
Express crude oil pipeline system, as well as full ownership of the Jet
Fuel pipeline system that serves the Vancouver (Canada) International
Airport to Kinder Morgan Energy Partners. As consideration for these
assets, Kinder Morgan Energy Partners issued approximately two million of
its common units to us, valued at $116.0 million. For additional
information regarding this transaction, see Note 10 of the accompanying
Notes to Consolidated Financial
Statements.
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·
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On
October 30, 2008, Kinder Morgan Energy Partners completed the construction
and commissioning of its approximately $544 million Anchor Loop project,
the second and final phase of a Trans Mountain pipeline system expansion
that in total, increased pipeline capacity from approximately 225,000 to
300,000 barrels of crude oil per
day.
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The
Anchor Loop project involved twinning (or looping) a 158-kilometer section of
the existing pipeline system between Hinton, Alberta and Hargreaves, British
Columbia and was completed in two phases, (i) 97 kilometers of 30-inch and
36-inch diameter pipeline and two new pump stations that increased the capacity
of the pipeline system by 25,000 barrels per day (the Jasper spread completed on
April 28, 2008) and (ii) 61 kilometers of 36-inch diameter pipeline that
increased the capacity of the pipeline system by an incremental 15,000 barrels
per day (the Mount Robson spread in British Columbia completed on October 30,
2008). The pipeline system is currently operating at full capacity and only
final right-of-way restoration on the Mount Robson spread remains to be
completed in the summer of 2009.
Debt
and Equity Offerings, Swap Agreements, Cash Distributions and Debt
Retirements
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On
February 12, 2008, Kinder Morgan Energy Partners completed a public
offering of senior notes. A total of $900 million in principal amount of
senior notes was issued, consisting of $600 million of 5.95% notes due
February 15, 2018 and $300 million of 6.95% notes due January 15, 2038.
Kinder Morgan Energy Partners used the net proceeds of $894.1 million to
reduce the borrowings under its commercial paper
program.
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Also
on this date, Kinder Morgan Energy Partners completed an offering of
1,080,000 of its common units at a price of $55.65 per unit in a privately
negotiated transaction and used the net proceeds of $60.1 million to
reduce the borrowings under its commercial paper
program.
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In March 2008, Kinder
Morgan Energy Partners completed a public offering of 5,750,000 of its
common units at a price of $57.70 per unit and used the net proceeds of
$324.2 million to reduce the borrowings under its commercial paper
program.
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On
June 6, 2008, Kinder Morgan Energy Partners completed a $700 million
public offering of senior notes and used the net proceeds of $687.7
million to reduce the borrowings under its commercial paper
program.
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8
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Items 1. and
2. Business and Properties.
(continued)
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Knight
Form 10-K
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On
November 24, 2008, Kinder Morgan Energy Partners announced that it
expected to declare cash distributions of $4.20 per unit for 2009, a 4.5%
increase over its cash distributions of $4.02 per unit for 2008. Kinder
Morgan Energy Partners’ expected growth in distributions in 2009 assumes
an average West Texas Intermediate (“WTI”) crude oil price of $68 per
barrel in 2009 with some minor adjustments for timing, quality and
location differences. Based on actual prices received through the first
seven weeks of 2009 and the forward curve, adjusted for the same factors
as the budget, our average realized price for 2009 is currently projected
to be $49 per barrel. Although the majority of the cash generated by
Kinder Morgan Energy Partners’ assets is fee based and is not sensitive to
commodity prices, the CO2–KMP
business segment is exposed to commodity price risk related to the price
volatility of crude oil and natural gas liquids. Kinder Morgan Energy
Partners hedges the majority of its crude oil production, but does have
exposure to unhedged volumes, the majority of which are natural gas
liquids volumes. For 2009, Kinder Morgan Energy Partners expects that
every $1 change in the average WTI crude oil price per barrel will impact
the CO2–KMP
segment’s cash flows by approximately $6 million (or approximately 0.2% of
Kinder Morgan Energy Partners’ combined business segments’ anticipated
distributable cash flow). This sensitivity to the average WTI crude oil
price is very similar to what was experienced in 2008. The 2009 Kinder
Morgan Energy Partners cash distribution expectations do not take into
account any capital costs associated with financing any payment Kinder
Morgan Energy Partners may make of reparations sought by shippers on its
West Coast Products Pipelines operations’ interstate
pipelines.
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On
December 19, 2008, Kinder Morgan Energy Partners closed a public offering
of $500 million in principal amount of senior notes and used the net
proceeds of $498.4 million to reduce the borrowings under its five-year
unsecured revolving bank credit
facility.
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On December 22, 2008,
Kinder Morgan Energy Partners completed a public offering of 3,900,000 of
its common units at a price of $46.75 per unit, less commissions and
underwriting expenses and used the net proceeds of $176.6 million to
reduce the borrowings under its five-year unsecured revolving bank credit
facility.
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In
December 2008 and January 2009, Kinder Morgan Energy Partners terminated
three existing fixed-to-variable interest rate swap agreements in three
separate transactions. These swap agreements had a combined notional
principal amount of $1.0 billion and Kinder Morgan Energy Partners
received combined proceeds of $338.7 million from the early termination of
these swap agreements.
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On
February 2, 2009, Kinder Morgan Energy Partners paid $250 million to
retire the principal amount of its 6.3% senior notes that matured on that
date.
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In
February and March 2009, Kinder Morgan Energy Partners
sold 5,666,000 of its common units in a public offering at a price of
$46.95 per unit. Kinder Morgan Energy Partners received net proceeds,
after commissions and underwriting expenses, of approximately $260 million
for the issuance of these 5,666,000 common units and used the
proceeds to reduce the borrowings under its bank credit facility.·On February
25, 2009, Kinder Morgan Energy Partners entered
into four additional fixed-to-floating interest rate swap
agreements having a combined notional principal amount of $1.0 billion
related to (i) $200 million 6% senior notes due 2017, (ii)
$300 million of 5.125% senior notes due 2014, (iii) $25 million 5% senior
notes due 2013 and (iv) $475 million of 5.95% senior notes due
2018.
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Capital
Expansion Projects
Kinder
Morgan Energy Partners’ capital expansion program in 2008 was approximately $2.9
billion (for both maintenance/sustaining and expansion/discretionary capital
spending, and including its equity contributions to the Rockies Express
Pipeline, the Midcontinent Express Pipeline and the Fayetteville Express
Pipeline natural gas pipeline projects). In 2009, Kinder Morgan Energy Partners
expects its capital expansion program to be approximately $2.8 billion
(including its equity contributions to the Rockies Express Pipeline and
Midcontinent Express Pipeline projects), which will help contribute to earnings
and cash flow growth in 2009 and beyond.
(B)
Financial Information About Segments
Note
19 of the accompanying Notes to Consolidated Financial Statements contains
financial information about our business segments.
9
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Items 1. and
2. Business and Properties.
(continued)
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Knight
Form 10-K
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(C)
Narrative Description of Business
The
objective of our business strategy is to grow our portfolio of businesses
by:
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focusing
on stable, fee-based energy transportation and storage assets that are
core to the energy infrastructure of growing markets within North
America;
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increasing
utilization of our existing assets while controlling costs, operating
safely and employing environmentally sound operating
practices;
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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
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maximizing
the benefits of our financial structure to create and return value to our
stockholders.
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We
(primarily through Kinder Morgan Energy Partners) regularly consider and enter
into discussions regarding potential acquisitions 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, if required. 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 “Risk Factors” elsewhere in this report, there are factors that
could affect our ability to carry out our strategy or affect its level of
success even if carried out.
Our
operations are conducted through our subsidiaries and are grouped into seven
business segments, the last five of which are also business segments of Kinder
Morgan Energy Partners:
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Natural Gas Pipeline Company
of America—which consists of our 20% interest in NGPL PipeCo LLC,
the owner of Natural Gas Pipeline Company of America LLC and certain
affiliates, collectively referred to as Natural Gas Pipeline Company of
America or NGPL, a major interstate natural gas pipeline and storage
system which we operate;
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Power—which consists of
two natural gas-fired electric generation
facilities;
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Products
Pipelines–KMP—which consists of approximately 8,300 miles of
refined petroleum products pipelines that deliver gasoline, diesel fuel,
jet fuel and natural gas liquids to various markets; plus approximately 60
associated product terminals and petroleum pipeline transmix processing
facilities serving customers across the United
States;
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Natural Gas
Pipelines–KMP—which consists of over 14,300 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;
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CO2–KMP—which produces,
markets and transports, through approximately 1,300 miles of pipelines,
carbon dioxide 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 450-mile crude oil pipeline system in
West Texas;
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Terminals–KMP—which
consists of approximately 110 owned or operated liquids and bulk terminal
facilities and more than 45 rail transloading and materials handling
facilities located throughout the United States and portions of Canada,
which together transload, store and deliver a wide variety of bulk,
petroleum, petrochemical and other liquids products for customers across
the United States and Canada; and
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Kinder Morgan
Canada–KMP—which consists of over 700 miles of common carrier
pipelines, originating at Edmonton, Alberta, for the transportation of
crude oil and refined petroleum to the interior of British Columbia and to
marketing terminals and refineries located in the greater Vancouver,
British Columbia area and Puget Sound in Washington State; plus five
associated product terminals. This segment also includes a one-third
interest in an approximately 1,700-mile integrated crude oil pipeline and
a 25-mile aviation turbine fuel pipeline serving the Vancouver
International Airport.
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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 the CO2–KMP
business segment, we engage in a hedging program to mitigate this
exposure.
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2. Business and Properties.
(continued)
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NGPL
is one of the nation’s largest natural gas storage operators with approximately
600 billion cubic feet of total natural gas storage capacity, approximately 258
billion cubic feet of working gas capacity and over 4.3 billion cubic feet per
day of peak deliverability from its storage facilities, which are located in
major supply areas and near the markets it serves. NGPL owns and operates 13
underground storage reservoirs in eight field locations in four states. These
storage assets complement its pipeline facilities and allow it to optimize
pipeline deliveries and meet peak delivery requirements in its principal
markets.
Competition. NGPL
competes with other transporters of natural gas in virtually all of the markets
it serves and, in particular, in the Chicago area, which is the northern
terminus of NGPL’s two major pipeline segments and its largest market. These
competitors include both interstate and intrastate natural gas pipelines that
transport United States produced natural gas along with the Alliance Pipeline,
which transports Canada-produced natural gas, into the Chicago area. The Vector
Pipeline provides the ability to transport Chicago area natural gas supplies to
additional markets that are farther north and farther east. The overall impact
of the considerable pipeline capacity into the Chicago area, combined with
additional take-away capacity and the increased demand in the area, has created
a situation that remains dynamic with respect to the ultimate impact on
individual transporters such as NGPL. From time to time, other pipelines are
proposed that would compete with NGPL. We cannot predict whether or when any
such pipeline might be built, or its impact on NGPL’s operations or
profitability.
In
January 2008, we sold our interests in three natural gas-fired power plants in
Colorado. Our remaining Power operations consist of (i) an ownership interest in
and operations of a 550-megawatt natural gas-fired electricity generation
facility in Michigan and (ii) operating and maintaining a 103-megawatt natural
gas-fired power plant in Snyder, Texas. During 2008, approximately 76% of
Power’s operating revenues represented tolling revenues of the Michigan
facility, the remaining 24% was primarily for operating the Snyder, Texas power
facility, which provides electricity to Kinder Morgan Energy Partners’ SACROC
operations within the CO2–KMP
segment.
The
principal impact of competition at the Michigan facility is the level of
dispatch of the plant and the related, but minor, effect on
profitability.
The
Products Pipelines–KMP segment consists of Kinder Morgan Energy Partners’
refined petroleum products and natural gas liquids pipelines and associated
terminals, Southeast terminals and transmix processing facilities.
West
Coast Products Pipelines
The
West Coast Products Pipelines include the Pacific operations (including SFPP,
L.P.), CALNEV Pipe Line LLC (“Calnev”) and the 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.
SFPP,
L.P. serves six western states with approximately 3,100 miles of refined
petroleum products pipelines and related terminal facilities that provide
refined products to major population centers in the United States, including
California; Las Vegas and Reno, Nevada; and the Phoenix-Tucson, Arizona
corridor. For 2008, the three main product types transported were gasoline
(59%), diesel fuel (23%) and jet fuel (18%).
Calnev
consists of two parallel 248-mile, 14-inch and 8-inch diameter pipelines that
run from Kinder Morgan Energy Partners’ facilities at Colton, California to Las
Vegas, Nevada. The pipeline serves the Mojave Desert through deliveries to a
terminal at Barstow, California and two nearby major railroad yards. It also
serves Nellis Air Force Base, located in Las
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Items 1. and
2. Business and Properties.
(continued)
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Knight
Form 10-K
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Vegas
and also includes approximately 55 miles of pipeline serving Edwards Air Force
Base.
The
West Coast Products Pipelines include 15 truck-loading terminals (13 on SFPP,
L.P. and two on Calnev) with an aggregate usable tankage capacity of
approximately 14.9 million barrels. The truck terminals provide services
including short-term product storage, truck loading, vapor handling, additive
injection, dye injection and ethanol blending.
The
West Coast Terminals are fee-based terminals located in the Seattle, Portland,
San Francisco and Los Angeles areas along the west coast of the United States
with a combined total capacity of approximately 8.4 million barrels of storage
for both petroleum products and chemicals.
Markets. Combined,
the West Coast Products Pipelines’ pipelines transport approximately 1.3 million
barrels per day of refined petroleum products, providing pipeline service to
approximately 31 customer-owned terminals, 11 commercial airports and 15
military bases. Currently, the West Coast Products Pipelines serve approximately
100 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 and purchase patterns and demographic changes in the markets served. Certain
product volumes can experience seasonal variations and, consequently, overall
volumes may be lower during the first and fourth quarters of each
year.
Supply. The
majority of refined products supplied to the West Coast Products Pipelines come
from the major refining centers around Los Angeles, San Francisco, El Paso and
Puget Sound, as well as from waterborne terminals and connecting pipelines
located near these refining centers.
Competition. The
two most significant competitors of the West Coast Products Pipelines’ are
proprietary pipelines owned and operated by major oil companies in the area
where it delivers products and also refineries with terminals that have trucking
arrangements within the West Coast Products Pipelines’ 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 the pipeline systems owned and operated by the
West Coast Products Pipelines will be built in the foreseeable future. However,
the possibility of individual pipelines (such as the Holly pipeline to Las
Vegas, Nevada) being constructed or expanded to serve specific markets is a
continuing competitive factor.
The
use of trucks for product distribution from either shipper-owned proprietary
terminals or from their refining centers continues to compete for short haul
movements by pipeline. The West Coast Terminals compete with terminals owned by
its shippers and by third-party terminal operators in California, Arizona and
Nevada. Competitors include Shell Oil Products U.S., BP (formerly Arco Terminal
Services Company), Wilmington Liquid Bulk Terminals (Vopak), NuStar and Chevron.
We cannot predict with any certainty whether the use of short haul trucking will
decrease or increase in the future.
Plantation
Pipe Line Company
Kinder
Morgan Energy Partners owns approximately 51% of Plantation Pipe Line Company
(“Plantation”), a 3,100-mile refined petroleum products pipeline system serving
the southeastern United States. An affiliate of ExxonMobil Corporation owns the
remaining 49% ownership interest. ExxonMobil is the largest shipper on the
Plantation system both in terms of volumes and revenues. Kinder Morgan Energy
Partners operates the system pursuant to agreements with Plantation Services LLC
and Plantation. 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 2008, Plantation delivered an average of 480,341 barrels per day of
refined petroleum products. These delivered volumes were comprised of gasoline
(61%), diesel/heating oil (25%) and jet fuel (14%). Average delivery volumes for
2008 were 10.3% lower than the 535,672 barrels per day delivered during 2007 and
13.5% lower than 555,063 barrels per day delivered during 2006. The decrease was
predominantly driven by (i) changes in production patterns from Louisiana
refineries related to refiners directing higher margin products (such as
reformulated gasoline blendstock for oxygenate blending) into markets not
directly served by Plantation, (ii) a rapid increase in ethanol blending in the
Southeast resulting in lower pipeline-delivered gasoline volumes and (iii) lower
regional demand as a result of high product prices during the first six months
of the year and a slowing economy.
Markets. Plantation
ships products for approximately 30 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
80% of total system volumes.
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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 12%
in 2008 compared to 2007, with the majority of this decline occurring at Dulles
Airport.
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.
Central
Florida Pipeline
The
Central Florida pipeline system consists of a 110-mile, 16-inch diameter
pipeline that transports gasoline and ethanol (beginning in November 2008) 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 Kinder
Morgan Energy Partners’ 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 Kinder Morgan Energy
Partners’ Taft, Florida terminal (located near Orlando) and is also the sole
pipeline supplying jet fuel to the Orlando International Airport in Orlando,
Florida. In 2008, the pipeline system transported approximately 106,700 barrels
per day of refined products, with the product mix being approximately 68%
gasoline, 12% diesel fuel and 20% jet fuel.
Kinder
Morgan Energy Partners owns and operates liquids terminals in Tampa and Taft,
Florida. The Tampa terminal contains approximately 1.5 million barrels of
storage capacity and is connected to two ship dock facilities in the Port of
Tampa. The Tampa terminal provides storage for gasoline, ethanol, diesel fuel
and jet fuel for further movement into either trucks or into the Central Florida
pipeline system. The Tampa terminal also provides storage and truck rack
blending services for ethanol and bio-diesel. The Taft terminal contains
approximately 0.7 million barrels of storage capacity, for gasoline, ethanol and
diesel fuel, for further movement into trucks.
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. Kinder Morgan Energy Partners distributes 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 Kinder Morgan Energy Partners’ 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 attractions located near Orlando.
Supply. The vast
majority of refined petroleum products consumed in Florida are 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. Kinder Morgan Energy Partners is 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 the 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.
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Knight
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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
Chevron and Motiva terminals in Port Tampa. These terminals generally support
the storage requirements of their parent or affiliated companies’ refining and
marketing operations and provide a mechanism for an oil company to enter into
exchange contracts with third parties to serve its storage needs in markets
where the oil company may not have terminal assets.
Federal
regulation of marine vessels, including the requirement under the Jones Act that
United States-flagged vessels contain double-hulls, is a significant factor
influencing the availability of vessels that transport refined petroleum
products. Marine vessel owners are phasing in the requirement based on the age
of the vessel and some older vessels are being redeployed into use in other
jurisdictions rather than being retrofitted with a double-hull for use in the
United States.
Cochin
Pipeline System
The
Cochin pipeline system consists of an approximate 1,900-mile, 12-inch diameter
multi-product pipeline operating between Fort Saskatchewan, Alberta and Windsor,
Ontario, including five terminals.
The
pipeline operates on a batched basis and has an estimated system capacity of
approximately 70,000 barrels per day. It includes 31 pump stations spaced at
60-mile intervals and five United States propane terminals. Underground storage
is available at Fort Saskatchewan, Alberta and Windsor, Ontario through third
parties. In 2008, the pipeline system transported approximately 30,800 barrels
per day of natural gas liquids.
Markets. The
pipeline traverses three provinces in Canada and seven states in the United
States and can transport propane, butane and natural gas liquids to the
Midwestern United States and eastern Canadian petrochemical and fuel markets.
Current operations involve only the transportation of propane on
Cochin.
Supply. Injection into the
system can occur from BP, Provident, Keyera or Dow facilities, with connections
at Fort Saskatchewan, Alberta and from Spectra at interconnects at Regina and
Richardson, Saskatchewan.
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
Kinder
Morgan Energy Partners’ 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. In 2008, the pipeline system
transported approximately 43,900 barrels per day of refined petroleum
products.
Markets. The
pipeline was built to service Westlake Petrochemicals Corporation in the Lake
Charles, Louisiana area under a 20-year ship-or-pay agreement that expires in
2011. The contract requires a minimum volume of 30,000 barrels per
day.
Supply. The
Cypress pipeline originates in Mont Belvieu where it is able to receive ethane
and ethane/propane mix from local storage facilities. Mont Belvieu has
facilities to fractionate natural gas liquids received from several pipelines
into ethane and other components. Additionally, pipeline systems that transport
natural gas liquids from major producing areas in Texas, New Mexico, Louisiana,
Oklahoma and the Mid-Continent region supply ethane and ethane/propane mix to
Mont Belvieu.
Competition. The
pipeline’s primary competition into the Lake Charles market comes from Louisiana
onshore and offshore natural gas liquids.
Southeast
Terminals
Kinder
Morgan Energy Partners’ Southeast terminal operations consist of Kinder Morgan
Southeast Terminals LLC and its consolidated affiliate, Guilford County Terminal
Company, LLC. Kinder Morgan Southeast Terminals LLC, Kinder Morgan Energy
Partners’ wholly owned subsidiary referred to in this report as KMST, was formed
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.
The
Southeast terminal operations consist of 24 petroleum products terminals with a
total storage capacity of approximately 8.0 million barrels. These terminals
transferred approximately 351,000 barrels of refined products per day during
2008 and approximately 361,000 barrels of refined products per day during
2007.
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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. During 2008, KMST expanded its ethanol blending and storage
services beyond northern Virginia into several conventional gasoline markets.
The new ethanol blending facilities are located in Athens, Georgia, Doralville,
Georgia, North Augusta, South Carolina, Charlotte, North Carolina, Greensboro,
North Carolina and Selma, North Carolina. Longer term storage is 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.
Supply. Product
supply is predominately from Plantation and Colonial pipelines, with a number of
terminals connected to both 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 significant independent terminal operators in this
region.
Transmix
Operations
Kinder
Morgan Energy Partners’ 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 pipeline
transportation, different products are transported through the pipelines
abutting each other, and generate a volume of different mixed products called
transmix. At transmix processing facilities, pipeline transmix is processed and
separated into pipeline-quality gasoline and light distillate products. Kinder
Morgan Energy Partners processes transmix at six separate processing facilities
located in Colton, California; Richmond, Virginia; Dorsey Junction, Maryland;
Indianola, Pennsylvania; Wood River, Illinois; and Greensboro, North Carolina.
Combined, its transmix facilities processed approximately 10.4 million barrels
of transmix in both 2008 and 2007.
Markets. The Gulf
and East Coast refined petroleum products distribution system, particularly the
Mid-Atlantic region, is the target market for Kinder Morgan Energy Partners’
East Coast transmix processing operations. The Mid-Continent area and the New
York Harbor are the target markets for Kinder Morgan Energy Partners’ Illinois
and Pennsylvania assets, respectively. Kinder Morgan Energy Partners’ West Coast
transmix processing operations support the markets served by its West Coast
Products Pipelines in Southern California.
Supply. Transmix
generated by Plantation, Colonial, Explorer, Sun, Teppco and Kinder Morgan
Energy Partners’ West Coast Products Pipelines provide the vast majority of the
supply. These suppliers are committed to the use of Kinder Morgan Energy
Partners’ 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 Kinder Morgan Energy Partners’ West Coast Products Pipelines; Dorsey
Junction is supplied by Colonial Pipeline Company and Greensboro is supplied by
Plantation.
Competition. Placid
Refining is Kinder Morgan Energy Partners’ main competitor for transmix business
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 Kinder Morgan Energy Partners’ transmix facilities. Motiva
Enterprises’ transmix facility located near Linden, New Jersey is the principal
competition for New York Harbor transmix supply and for the 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. The Colton processing facility also
competes with major oil company refineries in California.
The
Natural Gas Pipelines–KMP segment has both interstate and intrastate pipeline
assets and performs natural gas sales, transportation, storage, gathering,
processing and treating services. Within this segment, Kinder Morgan Energy
Partners owns approximately 14,300 miles of natural gas pipelines and associated
storage and supply lines that are strategically located at the center of the
North American pipeline grid. The 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.
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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:
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Kinder
Morgan Texas Pipeline;
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Kinder
Morgan Tejas Pipeline;
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Mier-Monterrey
Mexico Pipeline; and
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Kinder
Morgan North Texas Pipeline.
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The
two largest systems in the group are Kinder Morgan Texas Pipeline and 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
126 billion cubic feet of system natural gas storage capacity. In addition, the
combined system, through owned assets and contractual arrangements with third
parties, has the capability to process 685 million cubic feet per day of natural
gas for liquids extraction and to treat approximately 180 million cubic feet per
day of natural gas for carbon dioxide removal.
Collectively,
the combined system primarily serves the Texas Gulf Coast by selling,
transporting, processing and treating gas from multiple onshore and offshore
supply sources to serve the Houston/Beaumont/Port Arthur/Austin industrial
markets, 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. 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 the Kinder Morgan Tejas system is the 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 (“Pemex”) at the
international border between the United States (Hidalgo, County, Texas) and
Mexico, to a point of interconnection with other intrastate pipeline facilities
of Kinder Morgan Tejas located at King Ranch, Kleburg County, Texas. The
pipeline has a capacity of approximately 300 million cubic feet of natural gas
per day and is capable of importing this volume of Mexican gas into the United
States or exporting this volume of gas to Mexico.
The
Mier-Monterrey Pipeline consists of a 95-mile natural gas pipeline between Starr
County, Texas and 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. Kinder Morgan Energy Partners
has entered into a long-term contract (expiring in 2018) with Pemex, which has
subscribed for all of the pipeline’s capacity.
The
Kinder Morgan North Texas Pipeline consists of an 82-mile natural gas pipeline
that transports natural gas from an interconnect with the facilities of NGPL 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. The existing system is bi-directional,
permitting deliveries of additional supply from the Barnett Shale area into
NGPL’s pipeline as well as power plants in the area.
Kinder
Morgan Energy Partners also owns and operates various gathering systems in South
and East Texas. These systems aggregate natural gas supplies into Kinder Morgan
Energy Partners’ main transmission pipelines and in certain cases, aggregate
natural gas that must be processed or treated at its own or third-party
facilities. Kinder Morgan Energy Partners owns plants that can process up to 135
million cubic feet per day of natural gas for liquids extraction. Kinder Morgan
Energy Partners has contractual rights to process approximately 550 million
cubic feet per day of natural gas at third-party owned facilities. Kinder Morgan
Energy Partners also shares in gas processing margins on gas processed at
certain third-party owned facilities. Additionally, it owns and operates three
natural gas treating plants that provide carbon dioxide and/or hydrogen sulfide
removal. Kinder Morgan Energy Partners can treat up to 85 million cubic feet per
day of natural gas for carbon dioxide removal at the Fandango Complex in Zapata
County, Texas, 50 million cubic feet per day of natural gas at the Indian Rock
Plant in Upshur County, Texas and approximately 45 million cubic feet per day of
natural gas at the Thompsonville Facility located in Jim Hogg County,
Texas.
The
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 cushion gas. Kinder Morgan Energy Partners entered into a
long-term storage capacity and transportation agreement with NRG Energy, Inc.
covering two billion cubic feet of natural gas working capacity that expires in
March 2017. In June 2006, Kinder Morgan Energy Partners announced an expansion
project that will significantly increase natural gas storage capacity at the
North Dayton facility. The project is now expected to cost between $105 million
and $115 million and
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involves
the development of a new underground storage cavern that will add an estimated
6.5 billion cubic feet of incremental working natural gas storage capacity. The
additional capacity is expected to be available in mid-2010.
Kinder
Morgan Energy Partners also owns the West Clear Lake natural gas storage
facility located in Harris County, Texas. Under a long term contract that
expires in 2012, Shell Energy North American (US) L.P. operates the facility and
controls the 96 billion cubic feet of natural gas working capacity, and Kinder
Morgan Energy Partners provides transportation service into and out of the
facility.
Additionally,
Kinder Morgan Energy Partners leases a salt dome storage facility located near
Markham, Texas, according to the provisions of an operating lease that expires
in March 2013. Kinder Morgan Energy Partners can, at its sole option, extend the
term of this lease for two additional ten-year periods. The facility was
expanded in 2008 and now consists of five salt dome caverns with approximately
24.8 billion cubic feet of working natural gas capacity and up to 1.1 billion
cubic feet per day of peak deliverability. Kinder Morgan Energy Partners also
leases two salt dome caverns, known as the Stratton Ridge Facilities, from Ineos
USA, LLC 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 150 million cubic feet per day. In addition to the
aforementioned storage facilities, Kinder Morgan Energy Partners contracts for
storage services from third parties which it then sells to customers on its
pipeline system.
Markets. Texas is one of the
largest natural gas consuming states in the country. The natural gas demand
profile in Kinder Morgan Energy Partners’ Texas intrastate pipeline group’s
market area is primarily composed of industrial (including on-site cogeneration
facilities), merchant and utility power and local natural gas distribution
consumption. 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, Kinder Morgan Energy Partners has successfully attached many of
these new generation facilities to its pipeline systems in order to maintain and
grow its share of natural gas supply for power generation.
Kinder
Morgan Energy Partners serves the Mexico market through interconnection with the
facilities of Pemex at the United States-Mexico border near Arguellas, Mexico
and Kinder Morgan Energy Partners’ Meir-Monterrey Mexico pipeline. In 2008,
deliveries through the existing interconnection near Arguellas fluctuated from
zero to approximately 295 million cubic feet per day of natural gas, and there
were several days of exports to the United States that ranged up to 288 million
cubic feet per day. Deliveries to Monterrey also ranged from zero to 321 million
cubic feet per day. Kinder Morgan Energy Partners primarily provides transport
service to these markets on a fee for service basis, including a significant
demand component, which is paid regardless of actual throughput. Revenues earned
from Kinder Morgan Energy Partners’ activities in Mexico are paid in U.S. dollar
equivalent.
Supply. Kinder
Morgan Energy Partners purchases its natural gas directly from producers
attached to its system in South Texas, East Texas, West Texas and along the
Texas Gulf Coast. In addition, Kinder Morgan Energy Partners also purchases gas
at interconnects with third-party interstate and intrastate pipelines. While the
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. The
intrastate system has access to both onshore and offshore sources of supply and
liquefied natural gas from the Freeport LNG Terminal near Freeport, Texas and
from the Golden Pass Terminal currently under development by ExxonMobil south of
Beaumont, Texas.
Competition. The Texas
intrastate natural gas market is highly competitive, with many markets connected
to multiple pipeline companies. Kinder Morgan Energy Partners competes with
interstate and intrastate pipelines, and their shippers, for attachments to new
markets and supplies and for transportation, processing and treating
services.
Western
Interstate Natural Gas Pipeline Group
The
group, which operates primarily along the Rocky Mountain region of the western
portion of the United States, consists of the following four natural gas
pipeline systems:
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Kinder
Morgan Interstate Gas Transmission (“KMIGT”)
Pipeline;
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Trailblazer
Pipeline Company LLC
(“Trailblazer”);
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TransColorado
Gas Transmission Company LLC (“TransColorado”) Pipeline;
and
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51%
ownership interest in the Rockies Express Pipeline
LLC.
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KMIGT
owns approximately 5,100 miles of transmission lines in Wyoming, Colorado,
Kansas, Missouri and Nebraska. The pipeline system is powered by 26 transmission
and storage compressor stations with approximately 160,000 horsepower. KMIGT
also owns the Huntsman natural gas storage facility, located in Cheyenne County,
Nebraska, which has approximately 10 billion cubic feet of firm capacity
commitments and provides for withdrawal of up to 169 million cubic feet per day
of natural gas.
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Under
transportation agreements and FERC tariff provisions, KMIGT offers its customers
firm and interruptible transportation and storage services, including no-notice
service and park and loan services. For these services, KMIGT charges rates that
include the retention of fuel and gas lost and unaccounted for in-kind. Under
KMIGT’s tariffs, firm transportation and storage customers pay reservation
charges 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 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.
KMIGT has seen a significant increase in demand from ethanol producers, and has
expanded its system to meet the demands from the ethanol producing community.
Additionally, in November 2008, KMIGT completed the construction of the Colorado
Lateral Pipeline, which is a 41-mile, 12-inch pipeline from the Cheyenne Hub
southward to the Greeley, Colorado area. Atmos Energy is served by this pipeline
under a long-term firm transportation contract, and KMIGT is marketing
additional capacity along its route.
Supply. Approximately
11%, by volume, of KMIGT’s firm contracts expire within one year and 57% expire
within one to five years. Over 95% of the system’s total firm transport capacity
is currently subscribed, with 69% of the total
contracted capacity held by KMIGT’s top ten shippers.
Competition. KMIGT
competes with other interstate and intrastate natural gas pipelines transporting
natural gas from the supply sources in the Rocky Mountain and Hugoton Basins to
Mid-Continent pipelines and market centers.
Trailblazer
owns a 436-mile natural gas pipeline system. Trailblazer’s pipeline 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 NGPL’s and Northern Natural Gas
Company’s pipeline systems. NGPL manages, maintains and operates Trailblazer,
for which it is reimbursed at cost.
Trailblazer
offers its customers firm and interruptible transportation
services.
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, 2008, approximately 6% of Trailblazer’s firm contracts, by volume,
expire within one year and 53%, by volume, expire within one to five years.
Affiliated entities have contracted for 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 is transported on competing pipelines to the west or east.
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
Rockies Express Pipeline can transport approximately 1.6 billion cubic feet per
day of natural gas from the Rocky Mountain area to Midwest markets. These
systems compete with Trailblazer for natural gas pipeline transportation demand
from the Rocky Mountain area. Additional competition could come from other
proposed pipeline projects. No assurance can be given that additional competing
pipelines will not be developed in the future.
TransColorado
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 eight compressor stations having an aggregate of
approximately 40,000 horsepower.
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
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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 system 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. 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.
TransColorado’s
approximately $50 million Blanco-Meeker Expansion Project was placed into
service on January 1, 2008. The project increased capacity on the pipeline by
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 pipeline
for deliveries to the Rockies Express Pipeline system at an existing point of
interconnection located at the Meeker Hub in Rio Blanco County, Colorado. All of
the incremental capacity is subscribed under a long-term contract with
ConocoPhillips.
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 one of the largest
transporters of natural gas from the Western Slope supply basins of Colorado and
provides a competitively attractive outlet for that developing natural gas
resource. In 2008, TransColorado transported an average of approximately 675
million cubic feet per day of natural gas from these supply basins.
Supply. During
2008, 93% of TransColorado’s transport business was with processors or producers
or their own marketing affiliates, and 7% was with marketing companies and
various gas marketers. Approximately 69% of TransColorado’s transport business
in 2008 was conducted with its three largest customers. All of TransColorado’s
long-haul southbound pipeline capacity is committed under firm transportation
contracts that extend at least through year-end 2009. Of TransColorado’s
transportation contracts, 41%, by volume, expire between one and five years from
now, and TransColorado is actively pursuing contract extensions and or
replacement contracts to increase firm subscription levels beyond
2009.
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 and at
the north end of its system to accommodate greater natural gas volumes. In
addition, there are pipelines that are proposed to use Rocky Mountain gas to
supply markets on the West Coast, including Ruby Pipeline, which filed in
January 2009 for FERC authority to build pipeline from Opal, Wyoming to Malin,
Oregon, with a planned in-service date of March 2011.
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. New pipelines servicing these
producing basins have had the effect of reducing that price differential;
however, given the growth in the Piceance basin and the direct accessibility of
the TransColorado system to these basins, we believe TransColorado’s transport
business to be sustainable and not significantly affected by any new
competitors.
Kinder
Morgan Energy Partners operates and currently owns 51% of the 1,679-mile Rockies
Express pipeline system, which when fully completed will be one of the largest
natural gas pipelines ever constructed in North America. The project is expected
to cost $6.3 billion, including a previously announced expansion and will have
the capability to transport 1.8 billion cubic feet per day of natural gas.
Binding firm commitments have been secured for all of the pipeline
capacity.
Kinder
Morgan Energy Partners’ ownership is through its 51% interest in West2East
Pipeline LLC, the sole owner of Rockies Express Pipeline LLC, which owns the
Rockies Express Pipeline. Sempra Pipelines & Storage, a unit of Sempra
Energy and ConocoPhillips hold the remaining ownership interests in the Rockies
Express Pipeline project. Kinder Morgan Energy Partners accounts for its
investment under the equity method of accounting because its ownership interest
will be reduced to 50% when construction of the entire project is completed. At
that time, the capital accounts of West2East Pipeline LLC will be trued up to
reflect Kinder Morgan Energy Partners’ 50% economic interest in the
project.
On
August 9, 2005, the FERC approved Rockies Express Pipeline LLC’s application to
construct 327 miles of pipeline facilities in two phases. Phase I consisted of
the following two pipeline 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. Phase II of the project includes the construction of three compressor
stations referred to as the Meeker, Big Hole
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and
Wamsutter compressor stations. The Meeker and Wamsutter stations were completed
and placed in-service in January 2008. Construction of the Big Hole compressor
station was completed in the fourth quarter of 2008 in order to meet an expected
in-service date in April 2009.
On
April 19, 2007, the FERC issued a final order approving Rockies Express Pipeline
LLC’s 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 Pipeline LLC’s original
certificated facilities, and is comprised of approximately 713 miles of 42-inch
diameter pipeline extending eastward from the Cheyenne Hub to an interconnection
with Panhandle Eastern Pipe Line located in Audrain County, Missouri. The
segment extension transports approximately 1.5 billion cubic feet per day of
natural gas across the following five states: Wyoming, Colorado, Nebraska,
Kansas and Missouri, and includes certain improvements to pre-existing Rockies
Express Pipeline facilities located to the west of the Cheyenne Hub.
Construction of the Rockies Express-West project commenced on May 21, 2007, and
interim firm transportation service with capacity of approximately 1.4 billion
cubic feet per day began January 12, 2008. The entire project (Rockies
Express-West pipeline segment) became fully operational on May 20,
2008.
On
April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC
requesting approval to construct and operate the Rockies Express-East Project,
the third segment of the Rockies Express Pipeline system. The Rockies
Express-East Project will be comprised of approximately 639 miles of 42-inch
diameter pipeline commencing from the terminus of the Rockies Express-West
pipeline in Audrain County, Missouri to a terminus near the town of Clarington
in Monroe County, Ohio. The pipeline segment will be capable of transporting
approximately 1.8 billion cubic feet per day of natural gas. The FERC approved
the application on May 30, 2008 and construction commenced on the Rockies
Express-East Project on June 26, 2008. Rockies Express-East is currently
projected to commence service on April 1, 2009 to interconnects upstream of
Lebanon, followed by service to the Lebanon Hub in Warren County, Ohio beginning
June 15, 2009. Final completion and deliveries to Clarington, Ohio are expected
to commence by November 1, 2009.
Markets. The
Rockies Express Pipeline is capable of delivering gas to multiple markets along
its pipeline system, primarily through interconnects with other interstate
pipeline companies and direct connects to local distribution companies. Rockies
Express Pipeline’s Zone 1 encompasses receipts and deliveries of natural gas
west of the Cheyenne Hub, located in northern Colorado near Cheyenne, Wyoming.
Through the Zone 1 facilities, Rockies Express Pipeline can deliver gas to
TransColorado Gas Transmission Company LLC in northwestern Colorado, which can
in turn transport the gas farther south for delivery into the San Juan Basin
area. In Zone 1, Rockies Express Pipeline can also deliver gas into western
Wyoming through leased capacity on the Overthrust Pipeline Company system, or
through its interconnections with Colorado Interstate Gas Company and Wyoming
Interstate Company in southern Wyoming. In addition, through the pipeline’s Zone
1 facilities, shippers have the ability to deliver natural gas to points at the
Cheyenne Hub, which could be used in markets along the Front Range of Colorado,
or could be transported farther east through either Rockies Express Pipeline’s
Zone 2 and/or Zone 3 facilities into other pipeline systems.
Rockies
Express Pipeline’s Zone 2 extends from the Cheyenne Hub to an interconnect with
Panhandle Eastern Pipeline in Audrain County, Missouri. Through the Zone 2
facilities, Rockies Express Pipeline facilitates the delivery of natural gas
into the Mid-Continent area of the Unites States through various interconnects
with other major interstate pipelines in Nebraska (Northern Natural Gas Pipeline
and NGPL), Kansas (ANR Pipeline) and Missouri (Panhandle Eastern Pipeline).
Rockies Express Pipeline’s transportation is capable of delivering 1.5 billion
cubic feet per day through these interconnects to the Mid-Continent
market.
The
Zone 3 facilities covered by the Rockies Express-East project extend eastward
from the Rockies Express-West facilities and will permit delivery to pipelines
and local distribution companies providing service in the South, Midwest and
eastern seaboard. The interconnecting interstate pipelines include Midwestern
Gas Transmission, Trunkline, ANR, Columbia Gas, Dominion Transmission, Tennessee
Gas, Texas Eastern, Texas Gas and Dominion East Ohio and the local distribution
companies include Ameren and Vectren.
Supply. Rockies
Express Pipeline directly accesses major gas supply basins in western Colorado
and western Wyoming. In western Colorado, Rockies Express Pipeline has access to
gas supply from the Uinta and Piceance basins in eastern Utah and western
Colorado. In western Wyoming, Rockies Express Pipeline accesses the Green River
Basin through its facilities that are leased from Overthrust Pipeline Company.
With its connections to numerous other pipeline systems along its route, Rockies
Express Pipeline has access to almost all of the major gas supply basins in
Wyoming, Colorado and eastern Utah.
Competition. Although
there are some competitors to the Rockies Express Pipeline system that provide a
similar service, there are none that can compete with the economy-of-scale that
Rockies Express Pipeline provides to its shippers to transport gas from the
Rocky Mountain region to the Mid-Continent markets. The Rockies Express-East
Project, noted above, will put the Rockies Express Pipeline system in a very
unique position of being the only pipeline capable of offering a large volume of
transportation service from Rocky Mountain gas supply directly to interstate
pipelines and local distribution companies with facilities in Ohio and
beyond.
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Rockies
Express Pipeline could also experience competition for its Rocky Mountain gas
supply from both existing and proposed systems. Questar Pipeline Company
accesses many of the same basins as Rockies Express Pipeline and transports gas
to its markets in Utah and to other interconnects, which have access to the
California market. In addition, there are pipelines that are proposed to use
Rocky Mountain gas to supply markets on the West Coast, including Ruby Pipeline,
which filed in January 2009 for FERC authority to build a pipeline from Opal,
Wyoming to Malin, Oregon, with a planned in-service date of March
2011.
Central
Interstate Natural Gas Pipeline Group
In
September 2006, Kinder Morgan Energy Partners filed an application with the FERC
requesting approval to construct and operate the Kinder Morgan Louisiana
Pipeline. The natural gas pipeline project is expected to cost approximately
$950 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 20-year take-or-pay customer commitments with
Chevron and Total.
The
Kinder Morgan Louisiana Pipeline will consist of two segments:
|
|
·
|
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
|
|
|
·
|
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 NGPL’s natural gas pipeline. Kinder Morgan Louisiana
Pipeline is expected to be operational during the third quarter of
2009.
|
Kinder
Morgan Energy Partners has 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, 2008, there were no major
pipeline re-routes as a result of any landowner requests.
On
October 9, 2007, Midcontinent Express Pipeline LLC filed an application with the
FERC requesting a certificate of public convenience and necessity that would
authorize construction and operation of the approximate 500-mile Midcontinent
Express Pipeline natural gas transmission system. Kinder Morgan Energy Partners
currently owns a 50% interest in Midcontinent Express Pipeline LLC and accounts
for its investment under the equity method of accounting. Energy Transfer
Partners, L.P. owns the remaining 50% interest. The Midcontinent Express
Pipeline LLC will create long-haul, firm natural gas transportation takeaway
capacity, either directly or indirectly, from natural gas producing regions
located in Texas, Oklahoma and Arkansas. The project is expected to cost
approximately $2.2 billion, including previously announced expansions. This is
an increase from the $1.9 billion previous forecast. Much of the increase is
attributable to increased construction cost. Midcontinent Express Pipeline LLC
is currently finalizing negotiations with contractors for construction of the
final segment. Those contracts will fix the per unit prices, providing greater
cost certainty on that portion of the project and those construction costs are
incorporated into the current forecast.
In
July 2008, a successful binding open season was completed that increased
commitments on the main segment of the pipeline’s Zone 1 from 1.5 billion to 1.8
billon cubic feet per day of natural gas. The pipeline capacity is fully
subscribed with long-term binding commitments from creditworthy
shippers.
In
January 2008, in conjunction with the signing of additional binding
transportation commitments, Midcontinent Express Pipeline LLC and Mark West
Energy Partners L.P. entered into an option agreement, which provides Mark West
Energy Partners L.P. a one-time right to purchase a 10% ownership interest in
Midcontinent Express Pipeline LLC after the pipeline is fully constructed and
placed into service. If the option is exercised, Kinder Morgan Energy Partners
and Energy Transfer Partners will each own 45% of Midcontinent Express Pipeline
LLC, while Mark West Energy Partners L.P. will own the remaining
10%.
The
Fayetteville Express Pipeline, when completed, will be a 187-mile, 42-inch
diameter pipeline that originates in Conway County, Arkansas, continues eastward
through White County, Arkansas and terminates at an interconnect with Trunkline
Gas Company’s pipeline in Quitman County, Mississippi. We own a 50% interest in
Fayetteville Express Pipeline LLC and Energy Transfer Partners L.P. owns the
remaining interest.
The
Fayetteville Express Pipeline will also interconnect with Natural Gas Pipeline
Company of America LLC’s pipeline in White County, Arkansas, Texas Gas
Transmission LLC’s pipeline in Coahoma County, Mississippi, and ANR Pipeline
Company’s pipeline in Quitman County, Mississippi. The Fayetteville Express
Pipeline will have an initial capacity of 2.0
21
|
Items 1. and
2. Business and Properties.
(continued)
|
Knight
Form 10-K
|
billion
cubic feet of natural gas per day. Pending necessary regulatory approvals, the
approximate $1.2 billion pipeline project is expected to be in service by late
2010 or early 2011. Fayetteville Express Pipeline LLC has secured binding
10-year commitments totaling approximately 1.85 billion cubic feet per day and
completed a successful binding open season for shippers on November 7,
2008.
Kinder
Morgan Energy Partners owns and operates the Casper and Douglas natural gas
processing systems, which have the capacity to process up to 185 million cubic
feet per day of natural gas depending on raw gas quality.
Markets. Casper
and Douglas are processing plants servicing gas streams flowing into KMIGT.
Natural gas liquids processed by the Casper plant are sold into local markets
consisting primarily of retail propane dealers and oil refiners. Natural gas
liquids processed by the 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 (230 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.
Kinder
Morgan Energy Partners owns 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 three 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. 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
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 1,200 producing wells, 85,000 horsepower of
compression at 21 field compressor stations and two carbon dioxide treating
plants. The capacity and throughput of the Red Cedar system as currently
configured is approximately 750 million cubic feet per day of natural
gas.
The
CO2–KMP
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. KMCO2’s carbon
dioxide pipelines and related assets allow Kinder Morgan Energy Partners to
market a complete package of carbon dioxide supply, transportation and technical
expertise to the customer. Together, the CO2–KMP
business segment produces, transports and markets carbon dioxide for use in
enhanced oil recovery operations. Kinder Morgan Energy Partners also holds
ownership interests in several oil-producing fields and owns a 450-mile crude
oil pipeline, all located in the Permian Basin region of West
Texas.
Carbon
Dioxide Reserves
Kinder
Morgan Energy Partners owns approximately 45% of, and operates, the McElmo Dome
unit near Cortez, Colorado, which contains more than nine trillion cubic feet of
recoverable carbon dioxide. Deliverability and compression capacity exceeds one
billion cubic feet per day. Kinder Morgan Energy Partners completed the
installation of facilities and drilled eight wells that have increased the
production capacity from McElmo Dome by over 200 million cubic feet per day.
Kinder Morgan Energy Partners also owns approximately 11% of the Bravo Dome unit
in New Mexico, which contains more than one trillion cubic feet of recoverable
carbon dioxide and produces approximately 290 million cubic feet per
day.
Kinder
Morgan Energy Partners also owns approximately 87% of the Doe Canyon Deep unit
in southwest Colorado, which contains more than 1.5 trillion cubic feet of
carbon dioxide. During 2008, Kinder Morgan Energy Partners completed the
installation of facilities and drilled six wells that began to produce over 100
million cubic feet per day of carbon dioxide.
22
|
Items 1. and
2. Business and Properties.
(continued)
|
Knight
Form 10-K
|
Markets. Kinder
Morgan Energy Partners’ 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. Kinder Morgan Energy Partners is
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. Kinder
Morgan Energy Partners’ 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 PetroSource Energy Company, a wholly
owned subsidiary of SandRidge Energy, Inc., 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 Kinder Morgan Energy Partners or that new methodologies
for enhanced oil recovery will not replace carbon dioxide flooding.
Carbon
Dioxide Pipelines
As
a result of its 50% ownership interest in Cortez Pipeline Company, Kinder Morgan
Energy Partners owns a 50% equity interest in and operates the approximate
500-mile, Cortez pipeline. The pipeline carries carbon dioxide from the McElmo
Dome and Doe Canyon Deep source fields near Cortez, Colorado to the Denver City,
Texas hub. The Cortez pipeline currently transports over one billion cubic feet
of carbon dioxide per day, including approximately 99% of the carbon dioxide
transported downstream on the Central Basin pipeline and the Centerline
pipeline. The tariffs charged by Cortez Pipeline Company are not
regulated.
Kinder
Morgan Energy Partners’ Central Basin pipeline consists of approximately 143
miles of pipe and 177 miles of lateral supply lines located in the Permian Basin
between Denver City, Texas and McCamey, Texas, with a throughput capacity of 700
million cubic feet per day. At its origination point in Denver City, the 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 Oxy Permian). Central
Basin’s mainline terminates near McCamey where it interconnects with the Canyon
Reef Carriers pipeline and the Pecos pipeline. The tariffs charged by the
Central Basin pipeline are not regulated.
Kinder
Morgan Energy Partners’ Centerline pipeline consists of approximately 113 miles
of 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. The
tariffs charged by the Centerline pipeline are not regulated.
Kinder
Morgan Energy Partners owns a 13% undivided interest in the 218-mile Bravo
pipeline, which delivers carbon dioxide from the Bravo Dome source field in
northeast New Mexico to the Denver City hub and has a capacity of more than 350
million cubic feet per day. Tariffs on the Bravo pipeline are not
regulated.
In
addition, Kinder Morgan Energy Partners owns 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 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 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 KMCO2’s carbon
dioxide pipelines is to customers, including Kinder Morgan Energy Partners,
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. Kinder
Morgan Energy Partners’ ownership interests in the Central Basin, Cortez and
Bravo pipelines are in direct competition with other carbon dioxide pipelines.
Kinder Morgan Energy Partners also competes with other interest owners in McElmo
Dome and Bravo Dome for transportation of carbon dioxide to the Denver City,
Texas market area.
Oil
Acreage and Wells
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, an approximate 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.
23
|
Items 1. and
2. Business and Properties.
(continued)
|
Knight
Form 10-K
|
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 1.31 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 29% has been produced. The
field, discovered in 1926, is comprised of approximately 26,000 acres located
about 90 miles south of Midland, Texas.
In
2008, the average purchased CO2 injection
rate was 259 million cubic feet per day, up from an average of 212 million cubic
feet per day in 2007. The average oil production rate for 2008 was approximately
28,000 barrels of oil per day, up from an average of approximately 27,600
barrels of oil per day during 2007. The average natural gas liquids production
rate (net of the processing plant share) for 2008 was approximately 5,500
barrels per day, a decrease from an average of approximately 6,300 barrels per
day during 2007.
Kinder
Morgan Energy Partners’ 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. Kinder Morgan Energy Partners is implementing its plan and during
2008, the Yates unit produced about 27,600 barrels of oil per day, up from an
average of approximately 27,000 barrels of oil per day in 2007. Unlike
operations at SACROC, where carbon dioxide and water is used to drive oil to the
producing wells, Kinder Morgan Energy Partners is 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.
Kinder
Morgan Energy Partners also operates and owns an approximate 65% 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 producing 235 barrels of oil per day during
2008, up from an average of 218 barrels of oil per day during 2007. Kinder
Morgan Energy Partners is presently evaluating operating and subsurface
technical data from the Claytonville unit to further assess redevelopment
opportunities including carbon dioxide flood operations.
Kinder
Morgan Energy Partners also operates and owns working interests in the Katz CB
Long unit, the Katz Southwest River unit and Katz East River unit. The Katz
field is located in the Permian Basin area of West Texas and during 2008,
produced 425 barrels of oil per day, up from an average of 408 barrels of oil
per day during 2007. Kinder Morgan Energy Partners is presently evaluating
operating and subsurface technical data to further assess redevelopment
opportunities for the Katz field including the potential for carbon dioxide
flood operations.
The
following table sets forth productive wells, service wells and drilling wells in
the oil and gas fields in which Kinder Morgan Energy Partners owns interests as
of December 31, 2007. When used with respect to acres or wells, gross refers to
the total acres or wells in which Kinder Morgan Energy Partners has a working
interest; net refers to gross acres or wells multiplied, in each case, by the
percentage working interest owned by Kinder Morgan Energy Partners:
|
Productive Wells1
|
Service Wells2
|
Drilling Wells3
|
|||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||
|
Crude
Oil
|
2,906
|
2,029
|
895
|
700
|
4
|
4
|
|||||
|
Natural
Gas
|
6
|
3
|
36
|
18
|
─
|
─
|
|||||
|
Total
Wells
|
2,912
|
2,032
|
931
|
718
|
4
|
4
|
|||||
__________
|
1
|
Includes
active wells and wells temporarily shut-in. As of December 31, 2007,
Kinder Morgan Energy Partners did not operate any productive wells with
multiple completions.
|
|
2
|
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.
|
|
3
|
Consists
of development wells in the process of being drilled as of December 31,
2008. A development well is a well drilled in an already discovered oil
field.
|
24
|
Items 1. and
2. Business and Properties.
(continued)
|
Knight
Form 10-K
|
The
oil and gas producing fields in which Kinder Morgan Energy Partners owns
interests are located in the Permian Basin area of West Texas. The following
table reflects Kinder Morgan Energy Partners’ net productive and dry wells that
were completed in each of the three years ended December 31, 2008, 2007 and
2006:
|
2008
|
2007
|
2006
|
|||
|
Productive
|
|||||
|
Development
|
47
|
31
|
37
|
||
|
Exploratory
|
-
|
-
|
-
|
||
|
Dry
|
|||||
|
Development
|
-
|
-
|
-
|
||
|
Exploratory
|
-
|
-
|
-
|
||
|
Total
Wells
|
47
|
31
|
37
|
__________
|
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 reservoir.
|
The
following table reflects the developed and undeveloped oil and gas acreage that
Kinder Morgan Energy Partners held as of December 31, 2008:
|
Gross
|
Net
|
||
|
Developed
Acres
|
72,435
|
67,731
|
|
|
Undeveloped
Acres
|
9,555
|
8,896
|
|
|
Total
|
81,990
|
76,627
|
Operating
Statistics
Operating
statistics from Kinder Morgan Energy Partners’ oil and gas producing activities
for each of the years 2008, 2007 and 2006 are shown in the following
table:
Results
of Operations for Oil and Gas Producing Activities – Unit Prices and
Costs
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
|
Seven
Months Ended
December
31,
|
Five
Months Ended
May
31,
|
Year
Ended December 31,
|
|||||||||||||
|
2008
|
2007
|
2007
|
2006
|
|||||||||||||
|
Consolidated
Companies1
|
||||||||||||||||
|
Production
Costs per Barrel of Oil Equivalent2,3,4
|
$
|
20.44
|
$
|
17.00
|
$
|
15.15
|
$
|
13.30
|
||||||||
|
Crude
Oil Production (MBbl/d)
|
36.2
|
34.9
|
36.6
|
37.8
|
||||||||||||
|
Natural
Gas Liquids Production (MBbl/d)4
|
4.8
|
5.4
|
5.6
|
5.0
|
||||||||||||
|
Natural
Gas Liquids Production from Gas Plants (MBbl/d)5
|
3.5
|
4.2
|
4.1
|
3.9
|
||||||||||||
|
Total
Natural Gas Liquids Production (MBbl/d)
|
8.3
|
9.6
|
9.7
|
8.9
|
||||||||||||
|
Natural
Gas Production (MMcf/d)4,6
|
1.4
|
0.8
|
0.8
|
1.3
|
||||||||||||
|
Natural
Gas Production from Gas Plants (MMcf/d)5,6
|
0.2
|
0.3
|
0.2
|
0.3
|
||||||||||||
|
Total
Natural Gas Production (MMcf/d)6
|
1.6
|
1.1
|
1.0
|
1.6
|
||||||||||||
|
Average
Sales Prices Including Hedge Gains/Losses:
|
||||||||||||||||
|
Crude
Oil Price per Bbl7
|
$
|
49.42
|
$
|
36.80
|
$
|
35.03
|
$
|
31.42
|
||||||||
|
Natural
Gas Liquids Price per Bbl7
|
$
|
63.48
|
$
|
57.78
|
$
|
44.55
|
$
|
43.52
|
||||||||
|
Natural
Gas Price per Mcf8
|
$
|
7.73
|
$
|
5.86
|
$
|
6.41
|
$
|
6.36
|
||||||||
|
Total
Natural Gas Liquids Price per Bbl5
|
$
|
63.00
|
$
|
58.55
|
$
|
45.04
|
$
|
43.90
|
||||||||
|
Total
Natural Gas Price per Mcf5
|
$
|
7.63
|
$
|
5.65
|
$
|
6.27
|
$
|
7.02
|
||||||||
|
Average
Sales Prices Excluding Hedge Gains/Losses:
|
||||||||||||||||
|
Crude
Oil Price per Bbl7
|
$
|
97.70
|
$
|
78.65
|
$
|
57.43
|
$
|
63.27
|
||||||||
|
Natural
Gas Liquids Price per Bbl7
|
$
|
63.48
|
$
|
57.78
|
$
|
44.55
|
$
|
43.52
|
||||||||
|
Natural
Gas Price per Mcf8
|
$
|
7.73
|
$
|
5.86
|
$
|
6.41
|
$
|
6.36
|
||||||||
____________
|
1
|
Amounts
relate to Kinder Morgan CO2
Company, L.P. and its consolidated
subsidaries.
|
|
2
|
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.
|
25
|
Items 1. and
2. Business and Properties.
(continued)
|
Knight
Form 10-K
|
|
3
|
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.
|
|
4
|
Includes
only production attributable to leasehold
ownership.
|
|
5
|
Includes
production attributable to Kinder Morgan Energy Partners’ ownership in
processing plants and third-party processing
agreements.
|
|
6
|
Excludes
natural gas production used as
fuel.
|
|
7
|
Hedge
gains/losses for crude oil and natural gas liquids are included with crude
oil.
|
|
8
|
Natural
gas sales were not hedged.
|
See
Supplemental Information on Oil and Gas Producing Activities (Unaudited) to our
Consolidated Financial Statements included in this report for additional
information with respect to operating statistics and supplemental information on
Kinder Morgan Energy Partners’ oil and gas producing activities.
Gas
and Gasoline Plant Interests
Kinder
Morgan Energy Partners operates and owns an approximate 22% working interest
plus an additional 28% net profits interest in the Snyder gasoline plant. Kinder
Morgan Energy Partners also operates and owns 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 2008 was
approximately 13,900 barrels per day as compared to 15,500 barrels per day as of
December 2007.
Crude
Oil Pipeline
Kinder
Morgan Energy Partners owns the Kinder Morgan Wink Pipeline, a 450-mile Texas
intrastate crude oil pipeline system consisting of three mainline sections, two
gathering systems and numerous truck delivery stations. The segment that runs
from Wink to El Paso has a total capacity of 130,000 barrels of crude oil per
day. The pipeline allows Kinder Morgan Energy Partners to better manage crude
oil deliveries from its oil field interests in West Texas, and Kinder Morgan
Energy Partners has 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 20-inch pipeline segment transported
approximately 118,000 barrels of oil per day
in 2008 and approximately 119,000 barrels of oil per day in 2007. The Kinder
Morgan Wink Pipeline is regulated by both the FERC and the Texas Railroad
Commission.
Liquids
Terminals
The
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, vessels, tank trucks,
tank barges and tank railcars. Combined, the liquids terminals facilities
possess liquids storage capacity of approximately 54.2 million barrels, and in
2008, these terminals handled approximately 596 million barrels of petroleum,
chemicals and vegetable oil products.
In
the first quarter of 2008, Kinder Morgan Energy Partners completed the Phase III
expansions at its Pasadena and Galena Park, Texas liquids terminal facilities.
The expansions provided additional infrastructure to help meet the growing need
for refined petroleum products storage capacity along the Gulf Coast. The
investment of approximately $195 million included the construction of the
following: (i) new storage tanks at both the 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 its fully automated truck loading rack with ethanol handling
infrastructure located at its Pasadena terminal. All of the expansions are
supported by long-term customer commitments. With the completion of this
expansion, the Pasadena and Galena Park terminal facilities will have a storage
capacity of approximately 25 million barrels.
In
2008, Kinder Morgan Energy Partners announced future additional expansions at
its Pasadena and Galena Park terminal facilities. The investment of
approximately $114 million includes the construction of the following: (i) 12
new storage tanks at its Pasadena and Galena Park terminals, (ii) a barge dock
that will be capable of handling two 300-foot barges with an
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operating
crane for each location and (iii) a 20-inch, cross-channel line connecting the
two facilities. All of the expansions are supported by long-term customer
commitments.
In
the second quarter of 2008, Kinder Morgan Energy Partners completed and put into
service approximately 2.15 million barrels of new crude oil storage capacity at
its Kinder Morgan North 40 terminal located near Edmonton, Alberta, Canada. The
entire capacity of this terminal is contracted with long-term contracts. The
tank farm serves as a premier blending and storage hub for Canadian crude oil.
Originally estimated at C$132.6 million, the total investment in this tank farm
is now projected to be approximately C$170 million due primarily to additional
labor costs. The tank farm has access to more than 20 incoming pipelines and
several major outbound systems, including a connection with the Trans Mountain
pipeline system, which currently transports up to 300,000 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.
In
the first quarter of 2008, Kinder Morgan Energy Partners completed construction
and placed into service nine new storage tanks at its Perth Amboy, New Jersey
liquids terminal. The tanks have a combined storage capacity of 1.4 million
barrels for gasoline, diesel and jet fuel. These tanks have been leased on a
long-term basis to two customers. The total investment for this expansion was
approximately $68 million.
In
the third quarter of 2008, the Terminals-KMP segment completed and put into
service approximately 320,000 barrels of additional gasoline capacity at its
Shipyard River Terminal located in Charleston, South Carolina. This increase
will bring the terminal storage capacity to approximately 1.9 million barrels
for petroleum, ethanol and other liquid chemicals.
On
August 15, 2008, Kinder Morgan Energy Partners purchased the Kinder Morgan
Wilmington terminal, located in Wilmington, North Carolina, which has
approximately 1.1 million barrels of liquids storage capacity. The facility has
significant transportation infrastructure and provides liquid and heated storage
and custom tank blending capabilities for agricultural and chemical
products.
Competition. Kinder Morgan
Energy Partners is one of the largest independent operators of liquids terminals
in North America. Its primary competitors are IMTT, Magellan, Morgan Stanley,
NuStar, Oil Tanking, Teppco and Vopak.
Bulk
Terminals
The
bulk terminal operations primarily involve dry-bulk material handling services;
however, it also provides conveyor manufacturing and installation, engineering
and design services and in-plant services covering material handling, conveying,
maintenance and repair, railcar switching and miscellaneous marine services.
Combined, the dry-bulk and material transloading facilities handled
approximately 99.1 million tons of coal, petroleum coke, fertilizers, steel,
ores and other dry-bulk materials in 2008. Kinder Morgan Energy Partners owns or
operates approximately 100 dry-bulk terminals in the United States, Canada and
the Netherlands.
In
May 2007, Kinder Morgan Energy Partners purchased certain buildings and
equipment and entered into a 40-year agreement to operate Vancouver Wharves, a
bulk marine terminal located at the entrance to the Port of Vancouver, British
Columbia. To acquire the terminal assets, Kinder Morgan Energy Partners paid an
aggregate consideration of $59.5 million, consisting of $38.8 million in cash
and $20.7 million in assumed liabilities. The facility consists of five vessel
berths situated on a 139-acre site, extensive rail infrastructure, dry-bulk and
liquids storage and material handling systems, which allow the terminal to
handle over 3.5 million tons of cargo annually. Vancouver Wharves has
access to three major rail carriers connecting to shippers in western and
central Canada and the U.S. Pacific Northwest. Vancouver Wharves offers a
variety of inbound, outbound and value-added services for mineral concentrates,
wood products, agri-products and sulfur.
In
addition to the original purchase price, Kinder Morgan Energy Partners plans to
spend an additional C$57 million at Vancouver Wharves to upgrade and/or relocate
certain rail track and transloading systems, buildings and a
shiploader. The rail track and transloading relocations are on
schedule to be completed in the second quarter of 2009. The shiploader project
is expected to be completed in the fourth quarter of 2009.
Effective
September 1, 2007, Kinder Morgan Energy Partners purchased the assets of Marine
Terminals, Inc. for an aggregate consideration of approximately $102.1 million.
Combined, the assets handle approximately 13.5 million tons of alloys and steel
products annually from five facilities located in the southeast United States.
These strategically located terminals provide handling, processing, harboring
and warehousing services primarily to Nucor Corporation, one of the largest
steel and steel products companies in the world, under long-term
contracts.
In
the first quarter of 2008, Kinder Morgan Energy Partners completed and put into
service a barge unloading terminal located on 30 acres in Columbus, Mississippi.
The Columbus terminal provides for approximately 900,000 tons of capacity and
handles scrap metal, pig iron and hot briquetted iron that is brought in by
barge, unloaded and then trucked to the Severstal Steel Mill, which is also
located in Columbus.
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In
the first quarter of 2008, Kinder Morgan Energy Partners also completed and put
into service the Pier X expansion at its bulk handling facility located in
Newport News, Virginia. The expansion involved the construction of a new dock
and installation of additional equipment that increased throughput by
approximately 30%, to approximately nine million tons of bulk products per year.
The expansion allows the facility, which primarily handles coal, to now receive
product via vessel in addition to rail.
On
October 2, 2008, Kinder Morgan Energy Partners acquired certain terminal assets
from LPC Packaging, a California corporation, for an aggregate consideration of
$5.1 million. The acquired assets included state-of-the-art packaging machinery,
conveyors and mobile equipment and consist of two facilities located in
Stockton, California and a single facility located in San Diego, California.
Services provided by these locations include packaging 50 pound bags and super
sacks of fertilizer and starch, warehousing and storage of bags and bulk, and
inventory management. All three facilities benefit from strong relationships
with large customers, having term commitments averaging between three and five
years.
Competition. The 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 the bulk terminals were constructed
pursuant to long-term contracts for specific customers. As a result, other
terminal operators could face a significant disadvantage in competing for this
business.
Materials
Services (rail transloading)
The
materials services operations include rail or truck transloading operations
conducted at 32 owned and non-owned facilities. The Burlington Northern Santa
Fe, 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) or connect via
pipeline to storage facilities. Several facilities provide railcar storage
services. Kinder Morgan Energy Partners also designs and builds transloading
facilities, performs inventory management services and provides value-added
services such as blending, heating and sparging. In 2008, the materials services
operations handled approximately 348,000 railcars.
Competition. The material
services operations compete with a variety of national transload and terminal
operators across the United States, including Savage Services, Watco and Bulk
Plus Logistics. Additionally, single or multi-site terminal operators are often
entrenched in the network of Class 1 rail carriers.
Trans
Mountain Pipeline System
The
Trans Mountain common carrier pipeline system originates at Edmonton, Alberta
and transports crude oil and refined petroleum to destinations in the interior
and on the west coast of British Columbia. A connecting pipeline owned by Kinder
Morgan Energy Partners delivers petroleum to refineries in the state of
Washington.
Trans
Mountain’s pipeline is 715 miles in length. The capacity of the line at Edmonton
ranges from 300,000 barrels per day when heavy crude represents 20% of the total
throughput (which is a historically normal heavy crude percentage) to 400,000
barrels per day with no heavy crude. As discussed above in “—Recent
Developments,” the construction of the Anchor Loop expansion project, which
increased pipeline capacity from approximately 260,000 to 300,000 barrels of
crude oil per day was completed on October 30, 2008. The current Trans Mountain
pipeline system was already looped with a 30-inch diameter pipe between Darfield
and Kamloops, British Columbia and a 30-inch diameter pipe between Edson and
Hinton, Alberta.
Trans
Mountain also operates a 5.3-mile spur line from its Sumas Pump Station to the
U.S. – Canada international border where it connects with a 63-mile pipeline
system owned and operated by Kinder Morgan Energy Partners. The pipeline system
in Washington State has a sustainable throughput capacity of approximately
135,000 barrels per day when heavy crude represents approximately 25% of
throughput and connects to four refineries located in northwestern Washington
State. The volumes of petroleum shipped to Washington State fluctuate in
response to the price levels of Canadian crude oil in relation to petroleum
produced in Alaska and other offshore sources.
In
2008, deliveries on Trans Mountain averaged 237,172 barrels per day. This was a
decrease of 8% from average 2007 deliveries of 258,540 barrels per day.
Shipments of refined petroleum represent a significant portion of Trans
Mountain’s throughput. In 2008 and 2007, shipments of refined petroleum and
iso-octane represented 20% and 25% of throughput, respectively. In April 2007,
ten new pump stations were commissioned that boosted capacity on Trans Mountain
from 225,000 to approximately 260,000 barrels per day. An additional 40,000
barrel per day expansion that increased capacity on
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the
pipeline to approximately 300,000 barrels per day was completed in 2008. Service
on the first 25,000 barrels per day of this capacity increase began in May 2008,
and the remaining 15,000 barrels per day increase began in November 2008. The
crude oil and refined petroleum transported through Trans Mountain’s pipeline
system originates in Alberta and British Columbia. The refined and partially
refined petroleum transported to Kamloops, British Columbia and Vancouver
originates from oil refineries located in Edmonton. Petroleum products delivered
through Trans Mountain’s pipeline system are used in markets in British
Columbia, Washington state and elsewhere.
Supply. Overall
Alberta crude oil supply has been increasing steadily over the past few years as
a result of significant oil sands development with projects led by firms
including Royal Dutch Shell, Suncor Energy and Syncrude Canada. Notwithstanding
current economic factors and some announced project delays, further development
is expected to continue into the future with expansions to existing oil sands
production facilities as well as with new projects. In its moderate growth case,
the Canadian Association of Petroleum Producers forecasts Western Canadian crude
oil production to increase by over 1.4 million barrels per day by 2015. This
increasing supply will likely result in constrained export pipeline capacity
from Western Canada, which supports our view that both the demand for
transportation services provided by Trans Mountain’s pipeline and the supply of
crude oil will remain strong for the foreseeable future.
Shipments
of refined petroleum represent a significant portion of Trans Mountain’s
throughput. In 2008 and 2007, shipments of refined petroleum and iso-octane
represented 20% and 25% of throughput, respectively.
Competition. Trans Mountain’s
pipeline to the West Coast of North America is one of several pipeline
alternatives for Western Canadian petroleum production. This pipeline, like the
other Kinder Morgan Energy Partners’ petroleum pipelines, competes against other
pipeline companies who could be in a position to offer different tolling
structures.
Express
and Jet Fuel Pipeline Systems
Kinder
Morgan Energy Partners owns a one-third ownership interest in and operates the
Express pipeline system, and we own a long-term investment with a C$113.6
million face value in a debt security issued by Express US Holdings LP (the
obligor) the partnership that maintains ownership of the U.S. portion of the
Express pipeline system. The Express pipeline system investment is accounted for
under the equity method of accounting. The Express pipeline system is a
batch-mode, common carrier crude oil pipeline system comprised of the Express
Pipeline and the Platte Pipeline, collectively referred to in this report as the
Express pipeline system. The approximate 1,700-mile integrated oil
transportation pipeline connects Canadian and United States producers to
refineries located in the U.S. Rocky Mountain and Midwest regions.
The
Express Pipeline is a 780-mile long, 24-inch diameter pipeline that begins at
the crude pipeline hub at Hardisty, Alberta and terminates at the Casper,
Wyoming facilities of the Platte Pipeline. At the Hardisty, Canada oil hub, the
Express Pipeline receives a variety of light, medium and heavy crude oil
produced in Western Canada and makes deliveries to markets in Montana, Wyoming,
Utah and Colorado. The Express Pipeline has a design capacity of 280,000 barrels
per day. Receipts at Hardisty averaged 196,160 barrels per day during the year
ended December 31, 2008, compared with 213,477 barrels per day during the year
ended December 31, 2007.
The
Platte Pipeline is a 926-mile long, 20-inch diameter pipeline that runs from the
crude oil pipeline hub at Casper, Wyoming to refineries and interconnecting
pipelines in the Wood River, Illinois area and includes related pumping and
storage facilities (including tanks). The Platte Pipeline transports crude oil
shipped on the Express Pipeline and crude oil produced from the Rocky Mountain
area of the U.S. to markets located in Kansas and Illinois, and to other
interconnecting carriers in those areas. The Platte Pipeline has a capacity of
150,000 barrels per day when shipping heavy oil and averaged 133,637 barrels per
day east of Casper, Wyoming during the year ended December 31, 2008 as compared
to 110,757 barrels per day for the year ended December 31, 2007.
The
current Express pipeline system rate structure is a combination of committed
rates and uncommitted rates. The committed rates apply to those shippers who
have signed long-term (10 or 15 year) contracts with the Express pipeline system
to transport crude oil on a ship-or-pay basis.
As
of December 31, 2008, the Express pipeline system had total firm commitments of
approximately 231,000 barrels per day, or 83% of its total capacity. These
contracts expire in 2012, 2014 and 2015 in amounts of 40%, 11% and 32% of total
capacity, respectively. The remaining contracts provide for committed tolls for
transportation on the Express pipeline system, which can be increased each year
by up to 2%. The capacity in excess of 231,000 barrels per day is made available
to shippers as uncommitted capacity.
Kinder
Morgan Energy Partners also owns and operates the approximate 25-mile aviation
turbine fuel pipeline that serves the Vancouver International Airport, located
in Vancouver, British Columbia, Canada (referred to in this report as the Jet
Fuel pipeline system). In addition to its receiving and storage facilities
located at the Westridge Marine terminal, located in the Port of Vancouver, the
aviation turbine fuel operations include a terminal at the Vancouver airport
that consists of five jet fuel storage tanks with an overall volume of 15,000
barrels.
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Competition: The Express
pipeline system, serving the U.S. Rocky Mountains and Midwest, is one of several
pipeline alternatives for Western Canadian petroleum production, and throughput
on the Express pipeline system may decline if overall petroleum production in
Alberta declines, demand in the U.S. Rocky Mountains decreases, new pipelines
are built, or if tolls become uncompetitive compared to alternatives. The
Express pipeline system competes against other pipeline providers who could be
in a position to establish and offer lower tolls.
Our
total operating revenues are derived from a wide customer base. In 2008, the
seven months ended December 31, 2007, five months ended May 31, 2007 and in
2006, no revenues from transactions with a single external customer accounted
for 10% or more of our total consolidated revenues. Kinder Morgan Energy
Partners’ Texas Intrastate Natural Gas Pipeline Group buys and sells significant
volumes of natural gas within the state of Texas and, to a far lesser extent,
the CO2–KMP and
NGPL business segments also sell natural gas. Combined, total revenues from the
sales of natural gas from the Natural Gas Pipelines–KMP, CO2–KMP and
NGPL business segments accounted for approximately 63.7%, 56.7%, 58.4% and 61.0%
of our consolidated revenues in 2008, the seven months ended December 31, 2007,
five months ended May 31, 2007 and in 2006, respectively.
As
a result of Kinder Morgan Energy Partners’ Texas Intrastate Natural Gas Pipeline
Group selling natural gas in the same price environment in which it is
purchased, both its total consolidated revenues and its 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 Kinder Morgan Energy Partners
charges a fee to transport gas owned by others. To the extent possible, Kinder
Morgan Energy Partners attempts to balance the pricing and timing of its natural
gas purchases to its natural gas sales, and these contracts are often settled in
terms of an index price for both purchases and sales. 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.
Interstate
Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation—U.S.
Operations
Some
of our pipelines are interstate common carrier pipelines, subject to regulation
by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we
maintain our tariffs on file with the FERC. Those 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 Kinder Morgan Energy Partners charged for transportation
service on its 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 Kinder Morgan Energy Partners’ West Coast
Products Pipelines were subject to protest during the 365-day period established
by the Energy Policy Act. Accordingly, certain of the West Coast Products
Pipelines rates have been, and continue to be, subject to complaints with the
FERC, as is more fully described in Note 20 of the accompanying Notes to
Consolidated Financial Statements.
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.
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Common
Carrier Pipeline Rate Regulation—Canadian Operations
The
Canadian portion of our crude oil and refined petroleum products pipeline
systems is under the regulatory jurisdiction of Canada’s National Energy Board,
referred to in this report as the NEB. The National Energy Board Act gives the
NEB power to authorize pipeline construction and to establish tolls and
conditions of service.
Trans
Mountain
In
November 2004, Trans Mountain entered into negotiations with the Canadian
Association of Petroleum Producers and principal shippers for a new incentive
toll settlement to be effective for the period starting January 1, 2006 and
ending December 31, 2010. In January 2006, Trans Mountain reached agreement in
principle, which was reduced to a memorandum of understanding for the 2006 toll
settlement. A final agreement was reached with the Canadian Association of
Petroleum Producers in October 2006 and NEB approval was received in November
2006.
The
2006 toll settlement incorporates an incentive toll mechanism that is intended
to provide Trans Mountain with the opportunity to earn a return on equity
greater than that calculated using the formula established by the NEB. In return
for this opportunity, Trans Mountain has agreed to assume certain risks and
provide cost certainty in certain areas. Part of the incentive toll mechanism
specifies that Trans Mountain is allowed to keep 75% of the net revenue
generated by throughput in excess of 92.5% of the capacity of the pipeline. The
2006 incentive toll settlement provides for base tolls which will, other than
recalculation or adjustment in certain specified circumstances, remain in effect
for the five-year period. The toll settlement also governs the financial
arrangements for Trans Mountain’s two expansion projects totaling C$765 million,
which were completed during 2007 and 2008. In total, the two projects added
75,000 barrels per day of incremental capacity to the system, increasing
pipeline capacity to approximately 300,000 barrels per day. The toll charged for
the portion of Trans Mountain’s pipeline system located in the United States
falls under the jurisdiction of the FERC. See “Interstate Common Carrier Refined
Petroleum Products and Oil Pipeline Rate Regulation—U.S. Operations”
preceding.
Express
Pipeline System
The
Canadian segment of the Express pipeline system is regulated by the NEB as a
Group 2 pipeline, which results in rates and terms of service being regulated on
a complaint basis only. Express pipeline system’s committed rates are subject to
a 2% inflation adjustment April 1 of each year. The U.S. segment of the Express
Pipeline and the Platte Pipeline are regulated by the FERC. See “Interstate Common Carrier Refined
Petroleum Products and Oil Pipeline Rate Regulation—U.S. Operations.”
Additionally, movements on the Platte Pipeline within the State of Wyoming are
regulated by the Wyoming Public Service Commission, which regulates the tariffs
and terms of service of public utilities that operate in the state of Wyoming.
The Wyoming Public Service Commission standards applicable to rates are similar
to those of the FERC and the NEB.
Interstate
Natural Gas Transportation and Storage Regulation
The
FERC regulates the rates, terms and conditions of service, construction and
abandonment of facilities by companies performing interstate natural gas
transportation and storage services under the Natural Gas Act. To a lesser
extent, the FERC regulates interstate transportation rates, terms and conditions
of service under 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:
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·
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Order
No. 436 (1985), which required open-access, nondiscriminatory
transportation of natural gas;
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·
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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
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·
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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;
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·
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Natural
gas pipelines must now separately state the applicable rates for each
unbundled service they provide (i.e., for natural gas commodity,
transportation and storage). Order No. 636 contains a number of procedures
designed to increase competition in the interstate natural gas industry,
including:
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·
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requiring
the unbundling of sales services from other
services;
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·
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permitting
holders of firm capacity on interstate natural gas pipelines to release
all or a part of their capacity for resale by the pipeline; and the
issuance of blanket sales certificates to interstate pipelines for
unbundled services.
|
Order
No. 636 has been affirmed in all material respects upon judicial review, and our
own FERC orders approving
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our
unbundling plans are final and not subject to any pending judicial
review.
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·
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Order
No. 717 (2008), which prohibits transmission providers from disclosing to
a marketing function employee non-public information about the
transmission system or a transmission customer. The final rule also
retains the long-standing no-conduit rule, which prohibits a transmission
function provider from disclosing non-public information to marketing
function employees by using a third party conduit. Additionally, the final
rule requires that a transmission provider provide annual training on the
Standards of Conduct to all transmission function employees, marketing
function employees, officers, directors, supervisory employees and any
other employees likely to become privy to transmission function
information.
|
Please
refer to Note 20 of the accompanying Notes to Consolidated Financial Statements
for additional information regarding FERC regulatory requirements.
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.
Posted
tariff rates set the general range of maximum and minimum rates we charge
shippers on our interstate natural gas pipelines. Within that range, each
pipeline is permitted to charge discounted rates to meet competition, so long as
such discounts are offered to all similarly situated shippers and granted
without undue discrimination. Apart from discounted rates offered within the
range of tariff maximums and minimums, the pipeline is permitted to offer
negotiated rates where the pipeline and shippers want rate certainty,
irrespective of changes that may occur to the range of tariff-based maximum and
minimum rate levels. Accordingly, there are a variety of rates that different
shippers may pay. For example, some shippers may pay a negotiated rate that is
different than the posted tariff rate and some may pay the posted maximum tariff
rate or a discounted rate that is limited by the posted maximum and minimum
tariff rates. Most of the rates we charge shippers on our greenfield projects,
like the Rockies Express Pipeline or the Midcontinent Express Pipeline, are
pursuant to negotiated rate long-term transportation agreements. As such,
negotiated rates provide certainty to the pipeline and the shipper of a fixed
rate during the term of the transportation agreement, regardless of changes to
the posted tariff rates. While rates may vary by shipper and circumstance, the
terms and conditions of pipeline transportation and storage services are not
generally negotiable.
California
Public Utilities Commission Rate Regulation
The
intrastate common carrier operations of the West Coast Products Pipelines’
operations in California are subject to regulation by the California Public
Utilities Commission, referred to in this report as the CPUC, 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 the West Coast Products
Pipelines’ 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 the West Coast Products Pipelines’
pipeline rates have been, and continue to be, subject to complaints with the
CPUC, as is more fully described in Note 20 of the accompanying Notes to
Consolidated Financial Statements.
Texas
Railroad Commission Rate Regulation
The
intrastate operations of our natural gas and crude oil pipelines in Texas are
subject to certain regulation with respect to such intrastate transportation by
the Texas Railroad Commission. The Texas Railroad Commission has the authority
to regulate our transportation rates, though it generally has not investigated
the rates or practices of our intrastate pipelines in the absence of shipper
complaints.
Safety
Regulation
Our
interstate pipelines are subject to regulation by the United States Department
of Transportation (“U.S. DOT”) 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.
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.
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. Testing consists of
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hydrostatic
testing, internal magnetic flux or ultrasonic testing, or direct assessment of
the piping. In addition to the pipeline integrity tests, pipeline companies must
implement a qualification program to make certain that employees are properly
trained. A similar integrity management rule for refined petroleum products
pipelines became effective May 29, 2001.
We
are also subject to the requirements of the Federal Occupational Safety and
Health Act and other comparable federal and state statutes that address employee
health and safety.
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 increases in our
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.
Our
business operations are subject to federal, state, provincial and local laws and
regulations relating to environmental protection, pollution and human health and
safety in the United States and Canada. For example, if an accidental leak,
release or spill of liquid petroleum products, chemicals or other hazardous
substances occurs at or from our pipelines, or at or from our storage or other
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 damages, 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 materially and negatively affect our business, financial condition,
results of operations and cash flows. In addition, emission controls required
under federal, state and provincial environmental laws could require significant
capital expenditures at our facilities.
Environmental
and human health and safety laws and regulations are subject to change. The
clear trend in environmental regulation is to place more restrictions and
limitations on activities that may be perceived to affect the environment,
wildlife, natural resources and human health, and there can be no assurance as
to the amount or timing of future expenditures for environmental regulation
compliance or remediation, and actual future expenditures may be different from
the amounts we currently anticipate. Revised or additional regulations that
result in increased compliance costs or additional operating restrictions,
particularly if those costs are not fully recoverable from our customers, could
have a material adverse effect on our business, financial position, results of
operations and cash flows.
In
accordance with GAAP, we accrue liabilities for environmental matters when it is
probable that obligations have been incurred and the amounts can be reasonably
estimated. This policy applies to assets or businesses currently owned or
previously disposed. We have accrued liabilities for probable environmental
remediation obligations at various sites, including multiparty sites where the
U.S. Environmental Protection Agency, referred to as the U.S. EPA, or similar
state agency has identified us as one of the potentially responsible parties.
The involvement of other financially responsible companies at these multiparty
sites could increase or mitigate our actual joint and several liability
exposures. Although no assurance can be given, we believe that the ultimate
resolution of 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 $85.0 million as of December
31, 2008. Our reserve estimates range in value from approximately $85.0 million
to approximately $121.4 million and we recorded our liability equal to the low
end of the range, as we did not identify any amounts within the range as a
better estimate of the liability. For additional information related to
environmental matters, see Note 21 to the accompanying Notes to Consolidated
Financial Statements.
Hazardous
and Non-Hazardous Waste
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 U.S. EPA
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 our
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
handling and 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
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Items 1. and
2. Business and Properties.
(continued)
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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, its implementing regulations, and
analogous state statutes and regulations. We believe that the operations of our
pipelines, storage facilities and terminals are in substantial compliance with
such statutes. The Clean Air Act regulations contain lengthy, complex provisions
that may result in the imposition over the next several years of certain
pollution control requirements with respect to air emissions from the operations
of our pipelines, treating facilities, storage facilities and terminals.
Depending on the nature of those requirements and any additional requirements
that may be imposed by state and local regulatory authorities, we may be
required to incur certain capital and operating 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. 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.
We
are aware of the increasing focus of national and international regulatory
bodies on greenhouse gas emissions and climate change issues. We are also aware
of legislation, recently proposed by the Canadian legislature, to reduce
greenhouse gas emissions.
Clean
Water Act
Our
operations can result in the discharge of pollutants. The Federal Water
Pollution Control Act of 1972, as amended, its implementing regulations, also
known as the Clean Water Act, and analogous state laws and regulations 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.
Climate
Change
Studies
have suggested that emissions of certain gases, commonly referred to as
“greenhouse gases,” may be contributing to warming of the Earth’s atmosphere.
Methane, a primary component of natural gas, and carbon dioxide, which is
naturally occurring and also a byproduct of burning of natural gas, are examples
of greenhouse gases. The U.S. Congress is actively considering legislation to
reduce emissions of greenhouse gases. In addition, several states have developed
initiatives to regulate emissions of greenhouse gases, primarily through the
planned development of greenhouse gas emission inventories and/or regional
greenhouse gas cap and trade programs. The EPA is separately considering whether
it will regulate greenhouse gases as “air pollutants” under the existing federal
Clean Air Act. Passage of climate control legislation or other regulatory
initiatives by Congress or various states of the U.S. or provinces of Canada or
the adoption of regulations by the EPA or analogous state agencies that regulate
or restrict emissions of greenhouse gases including methane or carbon dioxide in
areas in which we conduct business, could result in changes to the consumption
and demand for natural gas and carbon dioxide produced from our source fields
and could have adverse effects on our business, financial position, results of
operations and prospects.
Such
changes could increase the costs of our operations, including costs to operate
and maintain our facilities, install new emission controls on our facilities,
acquire allowances to authorize our greenhouse gas emissions, pay any taxes
related to our greenhouse gas emissions and administer and manage a greenhouse
gas emissions program. While we may be able to include some or all of such
increased costs in the rates charged by our pipelines to our customers, such
recovery of costs is uncertain and may depend on events beyond our control
including the outcome of future rate proceedings before the FERC or comparable
state regulatory commissions and the provisions of any final
legislation.
34
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Items 1. and
2. Business and Properties.
(continued)
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Department
of Homeland Security
In
Section 550 of the Homeland Security Appropriations Act of 2007 (P.L. 109-295)
(Act), Congress gave the Department of Homeland Security (“DHS”) regulatory
authority over security at certain high-risk chemical facilities. Pursuant to
its congressional mandate, on April 9, 2007, DHS promulgated the Chemical
Facility Anti-Terrorism Standards (“CFATS”), 6 CFR Part 27.
In
the CFATS regulation, DHS requires all high-risk chemical and industrial
facilities, including oil and gas facilities, to complete security vulnerability
assessments, develop site security plans and implement protective measures
necessary to meet DHS-defined risk-based performance standards. DHS has not
provided final notice to all facilities that DHS determines to be high risk and
subject to the rule. Therefore, neither the extent to which our facilities may
be subject to coverage by the rules nor the associated costs to comply can
currently be determined, but it is possible that such costs could be
substantial.
Amounts
we spent during 2008, 2007 and 2006 on research and development activities were
not material. We employed approximately 7,800 full-time people at December 31,
2008, including employees of our indirect subsidiary KMGP Services Company,
Inc., who are dedicated to the operations of Kinder Morgan Energy Partners, and
employees of Kinder Morgan Canada Inc. Approximately 920 full-time hourly
personnel at certain terminals and pipelines are represented by labor unions
under collective bargaining agreements that expire between 2009 and 2013. KMGP
Services Company, Inc., Knight Inc. and Kinder Morgan Canada Inc. each consider
relations with their employees to be good. For more information on our related
party transactions, see Note 7 of the accompanying Notes to Consolidated
Financial Statements.
KMGP
Services Company, Inc., a subsidiary of Kinder Morgan G.P., Inc., provides
employees and Kinder Morgan Services LLC, a subsidiary of Kinder Morgan
Management, provides centralized payroll and employee benefits services to
Kinder Morgan Management, Kinder Morgan Energy Partners and Kinder Morgan Energy
Partners’ operating partnerships and subsidiaries (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 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 their allocated shares of these direct
costs. No profit or margin is charged by Kinder Morgan Services LLC to the
members of the Group. Our human resources department provides the administrative
support necessary to implement these payroll and benefits services, 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
the limited partnership agreement, Kinder Morgan Energy Partners provides
reimbursement for its share of these administrative costs and such
reimbursements are accounted for as described above. Kinder Morgan Energy
Partners reimburses Kinder Morgan Management with respect to the costs incurred
or allocated to Kinder Morgan Management in accordance with Kinder Morgan Energy
Partners’ limited partnership agreement, the Delegation of Control Agreement
among Kinder Morgan G.P., Inc., Kinder Morgan Management, Kinder Morgan Energy
Partners and others, and Kinder Morgan Management’s limited liability company
agreement.
Our
named executive officers and other employees that provide management or services
to both us and the Group are employed by us. Additionally, other of our
employees assist Kinder Morgan Energy Partners in the operation of its Natural
Gas Pipeline assets. These employees’ expenses are allocated without a profit
component between us and the appropriate members of the Group.
We
believe that we have generally satisfactory title to the properties we own and
use in our businesses, subject to liens on the assets of Knight Inc. and its
subsidiaries (excluding Kinder Morgan Energy Partners and its subsidiaries)
incurred in connection with the financing of the Going Private transaction,
liens for current taxes, liens incident to minor encumbrances, and easements and
restrictions that 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. 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 that 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.
35
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Items 1. and
2. Business and Properties.
(continued)
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Form 10-K
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Our
terminals, storage facilities, processing plants, regulator and compressor
stations, offices and related facilities are located on real property owned or
leased by us. In some cases, the real property we lease is on federal, state,
provincial or local government land.
(D)
Financial Information about Geographic Areas
For
information concerning our assets and operations that are located outside of the
continental United States of America, see Note 19 of the accompanying Notes to
Consolidated Financial Statements.
(E)
Available Information
We
make available free of charge on or through our internet website, at
www.kindermorgan.com, our annual reports 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.
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.
Our
business is subject to extensive regulation that affects our operations and
costs.
Our
assets and operations are subject to regulation by federal, state, provincial
and local authorities, including regulation by the FERC, and by various
authorities under federal, state and local environmental, human health and
safety and pipeline safety laws. Regulation affects almost every aspect of our
business, including, among other things, our ability to determine terms and
rates for our interstate pipeline services, to make acquisitions or to build
extensions of existing facilities. The costs of complying with such laws and
regulations are already significant, and additional or more stringent regulation
could have a material adverse impact on our business, financial condition and
results of operations.
In
addition, regulators have taken actions designed to enhance market forces in the
gas pipeline industry, which have led to increased competition. In a number of
U.S. markets, natural gas interstate pipelines face competitive pressure from a
number of new industry participants, such as alternative suppliers, as well as
traditional pipeline competitors. Increased competition driven by regulatory
changes could have a material impact on business in our markets and therefore
adversely affect our financial condition and results of operations.
Pending
Federal Energy Regulatory Commission (“FERC”) and California Public Utilities
Commission proceedings seek substantial refunds and reductions in tariff rates
on some of Kinder Morgan Energy Partners’ pipelines. If the proceedings are
determined adversely to Kinder Morgan Energy Partners, 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
Kinder Morgan Energy Partners’ pipelines have filed complaints with the FERC 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 Kinder Morgan Energy Partners’ West Coast Products Pipelines. We
may face challenges, similar to those described in Note 20 of the accompanying
Notes to Consolidated Financial Statements, 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.
Rulemaking
and oversight, as well as changes in regulations, 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. Furthermore, regulators and
shippers on our natural gas pipelines have rights to challenge the rates
shippers 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. New laws
or regulations or different interpretations of existing laws or regulations
applicable to our assets, including unexpected policy changes that sometimes
occur following a change of presidential administration, could have a material
adverse impact on our business, financial condition and results of
operations.
36
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Item
1A. Risk Factors.
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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.
Environmental
laws and regulations could expose us to significant costs and
liabilities.
Our
operations are subject to federal, state, provincial and local laws, regulations
and potential liabilities arising under or relating to the protection or
preservation of the environment, natural resources and human health and safety.
Such laws and regulations affect many aspects of our present and future
operations, and generally require us to obtain and comply with various
environmental registrations, licenses, permits, inspections and other approvals.
Liability under such laws and regulations may be incurred without regard to
fault under the Comprehensive Environmental Response, Compensation, and
Liability Act, commonly known as CERCLA or Superfund, the Resource Conservation
and Recovery Act, commonly known as RCRA, or analogous state laws for the
remediation of contaminated areas. Private parties, including the owners of
properties through which our pipelines pass may also have the right to pursue
legal actions to enforce compliance as well as to seek damages for
non-compliance with such laws and regulations or for personal injury or property
damage. Our insurance may not cover all environmental risks and costs or may not
provide sufficient coverage in the event an environmental claim is made against
us.
Failure
to comply with these laws and regulations may expose us to civil, criminal and
administrative fines, penalties and/or interruptions in our operations that
could influence our results of operations. For example, if an accidental leak,
release or spill of liquid petroleum products, chemicals or other hazardous
substances occurs at or from our pipelines or our storage or other 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 materially
and negatively affect our level of earnings and cash flows. In addition,
emission controls required under the Federal Clean Air Act and other similar
federal, state and provincial laws could require significant capital
expenditures at our facilities.
We
own and/or operate numerous properties that have been used for many years in
connection with our business activities. While we have utilized operating and
disposal practices that were standard in the industry at the time, hydrocarbons
or other hazardous substances may have been released at or from properties
owned, operated or used by us or our predecessors, or at or from properties
where our or our predecessors’ wastes have been taken for disposal. In addition,
many of these properties have been owned and/or operated by third parties whose
management, handling and disposal of hydrocarbons or other hazardous substances
were not under our control. These properties and the hazardous substances
released and wastes disposed on them may be subject to laws in the United States
such as CERCLA, which impose joint and several liability without regard to fault
or the legality of the original conduct. Under the regulatory schemes of the
various Canadian provinces, such as British Columbia’s Environmental Management
Act, Canada has similar laws with respect to properties owned, operated or used
by us or our predecessors. Under such laws and implementing regulations, we
could be required to remove or remediate previously disposed wastes or property
contamination, including contamination caused by prior owners or operators.
Imposition of such liability schemes could have a material adverse impact on our
operations and financial position.
In
addition, our oil and gas development and production activities are subject to
numerous 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, these activities 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 wastes. In addition,
legislation has been enacted that requires well and facility sites to be
abandoned and reclaimed to the satisfaction of state authorities.
Further,
we cannot ensure that such existing laws and regulations will not be revised or
that new laws or regulations will not be adopted or become applicable to us. The
clear trend in environmental regulation is to place more restrictions and
limitations on activities that may be perceived to affect the environment and
thus, there can be no assurance as to the amount or timing of future
expenditures for environmental compliance or remediation, and actual future
expenditures may be different from the amounts we currently anticipate. Revised
or additional regulations that result in increased compliance costs or
additional operating restrictions, particularly if those costs are not fully
recoverable from our customers, could have a
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Item
1A. Risk Factors.
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material
adverse effect on our business, financial position, results of operations and
prospects.
Cost
overruns and delays on our expansion and new build projects could adversely
affect our business.
Kinder
Morgan Energy Partners currently has several major expansion and new build
projects planned or underway, including the Rockies Express Pipeline, which is
expected to cost $6.3 billion, the Midcontinent Express Pipeline, which is
expected to cost $2.2 billion, the Fayetteville Express Pipeline, which is
expected to cost $1.2 billion and the Kinder Morgan Louisiana Pipeline, which is
expected to cost $950 million. The cost estimates for the Rockies Express and
Midcontinent Express pipelines include expansions of the base projects. 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, has resulted
in, and may continue to result in, increased costs or delays in construction.
Cost overruns or delays in completing a project could have a material adverse
effect on our return on investment, results of operations and cash
flows.
Climate
change regulation at the federal, state, provincial or regional levels and/or
new regulations issued by the Department of Homeland Security could result in
increased operating and capital costs for us.
Studies
have suggested that emissions of certain gases, commonly referred to as
“greenhouse gases,” may be contributing to warming of the Earth’s atmosphere.
Methane, a primary component of natural gas, and carbon dioxide, a byproduct of
the burning of natural gas, are examples of greenhouse gases. The U.S. Congress
is actively considering legislation to reduce emissions of greenhouse gases. In
addition, at least nine states in the Northeast and five states in the West have
developed initiatives to regulate emissions of greenhouse gases, primarily
through the planned development of greenhouse gas emission inventories and/or
regional greenhouse gas cap and trade programs. The EPA is separately
considering whether it will regulate greenhouse gases as “air pollutants” under
the existing federal Clean Air Act. Passage of climate control legislation or
other regulatory initiatives by Congress or various states of the U.S. or
provinces of Canada or the adoption of regulations by the EPA or analogous state
or provincial agencies that regulate or restrict emissions of greenhouse gases
including methane or carbon dioxide in areas in which we conduct business, could
result in changes to the consumption and demand for natural gas and carbon
dioxide produced from our source fields and could have adverse effects on our
business, financial position, results of operations and prospects.
Such
changes could increase the costs of our operations, including costs to operate
and maintain our facilities, install new emission controls on our facilities,
acquire allowances to authorize our greenhouse gas emissions, pay any taxes
related to our greenhouse gas emissions and administer and manage a greenhouse
gas emissions program. While we may be able to include some or all of such
increased costs in the rates charged by some of our pipelines or to our
customers, such recovery of costs is uncertain and may depend on events beyond
our control including the outcome of future rate proceedings before the FERC and
the provisions of any final legislation.
The
Department of Homeland Security Appropriation Act of 2007 requires the
Department of Homeland Security, or the DHS, to issue regulations establishing
risk-based performance standards for the security of chemical and industrial
facilities, including oil and gas facilities that are deemed to present “high
levels of security risk.” The DHS has issued rules that establish chemicals of
interest and their respective threshold quantities that will trigger compliance
with these standards. Covered facilities that are determined by the DHS to pose
a high level of security risk will be required to prepare and submit Security
Vulnerability Assessments and Site Security Plans as well as comply with other
regulatory requirements, including those regarding inspections, audits,
recordkeeping and protection of chemical-terrorism vulnerability information. We
have not yet determined the extent of the costs to bring our facilities into
compliance, but it is possible that such costs could be
substantial.
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. 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:
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·
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demands
on management related to the increase in our size after an acquisition, an
expansion, or a completed construction
project;
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·
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the
diversion of our management’s attention from the management of daily
operations;
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·
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difficulties
in implementing or unanticipated costs of accounting, estimating,
reporting and other systems;
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·
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goodwill
and intangible assets that are subject to impairment testing and potential
periodic impairment charges;
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·
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difficulties
in the assimilation and retention of necessary employees;
and
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potential
adverse effects on operating
results.
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38
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Item
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(continued)
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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 capital markets or more expensive capital would impair our ability to
grow.
Part
of our business strategy includes acquiring additional businesses and expanding
our assets. We may need to raise debt and equity to finance these acquisitions
and expansions. Limitations on our access to capital will impair our ability to
execute this strategy. We normally fund acquisitions and expansions 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.
Energy
commodity transportation and storage activities involve numerous risks that may
result in accidents or otherwise adversely affect operations.
There
are a variety of hazards and operating risks inherent to natural gas
transmission and storage activities, and refined petroleum products and carbon
dioxide transportation activities—such as leaks, explosions and mechanical
problems that could result in substantial financial losses. In addition, these
risks could result in loss of human life, significant damage to property,
environmental pollution and impairment of operations, any of which also could
result in substantial losses. For pipeline and storage assets located near
populated areas, including residential areas, commercial business centers,
industrial sites and other public gathering areas, the level of damage resulting
from these risks could be greater. If losses in excess of our insurance coverage
were to occur, they could have a material adverse effect on our business,
financial condition and results of operations.
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, while they may be reasonable, are by their nature 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 Kinder Morgan Energy Partners’
CO2
business segment and the carrying value of its oil, natural gas liquids and
natural gas properties depend to a large degree on prevailing oil and gas
prices. Prices for oil, natural gas liquids 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, natural gas liquids 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 Kinder Morgan Energy Partners’ proved reserves.
In the event prices fall substantially, Kinder Morgan Energy Partners may not be
able to realize a profit from its 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. These fluctuations necessarily impact the accuracy of
assumptions used in our budgeting process.
39
|
Item
1A. Risk Factors.
(continued)
|
Knight
Form 10-K
|
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 very complex, and even when
we engage in hedging transactions (for example, to mitigate our exposure to
fluctuations in commodity prices or currency exchange rates or to balance our
exposure to fixed and variable 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.
Kinder
Morgan Energy Partners must either obtain the right from landowners or exercise
the power of eminent domain in order to use most of the land on which its
pipelines are constructed, and it is subject to the possibility of increased
costs to retain necessary land use.
Kinder
Morgan Energy Partners obtains the right to construct and operate pipelines on
other owners’ land for a period of time. If it were to lose these rights or be
required to relocate its pipelines, its business could be affected negatively.
In addition, Kinder Morgan Energy Partners is subject to the possibility of
increased costs under its rental agreements with landowners, primarily through
rental increases and renewals of expired agreements.
Whether
Kinder Morgan Energy Partners has the power of eminent domain for its pipelines,
other than interstate natural gas 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. Kinder Morgan Energy Partners’
interstate natural gas pipelines have federal eminent domain authority. In
either case, Kinder Morgan Energy Partners must compensate landowners for the
use of their property and, in eminent domain actions, such compensation may be
determined by a court. The inability to exercise the power of eminent domain
could negatively affect Kinder Morgan Energy Partners’ business if it were to
lose the right to use or occupy the property on which its pipelines are
located.
Our
substantial debt could adversely affect our financial health and make us more
vulnerable to adverse economic conditions.
As
of December 31, 2008, we had outstanding $11.5 billion of consolidated debt
(excluding the fair value of interest rate swaps). Of this amount, $8.6 billion
was debt of Kinder Morgan Energy Partners and its subsidiaries, and the
remaining $2.9 billion was debt of Knight Inc. and its subsidiaries, other than
Kinder Morgan Energy Partners and its subsidiaries. Knight Inc.’s debt is
currently secured by most of the assets of Knight Inc. and its subsidiaries, but
the security interest does not apply to the assets of Kinder Morgan G.P., Inc.,
Kinder Morgan Energy Partners, Kinder Morgan Management and their respective
subsidiaries. This level of debt could have important consequences, such
as:
|
|
·
|
limiting
our ability to obtain additional financing to fund our working capital,
capital expenditures, debt service requirements or potential growth or for
other purposes;
|
|
|
·
|
limiting
our ability to use operating cash flow in other areas of our business
because we must dedicate a substantial portion of these funds to make
payments on our debt;
|
|
|
·
|
placing
us at a competitive disadvantage compared to competitors with less debt;
and
|
|
|
·
|
increasing
our vulnerability to adverse economic and industry
conditions.
|
Each
of these factors is to a large extent dependent on economic, financial,
competitive and other factors beyond our control.
Our
variable rate debt makes us vulnerable to increases in interest
rates.
As
of December 31, 2008, we had outstanding $11.5 billion of consolidated debt
(excluding the fair value of interest rate swaps). Of this amount, approximately
25.3% was subject to variable interest rates, either as short-term or long-term
debt of variable rate credit facilities or as long-term fixed-rate debt
converted to variable rates through the use of interest rate swaps. In addition,
subsequent to December 31, 2008 Kinder Morgan Energy Partners entered
into four fixed-to-floating interest rate swap agreements having a
combined notional principal amount of $1.0 billion. Should interest rates
increase significantly, the amount of cash required to service our debt would
increase and 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.”
40
|
Item
1A. Risk Factors.
(continued)
|
Knight
Form 10-K
|
Current
or future distressed financial conditions of customers could have an adverse
impact on us in the event these customers are unable to pay us for the products
or 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 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.
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 (i) incurring
additional debt; (ii) entering into mergers, consolidations and sales of assets;
(iii) granting liens; and (iv) 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.
Current
levels of market volatility are unprecedented.
The
capital and credit markets have been experiencing extreme volatility and
disruption for more than twelve months. In some cases, the markets have exerted
downward pressure on stock prices and credit capacity for certain issuers. Our
plans for growth require regular access to the capital and credit markets. If
current levels of market disruption and volatility continue or worsen, access to
capital and credit markets could be disrupted making growth through acquisitions
and development projects difficult or impractical to pursue until such time as
markets stabilize.
Our
operating results may be adversely affected by unfavorable economic and market
conditions.
Economic
conditions worldwide have from time to time contributed to slowdowns in the oil
and gas industry, as well as in the specific segments and markets in which we
operate, resulting in reduced demand and increased price competition for our
products and services. Our operating results in one or more geographic regions
may also be affected by uncertain or changing economic conditions within that
region, such as the challenges that are currently affecting economic conditions
in the United States. Volatility in commodity prices might have an impact on
many of our customers, which in turn could have a negative impact on their
ability to meet their obligations to us. In addition, decreases in the prices of
crude oil and natural gas liquids will have a negative impact on the results of
the CO2–KMP
business segment. If global economic and market conditions (including volatility
in commodity markets), or economic conditions in the United States or other key
markets, remain uncertain or persist, spread or deteriorate further, we may
experience material impacts on our business, financial condition and results of
operations.
The
recent downturn in the credit markets has increased the cost of borrowing and
has made financing difficult to obtain, each of which may have a material
adverse effect on our results of operations and business.
Recent
events in the financial markets have had an adverse impact on the credit markets
and, as a result, the availability of credit has become more expensive and
difficult to obtain. Some lenders are imposing more stringent restrictions on
the terms of credit and there may be a general reduction in the amount of credit
available in the markets in which we conduct business. In addition, as a result
of the current credit market conditions and the recent downgrade of Kinder
Morgan Energy Partners’ short-term credit ratings by Standard & Poor’s
Rating Services, it is currently unable to access commercial paper borrowings
and instead is meeting its short-term financing and liquidity needs through
borrowings under its bank credit facility. The negative impact on the tightening
of the credit markets may have a material adverse effect on Kinder Morgan Energy
Partners resulting from, but not limited to, an inability to expand facilities
or finance the acquisition of assets on favorable terms, if at all, increased
financing costs or financing with increasingly restrictive
covenants.
The
failure of any bank in which we deposit our funds could reduce the amount of
cash available for operations and investments and for Kinder Morgan Energy
Partners to pay distributions.
We
have diversified our cash and cash equivalents between several banking
institutions in an attempt to minimize exposure to any one of these entities.
However, the Federal Deposit Insurance Corporation, or “FDIC,” only insures
amounts up to $250,000 per depositor per insured bank until January 1, 2010 when
the standard coverage limit will decrease to $100,000. We currently have cash
and cash equivalents and restricted cash deposited in certain financial
institutions in excess of
41
|
Item
1A. Risk Factors.
(continued)
|
Knight
Form 10-K
|
federally
insured levels. If any of the banking institutions in which we have deposited
funds ultimately fails, we may lose our deposits over $250,000. The loss of our
deposits could reduce the amount of cash available for operations and
investments and that Kinder Morgan Energy Partners has available to distribute,
which could result in a decline in the value of our investment in Kinder Morgan
Energy Partners.
There
can be no assurance as to the impact on the financial markets of the United
States government’s plans to purchase large amounts of illiquid, mortgage-backed
and other securities from financial institutions.
In
response to the financial crises affecting the banking system and financial
markets and going concern threats to investment banks and other financial
institutions, the U.S. Treasury has announced plans to purchase mortgage-backed
and other securities from financial institutions for the purpose of stabilizing
the financial markets. There can be no assurance what impact these purchases or
similar actions by the United States government will have on the financial
markets. Although we are not one of the institutions that would sell securities
to the United States Treasury, the ultimate effects of these actions on the
financial markets and the economy in general could materially and adversely
affect our business, financial condition and results of operations.
The
Going Private transaction resulted in substantially more debt to us and a
downgrade of the ratings of our debt securities, which has increased our cost of
capital.
In
connection with the Going Private transaction, Standard & Poor’s Rating
Services and Moody’s Investors Service, Inc. downgraded the ratings assigned to
Knight Inc.’s senior unsecured debt to BB- and Ba2, respectively. Upon the
February 2008 80% ownership interest sale of our NGPL business segment, which
resulted in Knight Inc.’s repayment of a substantial amount of debt; Standard
& Poor’s Rating Services and Moody’s Investors Service, Inc. upgraded Knight
Inc.’s senior unsecured debt to BB and Ba1, respectively. However, these ratings
are still below investment grade. Since the Going Private transaction, Knight
Inc. has not had access to the commercial paper market and is currently
utilizing its $1.0 billion revolving credit facility for its short-term
borrowing needs.
The
future success of Kinder Morgan Energy Partners’ oil and gas development and
production operations depends in part upon its ability to develop additional oil
and gas reserves that are economically recoverable.
The
rate of production from oil and natural gas properties declines as reserves are
depleted. Without successful development activities, the reserves and revenues
of the oil producing assets within Kinder Morgan Energy Partners’ CO2 business
segment will decline. Kinder Morgan Energy Partners may not be able to develop
or acquire additional reserves at an acceptable cost or have necessary financing
for these activities in the future. Additionally, if Kinder Morgan Energy
Partners does not realize production volumes greater than, or equal to, its
hedged volumes, Kinder Morgan Energy Partners may suffer financial losses not
offset by physical transactions.
Competition
could ultimately lead to lower levels of profits and adversely impact our
ability to recontract for expiring transportation capacity at favorable rates or
maintain existing customers.
In
the past, competitors to our interstate natural gas pipelines have constructed
or expanded pipeline capacity into the areas served by our pipelines. To the
extent that an excess of supply into these market areas is created and persists,
our ability to recontract for expiring transportation capacity at favorable
rates or to maintain existing customers could be impaired. In addition, our
products pipelines compete against proprietary pipelines owned and operated by
major oil companies, other independent products pipelines, trucking and marine
transportation firms (for short-haul movements of products) and railcars.
Throughput on our products pipelines may decline if the rates we charge become
uncompetitive compared to alternatives.
Future
business development of our products, crude oil and natural gas pipelines is
dependent on the supply of and demand for those commodities.
Our
pipelines depend on production of natural gas, oil and other products in the
areas serviced by our pipelines. Without reserve additions, production will
decline over time as reserves are depleted and production costs may rise.
Producers may shut down production at lower product prices or higher production
costs, especially where the existing cost of production exceeds other extraction
methodologies, such as at the Alberta oil sands. Producers in areas serviced by
us may not be successful in exploring for and developing additional reserves,
and the gas plants and the pipelines may not be able to maintain existing
volumes of throughput. Commodity prices and tax incentives may not remain at a
level which encourages producers to explore for and develop additional reserves,
produce existing marginal reserves or renew transportation contracts as they
expire.
Changes
in the business environment, such as a decline in crude oil or natural gas
prices, an increase in production costs from higher feedstock prices, supply
disruptions, or higher development costs, could result in a slowing of supply
from the Alberta oil sands. In addition, changes in the regulatory environment
or governmental policies may have an impact on the supply of crude oil. Each of
these factors impact our customers shipping through our pipelines, which in turn
could impact the
42
|
Item
1A. Risk Factors.
(continued)
|
Knight
Form 10-K
|
prospects
of new transportation contracts or renewals of existing contracts.
Throughput
on our products pipelines may also decline as a result of changes in business
conditions. Over the long term, business will depend, in part, on the level of
demand for oil and natural gas in the geographic areas in which deliveries are
made by pipelines and the ability and willingness of shippers having access or
rights to utilize the pipelines to supply such demand. The implementation of new
regulations or the modification of existing regulations affecting the oil and
gas industry could reduce demand for natural gas and crude oil, increase our
costs and may have a material adverse effect on our results of operations and
financial condition. We cannot predict the impact of future economic conditions,
fuel conservation measures, alternative fuel requirements, governmental
regulation or technological advances in fuel economy and energy generation
devices, all of which could reduce the demand for natural gas and
oil.
We
are subject to U.S. dollar/Canadian dollar exchange rate
fluctuations.
As
a result of the operations of the Kinder Morgan Canada—KMP segment, a portion of
our assets, liabilities, revenues and expenses are denominated in Canadian
dollars. We are a U.S. dollar reporting company. Fluctuations in the exchange
rate between United States and Canadian dollars could expose us to reductions in
the U.S. dollar value of our earnings and cash flows and a reduction in our
stockholder’s equity under applicable accounting rules.
Terrorist
attacks, or the threat of them, may adversely affect our business.
The
U.S. government has issued public warnings that indicate that pipelines and
other energy assets might be specific targets of terrorist organizations. These
potential targets might include our pipeline systems or storage facilities. Our
operations could become subject to increased governmental scrutiny that would
require increased security measures. 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 in the near
future. These developments may subject our operations to increased risks, as
well as increased costs, and, depending on their ultimate magnitude, could have
a material adverse effect on our business, results of operations and financial
condition.
Some
of our pipelines, terminals and other assets are located in areas that are
susceptible to hurricanes and other natural disasters. These natural disasters
could potentially damage or destroy our pipelines, terminals and other assets
and disrupt the supply of the products we transport through our pipelines, which
could have a material adverse effect our business, financial condition and
results of operations.
There
is the potential for a change of control of the general partner of Kinder Morgan
Energy Partners if we default on debt.
We
own all of the common equity of Kinder Morgan G.P., Inc., the general partner of
Kinder Morgan Energy Partners. If we default on our debt, in exercising their
rights as lenders, our lenders could acquire control of Kinder Morgan G.P., Inc.
or otherwise influence Kinder Morgan G.P., Inc. through their control of us.
While our operations provide cash independent of the dividends we receive from
Kinder Morgan G.P., Inc., a change in control could materially affect our cash
flow and earnings.
The
tax treatment applied to Kinder Morgan Energy Partners depends on its status as
a partnership for United States federal income tax purposes, as well as it not
being subject to a material amount of entity-level taxation by individual
states. If the IRS treats it as a corporation or if it becomes subject to a
material amount of entity-level taxation for state tax purposes, it would
substantially reduce the amount of cash available for distribution to its
partners, including us.
The
anticipated after-tax economic benefit of an investment in Kinder Morgan Energy
Partners depends largely on it being treated as a partnership for United States
federal income tax purposes. In order for it to be treated as a partnership for
United States federal income tax purposes, current law requires that 90% or more
of its gross income for every taxable year consist of “qualifying income,” as
defined in Section 7704 of the Internal Revenue Code. Kinder Morgan Energy
Partners may not meet this requirement or current law may change so as to cause,
in either event, it to be treated as a corporation for United States federal
income tax purposes or otherwise subject to United States federal income tax.
Kinder Morgan Energy Partners has not requested, and does not plan to request, a
ruling from the IRS on this or any other matter affecting it.
If
Kinder Morgan Energy Partners were to be treated as a corporation for United
States federal income tax purposes, it would pay United States federal income
tax on its 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 its partners would generally be taxed again as corporate
distributions, and no income, gain, losses or deductions would flow through to
its partners. Because a tax would be imposed on Kinder Morgan Energy Partners as
a corporation, its cash available for distribution would be
substantially
43
|
Item
1A. Risk Factors.
(continued)
|
Knight
Form 10-K
|
reduced.
Therefore, treatment of Kinder Morgan Energy Partners as a corporation would
result in a material reduction in the anticipated cash flow and after-tax return
to its partners, likely causing a substantial reduction in the value of our
interest in Kinder Morgan Energy Partners.
Current
law or the business of Kinder Morgan Energy Partners may change so as to cause
it to be treated as a corporation for United States federal income tax purposes
or otherwise subject it to entity level taxation. Members of Congress are
considering substantive changes to the existing United States federal income tax
laws that affect certain publicly-traded partnerships. For example, United
States federal income tax legislation has been proposed that would eliminate
partnership tax treatment for certain publicly-traded partnerships. Although the
currently proposed legislation would not appear to affect Kinder Morgan Energy
Partners, L.P.’s tax treatment as a partnership, we are unable to predict
whether any of these changes, or other proposals, will ultimately be enacted.
Any such changes could negatively impact the value of our interest in Kinder
Morgan Energy Partners.
In
addition, because of widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to entity-level taxation
through the imposition of state income, franchise or other forms of taxation.
For example, Kinder Morgan Energy Partners is now subject to an entity-level tax
on the portion of its total revenue that is generated in Texas. Imposition of
such a tax on Kinder Morgan Energy Partners by Texas, or any other state, will
reduce its cash available for distribution to its partners, including
us.
The
Kinder Morgan Energy Partners partnership agreement provides that if a law is
enacted that subjects Kinder Morgan Energy Partners to taxation as a corporation
or otherwise subjects it to entity-level taxation for United States federal
income tax purposes, the minimum quarterly distribution and the target
distribution levels will be adjusted to reflect the impact of that law on Kinder
Morgan Energy Partners.
Kinder
Morgan Energy Partners adopted certain valuation methodologies that may result
in a shift of income, gain, loss and deduction between it and its unitholders.
The IRS may challenge this treatment, which could adversely affect the value of
the common units.
When
Kinder Morgan Energy Partners issues additional units or engages in certain
other transactions, it determines the fair market value of its assets and
allocates any unrealized gain or loss attributable to its assets to the capital
accounts of its unitholders and us. This methodology may be viewed as
understating the value of Kinder Morgan Energy Partners’ assets. In that case,
there may be a shift of income, gain, loss and deduction between certain
unitholders and us, which may be unfavorable to such unitholders. Moreover,
under Kinder Morgan Energy Partners’ current valuation methods, subsequent
purchasers of common units may have a greater portion of their Internal Revenue
Code Section 743(b) adjustment allocated to its tangible assets and a lesser
portion allocated to its intangible assets. The IRS may challenge these
valuation methods, or Kinder Morgan Energy Partners’ allocation of the Section
743(b) adjustment attributable to its tangible and intangible assets, and
allocations of income, gain, loss and deduction between it and certain of its
unitholders. A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being allocated to Kinder
Morgan Energy Partners’ partners, including us. It also could affect the amount
of gain from Kinder Morgan Energy Partners’ unitholders’ sale of common units
and could have a negative impact on the value of the common units or result in
audit adjustments to its unitholders’ tax returns without the benefit of
additional deductions.
Kinder
Morgan Energy Partners’ treatment of a purchaser of common units as having the
same tax benefits as the seller could be challenged, resulting in a reduction in
value of the common units.
Because
Kinder Morgan Energy Partners cannot match transferors and transferees of common
units, it is required to maintain the uniformity of the economic and tax
characteristics of these units in the hands of the purchasers and sellers of
these units. It does so by adopting certain depreciation conventions that do not
conform to all aspects of the United States Treasury regulations. A successful
IRS challenge to these conventions could adversely affect the tax benefits to a
unitholder of ownership of the common units and could have a negative impact on
their value or result in audit adjustments to unitholders’ tax
returns.
None.
See
Note 21 of the accompanying Notes to Consolidated Financial
Statements.
None.
44
|
Knight
Form 10-K
|
|
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity
Securities.
|
Prior
to the Going Private transaction, our common stock was listed for trading on the
New York Stock Exchange under the symbol “KMI.” Dividends paid and the high and
low sale prices per share, as reported on the New York Stock Exchange, of our
common stock by quarter for the last two years are provided below.
|
Market Price Per
Share1
|
|||||||
|
2008
|
2007
|
||||||
|
Low
|
High
|
Low
|
High
|
||||
|
Quarter
Ended
|
|||||||
|
March
31
|
n/a
|
n/a
|
$104.97
|
$107.02
|
|||
|
June
30
|
n/a
|
n/a
|
$105.32
|
$108.14
|
|||
|
September
30
|
n/a
|
n/a
|
n/a
|
n/a
|
|||
|
December
31
|
n/a
|
n/a
|
n/a
|
n/a
|
|||
|
Dividends
Paid Per Share
|
|||
|
2008
|
2007
|
||
|
Quarter
Ended
|
|||
|
March
31
|
n/a
|
$0.8750
|
|
|
June
30
|
n/a
|
$0.8750
|
|
|
September
30
|
n/a
|
n/a
|
|
|
December
31
|
n/a
|
n/a
|
|
__________
|
1
|
As
a result of the Going Private transaction, our common stock ceased trading
on May 30, 2007.
|
For
information regarding our equity compensation plans, please refer to Part III,
Item 12, included elsewhere in this report.
|
Selected
Financial Data.
|
Five-Year
Review
Knight
Inc. and Subsidiaries
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||||||||||
|
Year
Ended
December
31,
|
Seven
Months
Ended
December
31,
|
Five
Months
Ended
May 31,
|
Year
Ended December 31,
|
|||||||||||||||||||||
|
20081,2
|
20071,2
|
20072,3
|
20062,3
|
20053
|
2004
|
|||||||||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||||||||||
|
Operating
Revenues
|
$
|
12,094.8
|
$
|
6,394.7
|
$
|
4,165.1
|
$
|
10,208.6
|
$
|
1,025.6
|
$
|
877.7
|
||||||||||||
|
Gas
Purchases and Other Costs of Sales
|
7,744.0
|
3,656.6
|
2,490.4
|
6,339.4
|
302.6
|
194.2
|
||||||||||||||||||
|
Other
Operating Expenses4,5,6,7
|
6,822.9
|
1,695.3
|
1,469.9
|
2,124.0
|
341.7
|
342.5
|
||||||||||||||||||
|
Operating
Income (Loss)
|
(2,472.1
|
)
|
1,042.8
|
204.8
|
1,745.2
|
381.3
|
341.0
|
|||||||||||||||||
|
Other
Income and (Expenses)
|
(822.0
|
)
|
(566.9
|
)
|
(302.0
|
)
|
(858.9
|
)
|
470.0
|
365.2
|
||||||||||||||
|
Income
(Loss) from Continuing Operations Before Income Taxes
|
(3,294.1
|
)
|
475.9
|
(97.2
|
)
|
886.3
|
851.3
|
706.2
|
||||||||||||||||
|
Income
Taxes
|
304.3
|
227.4
|
135.5
|
285.9
|
337.1
|
208.0
|
||||||||||||||||||
|
Income
(Loss) from Continuing Operations
|
(3,598.4
|
)
|
248.5
|
(232.7
|
)
|
600.4
|
514.2
|
498.2
|
||||||||||||||||
|
Income
(Loss) from Discontinued Operations, Net of Tax8
|
(0.9
|
)
|
(1.5
|
)
|
298.6
|
(528.5
|
)
|
40.4
|
23.9
|
|||||||||||||||
|
Net
Income (Loss)
|
$
|
(3,599.3
|
)
|
$
|
247.0
|
$
|
65.9
|
$
|
71.9
|
$
|
554.6
|
$
|
522.1
|
|||||||||||
|
|
||||||||||||||||||||||||
|
Capital
Expenditures9
|
$
|
2,545.3
|
$
|
1,287.0
|
$
|
652.8
|
$
|
1,375.6
|
$
|
134.1
|
$
|
103.2
|
||||||||||||
__________
|
1
|
Includes
significant impacts resulting from the Going Private transaction. See Note
1 of the accompanying Notes to Consolidated Financial Statements for
additional information.
|
|
2
|
Due
to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts,
balances and results of operations of Kinder Morgan Energy Partners are
included in our financial statements and we no longer apply the equity
method of accounting to our investments in Kinder Morgan Energy Partners.
See Note 1 of the accompanying Notes to Consolidated Financial
Statements.
|
|
3
|
Includes
the results of Terasen Inc. subsequent to its November 30, 2005
acquisition by us. See Notes 10 and 11 of the accompanying Notes to
Consolidated Financial Statements for information regarding
Terasen.
|
45
|
Item 6.
Selected Financial
Data (continued)
|
Knight
Form 10-K
|
|
4
|
Includes
non-cash goodwill charges of $4,033.3 million in the year ended December
31, 2008.
|
|
5
|
Includes
charges of $1.2 million, $6.5 million and $33.5 million in 2006, 2005 and
2004, respectively, to reduce the carrying value of certain power
assets.
|
|
6
|
Includes
an impairment charge of $377.1 million in the five months ended May 31,
2007 relating to Kinder Morgan Energy Partners’ acquisition of Trans
Mountain pipeline from us on April 30, 2007. See Note 3 of the
accompanying Notes to Consolidated Financial
Statements.
|
|
8
|
Includes
a charge of $650.5 million in 2006 to reduce the carrying value of Terasen
Inc.; see Note 3 of the accompanying Notes to Consolidated Financial
Statements.
|
|
9
|
Capital
expenditures shown are for continuing operations
only.
|
|
As
of December 31,
|
||||||||||||||||||||||||||||||
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||||||||||||||||
|
2008
|
20071
|
20062
|
20053
|
2004
|
||||||||||||||||||||||||||
|
(In
millions, except percentages)
|
(In
millions, except percentages)
|
|||||||||||||||||||||||||||||
|
Total
Assets
|
$
|
25,444.9
|
$
|
36,101.0
|
$
|
26,795.6
|
$
|
17,451.6
|
$
|
10,116.9
|
||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||
|
Capitalization:
|
||||||||||||||||||||||||||||||
|
Common
Equity4
|
$
|
4,457.7
|
23
|
%
|
$
|
8,069.2
|
30
|
%
|
$
|
3,657.5
|
20
|
%
|
$
|
4,051.4
|
34
|
%
|
$
|
2,919.5
|
45
|
%
|
||||||||||
|
Deferrable
Interest Debentures
|
35.7
|
-
|
283.1
|
1
|
%
|
283.6
|
2
|
%
|
283.6
|
2
|
%
|
283.6
|
4
|
%
|
||||||||||||||||
|
Capital
Securities
|
-
|
-
|
-
|
-
|
106.9
|
1
|
%
|
107.2
|
1
|
%
|
-
|
-
|
||||||||||||||||||
|
Minority
Interests
|
4,072.6
|
21
|
%
|
3,314.0
|
13
|
%
|
3,095.5
|
17
|
%
|
1,247.3
|
10
|
%
|
1,105.4
|
17
|
%
|
|||||||||||||||
|
Outstanding
Notes and Debentures5
|
11,120.1
|
56
|
%
|
14,814.6
|
56
|
%
|
10,623.9
|
60
|
%
|
6,286.8
|
53
|
%
|
2,258.0
|
34
|
%
|
|||||||||||||||
|
Total
Capitalization
|
$
|
19,686.1
|
100
|
%
|
$
|
26,480.9
|
100
|
%
|
$
|
17,767.4
|
100
|
%
|
$
|
11,976.3
|
100
|
%
|
$
|
6,566.5
|
100
|
%
|
||||||||||
__________
|
1
|
Includes
significant impacts resulting from the Going Private transaction. See Note
1 of the accompanying Notes to Consolidated Financial Statements for
additional information.
|
|
2
|
Due
to our adoption of EITF No. 04-5, effective January 1, 2006 the accounts,
balances and results of operations of Kinder Morgan Energy Partners are
included in our financial statements and we no longer apply the equity
method of accounting to our investments in Kinder Morgan Energy
Partners.
|
|
3
|
Reflects
the acquisition of Terasen Inc. on November 30, 2005. See Notes 10 and 11
of the accompanying Notes to Consolidated Financial Statements for
information regarding this
acquisition.
|
|
4
|
Excluding
Accumulated Other Comprehensive Loss balances of $53.4 million, $247.7
million, $135.9 million, $127.0 million, and $54.7 million as of December
31, 2008, 2007, 2006, 2005, and 2004,
respectively.
|
|
5
|
Excluding
the value of interest rate swaps and short-term debt. See Note 14 of the
accompanying Notes to Consolidated Financial
Statements.
|
46
|
Knight
Form 10-K
|
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.
|
The
following discussion should be read in conjunction with the accompanying
Consolidated Financial Statements and related Notes.
We
are an energy infrastructure provider through our direct ownership and operation
of energy related assets, and through our ownership interests in and operation
of Kinder Morgan Energy Partners. Our strategy and focus are on ownership of
fee-based energy-related assets which are core to the energy infrastructure of
North America and serve growing markets. These assets tend to have relatively
stable cash flows while presenting us with opportunities to expand our
facilities to serve additional customers and nearby markets. We evaluate the
performance of our investment in these assets using, among other measures,
segment earnings before depreciation, depletion and amortization.
Our
principal business segments are:
|
|
·
|
Natural Gas Pipeline Company
of America LLC—which consists of our 20% interest in NGPL PipeCo
LLC, the owner of Natural Gas Pipeline Company of America and certain
affiliates, collectively referred to as Natural Gas Pipeline Company of
America or NGPL, a major interstate natural gas pipeline and storage
system which we operate;
|
|
|
·
|
Power—which consists of
two natural gas-fired electric generation
facilities;
|
|
|
·
|
Products
Pipelines–KMP—which consists of approximately 8,300 miles of
refined petroleum products pipelines that deliver gasoline, diesel fuel,
jet fuel and natural gas liquids to various markets; plus approximately 60
associated product terminals and petroleum pipeline transmix processing
facilities serving customers across the United
States;
|
|
|
·
|
Natural Gas
Pipelines–KMP—which consists of over 14,300 miles of natural gas
transmission pipelines and gathering lines, plus natural gas storage,
treating and processing facilities, through which natural gas is gathered,
transported, stored, treated, processed and
sold;
|
|
|
·
|
CO2–KMP—which produces,
markets and transports, through approximately 1,300 miles of pipelines,
carbon dioxide 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 450-mile crude oil pipeline system in
West Texas;
|
|
|
·
|
Terminals–KMP—which
consists of approximately 110 owned or operated liquids and bulk terminal
facilities and more than 45 rail transloading and materials handling
facilities located throughout the United States and portions of Canada,
which together transload, store and deliver a wide variety of bulk,
petroleum, petrochemical and other liquids products for customers across
the United States and Canada; and
|
|
|
·
|
Kinder Morgan
Canada–KMP—which consists of over 700 miles of common carrier
pipelines, originating at Edmonton, Alberta, for the transportation of
crude oil and refined petroleum to the interior of British Columbia and to
marketing terminals and refineries located in the greater Vancouver,
British Columbia area and Puget Sound in Washington state; plus five
associated product terminals. This segment also includes a one-third
interest in an approximately 1,700-mile integrated crude oil pipeline and
a 25-mile aviation turbine fuel pipeline serving the Vancouver
International Airport.
|
As
an energy infrastructure owner and operator in multiple facets of the United
States’ and Canada’s various energy businesses and markets, we examine a number
of variables and factors on a routine basis to evaluate our current performance
and our prospects for the future. The profitability of our products pipeline
transportation business is generally driven by the utilization of our facilities
in relation to their capacity, as well as the prices we receive for our
services. Transportation volume levels are primarily driven by the demand for
the petroleum products being shipped or stored. The prices for shipping are
generally based on regulated tariffs that are adjusted annually based on changes
in the Producer Price Index. Because of the overall effect of utilization on our
products pipeline transportation business, we seek to own refined products
pipelines located in or that transport to stable or growing markets and
population centers.
With
respect to our interstate natural gas pipelines and related storage facilities,
the revenues from these assets tend to be received under contracts with terms
that are fixed for various periods of time. To the extent practicable and
economically feasible in light of our strategic plans and other factors, we
generally attempt to mitigate risk of reduced volumes and prices by negotiating
contracts with longer terms, with higher per-unit pricing and for a greater
percentage of our available capacity. However, changes, either positive or
negative, in actual quantities transported on our interstate natural gas
pipelines may not accurately measure or predict associated changes in
profitability because many of the underlying transportation contracts, sometimes
referred to as take-or-pay contracts, specify that we receive the majority of
our fee for making the capacity available, whether or not the customer actually
chooses to utilize the capacity.
The
CO2–KMP
business segment sales and transportation business, like the natural gas
pipelines business, generally has take-or-pay contracts, although the contracts
in the CO2–KMP
business segment typically have minimum volume requirements. In the long term,
the success in this business is driven by the demand for CO2. However,
short-term changes in the demand for
47
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
CO2 typically
do not have a significant impact on us due to the required minimum volumes under
many of our contracts. In the oil and gas producing activities within the
CO2–KMP
business segment, we monitor the amount of capital we expend in relation to the
amount of production that is added or the amount of declines in production that
are postponed. In that regard, our production during any period and the reserves
that we add during that period are important measures. In addition, the revenues
we receive from our crude oil, natural gas liquids and CO2 sales are
affected by the prices we realize from the sale of these products. Over the long
term, we will tend to receive prices that are dictated by the demand and overall
market price for these products. In the shorter term, however, published market
prices are likely not indicative of the revenues we will receive due to our risk
management, or hedging, program in which the prices to be realized for certain
of our future sales quantities are fixed, capped or bracketed through the use of
financial derivatives, particularly for oil.
As
with our products pipeline transportation businesses, the profitability of our
terminals businesses is generally driven by the utilization of our terminals
facilities in relation to their capacity, as well as the prices we receive for
our services, which in turn are driven by the demand for the products being
shipped or stored. The extent to which changes in these variables affect this
business in the near term is a function of the length of the underlying service
contracts, the extent to which revenues under the contracts are a function of
the amount of product stored or transported and the extent to which such
contracts expire during any given period of time. To the extent practicable and
economically feasible in light of our strategic plans and other factors, we
generally attempt to mitigate the risk of reduced volumes and pricing by
negotiating contracts with longer terms, with higher per-unit pricing and for a
greater percentage of our available capacity. In addition, weather-related
factors such as hurricanes, floods and droughts may impact our facilities and
access to them and, thus, the profitability of certain terminals for limited
periods of time or, in relatively rare cases of severe damage to facilities, for
longer periods.
In
our discussions of the operating results of individual businesses that follow,
we generally identify the important fluctuations between periods that are
attributable to acquisitions and dispositions separately from those that are
attributable to businesses owned in both periods. Principally through Kinder
Morgan Energy Partners, we have a history of making accretive acquisitions and
economically advantageous expansions of existing businesses. Our ability to
increase earnings and Kinder Morgan Energy Partners’ ability to increase
distributions to us and other investors will, to some extent, be a function of
Kinder Morgan Energy Partners’ success in acquisitions and expansions. Kinder
Morgan Energy Partners continues to have opportunities for expansion of its
facilities in many markets and expects to continue to have such opportunities in
the future, although the level of such opportunities is difficult to
predict.
Kinder
Morgan Energy Partners’ ability to make accretive acquisitions is a function of
the availability of suitable acquisition candidates and, to some extent, its
ability to raise necessary capital to fund such acquisitions, factors over which
it has limited or no control. Thus, it has no way to determine the extent to
which it will be able to identify accretive acquisition candidates, or the
number or size of such candidates, in the future, or whether it will complete
the acquisition of any such candidates.
On
November 24, 2008, Kinder Morgan Energy Partners announced that it expected to
declare 2009 cash distributions of $4.20 per unit, a 4.5% increase over its 2008
cash distributions of $4.02 per unit. The expected growth in 2009 distributions
assumes an average West Texas Intermediate crude oil price of $68 per barrel in
2009 with some minor adjustments for timing, quality and location differences.
Based on actual prices received through the first seven weeks of 2009 and the
forward curve, adjusted for the same factors as the budget, the average realized
price for 2009 is currently projected to be $49 per barrel. Although the
majority of the cash generated by Kinder Morgan Energy Partners’ assets is fee
based and is not sensitive to commodity prices, the CO2–KMP
business segment is exposed to commodity price risk related to the price
volatility of crude oil and natural gas liquids. Kinder Morgan Energy Partners
hedges the majority of its crude oil production, but does have exposure to
unhedged volumes, the majority of which are natural gas liquids volumes. For
2009, Kinder Morgan Energy Partners expects that every $1 change in the average
WTI crude oil price per barrel will impact its CO2–KMP
segment’s cash flows by approximately $6 million (or approximately 0.2% of the
combined Kinder Morgan Energy Partners business segments’ anticipated
distributable cash flow). This sensitivity to the average WTI price is very
similar to what was experienced in 2008. Kinder Morgan Energy Partners’ 2009
cash distribution expectations do not take into account any capital costs
associated with financing any payment it may be required to make of reparations
sought by shippers on its Pacific operations’ interstate pipelines.
In
light of the above and other economic uncertainties we are taking cost reduction
measures for 2009. We are reducing our travel costs and compensation costs,
decreasing the use of outside consultants, reducing overtime where possible and
reviewing capital and operating budgets to identify the costs we can reduce
without compromising operating efficiency, maintenance or safety.
In
addition to any uncertainties described in this discussion and analysis, we are
subject to a variety of risks that could have a material adverse effect on our
business, financial condition, cash flows and results of operations. See “Risk
Factors” in Item 1A.
48
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
During
2006 and 2007, we reached agreements to sell certain businesses and assets in
which we no longer have any continuing interest, including Terasen Gas,
Corridor, the North System and our Kinder Morgan Retail segment. Accordingly,
the activities and assets related to these sales are presented as discontinued
items in the accompanying Consolidated Financial Statements. As discussed
following, many of our operations are regulated by various federal and state
regulatory bodies.
In
February 2007, we entered into a definitive agreement to sell our Canada-based
retail natural gas distribution operations to Fortis Inc., for approximately
C$3.7 billion including cash and assumed debt, and as a result of a
redetermination of fair value in light of this proposed sale, we recorded an
estimated goodwill impairment charge of approximately $650.5 million in 2006.
This sale was completed in May 2007; see Note 3 of the accompanying Notes to
Consolidated Financial Statements. Prior to its sale, we referred to these
operations principally as the Terasen Gas business segment.
In
March 2007, we entered into an agreement to sell the Corridor Pipeline System to
Inter Pipeline Fund, a Canada-based company, for approximately C$760 million,
including debt. This sale was completed in June 2007. Inter Pipeline Fund also
assumed all of the debt associated with the expansion taking place on Corridor
at the time of the sale. Prior to its sale, the Corridor Pipeline System was
included in the business segment named Kinder Morgan Canada. Also in March 2007,
we completed the sale of our U.S. retail natural gas distribution and related
operations to GE Energy Financial Services, a subsidiary of General Electric
Company and Alinda Investments LLC for $710 million and an adjustment for
working capital. Prior to their sale, we referred to these operations as the
Kinder Morgan Retail business segment. On October 5, 2007, Kinder Morgan Energy
Partners announced that it had completed the sale of the North System and also
its 50% ownership interest in the Heartland Pipeline Company to ONEOK Partners,
L.P. for approximately $295.7 million in cash. Prior to its sale, the North
System and the equity investment in the Heartland Pipeline were reported in the
Products Pipelines–KMP business segment. In February 2008, we sold an 80%
ownership interest in our NGPL business segment at a price equivalent to a total
enterprise value of approximately $5.9 billion; see Note 10 of the accompanying
Notes to Consolidated Financial Statements. In accordance with SFAS No. 144,
Accounting for the Impairment
or Disposal of Long-Lived Assets, the financial results of the Terasen
Gas, Corridor, Kinder Morgan Retail operations, the North System operations and
the equity investment in the Heartland Pipeline Company have been reclassified
to discontinued operations for all periods presented, and 100% of the assets and
liabilities associated with the NGPL business segment were reclassified to
assets and liabilities held for sale, and the non-current assets and long-term
debt held for sale balances were then reduced by our 20% ownership interest in
the NGPL business segment, which was recorded as an investment as of December
31, 2008 and 2007, respectively.
On
April 30, 2007, we sold the Trans Mountain pipeline system to Kinder Morgan
Energy Partners for approximately $550 million. The transaction was approved by
the independent members of our board of directors and those of Kinder Morgan
Management following the receipt, by each board, of separate fairness opinions
from different investment banks. The Trans Mountain pipeline system transports
crude oil and refined products from Edmonton, Alberta, Canada to marketing
terminals and refineries in British Columbia and the state of Washington. An
impairment of the Trans Mountain pipeline system was recorded in the first
quarter of 2007; see Note 3 of the accompanying Notes to Consolidated Financial
Statements.
On
November 20, 2007, we entered into a definitive agreement to sell our interests
in three natural gas-fired power plants in Colorado to Bear Stearns. The closing
of the sale occurred on January 25, 2008, effective January 1, 2008, and we
received net proceeds of $63.1 million.
On
August 28, 2008, we sold our one-third interest in the net assets of the Express
pipeline system and the net assets of the Jet Fuel pipeline to Kinder Morgan
Energy Partners for approximately 2 million Kinder Morgan Energy Partners’
common units worth approximately $116 million. The Express pipeline system
transports crude oil from Alberta to Illinois. The Jet Fuel pipeline serves the
Vancouver, British Columbia airport. Prior to the sales, we reported the results
of the Trans Mountain pipeline system in the Trans Mountain–KMP segment, the
equity investment in the Express pipeline system in the Express segment and the
results of Jet Fuel were included in the “Other” caption in the Consolidated
Financial Results table in the Management’s Discussion and Analysis of Financial
Condition and Results of Operations. In order to present the prior periods
consistent with the segments as now presented in 2008, these assets and their
results are included in the Kinder Morgan Canada–KMP segment for all periods
presented.
Notwithstanding
the consolidation of Kinder Morgan Energy Partners and its subsidiaries into our
financial statements, we are not liable for, and our assets are not available to
satisfy, the obligations of Kinder Morgan Energy Partners and/or its
subsidiaries and vice versa. Responsibility for payments of obligations
reflected in our or Kinder Morgan Energy Partners’ financial statements is a
legal determination based on the entity that incurs the liability.
Our
discussion and analysis of financial condition and results of operations are
based on our consolidated financial statements, prepared in accordance with
accounting principles generally accepted in the United States of America
(“GAAP”) and contained within this report. Certain amounts included in or
affecting our consolidated financial statements and related disclosure must be
estimated, requiring us to make certain assumptions with respect to values or
conditions that cannot be
49
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
known
with certainty at the time the financial statements are prepared. The reported
amounts of our assets and liabilities, revenues and expenses and associated
disclosures with respect to contingent assets and obligations are necessarily
affected by these estimates. We evaluate these estimates on an ongoing basis,
utilizing historical experience, consultation with experts and other methods we
consider reasonable in the particular circumstances. Nevertheless, actual
results may differ significantly from our estimates. Any effects on our
business, financial position or results of operations resulting from revisions
to these estimates are recorded in the period in which the facts that give rise
to the revision become known. In preparing our consolidated financial statements
and related disclosures, we must use estimates in determining the economic
useful lives of our assets, the fair values used to determine possible
impairment charges, the effective income tax rate to apply to our pre-tax
income, deferred income tax balances, obligations under our employee benefit
plans, provisions for uncollectible accounts receivable, cost and timing of
environmental remediation efforts, potential exposure to adverse outcomes from
judgments or litigation settlements, exposures under contractual
indemnifications and various other recorded or disclosed amounts. Certain of
these accounting estimates are of more significance in our financial statement
preparation process than others, which policies are discussed following. Our
policies and estimation methodologies are generally the same in both the
predecessor and successor company periods, except where explicitly
discussed.
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
recording of environmental accruals often coincides with the completion of a
feasibility study or the 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. These adjustments may result in increases in environmental
expenses and primarily result from quarterly reviews of potential environmental
issues and resulting changes in environmental liability estimates. The
environmental liability adjustments are recorded pursuant to management’s
requirement to recognize environmental liabilities wherever the associated
environmental issue is likely to occur and where the amount of the liability can
be reasonably estimated. In making these liability estimations, we consider the
effect of environmental compliance, pending legal actions against us, and
potential third-party liability claims. For more information on our
environmental disclosures, see Note 21 of the accompanying Notes to Consolidated
Financial Statements.
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. In general, we expense legal costs as incurred. When
we identify specific litigation that is expected to continue for a significant
period of time and require substantial expenditures, we identify a range of
possible costs expected to be required to litigate the matter to a conclusion or
reach an acceptable settlement. If no amount within this range is a better
estimate than any other amount, we record a liability equal to the low end of
the range. Any such liability recorded is revised as better information becomes
available.
As
of December 31, 2008 and December 31, 2007, our most significant ongoing
litigation proceedings involve Kinder Morgan Energy Partners’ West Coast
Products Pipelines operations. Tariffs charged by certain of these pipeline
systems are subject to certain proceedings at the Federal Energy Regulatory
Commission (“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 Kinder Morgan Energy Partners’
West Coast Products Pipelines 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, the West Coast Products Pipelines pipeline systems may be subject to
substantial exposure under these FERC complaints and could, therefore, owe
reparations and/or refunds to complainants as mandated by the FERC or the United
States’ judicial system. For more information on the West Coast Products
Pipelines pipeline systems’ regulatory proceedings, see Note 20 of the
accompanying Notes to Consolidated Financial Statements.
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 SFAS No. 141, Business Combinations and
SFAS 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 periodic amortization. Such assets are not to be
amortized unless and until their lives are determined to be finite.
Instead,
50
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
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. For the Predecessor Company, an impairment measurement test date
of January 1 of each year was selected; for the Successor Company, we use an
annual impairment measurement date of May 31.
As
of December 31, 2008 and December 31, 2007, our goodwill was $4,741.1 million
and $8,174.0 million, respectively. Included in these goodwill balances is
$250.1 million related to the Trans Mountain pipeline, which we sold to Kinder
Morgan Energy Partners on April 30, 2007. This sale transaction caused us to
reconsider the fair value of the Trans Mountain pipeline system in relation to
its carrying value, and to make a determination as to whether the associated
goodwill was impaired. As a result of our analysis, we recorded a goodwill
impairment charge of $377.1 million in the first quarter of 2007.
Our
remaining intangible assets, excluding goodwill, include customer relationships,
contracts and agreements, technology-based assets and lease value. 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 the accompanying Consolidated Balance Sheets. As of
December 31, 2008 and December 31, 2007, these intangibles totaled $251.5
million and $321.1 million, respectively.
In
conjunction with our annual impairment test of the carrying value of goodwill,
performed as of May 31, 2008, we determined that the fair value of certain
reporting units that are part of our investment in Kinder Morgan Energy Partners
were less than the carrying values. The fair value of each reporting unit was
determined from the present value of the expected future cash flows from the
applicable reporting unit (inclusive of a terminal value calculated using a
market multiple for the individual assets). The implied fair value of goodwill
within each reporting unit was then compared to the carrying value of goodwill
of each such unit, resulting in the following goodwill impairments by reporting
unit: Products Pipelines–KMP (excluding associated terminals) $1.20 billion,
Products Pipelines Terminals–KMP (separate from Products Pipelines–KMP for
goodwill impairment purposes)—$70 million, Natural Gas Pipelines–KMP—$2.09
billion, and Terminals–KMP $677 million, for a total impairment of $4.03
billion. The goodwill impairment is a non-cash charge and does not have any
impact on our cash flow. While the fair value of the CO2–KMP segment exceeded its
carrying value as of the date of our goodwill impairment test, decreases in the
market value of crude oil led us to reconsider this analysis as of December 31,
2008 and at that time our analysis also determined that the fair value exceeded
the carrying value. If the market price of crude oil continues to decline, we
may need to record non-cash goodwill impairment charges on this reporting unit
in future periods.
Estimated
Net Recoverable Quantities of Oil and Gas
We
use the successful efforts method of accounting for Kinder Morgan Energy
Partners’ 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.
Hedging
Activities
We
engage in a hedging program that utilizes derivative contracts to mitigate
(offset in whole or in part) our exposure to fluctuations in energy commodity
prices, fluctuations in currency exchange rates and to balance our exposure to
fixed and variable 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.
51
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
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.
Employee
Benefit Plans
With
respect to the amount of income or expense we recognize in association with our
pension and retiree medical plans, we must make a number of assumptions with
respect to both future financial conditions (for example, medical costs, returns
on fund assets and market interest rates) as well as future actions by plan
participants (for example, when they will retire and how long they will live
after retirement). Most of these assumptions have relatively minor impacts on
the overall accounting recognition given to these plans, but two assumptions in
particular, the discount rate and the assumed long-term rate of return on fund
assets, can have significant effects on the amount of expense recorded and
liability recognized. We review historical trends, future expectations, current
and projected market conditions, the general interest rate environment and
benefit payment obligations to select these assumptions. The discount rate
represents the market rate for a high quality corporate bond. The selection of
these assumptions is further discussed in Note 16 of the accompanying Notes to
Consolidated Financial Statements. While we believe our choices for these
assumptions are appropriate in the circumstances, other assumptions could also
be reasonably applied and, therefore, we note that, at our current level of
pension and retiree medical funding, a change of 1% in the long-term return
assumption would increase (decrease) our annual retiree medical expense by
approximately $0.5 million ($0.5 million) and would increase (decrease) our
annual pension expense by $1.8 million ($1.8 million) in comparison to that
recorded in 2008. Similarly, a 1% change in the discount rate would increase
(decrease) our accumulated postretirement benefit obligation by $6.4 million
($5.9 million) and would increase (decrease) our projected pension benefit
obligation by $29.3 million ($26.1 million) compared to those balances as of
December 31, 2008.
Income
Taxes
We
record a valuation allowance to reduce our deferred tax assets to an amount that
is more likely than not to be realized. While we have considered estimated
future taxable income and prudent and feasible tax planning strategies in
determining the amount of our valuation allowance, any change in the amount that
we expect to ultimately realize will be included in income in the period in
which such a determination is reached. In addition, we do business in a number
of states with differing laws concerning how income subject to each state’s tax
structure is measured and at what effective rate such income is taxed.
Therefore, we must make estimates of how our income will be apportioned among
the various states in order to arrive at an overall effective tax rate. Changes
in our effective rate, including any effect on previously recorded deferred
taxes, are recorded in the period in which the need for such change is
identified.
The
Going Private transaction was accounted for as a purchase business combination
and, as a result of the application of the Securities and Exchange Commission’s
“push-down” accounting requirements, this transaction has resulted in our
adoption of a new basis of accounting for our assets and liabilities.
Accordingly, our assets and liabilities have been recorded at their estimated
fair values as of the date of the completion of the Going Private transaction,
with the excess of the purchase price over these combined fair values recorded
as goodwill.
Therefore,
in the accompanying financial information, transactions and balances prior to
the closing of the Going Private transaction (the amounts labeled “Predecessor
Company”) reflect the historical basis of accounting for our assets and
liabilities, while the amounts subsequent to the closing (the amounts labeled
“Successor Company”) reflect the push-down of the investors’ new accounting
basis to our financial statements. While the Going Private transaction closed on
May 30, 2007, for convenience, the Predecessor Company is assumed to end on May
31, 2007 and the Successor Company is assumed to begin on June 1, 2007. The
results for the two-day period, from May 30 to May 31, 2007, are not material to
any of the periods presented. Additional information concerning the impact of
the Going Private transaction on the accompanying financial information is
contained under “Consolidated Financial Results” following.
Our
adoption of a new basis of accounting for our assets and liabilities as a result
of the Going Private transaction, the sale of our retail natural gas
distribution and related operations, our Corridor operations, the North System,
our 80% interest in NGPL PipeCo LLC (“PipeCo”), the goodwill impairments
described above, and other acquisitions and divestitures (including the transfer
of certain assets to Kinder Morgan Energy Partners), among other factors, affect
comparisons of our financial position and results of operations between certain
periods.
52
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
The
following discussion provides an analysis of material events that affected our
operating results for the year ended December 31, 2008 (successor basis), seven
months ended December 31, 2007 (successor basis) and five months ended May 31,
2007 (predecessor basis) and year ended December 31, 2006 (predecessor
basis).
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May 31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Segment
Earnings (Loss) before Depreciation, Depletion and Amortization of Excess
Cost of Equity Investments1
|
||||||||||||||||
|
NGPL2
|
$
|
129.8
|
$
|
422.8
|
$
|
267.4
|
$
|
603.5
|
||||||||
|
Power
|
5.7
|
13.4
|
8.9
|
23.2
|
||||||||||||
|
Products
Pipelines–KMP3,8
|
(722.0
|
)
|
162.5
|
224.4
|
467.9
|
|||||||||||
|
Natural
Gas Pipelines–KMP4,8
|
(1,344.3
|
)
|
373.3
|
228.5
|
574.8
|
|||||||||||
|
CO2–KMP8
|
896.1
|
433.0
|
210.0
|
488.2
|
||||||||||||
|
Terminals–KMP5,8
|
(156.5
|
)
|
243.7
|
172.3
|
408.1
|
|||||||||||
|
Kinder
Morgan Canada–KMP6
|
152.0
|
58.8
|
(332.0
|
)
|
95.1
|
|||||||||||
|
Segment
Earnings (Loss) before Depreciation, Depletion and Amortization of Excess
Cost of Equity Investments
|
(1,039.2
|
)
|
1,707.5
|
779.5
|
2,660.8
|
|||||||||||
|
Depreciation,
Depletion and Amortization Expense
|
(918.4
|
)
|
(472.3
|
)
|
(261.0
|
)
|
(531.4
|
)
|
||||||||
|
Amortization
of Excess Cost of Equity Investments
|
(5.7
|
)
|
(3.4
|
)
|
(2.4
|
)
|
(5.6
|
)
|
||||||||
|
Other
Operating Income (Loss)
|
39.0
|
(0.3
|
)
|
2.9
|
6.8
|
|||||||||||
|
General
and Administrative Expenses
|
(352.5
|
)
|
(175.6
|
)
|
(283.6
|
)
|
(305.1
|
)
|
||||||||
|
Interest
and Other, Net
|
(1,019.7
|
)
|
(624.0
|
)
|
(348.2
|
)
|
(968.2
|
)
|
||||||||
|
Income
(Loss) From Continuing Operations Before Income Taxes1
|
(3,296.5
|
)
|
431.9
|
(112.8
|
)
|
857.3
|
||||||||||
|
Income
Taxes1
|
(301.9
|
)
|
(183.4
|
)
|
(119.9
|
)
|
(256.9
|
)
|
||||||||
|
Income
(Loss) From Continuing Operations
|
(3,598.4
|
)
|
248.5
|
(232.7
|
)
|
600.4
|
||||||||||
|
Income
(Loss) From Discontinued Operations, Net of Tax7
|
(0.9
|
)
|
(1.5
|
)
|
298.6
|
(528.5
|
)
|
|||||||||
|
Net
Income (Loss)
|
$
|
(3,599.3
|
)
|
$
|
247.0
|
$
|
65.9
|
$
|
71.9
|
|||||||
__________
|
1
|
Kinder
Morgan Energy Partners’ income taxes expenses for the year ended December
31, 2008, seven months ended September 30, 2007, five months ended May 31,
2007 and year ended December 31, 2006 were $2.4 million, $44.0 million,
$15.6 million and $29.0 million, respectively, and are included in segment
earnings.
|
|
2
|
Effective
February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC.
As a result of the sale, beginning February 15, 2008, we account for our
20% ownership interest in NGPL PipeCo LLC as an equity method
investment.
|
|
3
|
2008
amount includes a non-cash goodwill impairment charge of $1,266.5
million.
|
|
4
|
2008
amount includes a non-cash goodwill impairment charge of $2,090.2
million.
|
|
5
|
2008
amount includes a non-cash goodwill impairment charge of $676.6
million.
|
|
6
|
Includes
earnings of the Trans Mountain pipeline system, Kinder Morgan Energy
Partners’ interest in the Express pipeline system and the Jet Fuel
pipeline system and a non-cash goodwill impairment charge of $377.1
million for the five months ended May 31,
2007.
|
|
7
|
2006
includes a $650.5 million goodwill impairment associated with Terasen (see
Note 3 of the accompanying Notes to Consolidated Financial
Statements).
|
|
8
|
2008
amounts include a total of $18.3 million of expense associated with
hurricanes Hanna, Gustav and Ike and three terminal fires among the
Terminals–KMP, Products Pipelines–KMP, Natural Gas Pipelines–KMP and
CO2–KMP
business segments.
|
Year
Ended December 31, 2008
The
net loss primarily resulted from a $4.03 billion non-cash goodwill impairment
charge that was recorded in the second quarter of 2008 (see Note 3 of the
accompanying Notes to Consolidated Financial Statements). Other items negatively
affecting results for the year ended December 31, 2008 include (i) reduced
earning contributions from NGPL and Power as portions of these segments were
sold in 2008, (ii) depreciation, depletion and amortization (“DD&A”) expense
associated with expansion capital expenditures, (iii) general and administrative
costs that included labor costs and associated costs for new hires during this
period to support Kinder Morgan Energy Partners’ growing operations, (iv) $18.3
million of incremental expenses associated with hurricanes Hanna, Gustav and Ike
and fires at three separate terminal locations and (v) lower crude oil, natural
gas liquids and natural gas prices in the fourth quarter of 2008.
53
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
The
net loss was partially offset by (i) contributions from Rockies Express-West,
which began service in January 2008 and reached full operations in May 2008, and
increasing margins in the Texas Intrastate pipelines, (ii) favorable interest
expense due to the February 2008 sale of an 80% ownership interest in NGPL
PipeCo LLC for approximately $5.9 billion, with the proceeds from the sale used
to pay down debt, (iii) strong CO2 sales and
transport volumes in the CO2–KMP
segment, as well as increases of the average crude oil sale prices, (iv) the
completion of expansion projects at existing facilities and recent acquisitions
within the Terminals–KMP segment and (v) the completion of the pump station
expansion in April 2007 and Anchor Loop expansion, which was placed in service
in April 2008 (partially) and October 2008 (fully) within Kinder Morgan
Canada–KMP.
Seven
Months Ended December 31, 2007
Net
income for the period was driven by solid contributions from CO2–KMP, NGPL,
Natural Gas Pipelines–KMP and Products Pipelines–KMP, which accounted for 25.4%,
24.7%, 21.9% and 9.5%, respectively, or 81.5% collectively, of segment earnings
before DD&A. CO2–KMP was
driven almost equally by our sales and transport and oil and gas producing
activities. The Texas Intrastate Natural Gas Pipelines Group accounted for over
50% of the Natural Gas Pipelines–KMP performance and the West Coast Products
Pipelines accounted for approximately 50% of the Product Pipelines–KMP segment
earnings. NGPL contributed earnings of $422.8 million with incremental earnings
coming from the re-contracting of transportation and storage services at higher
rates, increased contract volumes, and recent transportation and storage
expansions.
Net
income was adversely impacted by (i) interest expenses related to the $4.8
billion of incremental debt resulting from the Going Private transaction (see
discussion below on the impact of the purchase method of accounting on segment
earnings) and (ii) DD&A expense associated with expansion capital
expenditures.
Five
Months Ended May 31, 2007
Net
income was driven by solid performance from NGPL as well as all Kinder Morgan
Energy Partners segments except Kinder Morgan Canada–KMP, as discussed below.
NGPL contributed $267 million while Products Pipelines–KMP, Natural Gas
Pipelines–KMP and CO2–KMP each
contributed over $200 million.
Offsetting
these positive factors were (i) a $377.1 million goodwill impairment charge
associated with the Trans Mountain Pipeline (see Note 3 of the accompanying
Notes to Consolidated Financial Statements) and (ii) $141.0 million in
additional general and administrative expense associated with the Going Private
transaction.
Year
Ended December 31, 2006
Net
income for the year ended December 31, 2006 was driven by solid contributions
from NGPL, Natural Gas Pipelines–KMP, CO2–KMP and
Products Pipelines–KMP, which accounted for 22.7%, 21.6%, 18.4% and 17.6%,
respectively, or 80.3% collectively, of segment earnings before DD&A. NGPL
was driven by successful re-contracting of transportation and storage services
and increased gas sales prices. The Texas Intrastate Natural Gas Pipeline Group
and the western interstate natural gas pipelines group accounted for 53.1% and
35.0%, respectively, of the Natural Gas Pipelines–KMP earnings. The
TransColorado pipeline system improvements completed in 2005 contributed to the
western interstate natural gas pipelines group 2006 earnings. In addition, the
earnings from the Trans Mountain pipeline, purchased in 2005 and part of the
Kinder Morgan Canada–KMP business segment, were accretive to earnings for
2006.
Impact
of the Purchase Method of Accounting on Segment Earnings (Loss)
The
impacts of the purchase method of accounting on segment earnings (loss) before
DD&A relate primarily to the revaluation of the accumulated other
comprehensive income related to derivatives accounted for as hedges in the
CO2–KMP and
Natural Gas Pipelines–KMP segments. Where there is an impact to segment earnings
(loss) before DD&A from the Going Private transaction, the impact is
described in the individual business segment discussions, which follow. The
effects on DD&A expense result from changes in the carrying values of
certain tangible and intangible assets to their estimated fair values as of May
30, 2007. This revaluation results in changes to DD&A expense in periods
subsequent to May 30, 2007. The purchase accounting effects on “Interest and
Other, Net” result principally from the revaluation of certain debt instruments
to their estimated fair values as of May 30, 2007, resulting in changes to
interest expense in subsequent periods.
Please
refer to the individual business segment discussions included elsewhere in this
management’s discussion and analysis for additional information regarding
individual business segment results. Refer to the headings “General and
Administrative Expense,” “Interest and Other, Net” and “Income Taxes—Continuing
Operations” also included elsewhere herein, for additional information regarding
these items.
54
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
The
following discussion of our results of operations is by segment for factors
affecting segment earnings, and on a consolidated basis for other
factors.
The
variability of our operating results is attributable to a number of factors
including (i) variability within U.S. and Canadian national and local markets
for energy and related services, including the effects of competition, (ii) the
impact of regulatory proceedings, (iii) the effect of weather on customer energy
and related services usage, as well as our operation and construction
activities, (iv) increases or decreases in interest rates, (v) the degree of our
success in controlling costs, identifying and carrying out profitable expansion
projects, and integrating new acquisitions into our operations and (vi) changes
in taxation policy or regulated rates. Certain of these factors are beyond our
direct control, but we operate a structured risk management program to mitigate
certain of the risks associated with changes in the price of natural gas,
interest rates and currency exchange rates. Also see Item 1A “Risk Factors”
elsewhere in this report.
We
manage our various businesses by, among other things, allocating capital and
monitoring operating performance. This management process includes dividing the
company into business segments so that performance can be effectively monitored
and reported for a limited number of discrete businesses.
The
accounting policies we apply in the generation of business segment earnings are
generally the same as those applied to the accompanying Consolidated Statements
of Operations and described in Note 1 of the accompanying Notes to Consolidated
Financial Statements. Certain items included in earnings from continuing
operations are either not allocated to business segments or are not considered
by management in its evaluation of business segment performance. In general, the
items not included in segment results are interest expense, general and
administrative expenses, DD&A and income taxes. We currently evaluate
business segment performance primarily based on segment earnings before DD&A
in relation to the level of capital employed. Because Kinder Morgan Energy
Partners’ partnership agreement requires it to distribute 100% of its available
cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’
available cash consists primarily of all of its cash receipts, less cash
disbursements and changes in reserves), we consider each period’s earnings
before all non-cash depreciation, depletion and amortization expenses to be an
important measure of business segment performance for our segments that are also
segments of Kinder Morgan Energy Partners. We account for intersegment sales at
market prices. We account for the
transfer of net assets between entities under common control by carrying forward
the net assets recognized in the balance sheets of each combining entity to the
balance sheet of the combined entity, and no other assets or liabilities are
recognized as a result of the combination. Transfers of net assets between
entities under common control do not affect the income statement of the combined
entity.
Natural
Gas Pipeline Company of America
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Segment
Earnings Before DD&A
|
$
|
129.8
|
$
|
422.8
|
$
|
267.4
|
$
|
603.5
|
||||||||
On
February 15, 2008, we sold an 80% ownership interest in our NGPL business
segment to Myria Acquisition Inc. (“Myria”) for approximately $5.9 billion. As a
result of the sale, beginning February 15, 2008, we account for our 20%
ownership interest as an equity method investment. We continue to operate NGPL’s
assets pursuant to a 15-year operating agreement. Myria is owned by a syndicate
of investors led by Babcock & Brown, an international investment and
specialized fund and asset management group.
Year
Ended December 31, 2008
Although
we have a 20% ownership interest in NGPL, at the 100% ownership level, NGPL’s
earnings before depreciation, depletion and amortization expenses for the year
ended December 31, 2008 was $702.0 million. Included in the earnings for this
period were (i) $650.8 million of gross profit from transportation and storage
revenues, which reflects the positive impact of re-contracting of transportation
and storage services at higher rates and increased contract volumes, (ii) $226.5
million of gross profit from operational gas recoveries and sales, (iii) $5.0
million of gross profit from liquids sales, (iv) $0.6 million of other revenues,
(v) $15.8 million of gross profit from working and cushion sales and (vi) $7.1
million from other activities. These gross profits were reduced by operation and
maintenance expenses of $203.8 million.
55
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Seven
Months Ended December 31, 2007
Segment
revenues and earnings for the seven months ended December 31, 2007 were
positively impacted primarily by (i) $334.4 million of gross profit from
transportation and storage revenues, which reflects the positive impact of
re-contracting of transportation and storage services at higher rates and
increased contract volumes, and recent transportation and storage system
expansions, (ii) $116.0 million of gross profit from operational gas recoveries
and sales and (iii) $61.4 million of gross profit from cushion sales. Total
system throughput volumes of 1,027.2 trillion Btus in 2007 during the seven
months ended December 31, 2007 did not have a significant direct impact on
revenues or segment earnings due to the fact that transportation revenues are
derived primarily from “firm” contracts in which shippers pay a “demand” fee to
reserve a set amount of system capacity for their use.
Five
Months Ended May 31, 2007
Segment
revenues and earnings for the five months ended May 31, 2007 were positively
impacted primarily by (i) $245.9 million of gross profit from transportation and
storage revenues, which reflects the positive impact of re-contracting of
transportation and storage services at higher rates and increased contract
volumes, and recent transportation and storage system expansions and (ii) $77.6
million of gross profit from operational gas recoveries and sales.
Year
Ended December 31, 2006
Segment
revenues and earnings for the year ended December 31, 2006 were positively
impacted primarily by (i) $547.5 million of gross profit from transportation and
storage revenues, which reflects the positive impact of re-contracting of
transportation and storage services at higher rates and increased contract
volumes, and recent transportation and storage system expansions and (ii) $189.4
million of gross profit from operational gas recoveries and sales.
As
discussed in Note 10 of the accompanying Notes to Consolidated Financial
Statements, on January 25, 2008, we sold our interests in three natural
gas-fired power plants in Colorado to Bear Stearns, including the Thermo
Cogeneration Partnership and the Thermo Greeley facility. The closing of the
sale was effective January 1, 2008, and we received net proceeds of $63.1
million.
The
remaining operations for the Power segment are (i) Triton Power Michigan LLC’s
lease and operation of the Jackson, Michigan 550-megawatt natural gas-fired
electric power plant and (ii) a 103-megawatt natural gas-fired power plant in
Snyder, Texas that generates electricity for the CO2–KMP
segment’s SACROC operations, the plant’s sole customer.
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Operating
Revenues
|
$
|
44.0
|
$
|
40.2
|
$
|
19.9
|
$
|
60.0
|
||||||||
|
Operating
Expenses and Minority Interests
|
(38.3
|
)
|
(34.8
|
)
|
(16.1
|
)
|
(49.6
|
)
|
||||||||
|
Other
Income (Expense)1
|
-
|
-
|
-
|
(1.2
|
)
|
|||||||||||
|
Equity
in Earnings of Thermo Cogeneration Partnership2
|
-
|
8.0
|
5.1
|
11.3
|
||||||||||||
|
Gain
on Asset Sales
|
-
|
-
|
-
|
2.7
|
||||||||||||
|
Segment
Earnings Before DD&A
|
$
|
5.7
|
$
|
13.4
|
$
|
8.9
|
$
|
23.2
|
||||||||
__________
|
1
|
To
record the impairment of certain surplus equipment held for
sale.
|
|
2
|
This
interest was part of the sale effective January 1, 2008 as discussed
above.
|
Year
Ended December 31, 2008
Earnings
before DD&A for 2008 reflect (i) $3.4 million in earnings from the lease and
operations of the Triton Power Michigan facility, (ii) a $1.5 million property
tax settlement received in 2008, (iii) $0.3 million in earnings from the Snyder,
Texas operations and (iv) $0.5 million from other activities.
Seven
Months Ended December 31, 2007
Earnings
before DD&A for the seven months ended December 31, 2007 reflect the
positive impacts of (i) contributions of $2.0 million of earnings before
DD&A from our Jackson, Michigan facility, (ii) $8.0 million of equity
earnings from our investment in Thermo Cogeneration Partnership and (iii) $1.4
million of earnings from the Thermo Greeley facility associated with gas
purchase and sale agreements. These favorable impacts to earnings were partially
offset by an
56
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
unfavorable
impact to operating revenues associated with 2006 equipment sales.
Five
Months Ended May 31, 2007
Earnings
before DD&A for the five months ended May 31, 2007 reflect an unfavorable
impact to operating revenues associated with 2006 equipment sales. These
unfavorable impacts to earnings were partially offset by (i) contributions of
$1.3 million of earnings from our Jackson, Michigan facility, (ii) contributions
of $1.2 million of earnings from the Thermo Greeley facility associated with gas
purchase and sales agreements and (iii) our $5.1 million of equity earnings from
our investment in Thermo Cogeneration Partnership.
Year
Ended December 31, 2006
Earnings
before DD&A for the year ended December 31, 2006 reflects the positive
impacts of (i) contributions of $3.1 million of earnings before DD&A from
our Jackson, Michigan facility, (ii) $11.3 million of equity earnings from our
investment in Thermo Cogeneration Partnership and (iii) $4.2 million of earnings
from the Thermo Greeley facility associated with gas purchase and sale
agreements. These favorable impacts to earnings were partially offset by an
unfavorable impact to operating revenues associated with $1.9 million of
equipment sales.
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions, except operating statistics)
|
(In
millions, except operating statistics)
|
|||||||||||||||
|
Operating
Revenues
|
$
|
815.9
|
$
|
471.5
|
$
|
331.8
|
$
|
732.5
|
||||||||
|
Operating
Expenses
|
(291.0
|
)
|
(320.6
|
)
|
(116.4
|
)
|
(285.5
|
)
|
||||||||
|
Other
Income (Expense)
|
(3.0
|
)
|
0.8
|
(0.6
|
)
|
-
|
||||||||||
|
Goodwill
Impairment Charge1
|
(1,266.5
|
)
|
-
|
-
|
-
|
|||||||||||
|
Earnings
from Equity Investments
|
15.7
|
11.5
|
12.4
|
14.2
|
||||||||||||
|
Interest
Income and Other Income, Net
|
2.0
|
4.7
|
4.7
|
11.9
|
||||||||||||
|
Income
Taxes Benefit (Expense)
|
4.9
|
(5.4
|
)
|
(7.5
|
)
|
(5.2
|
)
|
|||||||||
|
Segment
Earnings (Loss) Before DD&A
|
$
|
(722.0
|
)
|
$
|
162.5
|
$
|
224.4
|
$
|
467.9
|
|||||||
|
Operating
Statistics
|
||||||||||||||||
|
Gasoline
(MMBbl)
|
398.4
|
252.7
|
182.8
|
449.8
|
||||||||||||
|
Diesel
Fuel (MMBbl)
|
157.9
|
97.5
|
66.6
|
158.2
|
||||||||||||
|
Jet
Fuel (MMBbl)
|
117.3
|
73.8
|
51.3
|
119.5
|
||||||||||||
|
Total
Refined Products Volumes (MMBbl)
|
673.6
|
424.0
|
300.7
|
727.5
|
||||||||||||
|
Natural
Gas Liquids (MMBbl)
|
27.3
|
16.7
|
13.7
|
34.0
|
||||||||||||
|
Total
Delivery Volumes (MMBbl)2
|
700.9
|
440.7
|
314.4
|
761.5
|
||||||||||||
____________
|
1
|
2008
amount represents a non-cash goodwill impairment charge; see Note 3 of the
accompanying Notes to Consolidated Financial
Statements.
|
|
2
|
Includes
Pacific operations, Plantation, Calnev, Central Florida, Cochin and
Cypress pipeline volumes.
|
57
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Earnings
Before DD&A by Major Segment Asset
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Pacific
Operations
|
$
|
233.6
|
$
|
(10.3
|
)
|
$
|
105.1
|
$
|
245.0
|
|||||||
|
Calnev
Pipeline
|
49.2
|
27.5
|
20.1
|
42.2
|
||||||||||||
|
West
Coast Terminals
|
50.7
|
24.3
|
19.3
|
36.3
|
||||||||||||
|
Plantation
Pipeline
|
37.1
|
22.2
|
18.2
|
28.4
|
||||||||||||
|
Central
Florida Pipeline
|
41.1
|
21.9
|
15.3
|
31.4
|
||||||||||||
|
Cochin
Pipeline System
|
46.7
|
30.6
|
15.3
|
14.1
|
||||||||||||
|
Southeast
Terminals
|
51.6
|
24.8
|
16.6
|
37.5
|
||||||||||||
|
Transmix
Operations
|
29.8
|
18.3
|
12.4
|
28.4
|
||||||||||||
|
Goodwill
Impairment Charge
|
(1,266.5
|
)
|
-
|
-
|
-
|
|||||||||||
|
All
Other
|
4.7
|
3.2
|
2.1
|
4.6
|
||||||||||||
|
Segment
Earnings (Loss) Before DD&A
|
$
|
(722.0
|
)
|
$
|
162.5
|
$
|
224.4
|
$
|
467.9
|
|||||||
Revenues
by Major Segment Asset
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Pacific
Operations
|
$
|
374.6
|
$
|
224.4
|
$
|
156.0
|
$
|
362.0
|
||||||||
|
Calnev
Pipeline
|
71.4
|
41.9
|
27.7
|
66.2
|
||||||||||||
|
West
Coast Terminals
|
79.5
|
42.9
|
29.1
|
64.5
|
||||||||||||
|
Plantation
Pipeline
|
44.0
|
24.6
|
17.6
|
41.2
|
||||||||||||
|
Central
Florida Pipeline
|
52.4
|
27.1
|
19.3
|
43.1
|
||||||||||||
|
Cochin
Pipeline System
|
63.3
|
42.6
|
32.3
|
35.7
|
||||||||||||
|
Southeast
Terminals
|
81.9
|
38.4
|
29.9
|
81.1
|
||||||||||||
|
Transmix
Operations
|
42.4
|
25.8
|
17.5
|
32.8
|
||||||||||||
|
All
Other (Including Eliminations)
|
6.4
|
3.8
|
2.4
|
5.9
|
||||||||||||
|
Total
Segment Operating Revenues
|
$
|
815.9
|
$
|
471.5
|
$
|
331.8
|
$
|
732.5
|
||||||||
Year
Ended December 31, 2008
Earnings
before DD&A were positively affected by strong earnings for the Southeast
terminals, Cochin Pipeline, Central Florida Pipeline and West Coast Terminals
operations that were principally from (i) favorable margins on liquids inventory
sales, (ii) incremental terminal throughput and storage activity, (iii) solid
demand for ethanol and (iv) incremental returns from the completion of a number
of capital expansion projects that modified and upgraded terminal
infrastructure, enabling Kinder Morgan Energy Partners to provide additional
ethanol-related services to its customers. The Central Florida Pipeline also
benefited from strong product delivery revenues, driven by an increase in the
average tariff per barrel moved as a result of a mid-year 2007 tariff rate
increase on product deliveries. The Cochin Pipeline also benefited from a
year-end 2008 reduction in income tax expense, related to lower Canadian
operating results in 2008 and from Canadian income tax liability adjustments.
The decrease in income tax expense more than offset the drop in operating
revenues.
Earnings
before DD&A were adversely affected by (i) a $1,266.5 million goodwill
impairment charge, (ii) $20.0 million for charges, net of tax related to
settlement of certain litigation matters or environmental liability adjustments,
mostly related to Pacific operations’ East Line pipeline and (iii) Pacific
operations expenses for major maintenance and pipeline integrity
expenses.
Seven
Months Ended December 31, 2007
The
results for the seven months were negatively impacted by $154.9 million of legal
liability adjustments primarily associated with the Pacific operations.
Offsetting the charges, earnings before DD&A for this segment were
positively affected by (i) approximately $15.4 million associated with Kinder
Morgan Energy Partners’ January 1, 2007 acquisition of
58
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
the
remaining ownership interest in Cochin (approximately 50.2%) that it did not
already own, at which time Kinder Morgan Energy Partners became the pipeline
operator, (ii) strong pipeline revenues from the Plantation Pipeline for the
period, largely due to favorable oil loss allowance tariff rates, relative to
pipeline operating expenses that included only minor pipeline integrity
expenses, (iii) favorable margins and strong mainline delivery volumes from the
2006 East Line pipeline expansion and demand from West Coast military bases
within the Pacific operations, (iv) military and commercial tariff rate
increases in 2007 on the Calnev Pipeline, (v) strong demand for terminal
services at the Carson/Los Angeles Harbor terminal system, recently expanded in
2006, and the Linnton and Willbridge terminals located in Portland, Oregon,
included in the West Coast Terminals operations, (vi) $4.8 million of earnings
before DD&A and $5.7 million of revenue generated by the Kinder Morgan
Energy Partners’ approximate $11 million Greensboro facility, placed in service
in 2006, which is used for petroleum pipeline transmix operations and (vii) the
West Coast Terminals operation’s $3.6 million gain on the sale of its interest
in the Black Oil pipeline system in Los Angeles, California in June
2007.
Five
Months Ended May 31, 2007
The
results for the five months were negatively impacted by a $2.2 million expense
associated with Pacific operations’ East Line pipeline legal liability
adjustments. Earnings before DD&A were positively affected by (i)
approximately $7.7 million associated with Kinder Morgan Energy Partners’
January 1, 2007 acquisition of the remaining ownership interest in Cochin
(approximately 50.2%) that it did not already own, at which time Kinder Morgan
Energy Partners became the pipeline operator, (ii) an increase in average tariff
rates and mainline delivery from the 2006 expansion of the East Line pipeline
within the Pacific operations and demand from West Coast military bases, which
contributed to the Pacific operations’ revenues and earnings, (iii) strong
demand for throughput volumes at the combined Carson/Los Angeles Harbor terminal
system and the Linnton and Willbridge terminals located in Portland, Oregon, for
the West Coast Terminals operations and (iv) $2.8 million of earnings before
DD&A and $3.3 million of revenue generated by the Kinder Morgan Energy
Partners’ Greensboro facility discussed above.
Year
Ended December 31, 2006
Earnings
before DD&A for 2006 were positively impacted by (i) contributions from the
Pacific operations and the Calnev operations with solid refined products
deliveries and terminal and other fee revenues that more than offset operating
costs for the period which were affected by high fuel and power expenses, (ii)
positive performance from the Southeast Terminals products operations with
strong demand for liquids throughput volumes at favorable rates and optimal
margins on ethanol blending and sales activities and (iii) solid product
delivery revenues in 2006 from other segment assets driven by Central Florida
Pipeline’s increased average tariff and terminal rates during the
period.
Partially
offsetting these positive factors in 2006 were (i) $13.5 million of legal
liability adjustments associated with the Pacific operations, (ii) incremental
pipeline maintenance expenses recognized in the last half of the year, (iii)
$6.2 million of environmental expenses recognized by the West Coast Terminals
operations in 2006 and (iv) $3.0 million of environmental liability adjustments
(net of tax benefits) on the Plantation Pipe Line Company. Beginning in the
third quarter of 2006, the refined petroleum products pipelines and associated
terminal operations included within the Products Pipelines–KMP segment
(including Plantation Pipe Line Company, the 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.
Combined, this change reduced the segment’s earnings before DD&A 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.
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. The pipeline integrity program is designed to provide management with
the information needed to effectively allocate resources for appropriate
prevention, detection and mitigation activities.
Contributing
to the total delivery volumes of refined petroleum products were (i) the East
Line expansion, which was in service for the last seven months of 2006 and
substantially increased pipeline capacity from El Paso, Texas to Tucson and
Phoenix, Arizona and (ii) strong demand from the Southern California and Las
Vegas, Nevada markets on the Calnev Pipeline. Partially offsetting these factors
was shortened demand for throughput volumes on Plantation Pipeline, which was
impacted by a competing pipeline that began service in mid-2006.
Other
Products Pipelines – KMP Segment Events
Effective
October 5, 2007, Kinder Morgan Energy Partners sold its North System common
carrier natural gas liquids pipeline and its 50% ownership interest in the
Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7
million in cash, and used the proceeds received to pay down short-term debt
borrowings. The North System business results of operations are not included in
the tables and discussion above and have been classified to Discontinued
Operations on the accompanying Statements of Operations for the seven months
ended December 31, 2007, five months ended May 31, 2007
59
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
and
year ended December 31, 2006.
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions, except operating statistics)
|
(In
millions, except operating statistics)
|
|||||||||||||||
|
Operating
Revenues
|
$
|
8,422.0
|
$
|
3,825.9
|
$
|
2,640.6
|
$
|
6,577.7
|
||||||||
|
Operating
Expenses
|
(7,803.3
|
)
|
(3,461.4
|
)
|
(2,418.5
|
)
|
(6,057.8
|
)
|
||||||||
|
Other
Income (Expense)
|
0.2
|
1.9
|
(0.1
|
)
|
15.1
|
|||||||||||
|
Goodwill
Impairment Charge1
|
(2,090.2
|
)
|
-
|
-
|
||||||||||||
|
Earnings
from Equity Investments
|
113.4
|
10.3
|
8.9
|
40.5
|
||||||||||||
|
Interest
Income and Other Income, Net
|
16.3
|
-
|
0.2
|
0.7
|
||||||||||||
|
Income
Taxes
|
(2.7
|
)
|
(3.4
|
)
|
(2.6
|
)
|
(1.4
|
)
|
||||||||
|
Segment
Earnings (Loss) Before DD&A
|
$
|
(1,344.3
|
)
|
$
|
373.3
|
$
|
228.5
|
$
|
574.8
|
|||||||
|
|
||||||||||||||||
|
Operating
Statistics
|
||||||||||||||||
|
Natural
Gas Transport Volumes (Trillion Btus)2
|
2,156.3
|
1,067.0
|
645.6
|
1,440.9
|
||||||||||||
|
Natural
Gas Sales Volumes (Trillion Btus)3
|
866.9
|
519.7
|
345.8
|
909.3
|
||||||||||||
__________
|
1
|
2008
amount represents a non-cash goodwill impairment charge; see Note 3 of the
accompanying Notes to Consolidated Financial
Statements.
|
|
2
|
Includes
Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline
Company LLC, TransColorado Gas Transmission Company LLC, Rockies Express
Pipeline LLC and Texas Intrastate Natural Gas Pipeline Group pipeline
volumes.
|
|
3
|
Represents
Texas Intrastate Natural Gas Pipeline Group
volumes.
|
Earnings
Before DD&A by Major Segment Asset
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Texas
Intrastate Natural Gas Pipeline Group
|
$
|
385.6
|
$
|
221.1
|
$
|
133.0
|
$
|
305.5
|
||||||||
|
Kinder
Morgan Interstate Gas Transmission
|
114.4
|
65.7
|
43.1
|
107.4
|
||||||||||||
|
Trailblazer
Pipeline
|
44.4
|
31.9
|
18.1
|
50.8
|
||||||||||||
|
TransColorado
Pipeline
|
55.0
|
25.7
|
17.9
|
43.1
|
||||||||||||
|
Rockies
Express Pipeline
|
84.4
|
(8.3
|
)
|
(4.3
|
)
|
-
|
||||||||||
|
Kinder
Morgan Louisiana Pipeline
|
11.3
|
-
|
-
|
-
|
||||||||||||
|
Casper
and Douglas Gas Processing
|
20.0
|
18.0
|
7.3
|
29.3
|
||||||||||||
|
Goodwill
Impairment Charge
|
(2,090.2
|
)
|
-
|
-
|
-
|
|||||||||||
|
All
Others
|
30.8
|
19.2
|
13.4
|
38.7
|
||||||||||||
|
Segment
Earnings (Loss) Before DD&A
|
$
|
(1,344.3
|
)
|
$
|
373.3
|
$
|
228.5
|
$
|
574.8
|
|||||||
60
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Revenues
by Major Segment Asset
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Texas
Intrastate Natural Gas Pipeline Group
|
$
|
7,979.4
|
$
|
3,562.0
|
$
|
2,492.4
|
$
|
6,196.6
|
||||||||
|
Kinder
Morgan Interstate Gas Transmission
|
199.5
|
130.7
|
70.7
|
183.6
|
||||||||||||
|
Trailblazer
Pipeline
|
53.9
|
36.4
|
22.6
|
50.1
|
||||||||||||
|
TransColorado
Pipeline
|
63.5
|
30.3
|
20.7
|
47.9
|
||||||||||||
|
Rockies
Express Pipeline
|
-
|
-
|
-
|
0.7
|
||||||||||||
|
Casper
and Douglas Gas Processing
|
126.3
|
67.1
|
34.7
|
96.2
|
||||||||||||
|
All
Others
|
3.0
|
0.2
|
-
|
4.1
|
||||||||||||
|
Eliminations
|
(3.6
|
)
|
(0.8
|
)
|
(0.5
|
)
|
(1.5
|
)
|
||||||||
|
Segment
Revenues
|
$
|
8,422.0
|
$
|
3,825.9
|
$
|
2,640.6
|
$
|
6,577.7
|
||||||||
Year
Ended December 31, 2008
The
Natural Gas Pipelines–KMP segment’s earnings before DD&A in the year ended
December 31, 2008 were driven by (i) a strong performance by the Texas
Intrastate Natural Gas Pipeline Group due to (a) higher natural gas sales
margins, (b) increased transportation service revenues due to long-term contract
with a major customer that became effective April 1, 2007 and (c) greater
natural gas processing revenues, (ii) contributions from Kinder Morgan Energy
Partners’ 51% ownership interest in the Rockies Express Pipeline LLC, whose
Rockies Express-West pipeline segment became fully operational in May 2008,
(iii) a strong performance from the TransColorado Pipeline primarily due to
contract improvements and expansions completed since the end of the third
quarter of 2007, (iv) strong performance from the Kinder Morgan Interstate Gas
Transmission system (“KMIGT”) primarily due to decreased electricity used and
lower negotiated rates, lower natural gas purchase costs and lower tax expenses
payable to the state of Texas in 2008. Also, in October 2008, KMIGT completed
construction on an approximately $22 million expansion project that provides for
the delivery of natural gas to five separate industrial plants (four of which
produce ethanol) located near Grand Island, Nebraska. The project is fully
subscribed with long-term customer contracts; and (v) earnings from the Kinder
Morgan Louisiana Pipeline that benefited from FERC regulations governing
allowances for capital funds that are used for pipeline construction costs (an
equity cost of capital allowance).
Offsetting
the above positive impacts to the segment’s earnings before DD&A were the
following: (i) a $2,090.2 million goodwill impairment charge, (ii) the Casper
and Douglas gas processing operations were adversely affected by higher natural
gas purchase costs, due to increases in both prices and volumes, which more than
offset revenue increases resulting from both higher average prices on natural
gas liquids sales and higher revenues from sales of excess natural gas and (iii)
the Trailblazer Pipeline’s earnings were affected by lower revenues from both
natural gas transportation services and sales of excess natural
gas.
Seven
Months Ended December 31, 2007
Earnings
before DD&A in the seven months ended December 31, 2007 were also positively
affected by (i) strong performances by the Texas Intrastate Pipeline group due
to (a) favorable natural gas sales margins on renewal contracts, (b) increased
transportation service revenue due to a new long-term contract with a major
customer that became effective April 1, 2007, (c) greater value from natural gas
storage activities and natural gas processing margins, (d) sales of cushion gas
due to the termination of a storage facility lease and (e) storage revenues from
transportation and storage under a new long term contract with a major customer
that became effective April 1,2007, (ii) strong performance from KMIGT,
Trailblazer Pipeline and TransColorado Pipeline due mainly to solid earnings
from transportation and natural gas park and loan services and (iii) earnings
from Casper and Douglas gas processing operations that had solid natural gas
liquids sales revenues driven by favorable prices and volumes.
Adversely
affecting earnings before DD&A in the seven months ended December 31, 2007
was Kinder Morgan Energy Partners’ share of net losses from its equity
investment in Rockies Express Pipeline LLC due to depreciation and interest
expenses allocable to a segment of this project that was placed in service in
February 2007, and until the completion of the Rockies Express-West project
which became fully operational in May 2008, generated only limited natural gas
reservation revenues and volumes. See Note 19 of the accompanying Notes to
Consolidated Financial Statements for additional information on the Rockies
Express Pipeline project.
61
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Five
Months Ended May 31, 2007
Earnings
before DD&A in the five months ended May 31, 2007 were positively affected
by (i) strong performances by the Texas Intrastate Natural Gas Pipeline Group
due to (a) favorable natural gas sales margins on renewal and incremental
contracts, (b) strong demand for and favorable rates on transportation services,
(c) greater value from natural gas storage activities and natural gas processing
margins, (d) sales of cushion gas due to the termination of a storage facility
lease and (e) storage revenues from a new long-term contract with a major
customer that became effective April 1, 2007, (ii) strong performance from
KMIGT, Trailblazer Pipeline and TransColorado Pipeline due mainly to solid
earnings from transportation and natural gas park and loan services and (iii)
earnings from Casper and Douglas gas processing operations that had solid
natural gas liquids sales revenues driven by favorable prices and
volumes.
Rockies
Express Pipeline LLC operations adversely affected earnings before DD&A by
$4.3 million for the five months ended May 31, 2007 as depreciation and interest
expenses were in excess of gross profits realized on limited natural gas
reservation revenues and volumes, as discussed above in the Seven Months Ended December 31,
2007 discussion.
Year
Ended December 31, 2006
Combined,
gains on sales of gas processing facilities and the revaluation of purchase/sale
contracts increased earnings before DD&A by $21.4 million in the year ended
December 31, 2006. Earnings before DD&A in 2006 were also positively
impacted by (i) a strong revenue stream with favorable imbalance resolution from
the Texas Intrastate Natural Gas Pipeline Group, (ii) revenues earned in 2006
from both operational sales of natural gas and natural gas park and loan
services by KMIGT, (iii) natural gas transmission revenues earned by
TransColorado Pipeline, chiefly related to strong natural gas delivery volumes
resulting from both system improvements and the successful negotiation of
incremental firm transportation contracts and (iv) increased prices during the
period on incremental sales of excess fuel gas and strong natural gas gathering
revenues from the 49% equity investment in the Red Cedar Gathering Company
within the “All Others” assets group in the tables above.
KMIGT’s
operational gas sales are primarily made possible by its collection of fuel
in-kind pursuant to its transportation tariffs and recovery of storage cushion
gas volumes. The TransColorado Pipeline system improvements were associated with
a 2005 expansion on the northern portion of the pipeline.
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions, except operating statistics)
|
(In
millions, except operating statistics)
|
|||||||||||||||
|
Operating
Revenues
|
$
|
1,269.2
|
$
|
605.9
|
$
|
324.2
|
$
|
736.5
|
||||||||
|
Operating
Expenses
|
(391.8
|
)
|
(182.7
|
)
|
(121.5
|
)
|
(268.1
|
)
|
||||||||
|
Earnings
from Equity Investments
|
20.7
|
10.5
|
8.7
|
19.2
|
||||||||||||
|
Other
Income (Expense), Net
|
1.9
|
0.1
|
(0.1
|
)
|
0.8
|
|||||||||||
|
Income
Taxes
|
(3.9
|
)
|
(0.8
|
)
|
(1.3
|
)
|
(0.2
|
)
|
||||||||
|
Segment
Earnings Before DD&A
|
$
|
896.1
|
$
|
433.0
|
$
|
210.0
|
$
|
488.2
|
||||||||
|
|
||||||||||||||||
|
Operating
Statistics
|
||||||||||||||||
|
Carbon
Dioxide Delivery Volumes (Bcf)1
|
732.1
|
365.0
|
272.3
|
669.2
|
||||||||||||
|
SACROC
Oil Production (Gross)(MBbl/d)2
|
28.0
|
26.5
|
29.1
|
30.8
|
||||||||||||
|
SACROC
Oil Production (Net)(MBbl/d)3
|
23.3
|
22.1
|
24.2
|
25.7
|
||||||||||||
|
Yates
Oil Production (Gross)(MBbl/d)2
|
27.6
|
27.4
|
26.4
|
26.1
|
||||||||||||
|
Yates
Oil Production (Net)(MBbl/d)3
|
12.3
|
12.2
|
11.7
|
11.6
|
||||||||||||
|
Natural
Gas Liquids Sales Volumes (Net)(MBbl/d)3
|
8.4
|
9.5
|
9.7
|
8.9
|
||||||||||||
|
Realized
Weighted-average Oil Price per Bbl4,5
|
$
|
49.42
|
$
|
36.80
|
$
|
35.03
|
$
|
31.42
|
||||||||
|
Realized
Weighted-average Natural Gas Liquids Price per Bbl5,6
|
$
|
63.00
|
$
|
58.55
|
$
|
45.04
|
$
|
43.90
|
||||||||
__________
|
1
|
Includes
Cortez, Central Basin, Canyon Reef Carriers, Centerline and Pecos pipeline
volumes.
|
|
2
|
Represents
100% of the production from the field. Kinder Morgan Energy Partners owns
an approximate 97% working interest in the SACROC unit and an approximate
50% working interest in the Yates
unit.
|
|
3
|
Net
to Kinder Morgan Energy Partners, after royalties and outside working
interests.
|
|
4
|
Includes
all Kinder Morgan Energy Partners crude oil production
properties.
|
62
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
5
|
Hedge
gains/losses for crude oil and natural gas liquids are included with crude
oil.
|
|
6
|
Includes
production attributable to leasehold ownership and production attributable
to Kinder Morgan Energy Partners’ ownership in processing plants and
third-party processing agreements.
|
Because
the CO2–KMP
segment is exposed to commodity price risk related to the price volatility of
crude oil and natural gas liquids, it mitigates this risk through a long-term
hedging strategy that is intended to generate more stable realized prices by
using derivative contracts as hedges to the exposure of fluctuating expected
future cash flows produced by changes in commodity sales prices. All of the
hedge gains and losses for crude oil and natural gas liquids are included in the
realized weighted average price for oil. Had energy derivative contracts not
been used to transfer commodity price risk, crude oil sales prices would have
averaged $97.70 per barrel in 2008, $78.65 per barrel in the seven months ended
December 31, 2007, $57.43 per barrel in the five months ended May 31, 2007 and
$63.27 per barrel in 2006. For more information on hedging activities, see Note
15 of the accompanying Notes to Consolidated Financial Statements.
Additionally,
the decline in crude oil production at the SACROC field unit in the seven months
ended December 31, 2007, five months ended May 31, 2007 and year ended December
31, 2006 is attributable to lower observed recoveries from recent project areas
and an intentional slow down in development pace given this reduction in
recoveries. For more information on Kinder Morgan Energy Partners’ ownership
interests in the net quantities of proved oil and gas reserves and its measures
of discounted future net cash flows from oil and gas reserves, please see the
caption titled “Supplemental Information on Oil and Gas Producing Activities
(Unaudited)” in the Financial Statements and Supplementary Data included in Item
8 of this report.
Earnings
Before DD&A by Major Segment Activities
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Sales
and Transportation
|
$
|
301.0
|
$
|
110.4
|
$
|
67.2
|
$
|
186.8
|
||||||||
|
Oil
and Gas Production
|
595.1
|
322.6
|
142.8
|
301.4
|
||||||||||||
|
Segment
Earnings Before DD&A
|
$
|
896.1
|
$
|
433.0
|
$
|
210.0
|
$
|
488.2
|
||||||||
Revenues
by Major Segment Activities
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Sales
and Transportation
|
$
|
334.7
|
$
|
116.1
|
$
|
71.3
|
$
|
196.3
|
||||||||
|
Oil
and Gas Production
|
1,019.2
|
518.7
|
271.7
|
601.0
|
||||||||||||
|
Eliminations
|
(84.7
|
)
|
(28.9
|
)
|
(18.8
|
)
|
(60.8
|
)
|
||||||||
|
Total
Segment Operating Revenues
|
$
|
1,269.2
|
$
|
605.9
|
$
|
324.2
|
$
|
736.5
|
||||||||
Year
Ended December 31, 2008
The
CO2–KMP
segment’s earnings before DD&A in the year ended December 31, 2008 were
positively affected by the realization of higher market and hedge prices for the
sale of its crude oil, natural gas products and CO2 and an
expansion project completed in its sales and transportation business, which
increased CO2 delivery
volumes. Another positive impact on the period’s earnings before DD&A of
$136.3 million resulted from valuation adjustments related to derivative
contracts on crude oil hedges in place at the time of the Going Private
transaction and recorded in the application of the purchase method of
accounting.
Earnings
for the segment’s sales and transportation activities were positively impacted
by factors affecting carbon dioxide sales revenues (both price and volume
related) and carbon dioxide and crude oil pipeline transportation revenues.
Transportation revenues were impacted by increased carbon dioxide delivery
volume due to rising customer demand for carbon dioxide for use in oil recovery
projects throughout the Permian Basin. Another positive impact during 2008 in
carbon dioxide sales and delivery volumes was the January 17, 2008 start-up of
the Doe Canyon Deep unit carbon dioxide source field located in Dolores County,
Colorado. Kinder Morgan Energy Partners holds an approximately 87% working
interest in
63
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
the
Doe Canyon Deep unit.
With
respect to crude oil, overall sales volumes were essentially flat, but the
segment benefited from an increase in its realized weighted-average price per
barrel. With respect to natural gas liquids, a decrease in sales volumes was
more than offset by increases in its realized weighted-average price per barrel.
Sales volumes were adversely affected by Hurricane Ike, which resulted in
pro-rationing (production allocation).
Seven
Months Ended December 31, 2007
For
the seven months ended December 31, 2007, SACROC’s gross production averaged
26.5 thousand barrels per day and Yates’ gross production averaged 27.4 thousand
barrels per day. SACROC contributed approximately 56% of earnings before
DD&A for the total oil and gas producing activities. The earnings before
DD&A in the seven months ended December 31, 2007 were positively affected by
(i) strong average crude oil and natural gas plant product prices, (ii) strong
oil production at the Yates field unit and (iii) a favorable realized
weighted-average price per barrel in the SACROC field unit gas processing
operations. The period’s results were also positively affected by valuation
adjustments of $106.0 million for derivative contracts on crude oil hedges as
described above in the Year
Ended December 31, 2008 discussion.
Partially
offsetting these factors was a reduced average carbon dioxide realized sales
price resulting from the December 2006 expiration of a large volume high-priced
sales contract.
With
respect to crude oil, overall sales volumes were stable, but the segment
benefited from a strong realized weighted-average price per barrel. With respect
to natural gas liquids, low sales volumes were more than offset by a favorable
realized weighted-average price per barrel.
Five
Months Ended May 31, 2007
The
segment’s sales and transportation activities were adversely affected by a
decrease in average carbon dioxide prices. A significant portion of the decrease
in average carbon dioxide prices is timing related, as some of the segment’s
carbon dioxide contracts are tied to crude oil prices in prior periods, and the
2007 contracts had been tied to lower crude oil prices, relative to 2006. These
decreases in carbon dioxide prices were only partially offset by slightly higher
carbon dioxide sales volumes related to increased carbon dioxide production from
the McElmo Dome source field.
Highlights
surrounding oil and gas producing activities for the five months ended May 31,
2007 include (i) increases in oil production at the Yates field unit, (ii)
favorable weighted-average price per barrel and (iii) solid earnings from
natural gas liquids sales volumes and prices, largely due to increased
recoveries at the SACROC gas processing operations.
Year
Ended December 31, 2006
Earnings
before DD&A in 2006 were driven by strong earnings from carbon dioxide sales
and transportation activities, largely due to solid revenues—from both carbon
dioxide sales and deliveries, and from crude oil pipeline transportation,
despite only modest earnings from oil and gas producing activities and equity
earnings from the segment’s 50% ownership interest in Cortez Pipeline Company.
Earnings from oil and gas producing activities were positively impacted during
the period primarily by rising realized sales prices and partly from increased
crude oil production at the Yates field unit, however partially offsetting these
factors were increased operating and maintenance expenses (including well
workover expenses), property and severance taxes, and fuel and power
expenses.
64
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions, except operating statistics)
|
(In
millions, except operating statistics)
|
|||||||||||||||
|
Operating
Revenues
|
$
|
1,173.6
|
$
|
599.2
|
$
|
364.5
|
$
|
864.8
|
||||||||
|
Operating
Expenses
|
(631.8
|
)
|
(344.2
|
)
|
(192.2
|
)
|
(461.9
|
)
|
||||||||
|
Other
Income (Expense)
|
(6.4
|
)
|
3.3
|
3.0
|
15.2
|
|||||||||||
|
Goodwill
Impairment Charge1
|
(676.6
|
)
|
-
|
-
|
-
|
|||||||||||
|
Earnings
from Equity Investments
|
2.7
|
0.6
|
-
|
0.2
|
||||||||||||
|
Interest
Income and Other Income, Net
|
1.7
|
0.7
|
0.3
|
2.1
|
||||||||||||
|
Income
Taxes
|
(19.7
|
)
|
(15.9
|
)
|
(3.3
|
)
|
(12.3
|
)
|
||||||||
|
Segment
Earnings (Loss) Before DD&A
|
$
|
(156.5
|
)
|
$
|
243.7
|
$
|
172.3
|
$
|
408.1
|
|||||||
|
|
||||||||||||||||
|
Operating
Statistics
|
||||||||||||||||
|
Bulk
Transload Tonnage (MMtons)2
|
99.1
|
62.5
|
33.7
|
95.1
|
||||||||||||
|
Liquids
Leaseable Capacity (MMBbl)
|
54.2
|
47.5
|
43.6
|
43.5
|
||||||||||||
|
Liquids
Utilization %3
|
97.5
|
%
|
95.9
|
%
|
97.5
|
%
|
96.3
|
%
|
||||||||
__________
|
2008
amounts include a non-cash goodwill impairment charge; see Note 3 of the
accompanying Notes to Consolidated Financial
Statements.
|
|
2
|
Volumes
for acquired terminals are included for all
periods.
|
|
3
|
Represents
percentage of utilized available terminal storage
capacity.
|
Kinder
Morgan Energy Partners earnings have benefited from the incremental
contributions attributable to the bulk and liquids terminal businesses it has
built or acquired between 2005 and 2008. These transactions have included (among
others):
|
|
·
|
the
Texas Petcoke terminals acquisition on April 29,
2005;
|
|
|
·
|
three
separate terminals located in New York, Kentucky and Arkansas, which were
acquired in July 2005;
|
|
|
·
|
the
purchase of all of the ownership interests in General Stevedores, L.P. on
July 31, 2005;
|
|
|
·
|
the
acquisition of the Kinder Morgan Blackhawk terminal located in Black Hawk
County, Iowa, in August 2005;
|
|
|
·
|
the
September 2005 purchase of a terminal-related repair shop located in
Jefferson County, Texas;
|
|
|
·
|
three
terminal operations, which were 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;
|
|
|
·
|
all
of the membership interests of Transload Services, LLC, which were
acquired on November 20, 2006;
|
|
|
·
|
all
of the membership interests of Devco USA L.L.C., which were purchased on
December 1, 2006;
|
|
|
·
|
the
Vancouver Wharves bulk marine terminals, acquired on May 30,
2007;
|
|
|
·
|
the
terminal assets from Marine Terminals, Inc., purchased on September 1,
2007;
|
|
|
·
|
Phase
III expansions completed and put into service at the Pasadena and Galena
Park, Texas liquids terminal facilities in the first quarter of
2008;
|
|
|
·
|
nine
new storage tanks at the Perth Amboy, New Jersey liquids terminal, which
were completed and put into service in the first quarter of
2008;
|
|
|
·
|
a
barge unloading terminal located on 30 acres in Columbus, Mississippi,
completed and put into service in the first quarter of
2008;
|
|
|
·
|
our
Pier X expansion at our bulk handling facility located in Newport News,
Virginia, completed and put into service in the first quarter of
2008;
|
|
|
·
|
the
approximately 2.15 million barrels of new crude oil capacity at the Kinder
Morgan North 40 terminal located near Edmonton, Alberta, Canada, which was
completed and put into service in the second quarter of
2008;
|
|
|
·
|
the
approximately 320,000 barrels of additional gasoline capacity at the
Shipyard River Terminal located in Charleston, South Carolina, which was
completed and put into service in the third quarter of
2008;
|
|
|
·
|
the
Kinder Morgan Wilmington terminal, purchased on August 15, 2008;
and
|
|
|
·
|
the
acquisition of certain terminal assets from LPC Packaging on October 2,
2008.
|
Year
Ended December 31, 2008
Segment
earnings before DD&A were positively
affected by improved performance from existing assets such as $57.2 million of
total 2008 earnings before DD&A from the Texas Petcoke terminal operations
and assets acquired or expanded in
65
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
the
last eighteen months including (i) $8.3 million from the Vancouver Wharves bulk
marine terminal, (ii) $22.1 million from Marine Terminals, Inc. and other
acquired operations, (iii) $139.0 million from Kinder Morgan Energy Partners’
Gulf Coast terminals, primarily from its two expanded large liquids terminal
facilities located along the Houston Ship Channel in Pasadena and Galena Park,
Texas, (iv) $60.9 million from the Mid-Atlantic terminals, including strong coal
transfer volumes primarily from its Pier IX bulk terminal (including earnings
from the first quarter 2008 completion of construction of a new ship dock and
installation of added terminal equipment) located in Newport News, Virginia and
its Fairless Hills, Pennsylvania bulk terminal that began operations in the
second quarter of 2008 with a new import fertilizer facility, (v) $30.5 million
from the Western terminals, primarily from its recently completed North 40
terminal and (vi) $74.2 million from the Northeast terminals, primarily from its
Perth Amboy, New Jersey liquids terminal, located in the New York Harbor area,
driven by liquids throughput volumes as a result of an expansion completed at
the end of the first quarter of 2008.
Segment
earnings before DD&A for this period were adversely impacted by (i) a $676.6
million goodwill impairment charge and (ii) $12.9 million in hurricane and fire
damage clean-up, repair and write-offs, net of income tax benefit.
Seven
Months Ended December 31, 2007
Combined,
the operations acquired in 2006 and 2007 referred to above contributed earnings
before DD&A of $28.4 million, revenues of $73.3 million, operating expenses
of $45.4 million and equity earnings of $0.5 million in the seven months ended
December 31, 2007. This segment’s earnings benefited from the two large Gulf
Coast liquids terminal facilities located along the Houston Ship Channel in
Pasadena and Galena Park, Texas, which contributed $18.1 million of combined
earnings before DD&A. The two terminals continued to benefit from both
recent expansions that have added new liquids tank and truck loading rack
capacity since 2006 and business from ethanol and biodiesel storage and transfer
activity. Strong earnings during the period also resulted from (i) $12.1 million
of earnings before DD&A contributed from the combined operations of the Argo
and Chicago, Illinois liquids terminals, due to strong ethanol throughput and
increased capacity in the liquids storage and handling business, (ii) $30.9
million of earnings before DD&A contributed from the Texas Petcoke
terminals, due largely to strong demand for petroleum coke at the Port of
Houston facility and (iii) $5.5 million of earnings before DD&A contributed
from the Pier IX bulk terminal, located in Newport News, Virginia, largely due
to a favorable demand for coal transfers and increasing rail
incentives.
Five
Months Ended May 31, 2007
Acquisitions
in 2006 and 2007 as described above contributed $2.8 million in earnings before
DD&A during the five months ended May 31, 2007 were composed of (i) $2.0
million from Transload Services, LLC and (ii) $0.8 million from Devco USA L.L.C.
Segment earnings before DD&A also included strong earnings contributions
consisting of (i) $5.9 million from Kinder Morgan Energy Partners’ Shipyard
River terminal located in Charleston, South Carolina; (ii) $17.3 million from
the Lower Mississippi (Louisiana) terminals (which include its 66 2/3% ownership
interest in the International Marine Terminals partnership and the Port of New
Orleans liquids facility located in Harvey, Louisiana) and (iii) $7.8 million
from the combined operations of its Argo and Chicago, Illinois liquids
terminals. The increases from the Shipyard River terminal related to completed
expansion projects since the middle of 2006 that increased handling capacity for
imported coal volumes and the earnings increases from the Chicago liquids
facilities were driven by higher revenues, due to increased ethanol throughput
and incremental liquids storage and handling business.
Year
Ended December 31, 2006
Combined,
the terminal acquisitions in 2005 and 2006, mentioned above, accounted for
incremental amounts of earnings before DD&A 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 were
attributable to the inclusion of the Texas petcoke terminals, which were
acquired from Trans-Global Solutions, Inc. on April 29, 2005.
The
segment’s earnings before DD&A also benefited from (i) a solid revenue
stream from the Pasadena and Galena Park Gulf Coast liquids terminals, driven by
new and incremental customer agreements, additional liquids tank capacity from
capital expansions completed at the Pasadena terminal since the end of 2005,
increased truck loading rack service fees during the period, strong demand from
ethanol throughput and revenues from customer deficiency charges, (ii) strong
revenues from liquids warehousing and coal and cement handling at the Shipyard
River terminal, located in Charleston, South Carolina, (iii) strong demand for
petroleum coke handling from the Texas Petcoke terminals and (iv) contributions
from the Lower Mississippi River (Louisiana) terminals, primarily due to
incremental earnings from the Amory and DeLisle Mississippi bulk terminals. The
Amory terminal began operations in July 2005. The earnings from the DeLisle
terminal resulted from solid bulk transfer revenues in 2006.
66
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions, except operating statistics)
|
(In
millions, except operating statistics)
|
|||||||||||||||
|
Operating
Revenues
|
$
|
198.9
|
$
|
100.9
|
$
|
62.0
|
$
|
140.8
|
||||||||
|
Operating
Expenses
|
(68.0
|
)
|
(44.3
|
)
|
(23.1
|
)
|
(54.9
|
)
|
||||||||
|
Earnings
from Equity Investment
|
8.3
|
14.4
|
5.4
|
17.2
|
||||||||||||
|
Other
Income (Expense)1
|
-
|
-
|
(377.1
|
)
|
0.9
|
|||||||||||
|
Interest
Income and Other Income (Expense), Net2
|
(6.2
|
)
|
6.3
|
1.7
|
1.0
|
|||||||||||
|
Income
Tax Benefit (Expense)3
|
19.0
|
(18.5
|
)
|
(0.9
|
)
|
(9.9
|
)
|
|||||||||
|
Segment
Earnings (Loss) Before DD&A
|
$
|
152.0
|
$
|
58.8
|
$
|
(332.0
|
)
|
$
|
95.1
|
|||||||
|
|
||||||||||||||||
|
Operating
Statistics
|
||||||||||||||||
|
Transport
Volumes (MMBbl)
|
86.7
|
58.0
|
36.4
|
83.7
|
||||||||||||
__________
|
1
|
Amount
for the five months ended May 31, 2007 represents a non-cash goodwill
impairment charge; see Note 3 of the accompanying Notes to Consolidated
Financial Statements.
|
|
2
|
2008
amount includes a $12.3 million expense due to certain non-cash Trans
Mountain regulatory accounting
adjustments.
|
|
3
|
2008
amount includes a $19.3 million decrease in expense associated with
favorable changes in Canadian income tax rates and a $6.6 million increase
in expense due to certain non-cash Trans Mountain regulatory accounting
adjustments.
|
The
information in the table above reflects the results of operations for the seven
months ended December 31, 2007, five months ended May 31, 2007 and year ended
December 31, 2006 as though the transfer of the Trans Mountain one-third
interest in Express and Jet Fuel to Kinder Morgan Energy Partners had occurred
at the beginning of the period (January 1, 2006).
Year
Ended December 31, 2008
In
addition to the $12.7 million net favorable impact in Canadian income taxes
described in footnote 3 to the table above, earnings before DD&A for the
year ended December 31, 2008 include strong operating revenues resulting from
the April 2007 completion of an expansion project that included the
commissioning of ten new pump stations that boosted capacity on Trans Mountain
from 225,000 to approximately 260,000 barrels per day, and to the April 28, 2008
partial completion of the first portion of the Anchor Loop expansion that
boosted pipeline capacity from 260,000 to 285,000 barrels per day and resulted
in higher period-to-period average toll rates. Kinder Morgan Energy Partners
completed construction on a final 15,000 barrels per day expansion on October
30, 2008 and total pipeline capacity is now approximately 300,000 barrels per
day.
Seven
Months Ended December 31, 2007
During
seven months ended December 31, 2007, segment earnings before DD&A were
positively impacted by the completion of a pump station expansion on April 30,
2007 and its associated positive impact to revenue for the period.
Five
Months Ended May 31, 2007
During
the five months ended May 31, 2007, earnings before DD&A were adversely
affected by a $377.1 million goodwill impairment charge recorded against the
Trans Mountain asset. Slightly offsetting this negative impact to earnings was
the completion of a pump station expansion on April 30, 2007 and its associated
positive impact to revenue for the period.
Year
Ended December 31, 2006
In
2006, Kinder Morgan Canada–KMP started the expansion of the Trans Mountain
pipeline system, which is discussed above.
67
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Knight
Inc. General and Administrative Expense
|
$
|
(54.6
|
)
|
$
|
(33.2
|
)
|
$
|
(138.6
|
)
|
$
|
(36.9
|
)
|
||||
|
Kinder
Morgan Energy Partners General and Administrative Expense
|
(297.9
|
)
|
(142.4
|
)
|
(136.2
|
)
|
(238.4
|
)
|
||||||||
|
Terasen
General and Administrative Expenses
|
-
|
-
|
(8.8
|
)
|
(29.8
|
)
|
||||||||||
|
Consolidated
General and Administrative Expense
|
$
|
(352.5
|
)
|
$
|
(175.6
|
)
|
$
|
(283.6
|
)
|
$
|
(305.1
|
)
|
||||
Year
Ended December 31, 2008
“General
and Administrative Expense” for the year ended December 31, 2008 of $352.5
million primarily consists of (i) $209.7 million of Kinder Morgan Energy
Partners compensation expense, (ii) $57.8 million of Kinder Morgan Energy
Partners outside services and (iii) $45.1 million incurred by Knight, Inc.
general and administrative expenses related to Natural Gas Pipeline Company of
America LLC (“NGPL G&A”). $6.2 million of the $45.1 million NGPL
G&A was incurred during the period prior to the sale of an 80% interest in
NGPL PipeCo LLC, January 1, 2008 through February 14, 2008, and the remaining
$38.9 million was incurred subsequent to February 15, 2008 and billed to Natural
Gas Pipeline Company of America LLC; see Note 7 in the accompanying Notes to
Consolidated Statements for more information.
Seven
Months Ended December 31, 2007
“General
and Administrative Expense” for the seven months ended December 31, 2007
includes $33.2 million of Knight Inc. general and administrative expense,
primarily associated with $19.4 million of compensation expense and $142.4
million of Kinder Morgan Energy Partners general and administrative expense,
primarily associated with $108.6 million of compensation expense and $28.8
million of outside services.
Five
Months Ended May 31, 2007
“General
and Administrative Expense” for the five months ended May 31, 2007 includes a
total of $141.0 million related to the going private transaction, consisting of
$114.8 million expensed by Knight Inc. and $26.2 million allocated to Kinder
Morgan Energy Partners. In addition, during the five months ended May 31, 2007
we incurred $4.3 million in selling expenses associated with the sale of our (i)
U.S. based retail natural gas distribution and related operations, (ii) Terasen
Gas business and (iii) Terasen Pipelines (Corridor) Inc.
Year
Ended December 31, 2006
“General
and Administrative Expense” for the year ended December 31, 2006 includes $36.9
million of Knight Inc. general and administrative expense, primarily associated
with $19.5 million of compensation expense and $238.4 million of Kinder Morgan
Energy Partners general and administrative expense, primarily associated with
$144.3 million of compensation expense and $46.8 million of outside
services.
Kinder
Morgan Energy Partners’ and Knight Inc.’s general and administrative expenses
tend to increase over time in large part because the expansion of their
businesses through acquisitions and internal growth requires the hiring of
additional employees, resulting in increased payroll and other employee-related
expense.
68
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Interest
Expense, Net
|
$
|
(633.4
|
)
|
$
|
(581.5
|
)
|
$
|
(241.1
|
)
|
$
|
(552.8
|
)
|
||||
|
Interest
Income (Expense) – Deferrable Interest Debentures2
|
5.1
|
(12.8
|
)
|
(9.1
|
)
|
(21.9
|
)
|
|||||||||
|
Consolidated
Interest Expense
|
(628.3
|
)
|
(594.3
|
)
|
(250.2
|
)
|
(574.7
|
)
|
||||||||
|
Minority
Interests
|
||||||||||||||||
|
Kinder
Morgan Management
|
(80.5
|
)
|
(35.8
|
)
|
(17.1
|
)
|
(65.9
|
)
|
||||||||
|
Kinder
Morgan Energy Partners
|
(302.4
|
)
|
7.3
|
(75.1
|
)
|
(300.8
|
)
|
|||||||||
|
Triton
|
(13.0
|
)
|
(9.0
|
)
|
2.3
|
(7.3
|
)
|
|||||||||
|
Other
|
(0.2
|
)
|
(0.1
|
)
|
(0.8
|
)
|
(0.2
|
)
|
||||||||
|
Consolidated
Minority Interests Expense
|
(396.1
|
)
|
(37.6
|
)
|
(90.7
|
)
|
(374.2
|
)
|
||||||||
|
Loss
on Mark-to-market Interest Rate Swaps
|
-
|
-
|
-
|
(22.3
|
)
|
|||||||||||
|
Other1
|
4.7
|
7.9
|
(7.3
|
)
|
3.0
|
|||||||||||
|
$
|
(1,019.7
|
)
|
$
|
(624.0
|
)
|
$
|
(348.2
|
)
|
$
|
(968.2
|
)
|
|||||
__________
|
1
|
“Other”
represents offset to minority interest and interest income shown above and
included in segment earnings.
|
|
2
|
2008
amount includes $11.3 million gain on retirement, offset by $5.751 million
interest expense and $0.5 million of accounting
expense.
|
“Interest
Expense, Net” for the year ended December 31, 2008 includes (i)
$388.2 million of Kinder Morgan Energy Partners interest expense and (ii)
$240.1 million of Knight Inc. interest expense. Kinder Morgan Energy
Partners interest expense tends to increase over time as it incurs additional
debt to fund its capital spending and its acquisition of new assets and
businesses. Knight Inc.’s interest expense was affected by reduced debt levels,
primarily related to the application of the proceeds from the sale of an 80%
interest in NGPL PipeCo LLC to reduce outstanding debt.
“Interest
Expense, Net” for the seven months ended December 31, 2007 includes (i) $179.6
million of interest expense related to additional debt incurred as part of the
going private transaction, (ii) $236.4 million of Kinder Morgan Energy Partners
interest expense and (iii) $165.5 million of Knight Inc. interest expense not
related to the going private transaction.
“Interest
Expense, Net” for the five months ended May 31, 2007 includes (i)
$155.0 million of Kinder Morgan Energy Partners interest expense and (ii)
$86.1 million of Knight Inc. interest expense.
“Interest
Expense, Net” for the year ended December 31, 2006 includes (i) $333.4 million
of Kinder Morgan Energy Partners interest expense, (ii) $157.8 million of Knight
Inc. interest expense and (iii) $67.8 million related to Terasen.
During
the first quarter of 2006, we recorded a pre-tax charge of $22.3 million ($14.1
million after tax) related to the financing of the Terasen acquisition. The
charge was necessary because certain hedges put in place related to the debt
financing for the acquisition did not qualify for hedge treatment under GAAP,
thus requiring that they be marked-to-market, resulting in a non-cash charge to
income. These hedges have now been effectively terminated (see Note 15 of the
accompanying Notes to Consolidated Financial Statements).
Minority
interest expense associated with Kinder Morgan Management for the year ended
December 31, 2008, seven months ended December 31, 2007, five months ended May
31, 2007 and year ended December 31, 2006 was $80.5 million, $35.8 million,
$17.1 million and $65.9 million, respectively. Minority interest expense
reflects the earnings recorded by Kinder Morgan Management that are attributed
to its shares held by the public. Kinder Morgan Management’s earnings are solely
dependent on its ownership of Kinder Morgan Energy Partnership i-units.
Therefore, our minority interest expense associated with Kinder Morgan
Management is a function of Kinder Morgan Energy Partners’ earnings and the
shares of Kinder Morgan Management, which are held by the public. As of December
31, 2008, December 31, 2007 and May 31, 2007 we owned approximately 14.3% of
Kinder Morgan Managements’ outstanding shares. As of December 31, 2006 we owned
approximately 16.5% of Kinder Morgan Managements’ outstanding
shares.
Minority
interest expense (income) associated with Kinder Morgan Energy Partners for the
year ended December 31, 2008, seven months ended December 31, 2007, five months
ended May 31, 2007 and year ended December 31, 2006 was $302.4 million, ($7.3)
million, $75.1 million and $300.8 million, respectively. Minority interest
expense (income) reflects the earnings (loss) from continuing operations
recorded by Kinder Morgan Energy Partners that are attributed to its units held
by
69
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
the
public. During the seven months ended December 31, 2007, $141.6 million of
minority interest expense associated with Kinder Morgan Energy Partners’ North
System, which was sold by Kinder Morgan Energy Partners in October 2007, was
recorded in discontinued operations rather than minority interests from
continuing operations. See Note 11 of the accompanying Notes to Consolidated
Financial Statements.
Year
Ended December 31, 2008
The
year ended December 31, 2008 income tax expense from continuing operations of
$304.3 million consists of (i) $261.4 million of federal income tax expense,
(ii) $44.9 million related to Kinder Morgan Management minority interest income
tax expense, (iii) $11.7 million attributable to the net tax effects of
consolidating Kinder Morgan Energy Partners’ United States income tax provision,
(iv) $22.2 million of prior period adjustments, (v) $17.0 million of state
income taxes and (vi) $15.3 million of other income tax items. These income tax
expenses were offset by $68.2 million benefit primarily due to the termination
of certain of our subsidiaries’ presence in Canada, resulting in the elimination
of future taxable gains and a reduction in Canadian foreign tax
rates.
Seven
Months Ended December 31, 2007
The
seven months ended December 31, 2007 income tax expense from continuing
operations of $227.4 million consists of (i) $166.5 million of federal income
tax expense, (ii) $12.8 million related to Kinder Morgan Management minority
interest income tax expense, (iii) $ 27.6 million due to income taxes on foreign
earnings at different tax rates, (iv) $11.9 million attributable to the net tax
effects of consolidating Kinder Morgan Energy Partners’ United States income tax
provision and (v) $10.9 million of state income taxes. The above income tax
expense is net of $2.3 million of other income tax items.
Five
Months Ended May 31, 2007
The
five months ended May 31, 2007 income tax expense from continuing operations of
$135.5 million consists of (i) $34.0 million federal income tax benefit on the
$97.2 million loss from continuing operations before income taxes, (ii) $16.6
million tax benefit from the Terasen acquisition financing structure and (iii)
$2.0 million of other income tax items. These tax benefits and credits were
offset by income tax expenses consisting of (i) $30.7 million of income taxes on
non-deductible fees associated with the Going Private transaction, (ii) $132.1
million of expense related to the Trans Mountain goodwill impairment of $377.1
million, which is not deductible for tax purposes, (iii) $6.2 million related to
Kinder Morgan Management minority interest income tax expense, (iv) $8.4 million
due to income taxes on foreign earnings at different tax rates, (v) $4.0 million
attributable to the net tax effects of consolidating Kinder Morgan Energy
Partners’ United States income tax provision and (vi) $6.7 million of state
income taxes.
Year
Ended December 31, 2006
The
year ended December 31, 2006 income tax expense from continuing operations of
$285.9 million consists of (i) $309.8 million of federal income tax expense,
(ii) $23.9 million related to Kinder Morgan Management minority interest income
tax expense, (iii) $23.0 million due to income taxes on foreign earnings at
different tax rates, (iv) $12.4 million attributable to the net tax effects of
consolidating Kinder Morgan Energy Partners’ United States income tax provision
and (v) $15.0 million of state income taxes. These income tax expenses were
offset by the following tax benefits and credits: (i) a $45.1 million tax
benefit from the Terasen acquisition financing structure, (ii) a $38.1 million
tax benefit from a change in our deferred tax rates and (iii) a $15.0 million of
other income tax items.
See
Note 13 of the accompanying Notes to Consolidated Financial Statements for
additional information on income taxes.
A
capital loss carryforward can be utilized to reduce capital gain during the five
years succeeding the year in which a capital loss is incurred. We closed the
sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of
approximately $3.4 billion (C$3.7 billion) including cash and assumed debt. We
recorded a book gain on this disposition of $55.7 million in the second quarter
of 2007. The sale resulted in a capital loss of $998.6 million for tax purposes.
Approximately $223.3 million of the Terasen Inc. capital loss was utilized to
reduce capital gain principally associated with the sale of our U.S.-based
retail natural gas operations resulting in a tax benefit of approximately $82.2
million during 2007.
At
December 31, 2007, we had a remaining capital loss carryforward of $775.1
million, all of which was utilized to reduce the capital gain associated with
the sale of our 80% ownership interest in the NGPL business segment and other
dispositions, resulting in a tax benefit of approximately $279.5 million during
2008.
70
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Liquidity
We
believe that we and our subsidiaries and investments, including Kinder Morgan
Energy Partners, have liquidity and access to financial resources as discussed
below sufficient to meet future requirements for working capital, debt repayment
and capital expenditures associated with existing and future expansion projects
as follows:
|
|
·
|
Cash flow from
operations
|
Our
diverse set of energy infrastructure assets generated $1,397.6 million of cash
flows from continuing operations for the year ended December 31, 2008.
Additionally, Kinder Morgan Energy Partners expansion projects in aggregate are
expected to generate positive returns on our investment, based on long-term
contracted customer commitments and our current estimated expansion project
costs.
|
|
·
|
Credit facility
availability
|
As
of December 31, 2008, Knight Inc. had available credit capacity of $929.2
million and Kinder Morgan Energy Partners had available credit capacity of
$1,473.7 million after reduction for (i) our letters of credit, (ii) commercial
paper outstanding (none at December 31, 2008) and (iii) lending commitments made
by a Lehman Brothers related bank (see Customer and Capital Market Liquidity).
Kinder Morgan Energy Partners’ joint venture projects, Rockies Express Pipeline
LLC, Midcontinent Express Pipeline LLC and Cortez Capital Corporation, have
undrawn capacity of $366.6 million, $429.2 million and $9.0 million,
respectively, under their separate credit facilities, net of Lehman Brothers’
commitments (see Customer and Capital Market Liquidity).
|
|
·
|
Long-term debt and equity
markets
|
During
the year ended December 31, 2008, Kinder Morgan Energy Partners, for itself and
for its equity investment, Rockies Express Pipeline LLC, collectively has raised
$3.4 billion of long-term debt and $676.9 million of equity through the issuance
of Kinder Morgan Energy Partners units. Including the quarterly share
distributions paid by Kinder Morgan Management in 2008, which essentially
constitute an automatic distribution re-investment program, a total of
approximately $966.5 million in equity was raised during this
timeframe.
|
|
·
|
Kinder Morgan Energy Partners
equity infusion
|
Additionally,
in October 2008, our board of directors indicated Knight Inc’s willingness to
purchase up to $750 million of Kinder Morgan Energy Partners equity over the
next 15 months, if necessary, to support its capital raising
efforts.
|
|
·
|
Credit
Ratings
|
On
October 13, 2008, Standard and Poor’s Rating Services revised its outlook on
Kinder Morgan Energy Partners’ long-term credit rating to negative from stable
(but affirmed Kinder Morgan Energy Partners’ long-term credit rating at BBB),
due to Kinder Morgan Energy Partners’ previously announced expected delay and
cost increases associated with the completion of the Rockies Express Pipeline
project. At the same time, Standard and Poor’s Rating Services lowered Kinder
Morgan Energy Partners, Rockies Express Pipeline LLC and Cortez Capital
Corporation’s short-term credit rating to A-3 from A-2. As a result of this
revision and current commercial paper market conditions, Kinder Morgan Energy
Partners, Rockies Express Pipeline LLC and Cortez Capital Corporation are unable
to access commercial paper borrowings. However, Kinder Morgan Energy Partners,
Rockies Express Pipeline LLC and Cortez Capital Corporation expect that
short-term financing and liquidity needs will continue to be met through
borrowings made under their respective bank credit facilities. Knight Inc.’s
Standard and Poor’s Rating Services credit rating has not changed in the year
ended December 31, 2008 and remains BB on its secured senior debt.
Customer
and Capital Market Liquidity
Some
of Kinder Morgan Energy Partners’ customers are experiencing, or may experience
in the future, severe financial problems that have had or may have a significant
impact on their creditworthiness. These financial problems may arise from the
current credit market crisis, changes in commodity prices or otherwise. Kinder
Morgan Energy Partners is working to implement, to the extent allowable under
applicable contracts, tariffs and regulations, prepayments and other security
requirements, such as letters of credit, to enhance their credit position
relating to amounts owed from these customers. Knight Inc. and Kinder Morgan
Energy Partners cannot provide assurance that one or more of Kinder Morgan
Energy Partners’ financially distressed customers will not default on their
obligations to them or that such a default or defaults will not have a material
adverse effect on Kinder Morgan Energy Partners’ business, or Knight Inc.’s
financial position, future results of operations, or future cash flows; however,
Knight Inc. believes it has recorded adequate allowances for such
customers.
On
September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy
protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One
Lehman entity was a lending institution that provided a portion of Kinder Morgan
Energy Partners’, Rockies Express Pipeline LLC’s and Midcontinent Express
Pipeline LLC’s respective credit facilities. Since Lehman Brothers declared
bankruptcy, its affiliate, which is party to the credit facilities, has not met
its obligations to lend under those agreements. As such, the commitments have
been effectively reduced by $63 million, $41 million and $100
71
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
million,
respectively, to $1.8 billion, $2.0 billion and $1.3 billion. The commitments of
the other banks remain unchanged, and the facilities are not
defaulted.
Invested
Capital
Our
net debt (outstanding notes and debentures plus short-term debt, less cash and
cash equivalents) to total capital, excluding accumulated other comprehensive
income, for the years ended December 31, 2008 and 2007 was 56.4% and 56.9%,
respectively. Our net debt to total capital ratio was principally impacted by
debt reductions made possible by $5.9 billion in total proceeds related to the
sale of an 80% ownership interest in NGPL PipeCo LLC, which proceeds were used
to pay off the entire outstanding balances of our senior secured credit
facility’s Tranche A and Tranche B term loans (approximately $4.2 billion), to
repurchase $1.67 billion par value of our outstanding debt securities and to
reduce borrowings outstanding under our $1.0 billion revolving credit facility.
This increase was partially offset by a $4.03 billion non-cash goodwill
impairment charge associated with the Going Private transaction (see Note 3 of
the accompanying Notes to Consolidated Financial Statements) as well as $2.1
billion in additional borrowings by Kinder Morgan Energy Partners during
2008.
In
addition to the direct sources of debt and equity financing, we obtain financing
indirectly through our ownership interests in unconsolidated entities as
discussed in Note 18 of the accompanying Notes to Consolidated Financial
Statements. In addition to our results of operations, these balances are
affected by our financing activities as discussed following.
Except
for Kinder Morgan Energy Partners and its subsidiaries, we employ a centralized
cash management program that essentially concentrates the cash assets of our
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 subsidiaries be
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 intercompany 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
that neither we nor our subsidiaries (other than Kinder Morgan Energy Partners
and its subsidiaries) have rights with respect to the cash of Kinder Morgan
Energy Partners or its subsidiaries except as permitted by Kinder Morgan Energy
Partners’ partnership agreement.
In
addition, certain of our operating subsidiaries are subject to FERC-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.
Short-term
Liquidity
Our
principal sources of short-term liquidity are our revolving bank facilities and
cash provided by operations. The following represents the revolving credit
facilities that were available to Knight Inc. and its respective subsidiaries,
short-term debt outstanding under the credit facilities and available borrowing
capacity under the facilities after applicable letters of credit.
|
At
December 31, 2008
|
At
February 23, 2009
|
||||||||||
|
Short-term
Debt
Outstanding
|
Available
Borrowing
Capacity
|
Short-term
Debt
Outstanding
|
Available
Borrowing
Capacity
|
||||||||
|
(In
millions)
|
|||||||||||
|
Credit
Facilities
|
|||||||||||
|
Knight
Inc.
|
|||||||||||
|
$1.0
billion, six-year secured revolver, due May 2013
|
$
|
8.8
|
$
|
929.2
|
$
|
23.0
|
$
|
914.1
|
|||
|
Kinder
Morgan Energy Partners
|
|||||||||||
|
$1.85
billion, five-year unsecured revolver, due August 2010
|
$
|
-
|
$
|
1,473.7
|
$
|
527.6
|
$
|
1,022.4
|
|||
These
facilities can be used for the respective entity’s general corporate or
partnership purposes. Kinder Morgan Energy Partners’ facility is also used as
backup for its commercial paper program. These facilities include financial
covenants and events of default that are common in such arrangements. The terms
of these credit facilities are discussed in Note 14 of the accompanying Notes to
Consolidated Financial Statements.
Our
current maturities of long-term debt of $293.7 million at December 31, 2008
represent (i) $250 million in principal amount of Kinder Morgan Energy Partners’
6.30% senior notes due February 1, 2009, (ii) $23.7 million in principal amount
of tax-exempt bonds that mature on April 1, 2024, but are due on demand pursuant
to certain standby purchase agreement provisions contained in the bond indenture
(Kinder Morgan Energy Partners’ subsidiary Kinder Morgan Operating L.P. “B” is
the obligor on the bonds), (iii) $5.0 million of our 6.50% Series Debentures due
September 1, 2013, (iv) $8.5 million of a
72
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
5.40%
long-term note of Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada
Company due March 31, 2009 and (v) $6.5 million of Kinder Morgan Texas Pipeline,
L.P.’s 5.23% Series Notes due January 2, 2014. Apart from our notes payable,
current maturities of long-term debt, and the fair value of derivative
instruments, our current liabilities, net of our current assets, represent an
additional short-term obligation of $380.7 million at December 31, 2008. Given
our expected cash flows from operations, our unused debt capacity as discussed
preceding, including our credit facilities, and based on our projected cash
needs in the near term, we do not expect any liquidity issues to
arise.
Significant
Financing Transactions
For
additional information on significant financing Transactions, see Note 14 of the
accompanying Notes to Consolidated Financial Statements.
During
2008, we used the proceeds from the completed sale of an 80% ownership interest
in our NGPL business segment to repurchase $1.67 billion par value debt
securities and to pay off the balances of our Tranche A and Tranche B term
loans, and amounts outstanding, at the time, of our $1.0 billion revolving
credit facility totaling approximately $4.6 billion. In June 2007, we repaid the
outstanding borrowings under the Tranche C term facility.
Kinder
Morgan Energy Partners completed three offerings of senior notes during the year
ended December 31, 2008, two offerings during the seven months ended December
31, 2007 and one offering during the five months ended May 31, 2007, raising a
total (net of underwriting discounts and commissions) of $2,080.2 million,
$1,041.7 million and $992.8 million, respectively. During the seven months ended
December 31, 2007, Kinder Morgan Energy Partners also repaid $250 million of
senior notes. Kinder Morgan Energy Partners used the proceeds from each of the
three 2007 debt offerings and from the first two 2008 debt offerings to reduce
the borrowings under Kinder Morgan Energy Partners’ commercial paper program.
Kinder Morgan Energy Partners used the proceeds from its December 2008 debt
offering to reduce the borrowings under its credit facility.
Kinder
Morgan Energy Partners completed four offerings of common units during the year
ended December 31, 2008, which raised a total of $676.9 million, net of
underwriting discounts and commissions. For the seven months ended December 31,
2007 and five months ended May 31, 2007, Kinder Morgan Energy Partners raised a
total (net of underwriting costs and commissions) of $342.9 million and $297.9
million, respectively, from the issuance of common units. Proceeds from these
issuances were used to reduce borrowings under the commercial paper program and
bank credit facility.
On
July 27, 2007, Kinder Morgan G.P., Inc. sold 100,000 shares of its $1,000
Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred
Stock due 2057 to a single purchaser. We used the net proceeds of approximately
$98.6 million after the initial purchaser’s discounts and commissions to reduce
debt.
As
discussed in Note 11 of the accompany Notes to Consolidated Financial
Statements, on March 5, 2007 we entered into a definitive agreement to sell
Terasen Pipelines (Corridor) Inc. and on February 26, 2007, we entered into a
definitive agreement to sell Terasen Inc., which includes the assets of Terasen
Gas Inc. and Terasen Gas (Vancouver Island) Inc. These transactions closed on
June 15, 2007 and May 17, 2007, respectively. Our consolidated debt was reduced
by the debt balances of Terasen Inc. and Terasen Pipelines (Corridor) Inc. of
approximately $2.9 billion, including the Capital Securities, as a result of
these sales transactions. For the period from January 1, 2007 to May 17, 2007,
average borrowings under Terasen Gas Vancouver Island Inc.’s C$350 million
credit facility were $255.1 million at a weighted-average rate of 4.43%. For the
period from January 1, 2007 to May 17, 2007, average borrowings under the C$20
million demand facility were $3.3 million at a weighted-average rate of
5.31%.
On
May 30, 2007, investors led by Richard D. Kinder, our Chairman and Chief
Executive Officer, completed the Going Private transaction. In conjunction with
the Going Private transaction, Knight Inc. entered into a $5.755 billion credit
agreement dated May 30, 2007, which included three term credit facilities, which
were subsequently retired, and one revolving credit facility. See Notes 1 and 14
of the accompanying Notes to Consolidated Financial Statements for additional
information related to the Going Private transaction and the associated debt and
debt retirement.
On
May 7, 2007, we retired our $300 million 6.80% senior notes due March 1, 2008 at
101.39% of the face amount. We recorded a pre-tax loss of $4.2 million in
connection with this early extinguishment of debt.
Effective
January 1, 2007, Kinder Morgan Energy Partners acquired the remaining
approximate 50.2% interest in the Cochin pipeline system that Kinder Morgan
Energy Partners did not already own (see Note 10 of the accompanying Notes to
Consolidated Financial Statements). As part of Kinder Morgan Energy Partners’
purchase price, two of its subsidiaries issued a long-term note payable to the
seller having a fair value of $42.3 million. Kinder Morgan Energy Partners’
subsidiaries, Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company,
are the obligors on the note and, as of December 31, 2008, the outstanding
balance under the note was $36.6 million.
73
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Capital
Expenditures
Our
sustaining capital expenditures for the year ended December 31, 2008 were $183.9
million, and we expect to spend $203.4 million during 2009. Our sustaining
capital expenditures are funded with cash flows from operations.
Our
expansion capital expenditures for the year ended December 31, 2008 were
$2,361.4 million, primarily related to Kinder Morgan Energy Partners. Kinder
Morgan Energy Partners expects to spend another $1,188.2 million during 2009. In
addition to these amounts, Kinder Morgan Energy Partners contributed an
aggregate amount of $333.5 million for both the Rockies Express and Midcontinent
Express natural gas pipeline projects in 2008, and it expects to contribute,
based on Kinder Morgan Energy Partners’ proportionate share of equity ownership
interest in both projects, approximately $1.5 billion in the aggregate for both
projects in 2009. Kinder Morgan Energy Partners will fund its 2009 capital
expenditures and equity contributions through borrowings under its $1.85 billion
revolving credit facility, proceeds from issuance of long term notes and common
unit offerings.
Off
Balance Sheet Arrangements
We
have invested in entities that are not consolidated in our financial statements.
As of December 31, 2008, our obligations with respect to these investments, as
well as our obligations with respect to letters of credit, are summarized below
(dollars in millions):
|
Entity
|
Investment
Type
|
Our
Ownership
Interest
|
Remaining
Interest(s)
Ownership
|
Total
Entity
Assets
|
Total
Entity
Debt
|
Our
Contingent
Share
of
Entity
Debt
|
||||||||||||
|
Cortez
Pipeline Company
|
General
Partner
|
50%
|
1
|
$
|
95.7
|
2
|
$
|
169.6
|
$
|
84.8
|
3
|
|||||||
|
West2East
Pipeline LLC4
|
Limited
Liability
|
51%
|
ConocoPhillips
and
Sempra
Energy
|
$
|
4,787.0
|
2
|
$
|
3,458.9
|
5
|
$
|
1,102.1
|
6
|
||||||
|
|
||||||||||||||||||
|
Midcontinent
Express Pipeline LLC7
|
Limited
Liability
|
50%
|
Energy
Transfer
Partners,
L.P.
|
$
|
998.5
|
2
|
$
|
837.5
|
$
|
418.8
|
8
|
|||||||
|
|
||||||||||||||||||
|
Nassau
County, Florida Ocean Highway And Port Authority9
|
N/A
|
N/A
|
Nassau
County,
Florida
Ocean
Highway
and
Port
Authority
|
N/A
|
N/A
|
$
|
10.2
|
|||||||||||
|
|
||||||||||||||||||
|
NGPL
PipeCo LLC
|
Equity
|
20%
|
Myria
Acquisition Inc.
|
$
|
7,064.5
|
$
|
3,000.0
|
$
|
-
|
10
|
||||||||
_________
|
1
|
The
remaining general partner interests are owned by ExxonMobil Cortez
Pipeline, Inc., an indirect wholly owned subsidiary of Exxon Mobil
Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of
M.E. Zuckerman Energy Investors
Incorporated.
|
|
2
|
Principally
property, plant and equipment.
|
|
3
|
We
are severally liable for our percentage ownership share (50%) of the
Cortez Pipeline Company debt. As of December 31, 2008, Shell Oil Company
shares Kinder Morgan Energy Partners’ several guaranty obligations jointly
and severally for $53.6 million of Cortez Pipeline Company’s debt balance;
however, Kinder Morgan Energy Partners is obligated to indemnify Shell Oil
Company for the liabilities Shell Oil Company incurs in connection with
such guaranty. Accordingly, as of December 31, 2008 Kinder Morgan Energy
Partners has a letter of credit in the amount of $26.8 million issued by
JP Morgan Chase, in order to secure its indemnification obligations to
Shell Oil Company for 50% of the Cortez Pipeline Company debt balance of
$53.6 million.
|
Further,
pursuant to a Throughput and Deficiency Agreement, the partners of Cortez
Pipeline Company are required to contribute capital to Cortez Pipeline Company
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 Company to fund
cash deficiencies at Cortez Pipeline Company, 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
Company owners under this agreement.
|
4
|
West2East
Pipeline LLC is a limited liability company and is the sole owner of
Rockies Express Pipeline LLC. As of December 31, 2008, the remaining
limited liability member interests in West2East Pipeline LLC are owned by
ConocoPhillips (24%) and Sempra Energy (25%). Kinder Morgan Energy
Partners owned a 66 2/3% ownership interest in West2East Pipeline LLC from
October 21, 2005 until June 30, 2006, and included West2East Pipeline
LLC’s results in its consolidated financial statements until June 30,
2006. On June 30, 2006, Kinder Morgan Energy Partners’ ownership interest
was reduced to 51%, West2East Pipeline LLC was deconsolidated, and Kinder
Morgan Energy Partners subsequently accounted for its investment under the
equity method of accounting. Upon completion of the
pipeline,
|
74
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
|
Kinder
Morgan Energy Partners’ ownership percentage is expected to be reduced to
50%.
|
|
5
|
Amount
includes an aggregate of $1.3 billion in principal amount of fixed rate
senior notes issued by Rockies Express Pipeline LLC in a private offering
in June 2008. All payments of principal and interest in respect of these
senior notes are the sole obligation of Rockies Express Pipeline LLC.
Noteholders have no recourse against Kinder Morgan Energy Partners or the
other member owners of West2East Pipeline LLC for any failure by Rockies
Express Pipeline LLC to perform or comply with its obligations pursuant to
the notes or the indenture.
|
|
6
|
In
addition, there is a letter of credit outstanding to support the
construction of the Rockies Express Pipeline. As of December 31, 2008,
this letter of credit, issued by JPMorgan Chase, had a face amount of
$31.4 million. Kinder Morgan Energy Partners’ contingent responsibility
with regard to this outstanding letter of credit was $16.0 million (51% of
the total face amount).
|
|
7
|
Midcontinent
Express Pipeline LLC is a limited liability company and the owner of the
Midcontinent Express Pipeline. In January 2008, in conjunction with the
signing of additional binding pipeline transportation commitments,
Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a
subsidiary of MarkWest Energy Partners, L.P.) entered into an option
agreement that provides MarkWest Pioneer, L.L.C. a one-time
right to purchase a 10% ownership interest in Midcontinent Express
Pipeline LLC after the pipeline is fully constructed and placed into
service. If the option is exercised, Kinder Morgan Energy Partners and
Energy Transfer Partners, L.P. will each own 45% of Midcontinent Express
Pipeline LLC, while MarkWest Pioneer, L.L.C. will own the remaining
10%.
|
|
8
|
In
addition, there is a letter of credit outstanding to support the
construction of the Midcontinent Express Pipeline. As of December 31,
2008, this letter of credit, issued by the Royal Bank of Scotland plc, had
a face amount of $33.3 million. Kinder Morgan Energy Partners’ contingent
responsibility with regard to this outstanding letter of credit was $16.7
million (50% of the total face
amount).
|
|
9
|
This
arrangement rose from Kinder Morgan Energy Partners’ 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, Kinder Morgan Energy Partners acquired Nassau Terminals LLC and
became guarantor under the letter of credit agreement. In December 2002,
Kinder Morgan Energy Partners issued a $28 million letter of credit under
its credit facilities and the former letter of credit guarantee was
terminated. As of December 31, 2008, the face amount of this letter of
credit outstanding under Kinder Morgan Energy Partners’ credit facility
was $10.2 million. Principal payments on the bonds are made on the first
of December each year at which time reductions are made to the letter of
credit.
|
|
10
|
Debtors
have recourse only to the assets of the entity, not the
owners.
|
|
|
Aggregate
Contractual Obligations
|
|
|
Aggregate
Contractual Obligations
|
At
December 31, 2008
|
Total
|
Less
than
1
year
|
2-3
years
|
4-5
years
|
After
5 years
|
||||||||||
|
(In
millions)
|
||||||||||||||
|
Contractual
Obligations
|
||||||||||||||
|
Short-term
Borrowings
|
$
|
8.8
|
$
|
8.8
|
$
|
-
|
$
|
-
|
$
|
-
|
||||
|
Long-term
Debt, Including Current Maturities:
|
||||||||||||||
|
Principal
Payments
|
11,514.5
|
293.7
|
1,743.8
|
2,814.8
|
6,662.2
|
|||||||||
|
Interest
Payments1
|
9,252.5
|
717.5
|
1,349.4
|
1,062.4
|
6,123.2
|
|||||||||
|
Lease
Obligations2,3
|
664.7
|
57.5
|
103.4
|
85.4
|
418.4
|
|||||||||
|
Pension
and Postretirement Benefit Plans
|
90.5
|
25.1
|
10.7
|
12.2
|
42.5
|
|||||||||
|
Other
Obligations6
|
15.1
|
8.3
|
6.8
|
-
|
-
|
|||||||||
|
Total
Contractual Cash Obligations4
|
$
|
21,546.1
|
$
|
1,110.9
|
$
|
3,214.1
|
$
|
3,974.8
|
$
|
13,246.3
|
||||
|
|
||||||||||||||
|
Other
Commercial Commitments
|
||||||||||||||
|
Standby
Letters of Credit5
|
$
|
405.8
|
$
|
335.3
|
$
|
25.7
|
$
|
26.8
|
$
|
18.0
|
||||
|
Capital
Expenditures7
|
$
|
581.0
|
$
|
581.0
|
$
|
-
|
$
|
-
|
$
|
-
|
||||
__________
|
1
|
Interest
payments have not been adjusted for any amounts receivable related to our
interest rate swaps outstanding. See Item 7A, “Quantitative and
Qualitative Disclosures About Market
Risk.”
|
|
2
|
Represents
commitments for operating leases.
|
75
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
3
|
Approximately
$437.6 million, $20.6 million, $41.4 million, $40.7 million and $334.9
million in each respective column is attributable to the lease obligation
associated with the Jackson, Michigan power generation
facility.
|
|
4
|
As
of December 31, 2008, the liability for uncertain income tax positions,
excluding associated interest and penalties, was $26.2 million pursuant to
FASB Interpretation No. 48. This liability represents an estimate of tax
positions that we have taken in our tax returns, which may ultimately not
be sustained upon examination by the tax authorities. Since the ultimate
amount and timing of any future cash settlements cannot be predicted with
reasonable certainty, this estimated liability has been excluded from the
Aggregate Contractual Obligations.
|
|
5
|
See
Note 18 of the accompanying Notes to Consolidated Financial Statements for
a listing of letters of credit outstanding as of December 31,
2008.
|
|
6
|
Consists
of payments due under carbon dioxide take-or-pay contracts and, for the 1
Year or Less column only, Kinder Morgan Energy Partners’ purchase and sale
agreement with LPC Packaging (a California corporation) for the
acquisition of certain bulk terminal
assets.
|
|
7
|
Represents
commitments for the purchase of property, plant and equipment at December
31, 2008.
|
We
expect to have sufficient liquidity to satisfy our near-term obligations through
the combination of free cash flow and our credit facilities, including those of
Kinder Morgan Energy Partners.
|
Contingent
Liabilities:
|
Contingency
|
Amount
of Contingent Liability
at
December 31, 2008
|
||
|
Guarantor
of the Bushton Gas Processing Plant Lease1
|
Default
by ONEOK, Inc.
|
Total
$78.8 million; Averages $26.3 million per year through 2011
|
||
|
Jackson,
Michigan Power Plant Incremental Investment
|
Operational
Performance
|
$3
to $8 million per year for 10 years
|
||
|
Jackson,
Michigan Power Plant Incremental Investment
|
Cash
Flow Performance
|
Up
to a total of $25 million beginning in
2018
|
___________
|
1
|
In
conjunction with our sale of the Bushton gas processing facility to ONEOK,
Inc., at December 31, 1999, ONEOK, Inc. became primarily liable under the
associated operating lease and we became secondarily liable. Should ONEOK,
Inc. fail to make payments as required under the lease, we would be
required to make such payments, with recourse only to ONEOK,
Inc.
|
At
December 31, 2008, we owned, directly, and indirectly in the form of i-units
corresponding to the number of shares of Kinder Morgan Management we owned,
approximately 32.8 million limited partner units of Kinder Morgan Energy
Partners. These units, which consist of 16.4 million common units, 5.3 million
Class B units and 11.1 million i-units, represent approximately 12.3% of the
total limited partner interests of Kinder Morgan Energy Partners. In addition,
we are the sole common stockholder of the general partner of Kinder Morgan
Energy Partners, which holds an effective 2% interest in Kinder Morgan Energy
Partners and its operating partnerships. Together, our limited partner and
general partner interests represented approximately 14.1% of Kinder Morgan
Energy Partners’ total equity interests at December 31, 2008. As of the close of
the Going Private transaction, our limited partner interests and our general
partner interest represented an approximate 50% economic interest in Kinder
Morgan Energy Partners. This difference results from the existence of incentive
distribution rights held by the general partner shareholder.
76
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
The
following discussion of cash flows should be read in conjunction with the
accompanying Consolidated Statements of Cash Flows and related supplemental
disclosures. The following discussion is an analysis of the cash flows for the
year ended December 31, 2008 and seven months ended December 31, 2007 (both
successor basis) and the five months ended May 31, 2007 and year ended December
31, 2006 (both predecessor basis). All highly liquid investments purchased with
an original maturity of three months or less are considered to be cash
equivalents.
The
following table summarizes our net cash flows from operating, investing and
financing activities for each period presented.
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Net
Cash Provided by (Used in)
|
||||||||||||||||
|
Operating
Activities
|
$
|
1,396.8
|
$
|
1,044.5
|
$
|
603.0
|
$
|
1,707.3
|
||||||||
|
Investing
Activities
|
3,210.0
|
(15,751.1
|
)
|
723.7
|
(1,795.9
|
)
|
||||||||||
|
Financing
Activities
|
(4,628.1
|
)
|
12,956.8
|
440.9
|
88.7
|
|||||||||||
|
Effect
of Exchange Rate Changes on Cash
|
(8.7
|
)
|
(2.8
|
)
|
7.6
|
6.6
|
||||||||||
|
|
||||||||||||||||
|
Effect
of Accounting Change on Cash
|
-
|
-
|
-
|
12.1
|
||||||||||||
|
|
||||||||||||||||
|
Cash
Balance Included in Assets Held for Sale
|
-
|
(1.1
|
)
|
(2.7
|
)
|
(5.6
|
)
|
|||||||||
|
|
||||||||||||||||
|
Net
(Decrease) Increase in Cash and Cash Equivalents
|
$
|
(30.0
|
)
|
$
|
(1,753.7
|
)
|
$
|
1,772.5
|
$
|
13.2
|
||||||
Year
Ended December 31, 2008
Net
cash flows from operating activities during the period were positively affected
by (i) net income of $1,076.4 million, after adjustments for non-cash items
including, among other things, a $4.0 billion goodwill impairment charge and
$16.5 million of Kinder Morgan Energy Partners’ rate reserve adjustments, (ii)
$192.0 million of net proceeds received for the early termination of interest
rate swap agreements, primarily relating to agreements associated with Kinder
Morgan Energy Partners and (iii) distributions received from equity investments
of $241.6 million, comprised mainly of (a) $82.9 million of initial
distributions received from West2East Pipeline LLC, (b) $43.0 million from
Kinder Morgan Energy Partners’ investment in the Express pipeline system, (c)
$40.1 million from NGPL PipeCo LLC and (d) $33.3 million from Kinder Morgan
Energy Partners’ investment in Red Cedar Gathering Company.
Partially
offsetting these cash inflows were (i) a $44.9 million use of cash for working
capital items, primarily resulting from income tax payments made during the
period related to our ongoing operations and the sale of an 80% ownership
interest in NGPL PipeCo LLC, (ii) $30.2 million of FERC-mandated reparation
payments to certain Kinder Morgan Energy Partners’ Pacific operations’ pipelines
for settlements reached with certain shippers on its East Line pipeline and
(iii) a $28.0 million increase of gas in underground storage. Significant
period-to period variations in cash used or generated from gas in storage
transactions are generally due to changes in injection and withdrawal volumes as
well as fluctuations in natural gas prices.
Net
cash flows from investing activities during the period were positively affected
by (i) net proceeds of $2,899.3 million from the sale of an 80% ownership
interest in NGPL PipeCo LLC, (ii) $3,106.4 million of proceeds received from
NGPL PipeCo LLC restricted cash upon the sale to Myria (including approximately
$110.0 million we escrowed at the time of the bond closing), (iii) return of
capital from equity investments of $98.1 million consisting of $89.1 million and
$9.0 million from Midcontinent Express Pipeline LLC and NGPL PipeCo LLC,
respectively, (iv) net proceeds received of $111.1 million for the sale of other
assets and (v) a $71.0 million decrease in margin deposits.
These
positive impacts were partially offset by (i) capital expenditures of $2,545.3
million, primarily from Kinder Morgan Energy Partners’ natural gas pipeline
projects, including the construction of Kinder Morgan Louisiana Pipeline, the
expansion of the Trans Mountain crude oil and refined petroleum products
pipeline system and additions to Kinder Morgan Energy Partners’ carbon dioxide
producing and delivery operations, (ii) incremental contributions to equity
investments of $366.2 million, consisting primarily of (a) a $306.0 million
contribution to West2East Pipeline LLC made in February 2008 and (b)
contributions of $27.5 million for Kinder Morgan Energy Partners’ share of
Midcontinent Express Pipeline LLC construction costs, (iii) a $109.6 million
loan to a single customer within Kinder Morgan Energy Partners’ Texas Intrastate
Natural Gas Pipeline Group, (iv) acquisitions of $47.6 million and (v) a $7.2
million increase in underground natural gas storage volumes during the
period.
77
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Net
cash flows used in financing activities during the period were affected by (i) a
use of cash of $5,805.4 million for the retirement of long-term debt, primarily
for (a) $1.6 billion for a cash tender offer to purchase a portion of our
outstanding long-term debt, (b) a $997.5 million use of cash for the retirement
of our Tranche A term loan facilities and (c) a $3,191.8 million use of cash for
the retirement of our Tranche B term loan facilities, (ii) a net $879.2 million
decrease in short-term borrowings relating to our and Kinder Morgan Energy
Partners’ credit facilities and (iii) minority interest distributions of $630.3
million, primarily resulting from Kinder Morgan Energy Partners’ distributions
to common unit holders.
The
impact of these factors were partially offset by (i) net proceeds of $2,097.3
million from Kinder Morgan Energy Partners’ debt issuances, (ii) minority
interest contributions of $561.5 million, primarily from Kinder Morgan Energy
Partners’ issuance of common units from its first and fourth quarter 2008 public
offerings, (iii) an increase in cash book overdrafts of $14.5 million and (iv) a
$2.7 million increase in short-term advances from unconsolidated
affiliates.
Seven
Months Ended December 31, 2007
Net
cash flows from operating activities during the period were positively impacted
by (i) net income of $762.3 million after adjustments for non-cash items
including, among other things, Kinder Morgan Energy Partners’ reparations and
reserve adjustments of $140.0 million, (ii) a $104.0 million source of cash for
working capital items, (iii) $86.5 million of distributions received from equity
investments, (iv) a $51.3 million decrease of gas in underground storage and (v)
$49.1 million of payments received from Kinder Morgan Energy Partners’ pipeline
customers for future service.
Partially
offsetting these factors were (i) a $3.2 million use of cash attributable to
discontinued operations and (ii) a $2.2 million payment for the termination of
interest rate swap agreements.
Net
cash flows used in investing activities during the period were affected by (i)
$11,534.3 million of cash used to purchase Kinder Morgan, Inc. stock in the
Going Private transaction, (ii) $3,030.0 million of cash used to invest in NGPL
PipeCo LLC restricted deposits, (iii) $1,287.0 million in capital expenditures
primarily attributable to Kinder Morgan Energy Partners, (iv) $122.0 million of
other acquisitions, (v) incremental margin deposits of $39.3 million and (vi)
contributions of $246.4 million to equity investments.
These
negative impacts were partially offset by (i) $196.6 million of cash provided by
discontinued investing activities, primarily from the sale of Corridor, (ii)
$301.3 million of net proceeds from the sale of other assets, primarily from the
sale of Kinder Morgan Energy Partners’ North System operations and (iii) $10.0
million of proceeds received from the sale of underground natural gas storage
volumes.
Net
cash flows provided by financing activities during the period were principally
due to (i) $5,112.0 million of equity contributions from investors in the Going
Private transaction, (ii) $4,696.2 million of proceeds, net of issuance costs,
received from the issuance of senior secured credit facilities to partially
finance the Going Private transaction, (iii) $2,986.3 million of net proceeds
from NGPL PipeCo LLC’s issuance of senior notes, (iv) $1,041.7 million of net
proceeds from Kinder Morgan Energy Partners’ public debt offerings, (v) $342.9
million of contributions from minority interest owners attributable to Kinder
Morgan Energy Partners’ issuance of 7.13 million common units and (vi) $98.6
million of net proceeds from Kinder Morgan G.P., Inc.’s Series A
Fixed-to-Floating Rate Term Cumulative Preferred Stock.
The
impact of these factors was partially offset by (i) a $455 million use of cash
for the retirement of our senior secured Tranche C term loan facility, (ii) a
$250 million use of cash for a required payment on senior notes of Kinder Morgan
Energy Partners, (iii) a $110.75 million use of cash for (a) quarterly payments
of $2.5 million on our Tranche A and $8.25 million on our Tranche B term loan
facilities and (b) a $100 million voluntary payment on our Tranche B term loan
facility, (iv) $181.1 million of cash paid to share-based award holders due to
the Going Private transaction, (v) minority interest distributions of $259.6
million, primarily resulting from Kinder Morgan Energy Partners’ distributions
to common unit holders, (vi) a net decrease of $52.6 million in short-term debt
and (vii) a decrease of $14.0 million in cash book overdrafts.
Five
months Ended May 31, 2007
Net
cash flows from operating activities during the period were positively affected
by (i) net income of $688.2 million, after adjustments for non-cash items, (ii)
$109.8 of cash provided by discontinued operations, (iii) net proceeds of $51.9
million from the termination of interest rate swaps and (iv) $48.2 million of
distributions from equity investments.
These
positive factors were partially offset by (i) a use of cash of $202.9 million
for working capital items and (ii) an $84.2 million increase in gas in
underground storage.
Net
cash flows from investing activities during the period were positively impacted
by (i) $1,488.2 million of cash from discontinued investing activities,
primarily from the sales of our discontinued Terasen and U.S.-based retail
operations, (ii) $8.4 million of proceeds received from the sale of underground
natural gas storage volumes and (iii) $8.0 million of cash received for property
casualty indemnifications.
78
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Partially
offsetting these factors were (i) $652.8 million of capital expenditures, (ii) a
$54.8 million use of cash for margin deposits, (iii) incremental acquisitions of
$42.1 million and (iv) $29.7 million of contributions to equity
investments.
Net
cash flows from financing activities during the period were positively impacted
by (i) $992.8 million of net proceeds from Kinder Morgan Energy Partners’ public
debt offerings, (ii) $297.9 million of proceeds from the issuance of Kinder
Morgan Management shares, (iii) $140.1 million of cash provided from
discontinued financing activities, (iii) $56.7 million of cash received for
excess tax benefits from share-based payment arrangements and (iv) $9.9 million
of proceeds received from the issuance of our predecessor’s common
stock.
The
impact of these positive factors was partially offset by (i) a $304.2 million
use of cash for the early retirement of a portion of our senior notes, (ii)
$248.9 million of minority interest distributions, primarily resulting from
Kinder Morgan Energy Partners’ distributions to common unit holders, (iii) a net
decrease of $247.5 million in short-term debt, (iii) $234.9 million paid for
dividends on our predecessor’s common stock and (iv) a decrease of $14.9 million
in cash book overdrafts.
Year
Ended December 31, 2006
Net
cash flows from operating activities during the period were positively affected
by (i) net income of $1,425.7 million, after adjustments for non-cash items,
(ii) $212.6 of cash provided by discontinued operations, (iii) an $80.0 million
source of cash for working capital items and (iv) $74.8 million of distributions
from equity investments.
These
positive factors were partially offset by (i) a $35.3 million increase in gas in
underground storage and (ii) $19.1 million of payments made to certain shippers
on Kinder Morgan Energy Partners’ West Coast Products Pipelines as a result of a
settlement agreement regarding delivery tariffs and gathering enhancement fees
at its Watson Station.
Net
cash flows used in investing activities during the period were affected by (i)
$1,375.6 million in capital expenditures, (ii) $407.1 million of acquisitions,
(iii) $251.0 million of cash used for discontinued investing activities,
primarily attributable to Terasen’s capital expenditures, (iv) $12.9 million for
investments in underground storage volumes and payments made for natural gas
liquids line-fill and (v) contributions of $6.1 million to equity
investments.
These
negative impacts were partially offset by (i) $112.9 million of proceeds
received for the sale of Terasen’s discontinued Water and Utility Services, (ii)
$92.2 million of net proceeds from the sale of other assets, (iii) $38.6 million
of net proceeds from the sale of margin deposits and (iv) $13.1 million of cash
received for property casualty indemnifications.
Net
cash flows from financing activities during the period were positively impacted
by (i) a net increase of $1,009.5 million in short-term debt, (ii) $353.8
million of contributions from minority interest owners, primarily Kinder Morgan
Energy Partners’ issuance of 5.75 million common units receiving net proceeds
(after underwriting discount) of $248.0 million and Sempra Energy’s $104.2
million contribution for its 33 1/3 % share of the purchase price of Entrega
Pipeline LLC, (iii) $38.7 million of proceeds received from the issuance of our
predecessor’s common stock, (iv) $18.6 million of cash received for excess tax
benefits from share-based payment arrangements and (v) an increase of $17.9
million in cash book overdrafts.
The
impact of these positive factors was partially offset by (i) $575.0 million of
minority interest distributions, primarily resulting from Kinder Morgan Energy
Partners’ distributions to common unit holders, (ii) $468.5 million paid for
dividends on our predecessor’s common stock, (iii) $125.0 million of cash used
to retire our 7.35% Series debentures which were elected by the holders to be
redeemed on August 1, 2006 as provided in the indenture governing the
debentures, (iv) a $118.1 million use of cash related to our discontinued
Terasen financing activities, (v) $34.3 million in cash paid to repurchase our
predecessor’s common shares and (vi) a $4.9 million use of cash for short-term
advances to unconsolidated affiliates.
Kinder
Morgan Energy Partners’ partnership agreement requires that it distribute 100%
of “Available Cash,” as defined in its partnership agreement, to its 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 Kinder Morgan Energy Partners’ cash receipts, including cash received by its
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. (“SFPP”), in respect of its remaining 0.5% interest in
SFPP.
Kinder
Morgan Management, as the delegate of Kinder Morgan G.P., Inc., of which we
indirectly own all of the outstanding common equity, and the general partner of
Kinder Morgan Energy Partners, is granted discretion 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 Kinder Morgan Management
determines Kinder Morgan Energy Partners’ quarterly distributions, it considers
current and expected reserve needs along with current and expected cash flows to
identify the appropriate sustainable distribution level.
79
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
Available
cash is initially distributed 98% to Kinder Morgan Energy Partners’ limited
partners with 2% retained by Kinder Morgan G.P., Inc. as Kinder Morgan Energy
Partners’ general partner. These distribution percentages are modified to
provide for incentive distributions to be retained by Kinder Morgan G.P., Inc.
as general partner of Kinder Morgan Energy Partners in the event that quarterly
distributions to unitholders exceed certain specified targets.
Available
cash for each quarter is distributed:
|
|
·
|
first,
98% to the owners of all classes of units pro rata and 2% to Kinder Morgan
G.P., Inc. as general partner of Kinder Morgan Energy Partners until the
owners of all classes of units have received a total of $0.15125 per unit
in cash or equivalent i-units for such
quarter;
|
|
|
·
|
second,
85% of any available cash then remaining to the owners of all classes of
units pro rata and 15% to Kinder Morgan G.P., Inc. as general partner of
Kinder Morgan Energy Partners until the owners of all classes of units
have received a total of $0.17875 per unit in cash or equivalent i-units
for such quarter;
|
|
|
·
|
third,
75% of any available cash then remaining to the owners of all classes of
units pro rata and 25% to Kinder Morgan G.P., Inc. as general partner of
Kinder Morgan Energy Partners until the owners of all classes of units
have received a total of $0.23375 per unit in cash or equivalent i-units
for such quarter; and
|
|
|
·
|
fourth,
50% of any available cash then remaining to the owners of all classes of
units pro rata, to owners of common units in cash and to Kinder Morgan
Management as owners of i-units in the equivalent number of i-units, and
50% to Kinder Morgan G.P., Inc. as general partner of Kinder Morgan Energy
Partners.
|
During
the year ended December 31, 2008, Kinder Morgan Energy Partners paid
distributions of $3.89 per common unit, of which $626.6 million was paid to the
public holders (represented in minority interests) of Kinder Morgan Energy
Partners’ common units. On January 21, 2009, Kinder Morgan Energy Partners
declared a quarterly distribution of $1.05 per common unit for the quarterly
period ended December 31, 2008. The distribution was paid on February 13, 2009,
to unitholders of record as of January 30, 2009.
SFAS
No. 157, Fair Value
Measurements establishes a hierarchal disclosure framework associated
with the level of pricing observability utilized in measuring fair value. The
hierarchy of valuation techniques is based upon whether the inputs to those
valuation techniques reflect assumptions other market participants would use
based upon market data obtained from independent sources (observable inputs) or
reflect a company’s own assumptions of market participant valuation
(unobservable inputs). This framework defines three levels of inputs to the fair
value measurement process, and requires that each fair value measurement be
assigned to a level corresponding to the lowest level input that is significant
to the fair value measurement in its entirety. In accordance with SFAS No. 157,
the lowest level of fair value hierarchy based on these two types of inputs is
designated as Level 3 and is based on prices or valuations that require inputs
that are both significant to the fair value measurement and
unobservable.
As
of December 31, 2008, the fair value of our derivative contracts classified as
Level 3 under the established fair value hierarchy consisted primarily of West
Texas Intermediate (“WTI”) crude oil options (costless collars) and West Texas
Sour (“WTS”) crude oil hedges. Costless collars are designed to establish floor
and ceiling prices on anticipated future oil production from the assets we own
in the SACROC oil field unit. While the use of these derivative contracts limits
the downside risk of adverse price movements, they may also limit future
revenues from favorable price movements. In addition to these oil-commodity
derivatives, our Level 3 derivative contracts included natural gas basis swaps
and natural gas options. Basis swaps are used in connection with another
derivative contract to reduce hedge ineffectiveness by reducing a basis
difference between a hedged exposure and a derivative contract. Natural gas
options are used to offset the exposure related to certain physical
contracts.
The
following table summarizes the total fair value asset and liability measurements
of our Level 3 energy commodity derivative contracts in accordance with SFAS No.
157.
|
Significant
Unobservable Inputs (Level 3)
|
|||||||||||||||||||||||
|
Assets
|
Liabilities
|
||||||||||||||||||||||
|
December
31,
2008
|
December
31,
2007
|
Change
|
December
31,
2008
|
December
31,
2007
|
Change
|
||||||||||||||||||
|
WTI
Options
|
$
|
34.3
|
$
|
—
|
$
|
34.3
|
$
|
(2.2
|
)
|
$
|
—
|
$
|
(2.2
|
)
|
|||||||||
|
WTS
Oil Swaps
|
17.1
|
—
|
17.1
|
(0.2
|
)
|
(94.5
|
)
|
94.3
|
|||||||||||||||
|
Natural
Gas Basis Swaps
|
3.3
|
2.8
|
0.5
|
(5.2
|
)
|
(4.7
|
)
|
(0.5
|
)
|
||||||||||||||
|
Natural
Gas Options
|
—
|
—
|
—
|
(2.7
|
)
|
—
|
(2.7
|
)
|
|||||||||||||||
|
Other
|
0.5
|
1.0
|
(0.5
|
)
|
(0.8
|
)
|
(4.9
|
)
|
4.1
|
||||||||||||||
|
Total
|
$
|
55.2
|
$
|
3.8
|
$
|
51.4
|
$
|
(11.1
|
)
|
$
|
(104.1
|
)
|
$
|
93.0
|
|||||||||
80
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
The
largest changes in the fair value of our Level 3 assets and liabilities between
December 31, 2007 and December 31, 2008 were related to West Texas Intermediate
options and West Texas Sour hedges. We entered into the majority of our WTI
option contracts during 2008, which accounts for the changes. The changes in
value from our WTS swap contracts were largely due to favorable crude oil price
changes since the end of 2007. There were no transfers into or out of Level 3
during the period.
The
valuation techniques used for the above Level 3 input derivative contracts are
as follows:
|
|
·
|
Option
contracts—valued using internal model. Internal models incorporate the use
of options pricing and estimates of the present value of cash flows based
upon underlying contractual terms. The models reflect management’s
estimates, taking into account observable market prices, estimated market
prices in the absence of quoted market prices, the risk-free market
discount rate, volatility factors, estimated correlations of commodity
prices and contractual volumes;
|
|
|
·
|
WTS
oil swaps—prices obtained from a broker using their proprietary model for
similar assets and liabilities (quotes are non-binding);
and
|
|
|
·
|
Natural
gas basis swaps—values obtained through a pricing service, derived by
combining raw inputs from the New York Mercantile Exchange (referred to in
this report as NYMEX) with proprietary quantitative models and processes.
Although the prices are originating from a liquid market (NYMEX), we
believe the incremental effort to further validate these prices would take
undue effort and would not materially alter the assumptions. As a result,
we have classified the valuation of these derivatives as Level
3.
|
For
our energy commodity derivative contracts, the most observable inputs available
are used to determine the fair value of each contract. In the absence of a
quoted price for an identical contract in an active market, we use broker quotes
for identical or similar contracts, or internally prepared valuation models as
primary inputs to determine fair value. No adjustments were made to quotes or
prices obtained from brokers and pricing services, and our valuation methods
have not changed during the year ended December 31, 2008.
When
appropriate, valuations are adjusted for various factors including credit
considerations. Such adjustments are generally based on available market
evidence, including but not limited to our credit default swap quotes as of
December 31, 2008. Collateral agreements with our counterparties serve to reduce
our credit exposure and are considered in the adjustment. We adjust the fair
value measurements of our energy commodity derivative contracts for credit risk
in accordance with SFAS No. 157, and as of December 31, 2008, the net assets
balance associated with these contracts recorded in the accompanying
Consolidated Balance Sheet included a reduction of $2.2 million related to
discounting the value of our energy commodity derivative net assets for the
effect of credit risk.
With
the exception of the Casper and Douglas natural gas processing plant hedges and
the ineffective portion of our derivative contracts, our energy commodity
derivative contracts are accounted for as cash flow hedges. In accordance with
SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities and associated amendments
(“SFAS No. 133”), gains and losses associated with cash flow hedges are reported
in “Accumulated Other Comprehensive Loss” in the accompanying Consolidated
Balance Sheets.
As
of December 31, 2008, we have recorded a total reserve for environmental claims,
without discounting and without regard to anticipated insurance recoveries, in
the amount of $85.0 million. In addition, we have recorded a receivable of $20.9
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. As of December 31,
2007, our total reserve for environmental claims, without discounting and
without regard to anticipated insurance recoveries, amounted to $102.6
million.
Additionally,
as of December 31, 2008, we have recorded a total reserve for legal fees,
transportation rate cases and other litigation liabilities in the amount of
$234.8 million. The reserve is primarily related to various claims from lawsuits
arising from Kinder Morgan Energy Partners’ West Coast Products Pipelines, and
the recorded amount is based on both the estimated amount associated with
possible outcomes and probabilities of occurrence associated with such outcomes.
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, 2007, our total reserve for legal fees, transportation rate cases
and other litigation liabilities amounted to $249.4 million.
81
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
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. However, changing circumstances
could cause these matters to have a material adverse impact.
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 Note 21 of the accompanying Notes to Consolidated Financial Statements
for additional information regarding pending litigation and environmental
matters.
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 may 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 and we met that deadline. We have
included all incremental expenditures estimated to occur during 2009 associated
with the Pipeline Safety Improvement Act of 2002 and the integrity management of
our products pipelines in our 2009 budget and capital expenditure
plan.
Please
refer to Note 20 of the accompanying Notes to Consolidated Financial Statements
for additional information regarding regulatory matters.
Refer
to Note 22 of the accompanying Notes to Consolidated Financial Statements for
information regarding recent accounting pronouncements.
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 service debt or to pay
dividends 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 that could cause actual results to differ from those
in the forward-looking statements include:
|
|
·
|
price
trends and overall demand for natural gas liquids, refined petroleum
products, oil, carbon dioxide, natural gas, electricity, coal and other
bulk materials and chemicals in North
America;
|
|
|
·
|
economic
activity, weather, alternative energy sources, conservation and
technological advances that may affect price trends and
demand;
|
|
|
·
|
changes
in tariff rates charged by our or those of Kinder Morgan Energy Partners’
pipeline subsidiaries implemented by the Federal Energy Regulatory
Commission, or other regulatory agencies or the California Public
Utilities Commission;
|
|
|
·
|
our
ability to acquire new businesses and assets and integrate those
operations into our existing operations, as well as the ability to expand
our facilities;
|
|
|
·
|
difficulties
or delays experienced by railroads, barges, trucks, ships or pipelines in
delivering products to or from Kinder Morgan Energy Partners’ terminals or
pipelines;
|
|
|
·
|
our
ability to successfully identify and close acquisitions and make
cost-saving changes in operations;
|
|
|
·
|
shut-downs
or cutbacks at major refineries, petrochemical or chemical plants, ports,
utilities, military bases or other
|
82
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations (continued)
|
Knight
Form 10-K
|
|
|
businesses
that use our services or provide services or products to
us;
|
|
|
·
|
crude
oil and natural gas production from exploration and production areas that
we or Kinder Morgan Energy Partners serve, such as the Permian Basin area
of West Texas, the U.S. Rocky Mountains and the Alberta oil
sands;
|
|
|
·
|
changes
in laws or regulations, third-party relations and approvals and decisions
of courts, regulators and governmental bodies that may adversely affect
our business or ability to compete;
|
|
|
·
|
changes
in accounting pronouncements that impact the measurement of our results of
operations, the timing of when such measurements are to be made and
recorded, and the disclosures surrounding these
activities;
|
|
|
·
|
our
ability to offer and sell equity securities, and Kinder Morgan Energy
Partners’ ability to offer and sell equity securities and its ability to
sell debt securities or obtain debt financing in sufficient amounts to
implement that portion of our or Kinder Morgan Energy Partners’ business
plans that contemplates growth through acquisitions of operating
businesses and assets and expansions of
facilities;
|
|
|
·
|
our
indebtedness, which could make us vulnerable to general adverse economic
and industry conditions, limit our ability to borrow additional funds
and/or place us at competitive disadvantages compared to our competitors
that have less debt or have other adverse
consequences;
|
|
|
·
|
interruptions
of electric power supply to our facilities due to natural disasters, power
shortages, strikes, riots, terrorism, war or other
causes;
|
|
|
·
|
our
ability to obtain insurance coverage without significant levels of
self-retention of risk;
|
|
|
·
|
acts
of nature, sabotage, terrorism or other similar acts causing damage
greater than our insurance coverage
limits;
|
|
|
·
|
capital
and credit markets conditions, including availability of credit generally,
as well as inflation and interest
rates;
|
|
|
·
|
the
political and economic stability of the oil producing nations of the
world;
|
|
|
·
|
national,
international, regional and local economic, competitive and regulatory
conditions and developments;
|
|
|
·
|
our
ability to achieve cost savings and revenue
growth;
|
|
|
·
|
foreign
exchange fluctuations;
|
|
|
·
|
the
timing and extent of changes in commodity prices for oil, natural gas,
electricity and certain agricultural
products;
|
|
|
·
|
the
extent of Kinder Morgan Energy Partners’ 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;
|
|
|
·
|
engineering
and mechanical or technological difficulties that Kinder Morgan Energy
Partners may experience with operational equipment, in well completions
and workovers, and in drilling new
wells;
|
|
|
·
|
the
uncertainty inherent in estimating future oil and natural gas production
or reserves that Kinder Morgan Energy Partners may
experience;
|
|
|
·
|
the
ability to complete expansion projects on time and on
budget;
|
|
|
·
|
the
timing and success of Kinder Morgan Energy Partners’ and our business
development efforts; and
|
|
|
·
|
unfavorable
results of litigation and the fruition of contingencies referred to in the
accompanying Notes to Consolidated Financial
Statements.
|
The
foregoing list should not
be construed to be exhaustive. We believe the forward-looking statements in this
report are reasonable. However, 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.
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
83
|
Item 7A.
Quantitative
and Qualitative Disclosures About Market Risk.
(continued)
|
Knight
Form 10-K
|
predictable
earnings stream. Stated another way, we execute a hedging strategy that seeks to
protect us financially 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, or anticipated 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
policies require that we only enter into derivative contracts with carefully
selected major financial institutions or similar counterparties based upon their
credit ratings and other factors, and we maintain strict dollar and term limits
that correspond to our counterparties’ credit ratings. While we enter into
derivative transactions only with investment grade counterparties and actively
monitor their credit ratings, it is nevertheless possible that losses will
result from counterparty credit risk in the future. The credit ratings of the
primary parties from whom we transact in energy commodity derivative contracts
(based on contract market values) are as follows (credit ratings per
Standard & Poor’s Rating Services):
|
Credit
Rating
|
|
|
Citigroup
|
A
|
|
J.
Aron & Company / Goldman Sachs
|
A
|
|
Morgan
Stanley
|
A
|
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 for this purpose helps provide us increased certainty
with regard to our operating cash flows and 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 the
accompanying Consolidated Statements of Operations, 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 are recorded in other comprehensive income (loss), pending
occurrence of the expected transaction. Other comprehensive income (loss)
consists of those financial items that are included in “Accumulated Other
Comprehensive Loss” in the 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 until the
expected transaction occurs.
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.
The
accumulated components of other comprehensive income are to be reported
separately as accumulated other comprehensive income or loss in the
stockholder’s equity section of the balance sheet. For us, the amounts included
in “Accumulated Other Comprehensive Loss” in the accompanying Consolidated
Balance Sheets primarily include (i) the effective portion of the gains and
losses on cash flow hedging items, (ii) gains and losses and prior service costs
or credits associated with our pension and postretirement plans and (iii)
foreign currency translation adjustments. The gains and losses on hedging items
primarily relate 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. Amounts related to our pension
and
84
|
Item 7A.
Quantitative
and Qualitative Disclosures About Market Risk.
(continued)
|
Knight
Form 10-K
|
postretirement
plans result from gains and losses and prior service costs or credits that have
not been recognized as a component of net periodic benefit costs. The
translation adjustments are a cumulative total, resulting from translating all
of our foreign denominated assets and liabilities at current exchange rates,
while equity is translated by using historical or weighted-average exchange
rates.
The
total “Accumulated Other Comprehensive Loss” balance of $53.4 million included
in the accompanying Consolidated Balance Sheet at December 31, 2008 consisted of
(i) $5.1 million representing unrecognized net gains on energy commodity price
risk management activities, (ii) $35.8 million representing unrecognized net
gains relating to foreign currency translation adjustments and (iii) $94.3
million representing unrecognized net losses relating to the employee benefit
plans. The total “Accumulated Other Comprehensive Loss” balance of $247.7
million included in the accompanying Consolidated Balance Sheet at December 31,
2007 consisted of (i) $237.3 million representing unrecognized net losses on
energy commodity price risk management activities, (ii) $18.4 million
representing unrecognized net gains relating to foreign currency translation
adjustments and (iii) $28.8 million representing unrecognized net losses
relating to the employee benefit plans.
In
future periods, as the hedged cash flows from our actual purchases and sales of
energy commodities affect our net income, the related gains and losses included
in our accumulated other comprehensive loss as a result of our hedging are
transferred to the income statement as well, effectively offsetting the changes
in cash flows stemming from the hedged risk.
We
measure the risk of price changes in the natural gas, natural gas liquids and
crude oil markets utilizing a value-at-risk model. Value-at-risk is a
statistical measure indicating the minimum expected loss in a portfolio over a
given time period, 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, 2008 and 2007, our value-at-risk reached a
high of $1.8 million and $2.1 million, respectively, and a low of $0.7 million
and $0.7 million, respectively. Value-at-risk as of December 31, 2008 was $0.7
million, and averaged $1.5 million for 2008. Value-at-risk as of December 31,
2007 was $1.7 million, and averaged $1.4 million for 2007.
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 15 of the accompanying Notes to Consolidated Financial
Statements.
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, 2008 and 2007, the carrying values of our long-term fixed rate
debt were approximately $9,232.8 million and $8,439.2 million, respectively.
These amounts compare to fair values of $9,838.1 million and $10,651.3 million
as of December 31, 2008 and 2007, respectively. A 100 basis point change of the
average interest rates applicable to such debt for 2008 and 2007 would result in
changes of approximately $98.4 million and $106.5 million, respectively, in the
fair values of these instruments.
85
|
Item 7A.
Quantitative
and Qualitative Disclosures About Market Risk.
(continued)
|
Knight
Form 10-K
|
The
carrying value of our long-term variable rate debt, excluding the value of
interest rate swap agreements (discussed below), was $2,894.0 million and
$6,858.2 million as of December 31, 2008 and 2007, respectively. A 100 basis
point change of the weighted-average interest rate applicable to such debt, when
applied to our outstanding balance of variable rate debt as of December 31, 2008
and 2007, including adjustments for notional swap amounts, would result in
changes of approximately $28.9 million and $68.6 million, respectively, in our
2008 and 2007 annual pre-tax earnings.
We
adjusted the fair value measurement of our long-term debt in accordance with
SFAS No. 157, and the estimated fair value of our debt as of December 31, 2008
includes a discount related to the effect of credit risk.
As
of December 31, 2008, Kinder Morgan Energy Partners was a party to an interest
rate swap agreement with a notional principal amount of $2.8 billion. As of
December 31, 2007, we and our subsidiary Kinder Morgan Energy Partners were
party to interest rate swap agreements with notional principal amounts of $275
million and $2.3 billion, respectively, for a consolidated total of $2.575
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 purpose of 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 both December 31, 2008 and 2007, 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,
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.
As
of December 31, 2008, our cash and investment portfolio included approximately
$13.2 million in fixed-income debt securities. Because our investment in debt
securities was made and will be maintained in the future to directly offset the
interest rate risk on a like amount of long-term debt, a hypothetical 10%
increase in interest rates would not have a material effect on the fair market
value of our portfolio; and because 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
Notes 14, 15 and 23 of the accompanying Notes to Consolidated Financial
Statements for additional information on activity related to our debt
instruments and interest rate swap agreements.
Foreign
Currency Risk
We
are exposed to foreign currency risk from our investments in businesses owned
and operated outside the United States. To mitigate this risk, we have several
receive-fixed-rate, pay-fixed-rate U.S. dollar to Canadian dollar cross-currency
interest rate swap agreements that have been designated as a hedge of our net
investment in Canadian operations in accordance with SFAS No. 133. A 1% change
in the U.S. Dollar to Canadian Dollar exchange rate would impact the fair value
of these swap agreements by approximately $1.09 million.
86
|
Knight
Form 10-K
|
INDEX
|
Page
|
|
|
|
|
|
88-89
|
|
|
90
|
|
|
91
|
|
|
92-93
|
|
|
94-95
|
|
|
96-97
|
|
|
98-178
|
|
|
178
|
|
|
179-182
|
|
|
|
87
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
To
the Board of Directors
and
Stockholder of Knight Inc.:
In
our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, of comprehensive income, of stockholder’s
equity and of cash flows present fairly, in all material respects, the financial
position of Knight Inc. and its subsidiaries (the “Company”) at December 31,
2008 and 2007, and the results of their operations and their cash flows for the
year ended December 31, 2008 and the period from June 1, 2007 to December 31,
2007 in conformity with accounting principles generally accepted in the United
States of America. Also in our opinion, the Company maintained, in
all material respects, effective internal control over financial reporting as of
December 31, 2008, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible
for these financial statements, for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in Management’s Report on Internal
Control Over Financial Reporting appearing in item 9A. Our
responsibility is to express opinions on these financial statements and on the
Company’s internal control over financial reporting based on our integrated
audit. We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable assurance about whether
the financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included 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. Our audits of internal control over financial reporting
included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on
the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our
audits provide 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 assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
As
described in Management’s Report on Internal Control Over Financial Reporting,
management has excluded:
|
|
·
|
The
bulk terminal assets acquired from Chemserve, Inc., effective August 15,
2008; and
|
|
|
·
|
The
refined petroleum products storage terminal acquired from ConocoPhillips,
effective December 10, 2008,
|
(the
“Acquired Businesses”) from its assessment of internal control over financial
reporting as of December 31, 2008 because these businesses were each acquired by
the Company in purchase business combinations during 2008. We have
also excluded the Acquired Businesses from our audit of internal control over
financial reporting. These Acquired Businesses are wholly-owned
subsidiaries whose total assets and total revenues, in the aggregate, represent
0.23% and 0.01%, respectively, of the related consolidated financial statement
amounts as of and for the year ended December 31, 2008.
PricewaterhouseCoopers
LLP
Houston,
Texas
March
31, 2009
88
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Report of Independent
Registered Public Accounting Firm
To
the Board of Directors
and
Stockholder of Knight Inc.:
In
our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, of comprehensive income, of stockholder's
equity and of cash flows present fairly, in all material respects, the financial
position of Knight Inc. and its subsidiaries (the "Company") at December 31,
2006, and the results of their operations and their cash flows for the period
from January 1, 2007 to May 31, 2007, and the years ended December 31, 2006 and
2005 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility
of the Company’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 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.
PricewaterhouseCoopers
LLP
Houston,
Texas
March
28, 2008, except as to Note 19,
for
which the date is January 8, 2009
89
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
CONSOLIDATED
STATEMENTS OF OPERATIONS
(In
millions)
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Operating
Revenues
|
||||||||||||||||
|
Natural
Gas Sales
|
$
|
7,705.8
|
$
|
3,623.1
|
$
|
2,430.6
|
$
|
6,225.6
|
||||||||
|
Services
|
2,904.0
|
2,049.8
|
1,350.5
|
3,082.3
|
||||||||||||
|
Product
Sales and Other
|
1,485.0
|
721.8
|
384.0
|
900.7
|
||||||||||||
|
Total
Operating Revenues
|
12,094.8
|
6,394.7
|
4,165.1
|
10,208.6
|
||||||||||||
|
|
||||||||||||||||
|
Operating
Costs and Expenses
|
||||||||||||||||
|
Gas
Purchases and Other Costs of Sales
|
7,744.0
|
3,656.6
|
2,490.4
|
6,339.4
|
||||||||||||
|
Operations
and Maintenance
|
1,318.0
|
943.3
|
476.1
|
1,155.4
|
||||||||||||
|
General
and Administrative
|
352.5
|
175.6
|
283.6
|
305.1
|
||||||||||||
|
Depreciation,
Depletion and Amortization
|
918.4
|
472.3
|
261.0
|
531.4
|
||||||||||||
|
Taxes,
Other Than Income Taxes
|
191.4
|
110.1
|
74.4
|
165.0
|
||||||||||||
|
Other
Expenses (Income)
|
9.3
|
(6.0
|
)
|
(2.3
|
)
|
(34.1
|
)
|
|||||||||
|
Impairment
of Assets
|
4,033.3
|
-
|
377.1
|
1.2
|
||||||||||||
|
Total
Operating Costs and Expenses
|
14,566.9
|
5,351.9
|
3,960.3
|
8,463.4
|
||||||||||||
|
Operating
Income (Loss)
|
(2,472.1
|
)
|
1,042.8
|
204.8
|
1,745.2
|
|||||||||||
|
|
||||||||||||||||
|
Other
Income and (Expenses)
|
||||||||||||||||
|
Earnings
of Equity Investees
|
195.4
|
53.4
|
38.3
|
98.6
|
||||||||||||
|
Interest
Expense, Net
|
(633.4
|
)
|
(581.5
|
)
|
(241.1
|
)
|
(552.8
|
)
|
||||||||
|
Interest
Income (Expense)—Deferrable Interest Debentures
|
5.1
|
(12.8
|
)
|
(9.1
|
)
|
(21.9
|
)
|
|||||||||
|
Minority
Interests
|
(396.1
|
)
|
(37.6
|
)
|
(90.7
|
)
|
(374.2
|
)
|
||||||||
|
Other,
Net
|
7.0
|
11.6
|
0.6
|
(8.6
|
)
|
|||||||||||
|
Total
Other Income and (Expenses)
|
(822.0
|
)
|
(566.9
|
)
|
(302.0
|
)
|
(858.9
|
)
|
||||||||
|
Income
(Loss) from Continuing Operations Before Income Taxes
|
(3,294.1
|
)
|
475.9
|
(97.2
|
)
|
886.3
|
||||||||||
|
Income
Taxes
|
304.3
|
227.4
|
135.5
|
285.9
|
||||||||||||
|
Income
(Loss) from Continuing Operations
|
(3,598.4
|
)
|
248.5
|
(232.7
|
)
|
600.4
|
||||||||||
|
Income
(Loss) from Discontinued Operations, Net of Tax
|
(0.9
|
)
|
(1.5
|
)
|
298.6
|
(528.5
|
)
|
|||||||||
|
Net
Income (Loss)
|
$
|
(3,599.3
|
)
|
$
|
247.0
|
$
|
65.9
|
$
|
71.9
|
|||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
90
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME
(In
millions)
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Net
Income (Loss)
|
$
|
(3,599.3
|
)
|
$
|
247.0
|
$
|
65.9
|
$
|
71.9
|
|||||||
|
Other
Comprehensive Income (Loss), Net of Tax:
|
||||||||||||||||
|
Change
in Fair Value of Derivatives Utilized for Hedging Purposes (Net of Tax of
$121.3, Tax Benefit of $140.8, $19.1, and Tax of $26.8,
Respectively)
|
212.0
|
(249.6
|
)
|
(21.3
|
)
|
44.6
|
||||||||||
|
Reclassification
of Change in Fair Value of Derivatives to Net Income (Net of Tax of $69.4,
Tax Benefit of $0.6, Tax of $12.8 and $11.9, Respectively)
|
117.1
|
-
|
10.3
|
21.7
|
||||||||||||
|
Employee
Benefit Plans:
|
||||||||||||||||
|
Prior
Service Cost Arising During Period (Net of Tax Benefit of $0.2 and $1.0,
Respectively)
|
(0.3
|
)
|
-
|
(1.7
|
)
|
-
|
||||||||||
|
Net
(Loss) Gain Arising During Period (Net of Tax Benefit of $37.5, $15.3, and
Tax of $6.7, Respectively)
|
(66.2
|
)
|
(28.4
|
)
|
11.4
|
-
|
||||||||||
|
Amortization
of Prior Service Cost Included in Net Periodic Benefit Costs (Net of Tax
Benefit of $0.2)
|
-
|
-
|
(0.4
|
)
|
-
|
|||||||||||
|
Amortization
of Net Loss (Gain) Included in Net Periodic Benefit Costs (Net of Tax of
$0.2, Tax Benefit of Less than $0.1, and Tax of $0.8,
Respectively)
|
0.4
|
(0.2
|
)
|
1.4
|
-
|
|||||||||||
|
Change
in Foreign Currency Translation Adjustment (Net of Tax Benefit of $31.0,
Tax of $8.3, $3.9 and Tax Benefit of $11.5, Respectively)
|
(68.7
|
)
|
27.6
|
40.1
|
(31.9
|
)
|
||||||||||
|
Adjustment
to Recognize Minimum Pension Liability (Net of Tax of
$1.7)
|
-
|
-
|
-
|
3.5
|
||||||||||||
|
Total
Other Comprehensive Income (Loss)
|
194.3
|
(250.6
|
)
|
39.8
|
37.9
|
|||||||||||
|
|
||||||||||||||||
|
Comprehensive
Income (Loss)
|
$
|
(3,405.0
|
)
|
$
|
(3.6
|
)
|
$
|
105.7
|
$
|
109.8
|
||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
91
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
December
31,
2008
|
December
31,
2007
|
||||||
|
ASSETS
|
|||||||
|
Current
Assets
|
|||||||
|
Cash
and Cash Equivalents
|
$
|
118.6
|
$
|
148.6
|
|||
|
Restricted
Deposits
|
-
|
67.9
|
|||||
|
Accounts,
Notes and Interest Receivable, Net
|
992.5
|
975.2
|
|||||
|
Inventories
|
44.2
|
37.8
|
|||||
|
Gas
Imbalances
|
14.1
|
26.9
|
|||||
|
Assets
Held for Sale
|
-
|
3,353.3
|
|||||
|
Fair
Value of Derivative Instruments
|
115.2
|
37.1
|
|||||
|
Other
|
32.6
|
36.8
|
|||||
|
1,317.2
|
4,683.6
|
||||||
|
|
|||||||
|
Property,
Plant and Equipment, Net
|
16,109.8
|
14,803.9
|
|||||
|
Notes
Receivable—Related Parties
|
178.1
|
87.9
|
|||||
|
Investments
|
1,827.4
|
1,996.2
|
|||||
|
Goodwill
|
4,698.7
|
8,174.0
|
|||||
|
Other
Intangibles, Net
|
251.5
|
321.1
|
|||||
|
Assets
Held for Sale, Non-current
|
-
|
5,634.6
|
|||||
|
Fair
Value of Derivative Instruments, Non-current
|
828.0
|
143.5
|
|||||
|
Deferred
Charges and Other Assets
|
234.2
|
256.2
|
|||||
|
Total
Assets
|
$
|
25,444.9
|
$
|
36,101.0
|
|||
92
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
KNIGHT
INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS (continued)
(In
millions except share and per share amounts)
|
December
31,
2008
|
December
31,
2007
|
||||||
|
LIABILITIES
AND STOCKHOLDER’S EQUITY
|
|||||||
|
Current
Liabilities
|
|||||||
|
Current
Maturities of Long-term Debt
|
$
|
293.7
|
$
|
79.8
|
|||
|
Notes
Payable
|
8.8
|
888.1
|
|||||
|
Cash
Book Overdrafts
|
45.2
|
30.7
|
|||||
|
Accounts
Payable
|
849.8
|
943.7
|
|||||
|
Accrued
Interest
|
241.9
|
242.7
|
|||||
|
Accrued
Taxes
|
152.1
|
728.2
|
|||||
|
Gas
Imbalances
|
12.4
|
23.7
|
|||||
|
Liabilities
Held for Sale
|
-
|
168.2
|
|||||
|
Fair
Value of Derivative Instruments
|
129.5
|
594.7
|
|||||
|
Other
|
281.3
|
240.0
|
|||||
|
2,014.7
|
3,939.8
|
||||||
|
|
|||||||
|
Long-term
Debt
|
|||||||
|
Outstanding
Notes and Debentures
|
11,020.1
|
14,714.6
|
|||||
|
Deferrable
Interest Debentures Issued to Subsidiary Trusts
|
35.7
|
283.1
|
|||||
|
Preferred
Interest in General Partner of Kinder Morgan Energy
Partners
|
100.0
|
100.0
|
|||||
|
Value
of Interest Rate Swaps
|
971.0
|
199.7
|
|||||
|
|
12,126.8
|
15,297.4
|
|||||
|
|
|||||||
|
Deferred
Income Taxes, Non-current
|
2,081.3
|
1,849.4
|
|||||
|
Liabilities
Held for Sale, Non-current
|
-
|
2,424.1
|
|||||
|
Fair
Value of Derivative Instruments, Non-current
|
92.2
|
888.0
|
|||||
|
Other
Long-term Liabilities and Deferred Credits
|
653.0
|
566.8
|
|||||
|
14,953.3
|
21,025.7
|
||||||
|
Minority
Interests in Equity of Subsidiaries
|
4,072.6
|
3,314.0
|
|||||
|
Commitments
and Contingencies (Notes 18 and 21)
|
|||||||
|
|
|||||||
|
Stockholder’s
Equity
|
|||||||
|
Common
Stock – Authorized and Outstanding – 100 Shares, Par Value $0.01 Per
Share
|
-
|
-
|
|||||
|
Additional
Paid-in Capital
|
7,810.0
|
7,822.2
|
|||||
|
Retained
Earnings (Deficit)
|
(3,352.3
|
)
|
247.0
|
||||
|
Accumulated
Other Comprehensive Loss
|
(53.4
|
)
|
(247.7
|
)
|
|||
|
4,404.3
|
7,821.5
|
||||||
|
Total
Liabilities and Stockholder’s Equity
|
$
|
25,444.9
|
$
|
36,101.0
|
|||
The
accompanying notes are an integral part of these consolidated financial
statements.
93
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
CONSOLIDATED
STATEMENTS OF STOCKHOLDER’S EQUITY
(Dollars
in millions)
|
Successor
Company
|
|||||||||||||||
|
Year
Ended
December
31, 2008
|
Seven
Months Ended
December
31, 2007
|
||||||||||||||
|
Shares
|
Amount
|
Shares
|
Amount
|
||||||||||||
|
Common
Stock
|
100
|
$
|
-
|
100
|
$
|
-
|
|||||||||
|
|
|||||||||||||||
|
Additional
Paid-in Capital
|
|||||||||||||||
|
Beginning
Balance
|
7,822.2
|
-
|
|||||||||||||
|
MBO
Purchase Price
|
-
|
7,831.2
|
|||||||||||||
|
Revaluation
of Kinder Morgan Energy Partners (“KMP”) Investment (Note
14)
|
(19.8
|
)
|
(13.4
|
)
|
|||||||||||
|
A-1
Unit Amortization
|
7.6
|
4.4
|
|||||||||||||
|
Ending
Balance
|
7,810.0
|
7,822.2
|
|||||||||||||
|
|
|||||||||||||||
|
Retained
Earnings (Deficit)
|
|||||||||||||||
|
Beginning
Balance
|
247.0
|
-
|
|||||||||||||
|
Net
(Loss) Income
|
(3,599.3
|
)
|
247.0
|
||||||||||||
|
Ending
Balance
|
(3,352.3
|
)
|
247.0
|
||||||||||||
|
Accumulated
Other Comprehensive Loss (Net of Tax)
|
|||||||||||||||
|
Derivatives
|
|||||||||||||||
|
Beginning Balance
|
(246.7
|
)
|
2.9
|
||||||||||||
|
Change
in Fair Value of Derivatives Utilized for
Hedging Purposes
|
212.0
|
(249.6
|
)
|
||||||||||||
|
Reclassification
of Change in Fair Value of Derivatives to Net Income
|
117.1
|
-
|
|||||||||||||
|
Ending
Balance
|
82.4
|
(246.7
|
)
|
||||||||||||
|
Foreign
Currency Translation
|
|||||||||||||||
|
Beginning
Balance
|
27.6
|
-
|
|||||||||||||
|
Currency
Translation Adjustment
|
(68.7
|
)
|
27.6
|
||||||||||||
|
Ending
Balance
|
(41.1
|
)
|
27.6
|
||||||||||||
|
Employee
Benefit Plans
|
|||||||||||||||
|
Beginning
Balance
|
(28.6
|
)
|
-
|
||||||||||||
|
Benefit
Plan Adjustments
|
(66.5
|
)
|
(28.4
|
)
|
|||||||||||
|
Benefit
Plan Amortization
|
0.4
|
(0.2
|
)
|
||||||||||||
|
Ending
Balance
|
(94.7
|
)
|
(28.6
|
)
|
|||||||||||
|
Total
Accumulated Other Comprehensive Loss
|
(53.4
|
)
|
(247.7
|
)
|
|||||||||||
|
|
|||||||||||||||
|
Total
Stockholder’s Equity
|
100
|
$
|
4,404.3
|
100
|
$
|
7,821.5
|
|||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
94
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
KNIGHT
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF STOCKHOLDER’S EQUITY (continued)
(Dollars
in millions)
|
Predecessor
Company
|
|||||||||||||||
|
Five
Months Ended
May
31, 2007
|
Year
Ended
December
31, 2006
|
||||||||||||||
|
Shares
|
Amount
|
Shares
|
Amount
|
||||||||||||
|
Common
Stock
|
|||||||||||||||
|
Beginning
Balance
|
149,166,709
|
$
|
745.8
|
148,479,863
|
$
|
742.4
|
|||||||||
|
Employee
Benefit Plans
|
149,894
|
0.8
|
686,846
|
3.4
|
|||||||||||
|
Ending
Balance
|
149,316,603
|
746.6
|
149,166,709
|
745.8
|
|||||||||||
|
Additional
Paid-in Capital
|
|||||||||||||||
|
Beginning
Balance
|
3,048.9
|
3,056.3
|
|||||||||||||
|
Revaluation
of Kinder Morgan Energy Partners (“KMP”)
Investment (Note 14)
|
3.4
|
(40.3
|
)
|
||||||||||||
|
Employee
Benefit Plans
|
7.7
|
33.2
|
|||||||||||||
|
Tax
Benefits from Employee Benefit Plans
|
56.7
|
18.6
|
|||||||||||||
|
Implementation
of SFAS No. 123(R) Deferred Compensation Balance
|
-
|
(36.9
|
)
|
||||||||||||
|
Deferred
Compensation (Note 17)
|
21.9
|
18.0
|
|||||||||||||
|
Ending
Balance
|
3,138.6
|
3,048.9
|
|||||||||||||
|
Retained
Earnings
|
|||||||||||||||
|
Beginning
Balance
|
778.7
|
1,175.3
|
|||||||||||||
|
Net
Income
|
65.9
|
71.9
|
|||||||||||||
|
Cash
Dividends, Common Stock
|
(234.9
|
)
|
(468.5
|
)
|
|||||||||||
|
Implementation
of FIN No. 48 (Note 13)
|
(4.8
|
)
|
-
|
||||||||||||
|
Ending
Balance
|
604.9
|
778.7
|
|||||||||||||
|
Treasury
Stock at Cost
|
|||||||||||||||
|
Beginning
Balance
|
(15,022,751
|
)
|
(915.9
|
)
|
(14,712,901
|
)
|
(885.7
|
)
|
|||||||
|
Treasury
Stock Acquired
|
-
|
-
|
(339,800
|
)
|
(31.5
|
)
|
|||||||||
|
Employee
Benefit Plans
|
(7,384
|
)
|
(0.5
|
)
|
29,950
|
1.3
|
|||||||||
|
Ending
Balance
|
(15,030,135
|
)
|
(916.4
|
)
|
(15,022,751
|
)
|
(915.9
|
)
|
|||||||
|
Deferred
Compensation Plans
|
|||||||||||||||
|
Beginning
Balance
|
-
|
(36.9
|
)
|
||||||||||||
|
Implementation
of SFAS No. 123(R) Balance Transfer to Additional Paid-in
Capital
|
-
|
36.9
|
|||||||||||||
|
Ending
Balance
|
-
|
-
|
|||||||||||||
|
Accumulated
Other Comprehensive Loss (Net of Tax)
|
|||||||||||||||
|
Derivatives
|
|||||||||||||||
|
Beginning Balance
|
(60.8
|
)
|
(127.1
|
)
|
|||||||||||
|
Change
in Fair Value of Derivatives Utilized for Hedging Purposes
|
(21.3
|
)
|
44.6
|
||||||||||||
|
Reclassification
of Change in Fair Value of Derivatives to Net Income
|
10.3
|
21.7
|
|||||||||||||
|
Ending
Balance
|
(71.8
|
)
|
(60.8
|
)
|
|||||||||||
|
Foreign
Currency Translation
|
|||||||||||||||
|
Beginning
Balance
|
(24.5
|
)
|
7.4
|
||||||||||||
|
Currency
Translation Adjustment
|
40.1
|
(31.9
|
)
|
||||||||||||
|
Ending
Balance
|
15.6
|
(24.5
|
)
|
||||||||||||
|
Minimum
Pension Liability
|
|||||||||||||||
|
Beginning
Balance
|
-
|
(7.3
|
)
|
||||||||||||
|
Minimum
Pension Liability Adjustments
|
-
|
7.3
|
|||||||||||||
|
Ending
Balance
|
-
|
-
|
|||||||||||||
|
Employee
Retirement Benefits
|
|||||||||||||||
|
Beginning
Balance
|
(50.6
|
)
|
-
|
||||||||||||
|
Benefit
Plan Adjustments
|
-
|
(50.6
|
)
|
||||||||||||
|
Benefit
Plan Amortization
|
10.7
|
-
|
|||||||||||||
|
Ending
Balance
|
(39.9
|
)
|
(50.6
|
)
|
|||||||||||
|
Total
Accumulated Other Comprehensive Loss
|
(96.1
|
)
|
(135.9
|
)
|
|||||||||||
|
|
|||||||||||||||
|
Total
Stockholder’s Equity
|
134,286,468
|
$
|
3,477.6
|
134,143,958
|
$
|
3,521.6
|
|||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
95
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Cash
Flows from Operating Activities
|
||||||||||||||||
|
Net
(Loss) Income
|
$
|
(3,599.3
|
)
|
$
|
247.0
|
$
|
65.9
|
$
|
71.9
|
|||||||
|
Adjustments
to Reconcile Net (Loss) Income to Net Cash Flows from Operating
Activities
|
||||||||||||||||
|
Loss
(Income) from Discontinued Operations, Net of Tax
|
0.9
|
1.5
|
(287.9
|
)
|
542.8
|
|||||||||||
|
Loss
from Impairment of Assets
|
4,033.3
|
-
|
377.1
|
1.2
|
||||||||||||
|
Loss
on Early Extinguishment of Debt
|
23.6
|
-
|
4.4
|
-
|
||||||||||||
|
Depreciation,
Depletion and Amortization
|
918.4
|
476.2
|
264.9
|
540.3
|
||||||||||||
|
Deferred
Income Taxes
|
(496.4
|
)
|
(89.8
|
)
|
138.7
|
10.8
|
||||||||||
|
Income
from the Allowance for Equity Funds Used During Construction
|
(10.9
|
)
|
-
|
-
|
-
|
|||||||||||
|
Equity
in Earnings of Equity Investees
|
(195.4
|
)
|
(54.3
|
)
|
(39.1
|
)
|
(100.6
|
)
|
||||||||
|
Distributions
from Equity Investees
|
241.6
|
86.5
|
48.2
|
74.8
|
||||||||||||
|
Minority
Interests in Income of Consolidated Subsidiaries
|
396.1
|
48.0
|
90.7
|
374.2
|
||||||||||||
|
Gains
from Property Casualty Indemnifications
|
-
|
-
|
(1.8
|
)
|
(15.2
|
)
|
||||||||||
|
Net
Losses (Gains) on Sales of Assets
|
9.2
|
(6.3
|
)
|
(2.6
|
)
|
(22.0
|
)
|
|||||||||
|
Mark-to-Market
Interest Rate Swap (Gain) Loss
|
(19.8
|
)
|
-
|
-
|
22.3
|
|||||||||||
|
Foreign
Currency Loss
|
0.2
|
-
|
15.5
|
-
|
||||||||||||
|
Changes
in Gas in Underground Storage
|
(28.0
|
)
|
51.3
|
(84.2
|
)
|
(35.3
|
)
|
|||||||||
|
Changes
in Working Capital Items (Note 6)
|
(44.9
|
)
|
104.0
|
(202.9
|
)
|
80.0
|
||||||||||
|
Proceeds
from (Payment for) Termination of Interest Rate Swaps
|
192.0
|
(2.2
|
)
|
51.9
|
-
|
|||||||||||
|
Kinder
Morgan Energy Partners’ Rate Reparations, Refunds and
Reserve Adjustments
|
(13.7
|
)
|
140.0
|
-
|
(19.1
|
)
|
||||||||||
|
Other,
Net
|
(9.3
|
)
|
45.8
|
54.4
|
(31.4
|
)
|
||||||||||
|
Net
Cash Flows Provided by Continuing Operations
|
1,397.6
|
1,047.7
|
493.2
|
1,494.7
|
||||||||||||
|
Net
Cash Flows (Used in) Provided by Discontinued Operations
|
(0.8
|
)
|
(3.2
|
)
|
109.8
|
212.6
|
||||||||||
|
Net
Cash Flows Provided by Operating Activities
|
1,396.8
|
1,044.5
|
603.0
|
1,707.3
|
||||||||||||
|
|
||||||||||||||||
|
Cash
Flows from Investing Activities
|
||||||||||||||||
|
Purchase
of Predecessor Stock
|
-
|
(11,534.3
|
)
|
-
|
-
|
|||||||||||
|
Capital
Expenditures
|
(2,545.3
|
)
|
(1,287.0
|
)
|
(652.8
|
)
|
(1,375.6
|
)
|
||||||||
|
Proceeds
from Sale of 80% Interest in NGPL PipeCo LLC, Net of $1.1
Cash Sold
|
2,899.3
|
-
|
-
|
-
|
||||||||||||
|
Terasen
Acquisition
|
-
|
-
|
-
|
(10.6
|
)
|
|||||||||||
|
Other
Acquisitions
|
(47.6
|
)
|
(122.0
|
)
|
(42.1
|
)
|
(396.5
|
)
|
||||||||
|
Loans
to Customers
|
(109.6
|
)
|
-
|
-
|
-
|
|||||||||||
|
Proceeds
from (Investments in) NGPL PipeCo LLC Restricted Cash
|
3,106.4
|
(3,030.0
|
)
|
-
|
-
|
|||||||||||
|
Net
Proceeds from (Investment in) Margin Deposits
|
71.0
|
(39.3
|
)
|
(54.8
|
)
|
38.6
|
||||||||||
|
Distributions
from Equity Investees
|
98.1
|
-
|
-
|
-
|
||||||||||||
|
Contributions
to Investments
|
(366.2
|
)
|
(246.4
|
)
|
(29.7
|
)
|
(6.1
|
)
|
||||||||
|
Change
in Natural Gas Storage and Natural Gas Liquids Line Fill
Inventory
|
(7.2
|
)
|
10.0
|
8.4
|
(12.9
|
)
|
||||||||||
|
Property
Casualty Indemnifications
|
-
|
-
|
8.0
|
13.1
|
||||||||||||
|
Net
Proceeds (Costs of Removal) from Sales of Assets
|
111.1
|
301.3
|
(1.5
|
)
|
92.2
|
|||||||||||
|
Net
Cash Flows Provided by (Used in) Continuing Investing
Activities
|
3,210.0
|
(15,947.7
|
)
|
(764.5
|
)
|
(1,657.8
|
)
|
|||||||||
|
Net
Cash Flows Provided by (Used in) Discontinued Investing
Activities
|
-
|
196.6
|
1,488.2
|
(138.1
|
)
|
|||||||||||
|
Net
Cash Flows Provided by (Used in) Investing Activities
|
$
|
3,210.0
|
$
|
(15,751.1
|
)
|
$
|
723.7
|
$
|
(1,795.9
|
)
|
||||||
96
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
KNIGHT
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS (continued)
(In
millions)
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Cash
Flows from Financing Activities
|
||||||||||||||||
|
Short-term
Debt, Net
|
$
|
(879.3
|
)
|
$
|
(52.6
|
)
|
$
|
(247.5
|
)
|
$
|
1,009.5
|
|||||
|
Long-term
Debt Issued
|
2,113.2
|
8,805.0
|
1,000.0
|
-
|
||||||||||||
|
Long-term
Debt Retired
|
(5,874.6
|
)
|
(829.2
|
)
|
(302.4
|
)
|
(140.7
|
)
|
||||||||
|
Issuance of Kinder Morgan, G.P., Inc. Preferred Stock
|
-
|
100.0
|
-
|
-
|
||||||||||||
|
Discount
(Premium) on Early Extinguishment of Debt
|
69.2
|
-
|
(4.2
|
)
|
-
|
|||||||||||
|
Cash
Book Overdraft
|
14.5
|
(14.0
|
)
|
(14.9
|
)
|
17.9
|
||||||||||
|
Issuance
of Shares by Kinder Morgan Management, LLC
|
-
|
-
|
297.9
|
-
|
||||||||||||
|
Other
Common Stock Issued
|
-
|
-
|
9.9
|
38.7
|
||||||||||||
|
Excess
Tax Benefits from Share-based Payments
|
-
|
-
|
56.7
|
18.6
|
||||||||||||
|
Cash
Paid to Share-based Award Holders Due to Going Private Transaction
|
-
|
(181.1
|
)
|
-
|
-
|
|||||||||||
|
Contributions
from Successor Investors
|
-
|
5,112.0
|
-
|
-
|
||||||||||||
|
Short-term
Advances from (to) Unconsolidated Affiliates
|
2.7
|
10.9
|
2.3
|
(4.9
|
)
|
|||||||||||
|
Treasury
Stock Acquired
|
-
|
-
|
-
|
(34.3
|
)
|
|||||||||||
|
Cash
Dividends, Common Stock
|
-
|
-
|
(234.9
|
)
|
(468.5
|
)
|
||||||||||
|
Distributions
to Minority Interests
|
(630.3
|
)
|
(259.6
|
)
|
(248.9
|
)
|
(575.0
|
)
|
||||||||
|
Contributions
from Minority Interests
|
561.5
|
342.9
|
-
|
353.8
|
||||||||||||
|
Debt
Issuance Costs
|
(15.9
|
)
|
(81.5
|
)
|
(13.1
|
)
|
(4.8
|
)
|
||||||||
|
Other,
Net
|
10.9
|
4.0
|
(0.1
|
)
|
(3.5
|
)
|
||||||||||
|
Net
Cash Flows (Used In) Provided by Continuing Financing
Activities
|
(4,628.1
|
)
|
12,956.8
|
300.8
|
206.8
|
|||||||||||
|
Net
Cash Flows Provided by (Used in) Discontinued Financing
Activities
|
-
|
-
|
140.1
|
(118.1
|
)
|
|||||||||||
|
Net
Cash Flows (Used In) Provided by Financing Activities
|
(4,628.1
|
)
|
12,956.8
|
440.9
|
88.7
|
|||||||||||
|
Effect
of Exchange Rate Changes on Cash
|
(8.7
|
)
|
(2.8
|
)
|
7.6
|
6.6
|
||||||||||
|
|
||||||||||||||||
|
Effect
of Accounting Change on Cash
|
-
|
-
|
-
|
12.1
|
||||||||||||
|
|
||||||||||||||||
|
Cash
Balance Included in Assets Held for Sale
|
-
|
(1.1
|
)
|
(2.7
|
)
|
(5.6
|
)
|
|||||||||
|
|
||||||||||||||||
|
Net
(Decrease) Increase in Cash and Cash Equivalents
|
(30.0
|
)
|
(1,753.7
|
)
|
1,772.5
|
13.2
|
||||||||||
|
Cash
and Cash Equivalents at Beginning of Period
|
148.6
|
1,902.3
|
129.8
|
116.6
|
||||||||||||
|
Cash
and Cash Equivalents at End of Period
|
$
|
118.6
|
$
|
148.6
|
$
|
1,902.3
|
$
|
129.8
|
||||||||
The
accompanying notes are an integral part of these consolidated financial
statements.
97
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
1. Nature
of Operations and Summary of Significant Accounting Policies
Nature
of Operations
We
are a large energy transportation and storage company, operating or owning an
interest in approximately 36,000 miles of pipelines and approximately 170
terminals. We have both regulated and nonregulated operations. We also own the
general partner interest and a significant limited partner interest in Kinder
Morgan Energy Partners, L.P., a publicly traded pipeline limited partnership.
Our executive offices are located at 500 Dallas Street, Suite 1000, Houston,
Texas 77002 and our telephone number is (713) 369-9000. Unless the context
requires otherwise, references to “we,” “us,” “our,” or the “Company” are
intended to mean Knight Inc. (formerly Kinder Morgan, Inc.) and its consolidated
subsidiaries both before and after the Going Private transaction discussed
below. Unless the context requires otherwise, references to “Kinder Morgan
Energy Partners” and “KMP” are intended to mean Kinder Morgan Energy Partners,
L.P. and its consolidated subsidiaries.
Kinder
Morgan Management, LLC, referred to in this report as “Kinder Morgan Management”
is a publicly traded Delaware limited liability company that was formed on
February 14, 2001. Kinder Morgan G.P., Inc., of which we indirectly own all of
the outstanding common equity, owns all of Kinder Morgan Management’s voting
shares. Kinder Morgan Management’s shares (other than the voting shares we hold)
are traded on the New York Stock Exchange under the ticker symbol “KMR.” Kinder
Morgan Management, pursuant to a delegation of control agreement, has been
delegated, to the fullest extent permitted under Delaware law, all of Kinder
Morgan G.P., Inc.’s power and authority to manage and control the business and
affairs of Kinder Morgan Energy Partners, L.P., subject to Kinder Morgan G.P.,
Inc.’s right to approve certain transactions.
Basis
of Presentation
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America (“GAAP”) requires management
to make estimates and assumptions. These estimates and assumptions affect the
reported amounts of assets and liabilities, the disclosure of contingent assets
and liabilities, and the reported amounts of revenues and expenses. Actual
results could differ from these estimates.
Our
consolidated financial statements include the accounts of Knight Inc. and our
majority-owned subsidiaries, as well as those of (i) Kinder Morgan Energy
Partners, (ii) Kinder Morgan Management and (iii) Triton Power Company LLC, in
which we have a preferred investment. Except for Kinder Morgan Energy Partners,
Kinder Morgan Management and Triton Power Company LLC, investments in 50% or
less owned operations are accounted for under the equity method. All material
intercompany transactions and balances have been eliminated. Certain prior
period amounts have been reclassified to conform to the current presentation.
Notwithstanding the consolidation of Kinder Morgan Energy Partners and its
subsidiaries into our financial statements, we are not liable for, and our
assets are not available to satisfy, the obligations of Kinder Morgan Energy
Partners and/or its subsidiaries and vice versa. Responsibility for payments of
obligations reflected in our or Kinder Morgan Energy Partners’ financial
statements is a legal determination based on the entity that incurs the
liability.
On
May 30, 2007, Kinder Morgan, Inc. merged with a wholly owned subsidiary of
Knight Holdco LLC, with Kinder Morgan, Inc. continuing as the surviving legal
entity and subsequently renamed Knight Inc. Knight Holdco LLC is a private
company owned by Richard D. Kinder, our Chairman and Chief Executive Officer;
our co-founder William V. Morgan; former Kinder Morgan, Inc. board members Fayez
Sarofim and Michael C. Morgan; other members of our senior management, most of
whom are also senior officers of Kinder Morgan G.P., Inc. and Kinder Morgan
Management; and affiliates of (i) Goldman Sachs Capital Partners, (ii) Highstar
Capital, (iii) The Carlyle Group and (iv) Riverstone Holdings LLC. This
transaction is referred to in this report as the Going Private transaction. As a
result of this transaction, we are now privately owned, our stock is no longer
traded on the New York Stock Exchange, and we have adopted a new basis of
accounting for our assets and liabilities. This transaction was a “business
combination” for accounting purposes, requiring that these investors, pursuant
to SFAS No. 141, Business
Combinations, record the assets acquired and liabilities assumed at their
fair market values as of the acquisition date, resulting in a new basis of
accounting.
As
a result of the application of the SEC rules and guidance regarding “push down”
accounting, the investors’ new accounting basis in our assets and liabilities is
reflected in our financial statements effective with the closing of the Going
Private transaction. Therefore, in the accompanying Consolidated Financial
Statements, transactions and balances prior to the closing of the Going Private
transaction (the amounts labeled “Predecessor Company”) reflect the historical
accounting basis in our assets and liabilities, while the amounts subsequent to
the closing (labeled “Successor Company”) reflect the push down of the
investors’ new accounting basis to our financial statements. Hence, there is a
blackline division on the financial statements and relevant notes, which is
intended to signify that the amounts shown for periods prior to and subsequent
to the Going Private transaction are not comparable.
98
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
As
required by SFAS No. 141 (applied by the investors and pushed down to our
financial statements), effective with the closing of the Going Private
transaction, all of our assets and liabilities have been recorded at their
estimated fair market values based on an allocation of the aggregate purchase
price paid in the Going Private transaction. To the extent that we consolidate
less than wholly owned subsidiaries (such as Kinder Morgan Energy Partners,
Kinder Morgan Management and Triton Power Company LLC), the reported assets and
liabilities for these entities have been given a new accounting basis only to
the extent of our economic ownership interest in those entities. Therefore, the
assets and liabilities of these entities are included in our financial
statements, in part, at a new accounting basis reflecting the investors’
purchase of our economic interest in these entities (approximately 50% in the
case of Kinder Morgan Energy Partners and 14% in the case of Kinder Morgan
Management). The remaining percentage of these assets and liabilities,
reflecting the continuing minority ownership interest, is included at its
historical accounting basis. The purchase price paid in the Going Private
transaction and the allocation of that purchase price is as
follows:
|
(In
millions)
|
|||
|
The
Total Purchase Price Consisted of the Following
|
|||
|
Cash
Paid
|
$
|
5,112.0
|
|
|
Kinder
Morgan, Inc. Shares Contributed
|
2,719.2
|
||
|
Equity
Contributed
|
7,831.2
|
||
|
Cash
from Issuances of Long-term Debt
|
4,696.2
|
||
|
Total
Purchase Price
|
$
|
12,527.4
|
|
|
|
|||
|
The
Allocation of the Purchase Price is as Follows
|
|||
|
Current
Assets
|
$
|
1,551.2
|
|
|
Investments
|
897.8
|
||
|
Goodwill
|
13,786.1
|
||
|
Property,
Plant and Equipment, Net
|
15,281.6
|
||
|
Deferred
Charges and Other Assets
|
1,639.8
|
||
|
Current
Liabilities
|
(3,279.5
|
)
|
|
|
Deferred
Income Taxes, Non-current
|
(2,392.8
|
)
|
|
|
Other
Long-term Liabilities and Deferred Credits
|
(1,786.3
|
)
|
|
|
Long-term
Debt
|
(9,855.9
|
)
|
|
|
Minority
Interests in Equity of Subsidiaries
|
(3,314.6
|
)
|
|
|
$
|
12,527.4
|
||
The
following is a reconciliation of shares purchased and contributed and the Going
Private transaction purchase price (in millions except per share
information):
|
Number
of
Shares
|
Price
per
Share
|
Total
Value
|
|||||||||
|
Shares
Purchased with Cash
|
107.6
|
$
|
107.50
|
$
|
11,561.3
|
||||||
|
Shares
Contributed
|
|||||||||||
|
Richard
D. Kinder
|
24.0
|
$
|
101.00
|
2,424.0
|
|||||||
|
Other
Kinder Morgan, Inc. Management and Board Members
|
2.7
|
$
|
107.50
|
295.2
|
|||||||
|
Total
Shares Contributed
|
26.7
|
2,719.2
|
|||||||||
|
Total
Shares Outstanding as of May 31, 2007
|
134.3
|
14,280.5
|
|||||||||
|
Less:
Portion of Shares Acquired using Knight Inc. Cash on Hand
|
(1,756.8
|
)
|
|||||||||
|
Add:
Cash Contributions by Management At or After May 30, 2007
|
3.7
|
||||||||||
|
Purchase
Price
|
$
|
12,527.4
|
|||||||||
The
shares contributed by members of management and the board members other than
Richard D. Kinder who were investors in the Going Private transaction were
valued at $107.50 per share, the same as the amount per share paid to the public
shareholders in the Going Private transaction. Richard D. Kinder agreed to value
the shares he contributed at $101.00 per share because Mr. Kinder agreed to
participate in the transaction at less than the merger price in order to help
increase the merger price for the other public shareholders.
Revenue
Recognition Policies
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 at
a
99
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
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, in general our
natural gas marketing revenues are recorded at gross, rather than net of cost of
gas sold.
We
provide various types of natural gas storage and transportation services to
customers. When we provide these services, 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. In addition to our “firm”
and “interruptible” transportation services, we also provide natural gas park
and loan service to assist customers in managing short-term gas surpluses or
deficits. Revenues are recognized based on the terms negotiated under these
contracts.
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.
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 natural 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.
Restricted
Deposits
Except
as discussed following, Restricted Deposits consist of restricted funds on
deposit with brokers in support of our risk management activities (see Note 15).
The $3 billion of proceeds from NGPL PipeCo LLC’s sale of debt in a private
placement (see Note 10) were held in escrow and are included in the caption
“Current Assets: Assets Held for Sale” in the accompanying Consolidated Balance
Sheet at December 31, 2007.
Accounts
Receivable
The
caption “Accounts, Notes and Interest Receivable, Net” in the accompanying
Consolidated Balance Sheets is presented net of allowances for doubtful
accounts. Our policy for determining an appropriate allowance for doubtful
accounts varies according to the type of business being conducted and the
customers being served. Generally, we make periodic reviews and evaluations of
the appropriateness of the allowance for doubtful accounts based on a historical
analysis of uncollected amounts, and we record adjustments as necessary for
changed circumstances and customer-specific information. When specific
receivables are determined to be uncollectible, the reserve and receivable are
relieved.
Inventory
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.
Gas
Imbalances and Gas Purchase Contracts
We
value gas imbalances due to or due from interconnecting pipelines at the lower
of cost or market. Gas imbalances represent the difference between customer
nominations and actual gas receipts from and gas deliveries to our
interconnecting pipelines and shippers under various operational balancing and
shipper imbalance agreements. Natural gas imbalances are settled in cash or made
up in-kind subject to the terms of the various pipelines’ tariffs or other
contractual provisions.
100
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Assets
and Liabilities Held for Sale
On
December 10, 2007, we entered into a definitive agreement to sell an 80%
ownership interest in our NGPL business segment (primarily MidCon Corp, which
was the parent of Natural Gas Pipeline Company of America) to Myria Acquisition
Inc. (“Myria”), a Delaware corporation, for approximately $5.9 billion, subject
to certain adjustments. The closing of the sale occurred on February 15, 2008.
We continue to operate NGPL assets pursuant to a 15-year operating agreement.
See Note 10 for further information regarding this transaction.
In
accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, as of December 31, 2007, 100% of the
assets and liabilities in our NGPL business segment were reclassified to assets
and liabilities held for sale in connection with our February 2008 sale of an
80% interest in that segment. The non-current assets and long-term debt held for
sale balances were reduced by the 20% ownership interest, which we retained in
the NGPL business segment and recorded as an investment. Therefore, the
accompanying Consolidated Balance Sheet at December 31, 2007 includes the
following:
|
December
31,
2007
|
|||
|
Current
Assets: Assets Held for Sale
|
|||
|
Restricted
Deposits
|
$
|
3,030.0
|
|
|
Other
|
323.3
|
||
|
$
|
3,353.3
|
||
|
Assets
Held for Sale, Non-current
|
|||
|
Goodwill
|
$
|
5,216.4
|
|
|
Plant,
Property and Equipment, Net
|
1,699.3
|
||
|
Deferred
Charges and Other Assets
|
38.9
|
||
|
Less:
Investment in Net Assets of NGPL
|
(1,320.0
|
)
|
|
|
$
|
5,634.6
|
||
|
Current
Liabilities: Liabilities Held for Sale
|
$
|
168.2
|
|
|
Liabilities
Held for Sale, Non-current
|
|||
|
Long-term
Debt: Outstanding Notes and Debentures
|
$
|
3,000.0
|
|
|
Other
Liabilities and Minority Interests
|
24.1
|
||
|
Less:
Investment in Long-term Debt of NGPL
|
(600.0
|
)
|
|
|
$
|
2,424.1
|
||
The
20% ownership interest that we retained in the NGPL business segment is included
in our Consolidated Balance Sheet as of December 31, 2007 as
follows:
|
Investments
|
|||
|
20%
Investment of NGPL’s Net Assets
|
$
|
1,320.0
|
|
|
20%
Investment of NGPL’s Long-term Debt
|
(600.0
|
)
|
|
|
$
|
720.0
|
Pensions
and Other Postretirement Benefits
We
account for pension and other postretirement benefit plans according to the
provisions of 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 consolidating
subsidiaries’ pension and postretirement benefit plans as either assets or
liabilities on our balance sheet. For more information on our pension
and postretirement benefit disclosures, see Note 16.
Accounting
for 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. We also utilize interest rate swap agreements to mitigate
our risk from fluctuations in interest rates and cross-currency interest rate
swap agreements to mitigate foreign currency risk from our investments in
businesses owned and operated outside the United States. Pursuant to current
accounting provisions, we record our derivative contracts at their estimated
fair values as of each reporting date. For more information on our risk
management activities; see Note 15.
101
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
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. For our pipeline system
assets, we generally charge the original cost of property sold or retired to
accumulated depreciation and amortization, net of salvage and cost of removal.
We do not include retirement gain or loss in income except in the case of
significant retirements or sales. Gains and losses on minor system sales,
excluding land, are recorded to the appropriate accumulated depreciation
reserve. Gains and losses for operating systems sales and land sales are booked
to income or expense accounts in accordance with regulatory accounting
guidelines.
We
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 & Equipment, Net” balance in the accompanying Consolidated
Balance Sheets) and 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.
Depreciation
on our long-lived assets is computed principally based on the straight-line
method over their estimated useful lives. Generally, we apply composite
depreciation rates to functional groups of property having similar economic
characteristics. These rates range from 1.6% 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 include
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
assets.
A
gain on the sale of property, plant and equipment used in our oil and gas
producing activities or in our bulk and liquids terminal activitities 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 market 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 SFAS 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 are less than its carrying
amount.
102
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
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. Due to the decline in crude oil and natural gas prices
during the course of 2008, on December 31, 2008, we conducted an impairment test
on our oil and gas producing properties in Kinder Morgan Energy Partners’
CO2
business segment and determined that no impairment was necessary. For the
purpose of impairment testing, we use the forward curve prices as observed at
the test date. The forward curve cash flows may differ from the amounts
presented in Supplemental
Information on Oil and Gas Producing Activities (Unaudited) contained
elsewhere herein, due to differences between the forward curve and spot
prices.
Goodwill
Goodwill
represents the excess of cost over fair value of the net assets of businesses
acquired. The Company tests for impairment of goodwill on an annual basis and at
any other time if events occur or circumstances indicate that the carrying
amount of goodwill may not be recoverable. See Note 3 for more information about
Goodwill and our annual impairment test.
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 the acquisition, minus distributions received.
Income
Taxes
Income
tax expense is recorded based on an estimate of the effective tax rate in effect
or to be in effect during the relevant periods. Deferred income tax assets and
liabilities are recognized for temporary differences between the basis of 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 we do not expect to be realized.
Note 13 contains information about our income taxes, including the components of
our income tax provision and the composition of our deferred income tax assets
and liabilities.
In
determining the deferred income tax asset and liability balances attributable to
our investments, we have applied an accounting policy that looks through our
investments including our Kinder Morgan Energy Partners investment. The
application of this policy resulted in no deferred income taxes being provided
on the difference between the book and tax basis on the non-tax-deductible
goodwill portion of our investment in Kinder Morgan Energy Partners. See Note 3
regarding the Going Private transaction goodwill assigned to our Kinder Morgan
Energy Partners investment.
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. These reviews assist us in identifying
environmental issues and estimating the costs and timing of remediation efforts.
We also routinely adjust our environmental liabilities to reflect changes in
previous estimates. In making environmental liability estimations, we consider
the material effect of environmental compliance, pending legal actions against
us, and potential third-party liability claims. 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. For more information on our
environmental matters, see Note 21.
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. In general, we expense legal costs as incurred and all
recorded legal liabilities are revised as better information becomes available.
When we identify specific litigation that is expected to continue for a
significant period of time and require substantial expenditures, we identify a
range of possible costs expected to be required to litigate the matter to
a
103
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
conclusion
or reach an acceptable settlement, and we accrue for such amounts. 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.
For more information on our legal disclosures, see Note 21.
Foreign
Currency Translation
We
translate the financial statements of our foreign consolidated subsidiaries into
United States dollars using the current rate method of foreign currency
translation. Under this method, assets and liabilities are translated at the
rate of exchange in effect at the balance sheet date, revenue and expense items
are translated at average rates of exchange for the period, stockholder’s equity
accounts at historical exchange rates and the exchange gains and losses arising
on the translation of the financial statements are reflected as a separate
component of the “Accumulated Other Comprehensive Income” caption in the
accompanying Consolidated Balance Sheets.
Foreign
currency transaction gains or losses, other than hedges of net investments in
foreign companies, are included in results of operations. In 2006, we recorded
net pre-tax losses of $22.5 million from foreign currency transactions and
swaps. See Note 15 for information regarding our hedges of net investments in
foreign companies.
Canadian
dollars are designated as C$ in these Notes to Consolidated Financial
Statements. To convert December 31, 2008 balances denominated in Canadian
dollars to U.S. dollars, we used the December 31, 2008 Bank of Canada closing
exchange rate of 0.8210 U.S. dollars per Canadian dollar.
Transfer
of Net Assets Between Entities Under Common Control
We
account for the transfer of net assets between entities under common control by
carrying forward the net assets recognized in the balance sheets of each
combining entity to the balance sheet of the combined entity, and no other
assets or liabilities are recognized as a result of the combination. Transfers
of net assets between entities under common control do not affect the income
statement of the combined entity.
2.
Investment in Kinder Morgan Energy Partners, L.P.
At
December 31, 2008, we owned, directly, and indirectly in the form of i-units
corresponding to the number of shares of Kinder Morgan Management we owned,
approximately 32.8 million limited partner units of Kinder Morgan Energy
Partners. These units, which consist of 16.4 million common units, 5.3 million
Class B units and 11.1 million i-units, represent approximately 12.3% of the
total limited partner interests of Kinder Morgan Energy Partners. See Note 9 for
additional information regarding Kinder Morgan Management and Kinder Morgan
Energy Partners’ i-units. In addition, we are the sole common stockholder of the
general partner of Kinder Morgan Energy Partners, which holds an effective 2%
combined interest in Kinder Morgan Energy Partners and its operating
partnerships. Together, our limited partner and general partner interests
represented approximately 14.1% of Kinder Morgan Energy Partners’ total equity
interests at December 31, 2008. As of the close of the Going Private
transaction, our limited partner interests and our general partner interest
represented an approximate 50% economic interest in Kinder Morgan Energy
Partners. This difference results from the existence of incentive distribution
rights held by the general partner shareholder.
In
conjunction with Kinder Morgan Energy Partners’ acquisition of certain natural
gas pipelines from us, we agreed to indemnify Kinder Morgan Energy Partners with
respect to approximately $733.5 million of its debt. We would be obligated to
perform under this indemnity only if Kinder Morgan Energy Partners’ assets were
unable to satisfy its obligations.
Additional
information regarding Kinder Morgan Energy Partners’ results of operations and
financial position are contained in its Annual Report on Form 10-K for the year
ended December 31, 2008.
104
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
3. Goodwill
and Other Intangibles
Goodwill
Changes
in the carrying amount of our goodwill for the year ended December 31, 2008 are
summarized as follows:
|
December
31,
2007
|
Acquisitions
and
Purchase
Price
Adjustments1
|
Impairment
of
Assets
|
Other2
|
December
31,
2008
|
|||||||||||||||||
|
(In
millions)
|
|||||||||||||||||||||
|
Products
Pipelines–KMP
|
$
|
2,179.4
|
$
|
(54.8
|
)
|
$
|
(1,266.5
|
)
|
$
|
(8.1
|
)
|
$
|
850.0
|
||||||||
|
Natural
Gas Pipelines–KMP
|
3,201.0
|
251.2
|
(2,090.2
|
)
|
(12.8
|
)
|
1,349.2
|
||||||||||||||
|
CO2–KMP
|
1,077.6
|
450.9
|
-
|
(6.8
|
)
|
1,521.7
|
|||||||||||||||
|
Terminals–KMP
|
1,465.9
|
(9.5
|
)
|
(676.6
|
)
|
(5.6
|
)
|
774.2
|
|||||||||||||
|
Kinder
Morgan Canada–KMP
|
250.1
|
-
|
-
|
(46.5
|
)
|
203.6
|
|||||||||||||||
|
Consolidated
Total
|
$
|
8,174.0
|
$
|
637.8
|
$
|
(4,033.3
|
)
|
$
|
(79.8
|
)
|
$
|
4,698.7
|
|||||||||
_______________
|
1
|
Adjustments
relate primarily to a reallocation between goodwill and property, plant,
and equipment in our final purchase price
allocation.
|
|
2
|
Adjustments
include (i) the translation of goodwill denominated in foreign currencies
and (ii) reductions in goodwill due to reductions in our ownership
percentage of Kinder Morgan Energy
Partners.
|
We
evaluate goodwill for impairment in accordance with the provisions of SFAS No.
142, Goodwill and Other
Intangible Assets. For this purpose, we have six reporting units as
follows: (i) Products Pipelines–KMP (excluding associated terminals), (ii)
Products Pipelines Terminals–KMP (evaluated separately from Products Pipelines
for goodwill purposes), (iii) Natural Gas Pipelines–KMP, (iv) CO–KMP, (v)
Terminals–KMP and (vi) Kinder Morgan Canada–KMP. For investments we account for
under the equity method of accounting, the premium or excess cost over
underlying fair value of net assets is referred to as equity method goodwill and
is not subject to amortization but rather to impairment testing in accordance
with APB No. 18, The Equity
Method of Accounting for Investments in Common Stock. As of both December
31, 2008 and December 31, 2007, we have reported $138.2 million of equity method
goodwill within the caption “Investments” in the accompanying Consolidated
Balance Sheets.
In
the second quarter of 2008, we finalized the purchase price allocation
associated with our May 2007 Going Private transaction, establishing the fair
values of our individual assets and liabilities including assigning the
associated goodwill to our six reporting units, in each case as of the May 31,
2007 acquisition date. A significant portion of the goodwill that arose in
conjunction with this acquisition was determined to be associated with the
general partner and significant limited partner interests in Kinder Morgan
Energy Partners (a publicly traded master limited partnership, or “MLP”),
attributable, in part, to the difference between the market multiples that might
be paid to acquire the general partner and limited interests in an MLP and the
market multiples that might be paid to acquire the individual assets that
comprise that MLP. This market premium is partially attributable to the
incentive distribution right that is embedded in the Kinder Morgan Energy
Partners general partner interest for which a separate intangible asset was not
recognized in purchase accounting because this right cannot be detached or
transferred apart from the entire general partner interest.
In
conjunction with our first annual impairment test of the carrying value of this
goodwill, performed as of May 31, 2008, we determined that the fair value of
certain reporting units that are part of our investment in Kinder Morgan Energy
Partners were less than the carrying values. The fair value of each reporting
unit was determined from the present value of the expected future cash flows
from the applicable reporting unit (inclusive of a terminal value calculated
using market multiples between six and nine times cash flows) discounted at a
rate of 9.00%. In accordance with paragraph 23 of SFAS No. 142, the value of
each reporting unit was determined on a stand-alone basis from the perspective
of a market participant and represents the price that would be received to sell
the unit as a whole in an orderly transaction between market participants at the
measurement date. Thus, any value generated from the inclusion of these assets
in an MLP structure was not captured in the valuation of these reporting units.
This resulted in several of the reporting units having fair values less than
their carrying values as the incremental value created by the inclusion of these
assets in an MLP structure was taken into account in the Going Private
transaction and thus was used in allocating the purchase price under SFAS No.
141. To capture this value at the reporting unit level, we believe it would be
necessary to recreate the MLP structure at the reporting unit level. We believe
this is not feasible for Knight Inc. or for any market participant, as further
discussed below.
Recreating
such structure would involve separating each of our reporting units into
separate entities so that each reporting unit could be valued on a stand alone
basis assuming each such unit was sold as an MLP. Creating separate MLPs would
involve significant structural difficulties including potentially numerous
adverse state and federal tax consequences to Kinder Morgan Energy Partners and
its unitholders. In addition, it would involve a significant amount of tax,
legal and commercial analysis, and based on that analysis may also require
customer and/or joint venture consents, lender consents, and regulatory
approvals and/or unitholder approval. As a result of these factors, we believe
that it is not feasible to apply the MLP structure related
105
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
value
to the individual reporting unit level.
For
the reporting units where the fair value was determined to be less than the
carrying value, we determined the implied fair value of goodwill. The implied
fair value of goodwill within each reporting unit was then compared to the
carrying value of goodwill of each such unit, resulting in the following
goodwill impairment charges by reporting units: Products Pipelines–KMP
(excluding associated terminals) – $1.20 billion, Products Pipelines
Terminals–KMP (separate from Products Pipelines–KMP for goodwill impairment
purposes) - $70 million, Natural Gas Pipelines–KMP – $2.09 billion, and
Terminals–KMP – $677 million, for a total impairment of $4.03 billion. The
goodwill impairment charges are non-cash charges and do not have any impact on
our cash flows.
The
decline in the market price of crude oil since May 31, 2008 has
required us to update our goodwill impairment analysis of the
CO2–KMP
segment as of December 31, 2008. The fair value of the CO2–KMP
segment was determined from the present value of the expected future cash flows
based on forward prices of crude oil as of December 31, 2008. The assumed price
of oil for each year in our analysis was $54.32, $63.83, $68.79, $71.07 and
$72.67 for the fiscal years 2009-2013. A terminal value calculated using a
market multiple for similar assets was applied to 2013 cash flows. This
calculated fair value of the CO2–KMP
reporting unit was greater than the book value of this reporting unit and thus
at December 31, 2008 goodwill impairment was not necessary.
On
April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain
pipeline system from us. This transaction caused us to evaluate the fair value
of the Trans Mountain pipeline system in determining whether goodwill related to
these assets was impaired. Accordingly, based on our consideration of supporting
information obtained regarding the fair values of the Trans Mountain pipeline
system assets, a goodwill impairment charge of $377.1 million was recorded in
2007.
In
February 2007, we entered into a definitive agreement, which closed on May 17,
2007 (see Note 11) to sell Terasen Inc. to Fortis, Inc., a Canada-based company
with investments in regulated distribution utilities. Execution of this sale
agreement constituted an event of the type that, under GAAP, required us to
consider the market value indicated by the definitive sales agreement in our
2006 goodwill impairment evaluation. Accordingly, based on the fair values of
these reporting unit(s) derived principally from this definitive sales
agreement, an estimated goodwill impairment charge of approximately $650.5
million was recorded in the 2006 period and is reported in the accompanying
Consolidated Statement of Operations for the year ended December 31, 2006 within
the caption, “Income (Loss) from Discontinued Operations, Net of
Tax.”
Other
Intangibles, Net
Our
intangible assets other than goodwill include customer relationships, contracts
and agreements, technology-based assets, lease values and other long-term
assets. These intangible assets are being amortized on a straight-line basis
over their estimated useful lives and are reported separately as “Other
Intangibles, Net” in the accompanying Consolidated Balance Sheets. Following is
information related to our intangible assets:
|
December
31,
|
|||||||
|
2008
|
2007
|
||||||
|
(In
millions)
|
|||||||
|
Customer
Relationships, Contracts and Agreements
|
|||||||
|
Gross
Carrying Amount
|
$
|
270.9
|
$
|
321.3
|
|||
|
Accumulated
Amortization
|
(30.3
|
)
|
(11.6
|
)
|
|||
|
Net
Carrying Amount
|
240.6
|
309.7
|
|||||
|
Technology-based
Assets, Lease Value and Other
|
|||||||
|
Gross
Carrying Amount
|
11.7
|
11.7
|
|||||
|
Accumulated
Amortization
|
(0.8
|
)
|
(0.3
|
)
|
|||
|
Net
Carrying Amount
|
10.9
|
11.4
|
|||||
|
Total
Other Intangibles, Net
|
$
|
251.5
|
$
|
321.1
|
|||
Amortization
expense on our intangibles consisted of the following:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Customer
Relationships, Contracts and Agreements
|
$
|
18.7
|
$
|
11.6
|
$
|
6.1
|
$
|
15.0
|
||||||||
|
Technology-based
Assets, Lease Value and Other
|
0.5
|
0.3
|
0.2
|
0.2
|
||||||||||||
|
Total
Amortizations
|
$
|
19.2
|
$
|
11.9
|
$
|
6.3
|
$
|
15.2
|
||||||||
106
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
As
of December 31, 2008, the weighted-average amortization period for our
intangible assets was approximately 16.6 years. Our estimated amortization
expense for these assets for each of the next five fiscal years is approximately
$17.2 million, $17.0 million, $16.8 million, $16.5 million and $16.5 million,
respectively.
4. Other
Investments
Our
long-term investments as of December 31, 2008 consisted of equity investments
totaling $1,814.2 million and bond investments totaling $13.2
million.
Our
significant equity investments as of December 31, 2008 (and our percentage of
ownership interests) consisted of:
|
|
·
|
NGPL
PipeCo LLC (20%);
|
|
|
·
|
West2East
Pipeline LLC (51%);
|
|
|
·
|
Plantation
Pipe Line Company (51%);
|
|
|
·
|
Red
Cedar Gathering Company (49%);
|
|
|
·
|
Express
Pipeline System (33⅓%);
|
|
|
·
|
Cortez
Pipeline Company (50%);
|
|
|
·
|
Fayetteville
Express Pipeline LLC (50%); and
|
|
|
·
|
Midcontinent
Express Pipeline LLC (50%);
|
On
February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC
(formerly MidCon Corp.), which owns Natural Gas Pipeline of America and certain
affiliates, collectively referred to as “NGPL,” to Myria Acquisition Inc.
(“Myria”). Pursuant to the purchase agreement, Myria acquired all 800 Class B
shares and we retained all 200 Class A shares of NGPL PipeCo LLC. We will
continue to operate NGPL’s assets pursuant to a 15-year operating agreement.
Myria is owned by a syndicate of investors led by Babcock & Brown, an
international investment and specialized fund and asset management group. See
Note 10 for further discussion regarding this transaction.
Kinder
Morgan Energy Partners operates and owns 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. When
construction of the entire Rockies Express Pipeline project is completed, Kinder
Morgan Energy Partners’ ownership interest will be reduced to 50%, at which time
the capital accounts of West2East Pipeline LLC will be trued up to reflect
Kinder Morgan Energy Partners’ 50% economic interest in the project. According
to the provisions of current accounting standards, because Kinder Morgan Energy
Partners will receive 50% of the economics of the Rockies Express Pipeline
project on an ongoing basis, Kinder Morgan Energy Partners is not considered the
primary beneficiary of West2East Pipeline LLC and thus, accounts for its
investment under the equity method of accounting.
Similarly,
Kinder Morgan Energy Partners operates and owns 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,
Kinder Morgan Energy Partners does not control Plantation Pipe Line Company and
accounts for its investment under the equity method of accounting.
Kinder
Morgan Energy Partners acquired its ownership interest in the Red Cedar
Gathering Company from us on December 31, 1999, and acquired its ownership
interest in the Express pipeline system from us effective August 28, 2008.
Kinder Morgan Energy Partners acquired a 50% ownership interest in Cortez
Pipeline Company from affiliates of Shell in April 2000. Kinder Morgan Energy
Partners formed Midcontinent Express Pipeline LLC in May 2006.
On
October 1, 2008, Kinder Morgan Energy Partners announced that it had entered
into a 50/50 joint venture with Energy Transfer Partners, L.P. to build and
develop the Fayetteville Express Pipeline, a new natural gas pipeline that will
provide shippers in the Arkansas Fayetteville Shale area with takeaway natural
gas capacity, added flexibility, and further access to growing markets.
Fayetteville Express Pipeline LLC will construct the 187-mile, 42-inch diameter
pipeline, which will originate in Conway County, Arkansas, continue eastward
through White County, Arkansas, and terminate at an interconnect with Trunkline
Gas Company’s pipeline in Quitman County, Mississippi. Pending necessary
regulatory approvals, the approximately $1.2 billion pipeline project is
expected to be in service by late 2010 or early 2011.
In
2007, Kinder Morgan Energy Partners began making cash contributions to
Midcontinent Express Pipeline LLC, the sole owner of the Midcontinent
Express Pipeline, for its share of the Midcontinent Express Pipeline
construction costs; however, as of December 31, 2008, Kinder Morgan Energy
Partners had no net investment in Midcontinent Express Pipeline LLC because in
2008, Midcontinent Express Pipeline LLC established and made borrowings under
its own revolving bank credit facility in order to fund its pipeline
construction costs and to make distributions to its member owners to fully
reimburse them for prior contributions.
107
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
In
January 2008, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a
subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement,
which provides MarkWest Pioneer, L.L.C. a one-time right to purchase a 10%
ownership interest in Midcontinent Express Pipeline LLC after the pipeline is
fully constructed and fully placed into service—currently estimated to be August
1, 2009. If the option is exercised, Kinder Morgan Energy Partners and Energy
Transfer Partners, L.P. will each own 45% of Midcontinent Express Pipeline LLC,
while MarkWest Pioneer, L.L.C. will own the remaining 10%.
In
addition to the investments listed above, significant equity investments as of
December 31, 2007 included a 25% equity interest in Thunder Creek Gas Services,
LLC and a 49.5% interest in Thermo Cogeneration Partnerships, L.P. and
Greenhouse Holdings, LLC (“Thermo Companies”). Kinder Morgan Energy Partners
sold its ownership interest in Thunder Creek Gas Services, LLC to PVR Midstream
LLC on April 1, 2008 and we sold our interests in the Thermo Companies to Bear
Stearns on January 25, 2008. Both Kinder Morgan Energy Partners’ divestiture of
its investment in Thunder Creek Gas Services, LLC and our sale of our investment
in the Thermo Companies are discussed in Note 10.
The
amount of our recorded long-term investments is as follows:
|
December
31,
|
|||||
|
2008
|
2007
|
||||
|
(In
millions)
|
|||||
|
Equity
Method Investments:
|
|||||
|
NGPL
PipeCo LLC
|
$
|
717.3
|
$
|
720.0
|
|
|
Express
Pipeline System
|
64.9
|
402.1
|
|||
|
Plantation
Pipe Line Company
|
343.6
|
351.4
|
|||
|
Thermo
Companies
|
-
|
53.5
|
|||
|
West2East
Pipeline LLC
|
501.1
|
191.9
|
|||
|
Red
Cedar Gathering Company
|
138.9
|
135.6
|
|||
|
Midcontinent
Express Pipeline LLC
|
-
|
63.0
|
|||
|
Thunder
Creek Gas Services, LLC
|
-
|
37.0
|
|||
|
Cortez
Pipeline Company
|
13.6
|
14.2
|
|||
|
Fayetteville
Express Pipeline LLC
|
9.0
|
-
|
|||
|
Horizon
Pipeline Company1
|
-
|
-
|
|||
|
Subsidiary
Trusts Holding Solely Debentures of Kinder Morgan
|
8.6
|
8.6
|
|||
|
All
Others
|
17.2
|
18.9
|
|||
|
Total
Equity Investments
|
1,814.2
|
1,996.2
|
|||
|
Gulf
Opportunity Zone Bonds
|
13.2
|
-
|
|||
|
Total
Long-term Investments
|
$
|
1,827.4
|
$
|
1,996.2
|
|
____________
|
1
|
Balance
at December 31, 2007 is included in the caption “Assets Held for Sale,
Non-current” in the accompanying Consolidated Balance
Sheet.
|
108
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Our
earnings (losses) from equity investments and our amortization of excess costs
over underlying fair value of net assets of these investments were as
follows:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
NGPL
PipeCo LLC
|
$
|
40.1
|
$
|
n/a
|
$
|
n/a
|
$
|
n/a
|
||||||||
|
Cortez
Pipeline Company
|
20.8
|
10.5
|
8.7
|
19.2
|
||||||||||||
|
Express
Pipeline System
|
8.2
|
14.9
|
5.0
|
17.1
|
||||||||||||
|
Plantation
Pipe Line Company
|
13.6
|
10.8
|
11.9
|
12.8
|
||||||||||||
|
Thermo
Companies
|
-
|
8.0
|
5.1
|
11.3
|
||||||||||||
|
Red
Cedar Gathering Company
|
26.7
|
16.1
|
11.9
|
36.3
|
||||||||||||
|
Customer
Works LP1
|
n/a
|
n/a
|
-
|
-
|
||||||||||||
|
Thunder
Creek Gas Services, LLC
|
1.3
|
1.2
|
1.0
|
2.5
|
||||||||||||
|
Midcontinent
Express Pipeline LLC
|
0.5
|
1.2
|
0.2
|
-
|
||||||||||||
|
West2East
Pipeline LLC
|
84.9
|
(8.2
|
)
|
(4.2
|
)
|
-
|
||||||||||
|
Horizon
Pipeline Company
|
0.2
|
1.0
|
0.6
|
1.8
|
||||||||||||
|
Heartland
Pipeline Company2
|
n/a
|
-
|
-
|
-
|
||||||||||||
|
All
Others
|
4.8
|
1.3
|
0.5
|
3.2
|
||||||||||||
|
Total
|
$
|
201.1
|
$
|
56.8
|
$
|
40.7
|
$
|
104.2
|
||||||||
|
Amortization
of Excess Costs
|
$
|
(5.7
|
)
|
$
|
(3.4
|
)
|
$
|
(2.4
|
)
|
$
|
(5.6
|
)
|
||||
|
|
____________
|
|
1
|
This
investment was part of the Terasen Inc. sale, therefore our earnings from
it are included in “(Loss) Income from Discontinued Operations, Net of
Tax” in the accompanying Consolidated Statements of Operations; see Note
11.
|
|
2
|
This
investment was part of the North System sale, therefore our earnings from
it are included in “(Loss) Income from Discontinued Operations, Net of
Tax” in the accompanying Consolidated Statements of Operations; see Note
11.
|
Summarized
combined unaudited financial information for our significant equity investments
(listed above) is reported below (amounts represent 100% of investee financial
information):
|
Year
Ended December 31,
|
|||||||||||
|
2008
|
2007
|
2006
|
|||||||||
|
(In
millions)
|
|||||||||||
|
Revenues
|
$
|
2,170.4
|
$
|
738.4
|
$
|
692.1
|
|||||
|
Costs
and Expenses
|
1,649.6
|
534.4
|
483.2
|
||||||||
|
Net
Income
|
$
|
520.8
|
$
|
204.0
|
$
|
208.9
|
|||||
|
December
31,
|
|||||
|
2008
|
20071
|
||||
|
(In
millions)
|
|||||
|
Current
Assets
|
$
|
501.7
|
$
|
3,566.2
|
|
|
Non-current
Assets
|
13,582.1
|
11,469.5
|
|||
|
Current
Liabilities
|
3,876.4
|
572.3
|
|||
|
Non-current
Liabilities
|
5,306.0
|
6,078.4
|
|||
|
Minority
Interest in Equity of Subsidiaries
|
0.6
|
1.7
|
|||
|
Partners’/Owners’
Equity
|
4,900.8
|
8,383.2
|
|||
____________
|
1
|
Includes
amounts associated with our NGPL business segment. In December 2007, we
entered into a definitive agreement to sell an 80% ownership interest in
our NGPL business segment. The closing of the sale occurred on February
15, 2008 (see Note 10).
|
5. Asset
Retirement Obligations
We
have included $2.5 million of our total asset retirement obligations as of
December 31, 2008 in the caption “Other” within “Current Liabilities” and the
remaining $74.0 million in the caption “Other Long-term Liabilities and Deferred
Credits:” in the accompanying Consolidated Balance Sheet. A reconciliation of
the changes in our accumulated asset retirement obligations for the year ended
December 31, 2008, seven months ended December 31, 2007 and five months ended
May 31, 2007 is as follows:
109
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Balance
at Beginning of Period
|
$
|
55.0
|
$
|
53.1
|
$
|
52.5
|
||||||
|
Additions
|
26.2
|
1.2
|
0.2
|
|||||||||
|
Liabilities
Settled
|
(8.2
|
)1
|
(0.8
|
)
|
(0.7
|
)
|
||||||
|
Accretion
Expense
|
3.5
|
1.5
|
1.1
|
|||||||||
|
Balance
at End of Period
|
$
|
76.5
|
$
|
55.0
|
$
|
53.1
|
||||||
____________
|
1
|
Amount
includes $2.8 million settled through our 80% sale of NGPL in
2008.
|
In
the CO2–KMP
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, 2008 and December 31, 2007, we have recognized
asset retirement obligations in the aggregate amount of $74.1 million and $49.2
million, respectively, relating to these requirements at existing sites within
the CO2–KMP
business segment. The $24.9 million increase since December 31, 2007 was
primarily related to higher estimated service, material and equipment costs
related to the CO2–KMP
business segment’s legal obligations associated with the retirement of tangible
long-lived assets.
In
the Natural Gas Pipelines–KMP business segment, the operating systems are
composed of underground piping, compressor stations and associated facilities,
natural gas storage facilities and certain other facilities and equipment.
Currently, we have no plans to abandon any of these facilities, the majority of
which have been providing utility services for many years. However, if we were
to cease providing utility services in total or in any particular area, we would
be required to remove certain surface facilities and equipment from land
belonging to our customers and others (we would generally have no obligations
for removal or remediation with respect to equipment and facilities, such as
compressor stations, located on land we own). We believe we can reasonably
estimate both the time and costs associated with the retirement of these
facilities and as of December 31, 2008 and December 31, 2007, we have recognized
asset retirement obligations in the aggregate amount of $2.4 million and $3.0
million, respectively, relating to the businesses within the Natural Gas
Pipelines–KMP business segment.
We
have various other obligations throughout our businesses to remove facilities
and equipment on rights-of- way and other leased facilities. We currently cannot
reasonably estimate the fair value of these obligations because the associated
assets have indeterminate lives. These assets include pipelines, certain
processing plants and distribution facilities, and certain bulk and liquids
terminal facilities. An asset retirement obligation, if any, will be recognized
once sufficient information is available to reasonably estimate the fair value
of the obligation.
6. Cash
Flow Information
We
consider all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents. “Other, Net,” presented as a
component of “Cash Flows From Operating Activities” in the accompanying
Consolidated Statements of Cash Flows includes, among other things, non-cash
charges and credits to income including amortization of deferred revenue and
amortization of gains and losses realized on the termination of interest rate
swap agreements; see Note 15.
110
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
ADDITIONAL
CASH FLOW INFORMATION
Changes
in Working Capital Items
(Net
of Effects of Acquisitions and Sales)
Increase
(Decrease) in Cash and Cash Equivalents
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Accounts
Receivable
|
$
|
60.6
|
$
|
(64.3
|
)
|
$
|
(31.9
|
)
|
$
|
192.5
|
||||||
|
Materials
and Supplies Inventory
|
(7.9
|
)
|
(8.1
|
)
|
(1.7
|
)
|
(0.5
|
)
|
||||||||
|
Other
Current Assets
|
11.1
|
(65.2
|
)
|
0.5
|
103.2
|
|||||||||||
|
Accounts
Payable
|
(99.3
|
)
|
68.7
|
26.3
|
(243.4
|
)
|
||||||||||
|
Accrued
Interest
|
0.7
|
65.9
|
(22.5
|
)
|
56.7
|
|||||||||||
|
Accrued
Taxes
|
109.0
|
142.5
|
(114.0
|
)
|
(4.3
|
)
|
||||||||||
|
Other
Current Liabilities
|
(119.1
|
)
|
(35.5
|
)
|
(59.6
|
)
|
(24.2
|
)
|
||||||||
|
$
|
(44.9
|
)
|
$
|
104.0
|
$
|
(202.9
|
)
|
$
|
80.0
|
|||||||
Supplemental
Disclosures of Cash Flow Information
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Cash
Paid for
|
||||||||||||||||
|
Interest
(Net of Amount Capitalized)
|
$
|
649.9
|
$
|
586.5
|
$
|
381.8
|
$
|
731.6
|
||||||||
|
Income
Taxes Paid (Net of Refunds)1
|
$
|
657.3
|
$
|
146.4
|
$
|
133.3
|
$
|
314.9
|
||||||||
__________
|
1
|
Income
taxes paid during 2008 includes taxes paid related to prior
periods.
|
During
the year ended December 31, 2008, seven months ended December 31, 2007, five
months ended May 31, 2007 and year ended December 31, 2006, we acquired $4.8
million, $1.2 million, $18.5 million and $6.1 million, respectively, of assets
by the assumption of liabilities.
Non-cash
investing activities during the year ended December 31, 2008, seven months ended
December 31, 2007, five months ended May 31, 2007 and year ended December 31,
2006 include increases in the accrual for construction costs of $17.7 million,
$83.0 million, $4.9 million and $70.5 million, respectively.
Pursuant
to the purchase and sale agreement with Trans-Global Solutions, Inc., Kinder
Morgan Energy Partners issued 266,813 common units in May 2007 to TGS to settle
a purchase price liability related to its acquisition of bulk terminal
operations from TGS in April 2005. As agreed between TGS and Kinder Morgan
Energy Partners, the units were issued equal to a value of $15.0 million.
Additionally, in December 2006, Kinder Morgan Energy Partners contributed 34,627
common units, representing approximately $1.7 million of value, as partial
consideration for the acquisition of Devco USA L.L.C.
In
March 2006, Kinder Morgan Energy Partners made a $17.0 million contribution of
net assets to its investment in Coyote Gulch.
We
adopted Emerging Issues Task Force No. 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, effective
January 1, 2006 which resulted in the inclusion of the accounts, balances and
results of operations of Kinder Morgan Energy Partners in our consolidated
financial statements. Prior to January 1, 2006, we applied the equity method of
accounting to our investment in Kinder Morgan Energy Partners. Therefore, we
have included Kinder Morgan Energy Partners’ cash and cash equivalents at
December 31, 2005 of $12.1 million as an “Effect of Accounting Change on Cash”
in the accompanying Consolidated Statement of Cash Flows for the year ended
December 31, 2006.
Distributions
received by our Kinder Morgan Management subsidiary from its investment in
i-units of Kinder Morgan Energy Partners are in the form of additional i-units,
while distributions made by Kinder Morgan Management to its shareholders are in
the form of additional Kinder Morgan Management shares, see Note 2.
111
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
As
discussed in Note 17 following, during the year ended December 31, 2006, we made
non-cash grants of restricted shares of common stock.
7. Transactions
with Related Parties
Related-party
operating revenues included in the accompanying Consolidated Statements of
Operations for the year ended December 31, 2008, seven months ended December 31,
2007, five months ended May 31, 2007 and year ended December 31, 2006 were $11.5
million, $6.7 million, $4.5 million and $6.1 million, respectively:
During
2008, 2007 and 2006, related-party operating revenues were primarily
attributable to Horizon Pipeline Company and Plantation Pipeline
Company.
The
caption “Gas Purchases and Other Costs of Sales” in the accompanying
Consolidated Statements of Operations includes related-party costs
totaling $5.4 million, $0.8 million, $0.3 million and $1.5 million
for the year ended December 31, 2008, seven months ended December 31, 2007, five
months ended May 31, 2007 and year ended December 31, 2006, respectively. During
2008, related party “Gas Purchases and Other Costs of Sales” is primarily
related to purchases from NGPL PipeCo LLC.
The
caption “Interest Expense, Net” in the accompanying Consolidated Statements of
Operations includes related-party costs totaling $5.5 million, $2.6 million,
$1.8 million and $4.5 million for the year ended December 31, 2008, seven months
ended December 31, 2007, five months ended May 31, 2007 and year ended December
31, 2006, respectively. Related party “Interest Expenses, Net” is primarily
related to interest income from Plantation Pipe Line Company and Express US
Holdings LP.
Significant
Investors
As
discussed in Note 1, as a result of the Going Private transaction, a number of
individuals and entities became significant investors in us because of their
investment in Knight Holdco LLC. By virtue of the size of their ownership
interest, two of those investors became “related parties” to us as that term is
defined in the authoritative accounting literature: (i) American International
Group, Inc. and certain of its affiliates, including Highstar Capital (“AIG”)
and (ii) Goldman Sachs Capital Partners and certain of its affiliates (“Goldman
Sachs”). We enter into transactions with certain AIG affiliates in the ordinary
course of their conducting insurance and insurance-related activities, although
no individual transaction is, and all such transactions collectively are not,
material to our consolidated financial statements. In addition, Goldman Sachs
has provided, and may in the future provide, us and our affiliates investment
banking services. Such activity is not material to our consolidated financial
statements. We also conduct commodity risk management activities in the ordinary
course of implementing our risk management strategies in which the counterparty
to certain of our derivative transactions is an affiliate of Goldman Sachs. In
conjunction with these activities, we are a party (through one of our
subsidiaries engaged in the production of crude oil) to a hedging facility with
J. Aron & Company/Goldman Sachs, which requires us to provide certain
periodic information but does not require the posting of margin. As a result of
changes in the market value of our derivative positions, we have recorded both
amounts receivable from and payable to Goldman Sachs affiliates. At December 31,
2008 and December 31, 2007, the fair values of these derivative contracts are
included in the accompanying Consolidated Balance Sheets within the captions
indicated in the following table:
|
December
31,
2008
|
December
31,
2007
|
||||||
|
(In
millions)
|
|||||||
|
Derivative
Assets (Liabilities)
|
|||||||
|
Current
Assets: Fair Value of Derivative Instruments
|
$
|
60.4
|
$
|
-
|
|||
|
Assets:
Fair Value of Derivative Instruments, Non-current
|
$
|
20.1
|
$
|
-
|
|||
|
Current
Liabilities: Fair Value of Derivative Instruments
|
$
|
(13.2
|
)
|
$
|
(239.8
|
)
|
|
|
Liabilities
and Stockholder’s Equity: Fair Value of Derivative Instruments,
Non-current
|
$
|
(24.1
|
)
|
$
|
(386.5
|
)
|
|
Knight
Holdco LLC
In
accordance with SFAS No. 123R (revised 2007), Share-Based Payment, our
parent, Knight Holdco LLC, is required to recognize compensation expense in
connection with its Class A-1 and Class B units over the expected life of such
units. As a subsidiary of Knight Holdco LLC, we and certain of our subsidiaries
are allocated this compensation expense, which totaled $7.6 million for the year
ended December 31, 2008, although none of us or any of our subsidiaries have any
obligation, nor do we expect to pay any amounts in respect of such
units.
112
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Plantation
Pipe Line Company
Kinder
Morgan Energy Partners has a seven-year note receivable bearing interest at the
rate of 4.72% per annum from Plantation Pipe Line Company, its 51.17%-owned
equity investee. The outstanding note receivable balance was $88.5 million and
$89.7 million as of December 31, 2008 and December 31, 2007, respectively. Of
these amounts, $3.7 million and $2.4 million are included within “Accounts,
Notes and Interest Receivable, Net” on the accompanying Consolidated Balance
Sheets as of December 31, 2008 and December 31, 2007, respectively, and the
remainder is included within “Accounts, Notes and Interest Receivable, Net ” at
each reporting date.
Express
US Holdings LP Note Receivable
On
June 30, 2008, we exchanged our C$113.6 million preferred equity interest in
Express US Holdings LP for two subordinated notes from Express US Holdings LP
with a combined face value of $111.4 million (C$113.6 million).
On
August 28, 2008, we sold our one-third interest in the net assets of the Express
pipeline system (“Express”), as well as our full ownership of the net assets of
the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners.
This transaction included the sale of our subordinated notes described above. We
accounted for this transaction as a transfer of net assets between entities
under common control. Therefore, following our sale of Express and Jet Fuel to
Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the
assets and liabilities acquired at our carrying amounts (historical cost) at the
date of transfer; see Note 14 for additional information relating to this
sale.
As
of December 31, 2008, the outstanding note receivable balance, representing the
translated amount included in our consolidated financial statements in U.S.
dollars, was $93.3
million, and we included this amount in the accompanying Consolidated Balance
Sheet within the caption “Accounts, Notes and Interest Receivable,
Net.”
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 Kinder Morgan Energy
Partners’ ownership interest in Coyote Gulch to Red Cedar Gathering on September
1, 2006, discussed below, Kinder Morgan Energy Partners was the managing partner
and owned a 50% equity interest in Coyote Gulch, with the Southern Ute Tribe
owning the remaining 50%.
On
September 1, 2006, Kinder Morgan Energy Partners and the Southern Ute Tribe
contributed the value of their 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 Kinder Morgan Energy Partners’ 50% equity
contribution from Coyote Gulch to Red Cedar on September 1, 2006 was $16.7
million, and this amount remains included within “Investments: Other” in the
accompanying Consolidated Balance Sheets.
NGPL
PipeCo LLC
On
February 15, 2008, Knight Inc. entered in to an Operations and Reimbursement
Agreement (“Agreement”) with Natural Gas Pipeline Company of America LLC, a
wholly owned subsidiary of NGPL PipeCo LLC. The Agreement provides for Knight
Inc. to be reimbursed, at cost, for pre-approved operations and maintenance
costs, plus a $43.2 million annual general and administration fixed fee charge
(“Fixed Fee”), for services provided under the Agreement. This Fixed Fee
escalates at 3% each year through 2010 and is billed monthly. For the year ended
December 31, 2008, these Fixed Fees totaled $38.9 million.
In
addition, Kinder Morgan Energy Partners purchases transportation and storage
services from NGPL PipeCo LLC. For the year ended December 31, 2008, these
purchases totaled $8.1 million.
8. Accounting
for Minority Interests
The
caption “Minority Interests in Equity of Subsidiaries” in the accompanying
Consolidated Balance Sheets is comprised of the following balances:
|
December
31,
|
|||||||
|
2008
|
2007
|
||||||
|
(In
millions)
|
|||||||
|
Kinder
Morgan Energy Partners
|
$
|
2,198.2
|
$
|
1,616.0
|
|||
|
Kinder
Morgan Management
|
1,826.5
|
1,657.7
|
|||||
|
Triton
Power Company LLC
|
39.0
|
29.2
|
|||||
|
Other
|
8.9
|
11.1
|
|||||
|
$
|
4,072.6
|
$
|
3,314.0
|
||||
113
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
During
the year ended December 31, 2008, Kinder Morgan Energy Partners paid
distributions of $3.89 per common unit, of which $626.6 million was paid to the
public holders (represented in minority interests) of Kinder Morgan Energy
Partners’ common units. On January 21, 2009, Kinder Morgan Energy Partners
declared a quarterly distribution of $1.05 per common unit for the quarterly
period ended December 31, 2008. The distribution was paid on February 13, 2009,
to unitholders of record as of January 30, 2009.
9. Kinder
Morgan Management, LLC
On
November 14, 2008, Kinder Morgan Management made a distribution of 0.021570 of
its shares per outstanding share (1,646,891 total shares) to shareholders of
record as of October 31, 2008, based on the $1.02 per common unit distribution
declared by Kinder Morgan Energy Partners. On February 13, 2009, Kinder Morgan
Management made a distribution of 0.024580 of its shares per outstanding share
(1,917,189 total shares) to shareholders of record as of January 30, 2009, based
on the $1.05 per common unit distribution declared by Kinder Morgan Energy
Partners. These distributions are paid in the form of additional shares or
fractions thereof calculated by dividing the Kinder Morgan Energy Partners’ cash
distribution per common unit by the average market price of a Kinder Morgan
Management share determined for a ten-trading day period ending on the trading
day immediately prior to the ex-dividend date for the shares. Kinder Morgan
Management has paid share distributions totaling 5,565,424, 2,402,439, 2,028,367
and 4,383,303 shares in the years ended December 31, 2008, seven months ended
December 31, 2007, five months ended May 31, 2007 and year ended December 31,
2006, respectively.
On
May 15, 2007, Kinder Morgan Management issued 5.7 million listed shares in a
public offering at a price of $52.26 per share. Kinder Morgan Management used
the net proceeds of $297.9 million from the sale to purchase 5.7 million i-units
from Kinder Morgan Energy Partners.
At
December 31, 2008, we owned 11.1 million Kinder Morgan Management shares
representing 14.3% of Kinder Morgan Management’s outstanding
shares.
10. Business
Combinations, Investments and Sales
The
following acquisitions were accounted for as business combinations and the
assets acquired and liabilities assumed were recorded at their estimated fair
market values as of the acquisition date. The preliminary allocation of purchase
price to assets acquired (and any liabilities assumed) may be adjusted to
reflect the final determined amounts during a 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. Additionally, goodwill associated with transactions occurring prior
to the Going Private transaction has been reallocated based on the purchase
price paid in the Going Private transaction (See Note 1). The results of
operations from these acquisitions are included in our consolidated financial
statements from the acquisition date.
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. Kinder Morgan Energy Partners contributed 66 2/3% of the consideration for
this purchase, which corresponded to its 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.
With
regard to Rockies Express Pipeline LLC’s acquisition of Entrega Gas Pipeline
LLC, the allocation of the purchase price to assets acquired and liabilities
assumed was as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
244.6
|
|
Total
Purchase Price
|
$
|
244.6
|
|
Allocation
of Purchase Price
|
||
|
Property,
Plant and Equipment
|
$
|
244.6
|
|
$
|
244.6
|
On
the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an
interstate natural gas pipeline that when fully constructed, will be over 300
miles in length. The acquired assets are included in the Natural Gas
Pipelines–KMP business segment.
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 by Rockies Express Pipeline LLC) will be known as the Rockies Express
Pipeline. The combined 1,679-mile
114
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
pipeline
system will be one of the largest natural gas pipelines ever constructed in
North America. The project, with an expected cost of $6.3 billion (including
expansion) 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. 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 Kinder Morgan
Energy Partners’ subsidiary Kinder Morgan W2E Pipeline LLC, Kinder Morgan Energy
Partners will continue to operate the project but its 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, Kinder Morgan
Energy Partners’ 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), Consolidation of Variable Interest
Entities-An Interpretation of ARB No. 51 (“FIN 46R”), because 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 on June 30, 2006, Kinder Morgan
Energy Partners receives 50% of the economics of the Rockies Express project on
an ongoing basis and thus, effective June 30, 2006, Kinder Morgan Energy
Partners was 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 the investment in West2East Pipeline LLC from full consolidation to the
equity method following the decrease in Kinder Morgan Energy Partners’ ownership
percentage.
Under
the equity method, the costs of the investment in West2East Pipeline LLC are
recorded within the “Investments” caption on the accompanying Consolidated
Balance Sheets 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” caption in the accompanying Consolidated Balance
Sheets.
In
addition, Kinder Morgan Energy Partners has guaranteed its proportionate share
of West2East Pipeline LLC’s debt borrowings under a $2 billion credit facility,
a $2 billion commercial program and $600 million of senior notes entered into by
Rockies Express Pipeline LLC. See Note 18 for additional information regarding
Rockies Express Pipeline LLC’s debt.
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 $63.6 million, consisting of $60.0
million in cash and $3.6 million in assumed liabilities. The acquisition was
effective March 1, 2006. However, Kinder Morgan Energy Partners divested certain
acquired properties that were not considered candidates for carbon dioxide
enhanced oil recovery, thus reducing the total investment. Kinder Morgan Energy
Partners 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,
produce approximately 400 barrels of oil equivalent per day and include some
fields with potential for enhanced oil recovery development near Kinder Morgan
Energy Partners’ current carbon dioxide operations. The acquired operations are
included as part of the CO2–KMP
business segment.
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
60.0
|
|
Liabilities
Assumed
|
3.6
|
|
|
Total
Purchase Price
|
$
|
63.6
|
|
Allocation
of Purchase Price
|
||
|
Current
Assets
|
$
|
0.1
|
|
Property,
Plant and Equipment
|
63.5
|
|
|
$
|
63.6
|
115
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Terminal
Assets
In
April 2006, Kinder Morgan Energy Partners 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 Kinder Morgan Energy Partners’ 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 Kinder Morgan
Energy Partners’ existing Texas petroleum coke terminal operations and maximizes
the value of its existing deepwater terminal by providing customers with both
rail and vessel transportation options for bulk products. Thirdly, Kinder Morgan
Energy Partners 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 Kinder Morgan
Energy Partners’ existing rail transloading operations. All of the acquired
assets are included in the Terminals–KMP business segment.
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
61.6
|
|
Liabilities
Assumed
|
0.3
|
|
|
Total
Purchase Price
|
$
|
61.9
|
|
Allocation
of Purchase Price
|
||
|
Current
Assets
|
$
|
0.5
|
|
Property,
Plant and Equipment
|
43.6
|
|
|
Goodwill
|
17.8
|
|
|
$
|
61.9
|
A
total of $17.8 million of goodwill was assigned to the Terminals–KMP business
segment and the entire amount is expected to be deductible for tax purposes.
Kinder Morgan Energy Partners believes the purchase price for the assets,
including intangible assets, exceeded the fair value of acquired net assets and
liabilities; in the aggregate, these factors represented goodwill.
Transload
Services, LLC
Effective
November 20, 2006, Kinder Morgan Energy Partners acquired all of the membership
interests of Transload Services, LLC from Lanigan Holdings, LLC for an aggregate
consideration of approximately $16.6 million, consisting of $15.8 million in
cash and $0.8 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
the Terminals–KMP business segment, and the acquisition further expanded and
diversified Kinder Morgan Energy Partners’ existing terminals’ materials
services (rail transloading) operations.
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
15.8
|
|
Liabilities
Assumed
|
0.8
|
|
|
Total
Purchase Price
|
$
|
16.6
|
|
Allocation
of Purchase Price
|
||
|
Current
Assets
|
$
|
1.6
|
|
Property,
Plant and Equipment
|
6.6
|
|
|
Goodwill
|
8.4
|
|
|
$
|
16.6
|
116
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
A
total of $8.4 million of goodwill was assigned to the Terminals–KMP business
segment, and the entire amount is expected to be deductible for tax purposes.
Kinder Morgan Energy Partners believes this acquisition resulted in the
recognition of goodwill primarily because it establishes a business presence in
several key markets, taking advantage of the non-residential and highway
construction demand for steel that contributed to our acquisition price
exceeding the fair value of acquired identifiable net assets and liabilities -
in the aggregate, these factors represented goodwill.
Devco
USA L.L.C.
Effective
December 1, 2006, Kinder Morgan Energy Partners 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 Kinder Morgan Energy
Partners believes the acquisition and subsequent application of this acquired
technology complements its existing dry-bulk terminal operations. Kinder Morgan
Energy Partners allocated $6.5 million of the total purchase price to the value
of this intangible asset, which is included as part of the Terminals–KMP
business segment.
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
4.8
|
|
Issuance
of Common Units
|
1.6
|
|
|
Liabilities
Assumed
|
0.9
|
|
|
Total
Purchase Price
|
$
|
7.3
|
|
Allocation
of Purchase Price
|
||
|
Current
Assets
|
$
|
0.8
|
|
Deferred
Charges and Other Assets
|
6.5
|
|
|
$
|
7.3
|
Roanoke,
Virginia Products Terminal
Effective
December 15, 2006, Kinder Morgan Energy Partners 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 Kinder Morgan
Energy Partners owns in the southeastern region of the United States, and the
acquired terminal is included as part of the Products Pipelines–KMP business
segment.
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
6.4
|
|
Total
Purchase Price
|
$
|
6.4
|
|
Allocation
of Purchase Price
|
||
|
Property,
Plant and Equipment
|
$
|
6.4
|
|
$
|
6.4
|
Interest
in Cochin Pipeline
Effective
January 1, 2007, Kinder Morgan Energy Partners acquired the remaining
approximate 50.2% interest in the Cochin pipeline system that it did not already
own for an aggregate consideration of approximately $47.8 million, consisting of
$5.5 million in cash and a note payable having a fair value of $42.3 million. As
part of the transaction, the seller also agreed to reimburse Kinder Morgan
Energy Partners for certain pipeline integrity management costs over a five-year
period in an aggregate amount not to exceed $50 million. Upon closing, Kinder
Morgan Energy Partners became the operator of the pipeline.
The
Cochin Pipeline is a multi-product liquids pipeline consisting of approximately
1,900 miles of pipe operating between Fort Saskatchewan, Alberta, and Windsor,
Ontario, Canada. Its operations are included as part of the Products
Pipeline–KMP business segment.
117
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
5.5
|
|
Notes
Payable (Fair Value)
|
42.3
|
|
|
Total
Purchase Price
|
$
|
47.8
|
|
Allocation
of Purchase Price
|
||
|
Property,
Plant and Equipment
|
$
|
47.8
|
|
$
|
47.8
|
Vancouver
Wharves Terminal
On
May 30, 2007, Kinder Morgan Energy Partners purchased the Vancouver Wharves bulk
marine terminal from British Columbia Railway Company, a crown corporation owned
by the Province of British Columbia, for aggregate consideration of $59.5
million, consisting of $38.8 million in cash and $20.7 million in assumed
liabilities. The acquisition both expanded and complemented Kinder Morgan Energy
Partners’ existing terminal operations and all of the acquired assets are
included in the Terminals–KMP business segment.
In
the first half of 2008, Kinder Morgan Energy Partners made its final purchase
price adjustments to reflect final fair value of acquired assets and final
expected value of assumed liabilities. Kinder Morgan Energy Partners’
adjustments increased “Property, Plant and Equipment, Net” by $2.7 million,
reduced working capital balances by $1.6 million, and increased long-term
liabilities by $1.1 million. Based on Kinder Morgan Energy Partners’ estimate of
fair market values, we allocated $53.4 million of our combined purchase price to
“Property, Plant and Equipment, Net,” and $6.1 million to items included within
“Current Assets.”
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
38.8
|
|
Assumed
Liabilities
|
20.7
|
|
|
Total
Purchase Price
|
$
|
59.5
|
|
|
||
|
Allocation
of Purchase Price
|
||
|
Current
Assets
|
$
|
6.1
|
|
Property,
Plant and Equipment
|
53.4
|
|
|
$
|
59.5
|
Marine
Terminals, Inc.
Effective
September 1, 2007, Kinder Morgan Energy Partners acquired certain bulk terminals
assets from Marine Terminals, Inc. for an aggregate consideration of
approximately $102.1 million, consisting of $100.8 million in cash and assumed
liabilities of $1.3 million. The acquired assets and operations are primarily
involved in the handling and storage of steel and alloys. The acquisition both
expanded and complemented Kinder Morgan Energy Partners existing ferro alloy
terminal operations and will provide customers further access to Kinder Morgan
Energy Partners’ growing national network of marine and rail terminals. All of
the acquired assets are included in the Terminals-KMP business
segment.
During
2008, Kinder Morgan Energy Partners paid an additional $0.5 million for purchase
price settlements, and made purchase price adjustments to reflect final fair
value of acquired assets and final expected value of assumed liabilities. Kinder
Morgan Energy Partners’ 2008 adjustments primarily reflected changes in the
allocation of the purchase cost to intangible assets acquired. Based on Kinder
Morgan Energy Partners’ estimate of fair market values, we allocated $60.8
million of the combined purchase price to “Property, Plant and Equipment, Net,”
$21.7 million to “Other Intangibles, Net,” $18.6 million to “Goodwill,” and $1.0
million to “Current Assets: Other” and “Deferred Charges and Other
Assets.”
The
allocation to “Other Intangibles, Net” included a $20.1 million amount
representing the fair value of a service contract entered into with Nucor
Corporation, a large domestic steel company with significant operations in the
Southeast region of the United States. For valuation purposes, the service
contract was determined to have a useful life of 20 years, and pursuant to the
contract’s provisions, the acquired terminal facilities will continue to provide
Nucor with handling, processing, harboring and warehousing
services.
The
allocation to “Goodwill,” which is expected to be deductible for tax purposes,
was based on the fact that this acquisition both expanded and complemented
Kinder Morgan Energy Partners’ existing ferro alloy terminal operations and will
provide Nucor and other customers further access to Kinder Morgan Energy
Partners’ growing national network of marine and rail
118
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
terminals.
Kinder Morgan Energy Partners believes the acquired value of the assets,
including all contributing intangible assets, exceeded the fair value of
acquired identifiable net assets and liabilities—in the aggregate, these factors
represented goodwill.
The
allocation of the purchase price to assets acquired and liabilities assumed was
as follows (in millions):
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
100.8
|
|
Assumed
Liabilities
|
1.3
|
|
|
Total
Purchase Price
|
$
|
102.1
|
|
Allocation
of Purchase Price
|
||
|
Current
Assets
|
$
|
0.2
|
|
Property,
Plant and Equipment
|
60.8
|
|
|
Deferred
Charges and Other
|
22.5
|
|
|
Goodwill
|
18.6
|
|
|
$
|
102.1
|
Wilmington,
North Carolina Liquids Terminal
On
August 15, 2008, Kinder Morgan Energy Partners purchased certain terminal assets
from Chemserve, Inc. for an aggregate consideration of $12.7 million, consisting
of $11.8 million in cash and $0.9 million in assumed liabilities. The liquids
terminal facility is located in Wilmington, North Carolina and stores petroleum
products and chemicals. The acquisition both expanded and complemented Kinder
Morgan Energy Partners’ existing Mid-Atlantic region terminal operations and all
of the acquired assets are included in the Terminals–KMP business segment. In
the fourth quarter of 2008, the purchase price was allocated to reflect the
final fair value of acquired assets and final expected value of assumed
liabilities. A total of $6.8 million of goodwill was assigned to the
Terminals–KMP business segment and the entire amount is expected to be
deductible for tax purposes. Kinder Morgan Energy Partners believes this
acquisition resulted in the recognition of goodwill primarily because of certain
advantageous factors (including the synergies provided by increasing the liquids
storage capacity in the Southeast region of the U.S.) that contributed to the
acquisition price exceeding the fair value of acquired identifiable net assets
and liabilities—in the aggregate, these factors represented
goodwill.
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
11.8
|
|
Assumed
Liabilities
|
0.9
|
|
|
Total
Purchase Price
|
$
|
12.7
|
|
Allocation
of Purchase Price
|
||
|
Property,
Plant and Equipment
|
$
|
5.9
|
|
Goodwill
|
6.8
|
|
|
$
|
12.7
|
Phoenix,
Arizona Products Terminal
Effective
December 10, 2008, Kinder Morgan Energy Partners’ West Coast Products Pipelines
acquired a refined petroleum products terminal located in Phoenix, Arizona from
ConocoPhillips for approximately $27.5 million in cash. The terminal has storage
capacity of approximately 200,000 barrels for gasoline, diesel fuel and ethanol.
The acquisition complemented Kinder Morgan Energy Partners’ existing Phoenix
liquids assets, and the acquired incremental storage will increase Kinder Morgan
Energy Partners’ combined storage capacity in the Phoenix market by
approximately 13%. The acquired terminal is included as part the Products
Pipelines-KMP business segment.
|
Purchase
Price
|
||
|
Cash
Paid, Including Transaction Costs
|
$
|
27.5
|
|
Total
Purchase Price
|
$
|
27.5
|
|
Allocation
of Purchase Price
|
||
|
Property,
Plant and Equipment
|
$
|
27.5
|
|
$
|
27.5
|
119
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Investment
in Rockies Express Pipeline
In
2008, Kinder Morgan Energy Partners made capital contributions of $306.0 million
to West2East Pipeline LLC (the sole owner of Rockies Express Pipeline LLC) to
partially fund its Rockies Express Pipeline construction costs. This cash
contribution was recorded as an increase to “Investments” in the accompanying
Consolidated Balance Sheet as of December 31, 2008, and it was included within
“Cash Flows from Investing Activities: Contributions to Investments” in the
accompanying Consolidated Statement of Cash Flows for the year ended December
31, 2008. Kinder Morgan Energy Partners owns a 51% equity interest in West2East
Pipeline LLC.
Midcontinent
Express Pipeline LLC
During
2008, Kinder Morgan Energy Partners made capital contributions of $27.5 million
to Midcontinent Express Pipeline LLC (“Midcontinent Express Pipeline”) to
partially fund its Midcontinent Express Pipeline construction costs. This cash
contribution has been recorded as an increase to “Investments” in the
accompanying Consolidated Balance Sheet as of December 31, 2008 and has been
included within “Cash Flows from Investing Activities: Contributions to
Investments” in the accompanying Consolidated Statement of Cash Flows for the
year ended December 31, 2008. Kinder Morgan Energy Partners owns a 50% equity
interest in Midcontinent Express Pipeline LLC.
Kinder
Morgan Energy Partners received, in 2008, an $89.1 million return of capital
from Midcontinent Express Pipeline LLC. In February 2008, Midcontinent Express
Pipeline LLC entered into and then made borrowings under a new $1.4 billion
three-year, unsecured revolving credit facility due February 28, 2011.
Midcontinent Express Pipeline LLC then made distributions (in excess of
cumulative earnings) to its two member owners to reimburse them for prior
contributions made to fund its pipeline construction costs, and this cash
receipt has been included in “Cash Flows from Investing Activities:
Distributions from Equity Investees” in the accompanying Consolidated Statement
of Cash Flows for the year ended December 31, 2008.
Fayetteville
Express Pipeline LLC
On
October 1, 2008, Kinder Morgan Energy Partners announced that it has entered
into a 50/50 joint venture with Energy Transfer Partners, L.P. to build and
develop the Fayetteville Express Pipeline, a new natural gas pipeline that will
provide shippers in the Arkansas Fayetteville Shale area with takeaway natural
gas capacity, added flexibility and further access to growing
markets.
The
new pipeline will also interconnect with Natural Gas Pipeline Company of America
LLC’s pipeline in White County, Arkansas; Texas Gas Transmission LLC’s pipeline
in Coahoma County, Mississippi; and ANR Pipeline Company’s pipeline in Quitman
County, Mississippi. Natural Gas Pipeline Company of America LLC’s pipeline
is operated and 20% owned by us. The Fayetteville Express Pipeline will
have an initial capacity of two billion cubic feet of natural gas per
day. Pending necessary regulatory approvals, the approximately $1.2 billion
pipeline project is expected to be in service by late 2010 or early
2011. Fayetteville Express Pipeline LLC has secured binding 10-year
commitments totaling approximately 1.85 billion cubic feet per day.
In
the fourth quarter of 2008, Kinder Morgan Energy Partners made capital
contributions of $9.0 million to Fayetteville Express Pipeline LLC to fund its
proportionate share of certain pre-construction pipeline costs. We included this
cash contribution as an increase to “Investments” in the accompanying
Consolidated Balance Sheet as of December 31, 2008, and we included it within
“Cash Flows from Investing Activities: Contributions to Investments” in the
accompanying Consolidated Statement of Cash Flows for the year ended December
31, 2008.
Pro
Forma Information
Pro
forma information regarding consolidated income statement information that
assumes all of the acquisitions we have made and joint ventures we have entered
into since January 1, 2007, including the ones listed above, had occurred as of
January 1, 2007, is not materially different from the information presented in
the accompanying Consolidated Statements of Operations.
Sales
In
connection with the August 28, 2008 sale to Kinder Morgan Energy Partners of our
33 1/3% ownership interest in the Express pipeline system and our full ownership
of the Jet Fuel pipeline system, Kinder Morgan Energy Partners issued 2,014,693
of common units to us. The units were issued August 28, 2008, and as agreed
between Kinder Morgan Energy Partners and us, were valued at $116.0 million. We
accounted for this transaction as a transfer of net assets between entities
under common control. Kinder Morgan Energy Partners recognized these assets and
liabilities acquired at our carrying amounts (historical cost) at the date of
transfer. For more information on this transaction; see Note 7.
120
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Effective
April 1, 2008, Kinder Morgan Energy Partners sold its 25% ownership interest in
Thunder Creek Gas Services, LLC to PVR Midstream LLC, a subsidiary of Penn
Virginia Corporation. Prior to the sale, we accounted for the investment in
Thunder Creek Gas Services, LLC, referred to in this report as Thunder Creek,
under the equity method of accounting and included its financial results within
the Natural Gas Pipelines–KMP business segment. In the second quarter of 2008,
Kinder Morgan Energy Partners received cash proceeds, net of closing costs and
settlements, of approximately $50.7 million for the investment and used the
proceeds from this sale to reduce the commercial paper borrowings. Due to the
fair market valuation resulting from the Going Private transaction (see Note 1),
the consideration Kinder Morgan Energy Partners received from the sale of its
North System was equal to its carrying value; therefore no gain or loss was
recorded on this disposal transaction.
On
February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC
(formerly MidCon Corp.), which owns Natural Gas Pipeline Company of America LLC
and certain affiliates, collectively referred to as “NGPL,” to Myria Acquisition
Inc. (“Myria”) for approximately $2.9 billion. We also received approximately
$3.0 billion of cash previously held in escrow related to a notes offering by
NGPL PipeCo LLC in December 2007, the net proceeds of which were distributed to
us principally as repayment of intercompany indebtedness and partially as a
dividend, immediately prior to the closing of the sale to Myria. Pursuant to the
purchase agreement, Myria acquired all 800 Class B shares and we retained all
200 Class A shares of NGPL PipeCo LLC. We continue to operate NGPL’s assets
pursuant to a 15-year operating agreement. Myria is owned by a syndicate of
investors led by Babcock & Brown, an international investment and
specialized fund and asset management group. The total proceeds from this sale
of $5.9 billion were used to pay off the entire outstanding balances of our
senior secured credit facility’s Tranche A and Tranche B term loans, to
repurchase $1.67 billion of our outstanding debt securities and to reduce
balances outstanding under our $1.0 billion revolving credit facility (see Note
14).
In
January 2008, we completed the sale of our interests in three natural gas-fired
power plants in Colorado to Bear Stearns. We received proceeds of $63.1
million.
During
2007, we completed the sales of (i) our U.S.-based retail natural gas
distribution and related operations, (ii) Terasen Inc., our Canada-based retail
natural gas distribution operations, which we previously referred to as the
Terasen Gas business segment and (iii) Terasen Pipelines (Corridor) Inc.
Additionally, in 2007 Kinder Morgan Energy Partners completed the sale of its
North System and its 50% ownership interest in the Heartland Pipeline Company.
Note 11 contains additional information regarding these discontinued
operations.
In
December 2007, we sold the remainder of our surplus power equipment for $3.0
million (net of marketing fees.) We did not recognize any gain or loss
associated with this sale.
On
April 30, 2007, Kinder Morgan Energy Partners acquired the Trans Mountain
pipeline system from us. We accounted for this transaction as a transfer of net
assets between entities under common control. Kinder Morgan Energy Partners
recognized the Trans Mountain assets and liabilities acquired at our carrying
amounts (historical cost) at the date of transfer. As discussed in Note 3, based
on an evaluation of the fair value of the Trans Mountain pipeline system, a
goodwill impairment charge of approximately $377.1 million was recorded in
2007.
In
December 2006, we sold power generation equipment for $13.3 million (net of
marketing fees). We recognized a pre-tax gain of $1.2 million associated with
this sale. During the first quarter of 2006, we sold power generation equipment
for $7.5 million (net of marketing fees). We recognized a pre-tax gain of $1.5
million associated with this sale. This equipment was a portion of the equipment
that became surplus as a result of our decision to exit the power development
business.
Effective
April 1, 2006, Kinder Morgan Energy Partners sold its Douglas natural gas
gathering system and its Painter Unit fractionation facility to Momentum Energy
Group, LLC for approximately $42.5 million in cash. Kinder Morgan Energy
Partners’ investment in the net assets sold in this transaction, including all
transaction related accruals, was approximately $24.5 million, most of which
represented property, plant and equipment, and Kinder Morgan Energy Partners
recognized approximately $18.0 million of gain on the sale of these net assets.
Kinder Morgan Energy Partners used the proceeds from these asset sales to reduce
the outstanding balance on its commercial paper borrowings.
Additionally,
upon the sale of Kinder Morgan Energy Partners’ Douglas gathering system, Kinder
Morgan Energy Partners 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 “Operating Costs and Expenses: Other Expenses
(Income)” in the accompanying Consolidated Statement of Operations for the year
ended December 31, 2006.
Investments
Kinder
Morgan Energy Partners spent approximately $333.5 million in 2008 for its
proportionate share of discretionary capital expenditures for both the Rockies
Express and Midcontinent Express natural gas pipeline projects, and it expects
to spend a combined $1.5 billion for its share of discretionary capital
expenditures for both projects in 2009.
121
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
During
2007, Kinder Morgan Energy Partners made incremental investments of $202.7
million for its share of construction costs of the Rockies Express Pipeline.
Kinder Morgan Energy Partners owns a 51% equity interest through West2East
Pipeline LLC, a limited liability company that is the sole owner of Rockies
Express Pipeline LLC. (See note 4 for further information regarding this equity
investment.)
During
2007, Kinder Morgan Energy Partners made incremental investments of $61.6
million for its share of construction costs of the Midcontinent Express
Pipeline. Kinder Morgan Energy Partners owns a 50% equity interest in the
approximate $2.2 billion, 500-mile interstate natural gas pipeline that will
extend between Bennington, Oklahoma and Butler, Alabama.
In
December 2006, Kinder Morgan Energy Partners issued 34,627 common units as
partial consideration for the acquisition of Devco USA L.L.C. This transaction
had the associated effects of increasing our minority interests associated with
Kinder Morgan Energy Partners by $1.57 million and reducing our (i) goodwill by
$110,000, (ii) associated accumulated deferred income taxes by $11,411 and (iii)
paid-in capital by $18,589.
11. Discontinued
Operations
North System Natural Gas Liquids
Pipeline System - In October 2007, Kinder Morgan Energy Partners
completed the sale of its North System and its 50% ownership interest in the
Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $298.6
million in cash. For the year ended December 31, 2008, Kinder Morgan Energy
Partners paid $2.4 million to ONEOK Partners, L.P. to fully settle both the sale
of working capital items and the allocation of pre-acquisition investee
distributions, and to partially settle the sale of liquids inventory balances.
Due to the fair market valuation resulting from the Going Private transaction
(see Note 1), the consideration Kinder Morgan Energy Partners received from the
sale of its North System was equal to its carrying value; therefore no gain or
loss was recorded on this disposal transaction. The North System consists of an
approximately 1,600-mile interstate common carrier pipeline system that delivers
natural gas liquids and refined petroleum products from south central Kansas to
the Chicago area. Also included in the sale were eight propane truck-loading
terminals located at various points in three states along the pipeline system,
and one multi-product terminal complex located in Morris, Illinois. All of these
assets were included in our Products Pipelines–KMP business
segment.
Terasen Pipelines (Corridor) Inc. -
In June 2007, we completed the sale of Terasen Pipelines (Corridor) Inc.
(“Corridor”) to Inter Pipeline Fund, a Canada-based company. Corridor transports
diluted bitumen from the Athabasca Oil Sands Project near Fort McMurray,
Alberta, to the Scotford Upgrader near Fort Saskatchewan, Alberta. The sale did
not include any other assets of Kinder Morgan Canada (formerly Terasen
Pipelines). The sale price was approximately $711 million (C$760 million) plus
the buyer’s assumption of all of the debt related to Corridor, including the
debt associated with the expansion taking place on Corridor at the time of the
sale. The consideration was equal to Corridor’s carrying value, therefore no
gain or loss was recorded on this disposal transaction.
Terasen Inc. - We closed the
sale of Terasen Inc. to Fortis Inc. on May 17, 2007, for sales proceeds of
approximately $3.4 billion (C$3.7 billion) including cash plus the buyers’
assumption of debt. The sale did not include the assets of Kinder Morgan Canada
(formerly Terasen Pipelines) discussed in the preceding paragraph. We recorded a
book gain on this disposition of $55.7 million in the second quarter of 2007.
The sale resulted in a capital loss of $998.6 million for tax purposes.
Approximately $223.3 million of this loss was utilized to reduce capital gains
principally associated with the sale of our U.S.-based retail gas operations
(see below) resulting in a tax benefit of approximately $82.2 million. The
remaining capital loss carryforward of $775.3 million was utilized to reduce the
capital gain associated with our sale of an 80% ownership interest in NGPL
PipeCo LLC (see Note 10).
Natural Gas Distribution and Retail
Operations - In March 2007, we completed the sale of our U.S.-based
retail natural gas distribution and related operations to GE Energy Financial
Services, a subsidiary of General Electric Company and Alinda Investments LLC
for $710 million and an adjustment for working capital. In conjunction with this
sale, we recorded a pre-tax gain of $251.8 million (net of $3.9 million of
transaction costs) in the first quarter of 2007. Our Natural Gas Pipelines–KMP
business segment (i) provides natural gas transportation and storage services
and sells natural gas to and (ii) receives natural gas transportation and
storage services, natural gas and natural gas liquids and other gas supply
services from the discontinued U.S.-based retail natural gas distribution
business. These transactions are continuing after the sale of this business and
will likely continue to a similar extent into the future. For the five months
ended May 31, 2007, revenues and expenses of our continuing operations totaling
$3.1 million and $1.2 million, respectively for products and services sold to
and purchased from our discontinued U.S.-based retail natural gas distribution
operations prior to its sale in March 2007, have been eliminated in the
accompanying Consolidated Statements of Operations. We are currently receiving
fees from SourceGas, a subsidiary of General Electric Company, to provide
certain administrative functions for a limited period of time and for the lease
of office space. We do not have any significant continuing involvement in or
retain any ownership interest in these operations and, therefore, the continuing
cash flows discussed above are not considered direct cash flows of the disposed
assets.
122
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Earnings of Discontinued Operations
- The financial results of discontinued operations have been reclassified
for all periods presented and reported in the caption, “Income (Loss) from
Discontinued Operations, Net of Tax” in the accompanying Consolidated Statements
of Operations. Summarized financial results of these operations are as
follows:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Operating
Revenues
|
$
|
-
|
$
|
24.1
|
$
|
921.8
|
$
|
1,999.3
|
||||||||
|
Earnings
(Loss) from Discontinued Operations Before Income Taxes
|
$
|
(0.9
|
)
|
$
|
(10.2
|
)
|
$
|
393.2
|
$
|
(530.6
|
)
|
|||||
|
Income
Taxes
|
-
|
8.7
|
(94.6
|
)
|
2.1
|
|||||||||||
|
Earnings
(Loss) from Discontinued Operations
|
$
|
(0.9
|
)
|
$
|
(1.5
|
)
|
$
|
298.6
|
$
|
(528.5
|
)
|
|||||
The
cash flows attributable to discontinued operations are included in the
accompanying Consolidated Statements of Cash Flows for the year ended December
31, 2008, seven months ended December 31, 2007, five months ended May 31, 2007
and year ended December 31, 2006 in the captions “Net Cash Flows (Used in)
Provided by Discontinued Operations,” “Net Cash Flows Provided by (Used in)
Discontinued Investing Activities” and “Net Cash Flows Provided by (Used in)
Discontinued Financing Activities.”
12. Property,
Plant and Equipment
Classes
and Depreciation
As
of December 31, 2008 and 2007, investments in property, plant and equipment are
as follows:
|
December
31,
|
|||||||
|
2008
|
2007
|
||||||
|
Knight
Inc.
|
|||||||
|
Natural
Gas and Liquids Pipelines
|
$
|
-
|
$
|
16.1
|
|||
|
Electric
Generation
|
-
|
10.3
|
|||||
|
General
and Other
|
44.4
|
43.9
|
|||||
|
Kinder
Morgan Energy Partners1
|
|||||||
|
Natural
Gas, Liquids and Carbon Dioxide Pipelines
|
5,641.5
|
6,572.6
|
|||||
|
Pipeline
and Terminals Station Equipment
|
7,577.0
|
5,596.0
|
|||||
|
General
and Other
|
2,084.5
|
1,095.9
|
|||||
|
|
|||||||
|
Accumulated
Amortization, Depreciation and Depletion
|
(979.0
|
)
|
(277.0
|
)
|
|||
|
14,368.4
|
13,057.8
|
||||||
|
Land
|
201.7
|
297.3
|
|||||
|
Natural
Gas, Liquids (including Line Fill) and Transmix Processing
|
210.3
|
168.2
|
|||||
|
Construction
Work in Process
|
1,329.4
|
1,280.6
|
|||||
|
Property,
Plant and Equipment, Net
|
$
|
16,109.8
|
$
|
14,803.9
|
|||
|
|
____________
|
|
1
|
Includes
the allocation of purchase accounting adjustments associated with the
Going Private transaction (see Note
1).
|
Property
Casualties
2005
Hurricanes
In
2006, Kinder Morgan Energy Partners reached settlements with its insurance
carriers on all property damage claims related to the 2005 hurricanes and
recognized a casualty gain of $15.2 million, excluding repair and clean-up
expenses. After proceeds from insurance carrier claim reimbursements of $8.0
million and $13.1 million in 2007 and 2006 respectively, which are included in
the caption “Property Casualty Indemnifications” within investing activities in
the accompanying Consolidated Statements of Cash Flows, Kinder Morgan Energy
Partners’ total increase in net income, net of repair and clean-up expenses, was
$8.6 million in 2006 from the 2005 hurricanes.
123
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
2008
Hurricanes and Fires
Kinder
Morgan Energy Partners realized a combined $11.1 million of incremental expenses
for clean-up and asset damage from hurricanes Hanna, Gustav and Ike, excluding
estimates for lost business and lost revenues. Additionally, fire damage at
three separate terminal locations resulted in $7.2 million of incremental
expenses, excluding estimates for lost business and lost revenues. Of these
incremental expenses for the hurricanes and terminal fires, $10.5 million and
$5.3 million were included within the captions “Operations and Maintenance” and
“Other Expenses (Income),” respectively, in the accompanying Consolidated
Statement of Operations for the year ended December 31, 2008.
13.
Income Taxes
The
components of income (loss) before income taxes from continuing operations are
as follows:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
United
States
|
$
|
(3,374.8
|
)
|
$
|
474.2
|
$
|
279.2
|
$
|
903.6
|
|||||||
|
Foreign
|
80.7
|
1.7
|
(376.4
|
)
|
(17.3
|
)
|
||||||||||
|
Total
|
$
|
(3,294.1
|
)
|
$
|
475.9
|
$
|
(97.2
|
)
|
$
|
886.3
|
||||||
Components
of the income tax provision applicable to continuing operations for federal and
state income taxes are as follows:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Current
Tax Provision
|
||||||||||||||||
|
U.S.
|
||||||||||||||||
|
Federal
|
$
|
786.6
|
$
|
268.6
|
$
|
(7.0
|
)
|
$
|
246.6
|
|||||||
|
State
|
18.6
|
25.1
|
3.2
|
10.2
|
||||||||||||
|
Foreign
|
(4.5
|
)
|
23.5
|
0.6
|
18.3
|
|||||||||||
|
800.7
|
317.2
|
(3.2
|
)
|
275.1
|
||||||||||||
|
|
||||||||||||||||
|
Deferred
Tax Provision
|
||||||||||||||||
|
U.S.
|
||||||||||||||||
|
Federal
|
(439.5
|
)
|
(95.2
|
)
|
134.0
|
46.9
|
||||||||||
|
State
|
11.5
|
0.5
|
6.4
|
(36.3
|
)
|
|||||||||||
|
Foreign
|
(68.4
|
)
|
4.9
|
(1.7
|
)
|
0.2
|
||||||||||
|
(496.4
|
)
|
(89.8
|
)
|
138.7
|
10.8
|
|||||||||||
|
Total
Tax Provision
|
$
|
304.3
|
$
|
227.4
|
$
|
135.5
|
$
|
285.9
|
||||||||
|
Effective
Tax Rate
|
9.2
|
%
|
47.8
|
%
|
139.3
|
%
|
32.3
|
%
|
||||||||
124
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
The
difference between the statutory federal income tax rate and our effective
income tax rate is summarized as follows:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Federal
Income Tax Rate
|
(35.0
|
%)
|
35.0
|
%
|
(35.0
|
%)
|
35.0
|
%
|
||||||||
|
Increase
(Decrease) as a Result of:
|
||||||||||||||||
|
Nondeductible
Goodwill Impairment
|
42.9
|
%
|
-
|
135.8
|
%
|
-
|
||||||||||
|
Terasen
Acquisition Financing Structure
|
-
|
-
|
(17.1
|
%)
|
(5.1
|
%)
|
||||||||||
|
Nondeductible
Going Private Costs
|
-
|
-
|
31.6
|
%
|
-
|
|||||||||||
|
Deferred
Tax Rate Change
|
0.5
|
%
|
-
|
-
|
(4.3
|
%)
|
||||||||||
|
Kinder
Morgan Management Minority Interest
|
0.9
|
%
|
2.7
|
%
|
6.4
|
%
|
2.7
|
%
|
||||||||
|
Foreign
Earnings Subject to Different Tax Rates
|
(2.1
|
%)
|
5.8
|
%
|
8.6
|
%
|
2.6
|
%
|
||||||||
|
Net
Effects of Consolidating Kinder Morgan Energy Partners’ United States
Income Tax Provision
|
0.9
|
%
|
2.5
|
%
|
4.1
|
%
|
1.4
|
%
|
||||||||
|
State
Income Tax, Net of Federal Benefit
|
0.5
|
%
|
2.3
|
%
|
6.9
|
%
|
1.7
|
%
|
||||||||
|
Other
|
0.6
|
%
|
(0.5
|
%)
|
(2.0
|
%)
|
(1.7
|
%)
|
||||||||
|
Effective
Tax Rate
|
9.2
|
%
|
47.8
|
%
|
139.3
|
%
|
32.3
|
%
|
||||||||
Income
taxes included in the financial statements were composed of the
following:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Continuing
Operations
|
$
|
304.3
|
$
|
227.4
|
$
|
135.5
|
$
|
285.9
|
||||||||
|
Discontinued
Operations
|
(0.4
|
)
|
(8.7
|
)
|
94.6
|
(2.1
|
)
|
|||||||||
|
Equity
Items
|
122.2
|
(219.4
|
)
|
(51.7
|
)
|
(22.2
|
)
|
|||||||||
|
Total
|
$
|
426.1
|
$
|
(0.7
|
)
|
$
|
178.4
|
$
|
261.6
|
|||||||
125
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Deferred
tax assets and liabilities result from the following:
|
December
31,
2008
|
December
31,
2007
|
|||||||
|
(In
millions)
|
(In
millions)
|
|||||||
|
Deferred
Tax Assets
|
||||||||
|
Postretirement
Benefits
|
$
|
79.8
|
$
|
12.1
|
||||
|
Book
Accruals
|
14.3
|
-
|
||||||
|
Derivatives
|
-
|
270.9
|
||||||
|
Capital
Loss Carryforwards
|
-
|
279.5
|
||||||
|
Interest
Rate Swaps
|
7.0
|
-
|
||||||
|
Other
|
7.9
|
-
|
||||||
|
Total
Deferred Tax Assets
|
109.0
|
562.5
|
||||||
|
Deferred
Tax Liabilities
|
||||||||
|
Property,
Plant and Equipment
|
160.0
|
125.2
|
||||||
|
Investments
|
1,937.2
|
1,909.0
|
||||||
|
Book
Accruals
|
-
|
62.1
|
||||||
|
Derivative
Instruments
|
5.7
|
-
|
||||||
|
Rate
Matters
|
-
|
0.4
|
||||||
|
Prepaid
Pension Costs
|
16.6
|
17.9
|
||||||
|
Assets/Liabilities
Held for Sale
|
-
|
897.5
|
||||||
|
Debt
Adjustment
|
23.0
|
-
|
||||||
|
Other
|
47.8
|
66.2
|
||||||
|
Total
Deferred Tax Liabilities
|
2,190.3
|
3,078.3
|
||||||
|
Net
Deferred Tax Liabilities
|
$
|
2,081.3
|
$
|
2,515.8
|
||||
|
|
||||||||
|
Current
Deferred Tax Asset
|
$
|
-
|
$
|
-
|
||||
|
Current
Deferred Tax Liability
|
-
|
666.4
|
||||||
|
Non-current
Deferred Tax Liability
|
2,081.3
|
1,849.4
|
||||||
|
Net
Deferred Tax Liabilities
|
$
|
2,081.3
|
$
|
2,515.8
|
||||
During
2007, our sale of Terasen Inc. resulted in a capital loss of $998.6 million of
which approximately $223.3 million was utilized to reduce capital gain
principally associated with the sale of our U.S.-based retail natural gas
operations. The remaining capital loss was carried forward and utilized to
reduce the capital gain on the sale of our 80% ownership interest in the NGPL
business segment.
In
July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income
Taxes—an Interpretation of FASB Statement No. 109, (“FIN No. 48”) which
became effective January 1, 2007. FIN No. 48 addressed the determination of how
tax benefits claimed or expected to be claimed on a tax return should be
recorded in the financial statements. Under FIN No. 48, we must recognize the
tax benefit from an uncertain tax position only if it is more likely than not
that the tax position will be sustained on examination by the taxing
authorities, based not only on the technical merits of the tax position based on
tax law, but also the past administrative practices and precedents of the taxing
authority. The tax benefits recognized in the financial statements from such a
position are measured based on the largest benefit that has a greater than 50%
likelihood of being realized upon ultimate resolution.
We
adopted the provisions of FIN No. 48 on January 1, 2007. The total amount of
unrecognized tax benefits as of the date of adoption was $63.1 million. We
recorded a $4.8 million decrease to the opening balance of retained earnings as
a result of the implementation of FIN No. 48.
A
reconciliation of our gross unrecognized tax benefit excluding interest and
penalties for the years ended December 31, 2008 and 2007 is as follows (in
millions):
|
2008
|
2007
|
|||||||
|
Balance
at beginning of period
|
$
|
41.5
|
$
|
63.1
|
||||
|
Additions
based on current year tax positions
|
2.1
|
9.8
|
||||||
|
Additions
based on prior year tax positions
|
15.9
|
0.5
|
||||||
|
Reductions
based on settlements with taxing authority
|
(10.2
|
)
|
(21.4
|
)
|
||||
|
Reductions
due to lapse in statue of limitations
|
(3.7
|
)
|
(2.7
|
)
|
||||
|
Reductions
for tax positions related to prior year
|
(19.4
|
)
|
(7.8
|
)
|
||||
|
Balance
at end of period
|
$
|
26.2
|
$
|
41.5
|
||||
126
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Our
continuing practice is to recognize interest and/or penalties related to income
tax matters in income tax expense, and as of December 31, 2007, we had $8.1
million of accrued interest and no accrued penalties. As of December 31, 2008,
we had $2.9 million of accrued interest and $0.8 million of accrued penalties. In
addition, we believe it is reasonably possible that our liability for
unrecognized tax benefits will increase by $4.8 million during the next twelve
months, and that approximately $34.1 million included
in the total $26.2
million of unrecognized tax benefits on the accompanying Consolidated Balance
Sheet as of December 31, 2008 would affect our effective tax rate in future
periods in the event those unrecognized tax benefits were recognized. Such
amounts exclude interest, while the latter amount of $26.6 million includes both
temporary and permanent differences.
We
are subject to taxation, and have tax years open to examination for the periods
2003-2008 in the United States and Mexico, 2004-2008 in Canada, and 1999-2008 in
various states.
14.
Financing
Notes
Payable
We
and our consolidated subsidiaries had the following unsecured credit facilities
outstanding at December 31, 2008.
Credit
Facilities
|
Knight
Inc.—$1.0 billion, six-year secured revolver, due May
2013
|
|
Kinder
Morgan Energy Partners—$1.85 billion, five-year unsecured revolver, due
August 2010
|
The
following are short-term borrowings, issued by the below-listed borrowers, where
the commercial paper is supported by each borrower’s respective credit
facilities. The short-term borrowings shown in the tables below, totaling $8.8
million and $888.1 million, respectively, are reported in the caption “Notes
Payable” in the accompanying Balance Sheets at December 31, 2008 and 2007,
respectively.
|
December
31, 2008
|
||||||||||||
|
Short-term
Borrowings
Outstanding
Under
Revolving
Credit
Facility
|
Commercial
Paper
Outstanding
|
Weighted-average
Interest
Rate of
Short-term
Debt
Outstanding
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Knight
Inc.
|
||||||||||||
|
$1.0
billion
|
$
|
8.8
|
-
|
3.38
|
%
|
|||||||
|
Kinder
Morgan Energy Partners
|
||||||||||||
|
$1.85
billion
|
$
|
-
|
-
|
-
|
%
|
|||||||
|
December
31, 2007
|
||||||||||||
|
Short-term
Borrowings
Outstanding
Under
Revolving
Credit
Facility
|
Commercial
Paper
Outstanding
|
Weighted-average
Interest
Rate of
Short-term
Debt
Outstanding
|
||||||||||
|
(In
millions)
|
||||||||||||
|
Knight
Inc.
|
||||||||||||
|
$1.0
billion
|
$
|
299.0
|
$
|
-
|
6.42
|
%
|
||||||
|
Kinder
Morgan Energy Partners
|
||||||||||||
|
$1.85
billion
|
$
|
-
|
$
|
589.1
|
5.58
|
%
|
||||||
The
weighted average interest rates on our outstanding borrowings under the $1.0
billion credit facility for the year ended December 31, 2008 and seven months
ended December 31, 2007 were approximately 4.43% and 6.61%, respectively. The
weighted average interest rate on Terasen Pipelines (Corridor) Inc.’s short term
debt was 4.33% for the seven months ended December 31, 2007. For the five months
ended May 31, 2007, the weighted average interest rates on outstanding
borrowings under Knight Inc.’s $800 million credit facility, which was
terminated on May 30, 2007, was 5.81% and the outstanding borrowings under the
Terasen Inc., Terasen Gas Inc. and Terasen Pipelines (Corridor) Inc.’s
respective credit facilities were 4.34%, 4.23% and 4.24% . Terasen Inc,
including Terasen Gas Inc., and Terasen Pipelines (Corridor) Inc. were sold on
May
127
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
17,
2007 and June 15, 2007 respectively. Accordingly, the average short-term debt
associated with these facilities for the seven months ended December 31, 2007
and five months ended May 31, 2007 are only through the respective dates of
sale.
The
weighted average interest rates under Kinder Morgan Energy Partners’ credit
facility for the year ended December 31, 2008 was 3.47%. Weighted average
interest rates under Kinder Morgan Energy Partners’ commercial paper program for
the year ended December 31, 2008, seven months ended December 31, 2007 and five
months ended May 31, 2007 were 3.47%, 5.46% and 5.40%, respectively. Kinder
Morgan Energy Partners currently does not have access to the commercial paper
market.
The
Knight Inc. $1.0 billion six-year senior secured revolving credit facility
matures on May 30, 2013 and includes a sublimit of $300 million for the issuance
of letters of credit and a sublimit of $50 million for swingline loans. Knight
Inc. does not have a commercial paper program. This revolving credit facility,
as part of a $5.755 billion credit agreement used to finance the Going Private
transaction, replaced an $800 million five-year credit facility dated August 5,
2005. The $5.755 billion credit agreement dated May 30, 2007, is with a
syndicate of financial institutions and Citibank, N.A., as administrative agent
and included three tranches of term loan facilities, which were subsequently
retired.
The
credit agreement permits one or more incremental increases under the revolving
credit facility or an addition of new term facilities in an aggregate amount of
up to $1.5 billion, provided certain conditions are met. Such additional
capacity is uncommitted. Additionally, the revolving credit facility allows for
one or more swingline loans from Citibank, N.A., in its individual capacity, up
to an aggregate amount of $50.0 million provided certain conditions are
met.
Our
obligations under the credit agreement and certain existing notes issued by us
and Kinder Morgan Finance Company, LLC, the sale of which were registered under
the Securities Act of 1933, as amended, are secured, subject to specified
exceptions, by a first-priority lien on all the capital stock of each of our
wholly owned subsidiaries (limited, in the case of foreign subsidiaries, to 65%
of the capital stock of such subsidiaries) and by perfected security interests
in, and mortgages on, substantially all of our and our subsidiaries’ tangible
and intangible assets (including, without limitation, accounts (other than
deposit accounts or other bank or securities accounts), inventory, equipment,
investment property, intellectual property, other general intangibles, material
fee-owned real property (other than pipeline assets and any leasehold property)
and proceeds of the foregoing). None of the assets of Kinder Morgan G.P., Inc.,
Kinder Morgan Management, Kinder Morgan Energy Partners or their respective
subsidiaries are pledged as security as part of this financing.
Loans
under the revolving credit facility will bear interest, at Knight Inc.’s option,
at:
|
|
·
|
a
rate equal to LIBOR (London Interbank Offered Rate) plus an applicable
margin, or
|
|
|
·
|
a
rate equal to the higher of (a) U.S. prime rate and (b) the federal funds
effective rate plus 0.50%, in each case, plus an applicable
margin.
|
The
swingline loans will bear interest at:
|
|
·
|
a
rate equal to the higher of (a) U.S. prime rate and (b) the federal funds
effective rate plus 0.50%, in each case, plus an applicable
margin.
|
The
applicable margin for the revolving credit facility is subject to decrease
pursuant to a leverage-based pricing grid. In addition, the credit agreement
provides for customary commitment fees and letter of credit fees under the
revolving credit facility. Based on our ratio, as defined in the credit
agreement, of consolidated total debt to earnings before interest, income taxes
and depreciation and amortization at December 31, 2008, our facility fee was 25
basis points. The credit agreement contains customary terms and conditions and
is unconditionally guaranteed by each of our wholly owned material domestic
restricted subsidiaries, to the extent permitted by applicable law and contract.
Voluntary prepayments can be made at any time on revolving credit loans and
swingline loans, in each case without premium or penalty, and on LIBOR Loans (as
defined in the credit agreement) on the interest payment date without premium or
penalty.
Our
$5.755 billion credit agreement includes the following restrictive
covenants:
|
|
·
|
total
debt divided by earnings before interest, income taxes, depreciation and
amortization for (i) the test period ending December 31, 2007 may not
exceed 8.75:1.00, (ii) January 1, 2008 to December 31, 2008 may not exceed
8.00:1.00, (iii) January 1, 2009 to December 31, 2009 may not exceed
7.00:1.00 and (iv) thereafter may not exceed
6.00:1.00;
|
|
|
·
|
certain
limitations on indebtedness, including payments and
amendments;
|
|
|
·
|
certain
limitations on entering into mergers, consolidations, sales of assets and
investments;
|
|
|
·
|
limitations
on granting liens; and
|
|
|
·
|
prohibitions
on making any dividend to shareholders if an event of default exists or
would exist upon making such
dividend.
|
128
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
The
Kinder Morgan Energy Partners $1.85 billion five-year unsecured bank credit
facility matures August 18, 2010 and can be amended to allow for borrowings up
to $2.1 billion. Borrowings under the credit facility can be used for
partnership purposes and as a backup for Kinder Morgan Energy Partners’
commercial paper program. As of December 31, 2008 and 2007, respectively, there
were no borrowings under the credit facility.
Kinder
Morgan Energy Partners’ five-year credit facility is with a syndicate of
financial institutions. Wachovia Bank, National Association is the
administrative agent. The credit facility permits Kinder Morgan Energy Partners
to obtain bids for fixed rate loans from members of the lending syndicate.
Interest on the credit facility accrues at Kinder Morgan Energy Partners’ option
at a floating rate equal to either (i) the administrative agent’s base rate (but
not less than the Federal Funds Rate, plus 0.5%); or (ii) London Interbank
Offered Rate (“LIBOR”), plus a margin, which varies depending upon the credit
rating of Kinder Morgan Energy Partners’ long-term senior unsecured
debt.
Kinder
Morgan Energy Partners’ credit facility included the following restrictive
covenants as of December 31, 2008:
|
|
·
|
total
debt divided by earnings before interest, income taxes, depreciation and
amortization for the preceding four quarters may not
exceed:
|
|
|
·
|
5.5,
in the case of any such period ended on the last day of (i) a fiscal
quarter in which Kinder Morgan Energy Partners makes any Specified
Acquisition, or (ii) the first or second fiscal quarter next succeeding
such a fiscal quarter; or
|
|
|
·
|
5.0,
in the case of any such period ended on the last day of any other fiscal
quarter;
|
|
|
·
|
certain
limitations on entering into mergers, consolidations and sales of
assets;
|
|
|
·
|
limitations
on granting liens; and
|
|
|
·
|
prohibitions
on making any distribution to holders of units if an event of default
exists or would exist upon making such
distribution.
|
In
addition to normal repayment covenants, under the terms of Kinder Morgan Energy
Partners’ credit facility, the occurrence at any time of any of the following
would constitute an event of default: (i) Kinder Morgan Energy Partners’ 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, (ii) Kinder Morgan G.P.,
Inc.’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, (iii) adverse judgments rendered against Kinder
Morgan Energy Partners 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 (iv)
voluntary or involuntary commencements of any proceedings or petitions seeking
Kinder Morgan Energy Partners’ 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, Kinder Morgan Energy Partners’ 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 also does not
contain a material adverse change clause coupled with a lockbox provision;
however, the facility does provide that the margin Kinder Morgan Energy Partners
will pay with respect to borrowings and the facility fee that Kinder Morgan
Energy Partners will pay on the total commitment will vary based on Kinder
Morgan Energy Partners’ senior debt investment rating. None of Kinder Morgan
Energy Partners’ debt is subject to payment acceleration as a result of any
change to its credit ratings.
On
September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy
protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One
Lehman entity was a lending institution that provided a portion of Kinder Morgan
Energy Partners’, Rockies Express’ and Mid Continent Express’ respective credit
facilities. Since Lehman Brothers declared bankruptcy, its affiliate, which is a
party to the credit facilities, has not met its obligations to lend under those
agreements. As such, the commitments have been effectively reduced by $63
million, $41 million and $100 million, respectively, to $1.8 billion, $2.0
billion and $1.3 billion. The commitments of the other banks remain unchanged
and the facilities are not defaulted.
Long-term
Debt
Since
we are accounting for the Going Private transaction (see Note 1) as a purchase
business combination that is required to be “pushed-down” to us, we have
adjusted the carrying value of our long-term debt securities to reflect their
fair values, to the extent of Knight Inc.’s economic ownership interest, at the
time of the Going Private transaction and the adjustments are being amortized
over the remaining lives of the debt securities. The unamortized fair value
adjustment balances reflected within the caption “Long-term Debt” in the
accompanying Consolidated Balance Sheet at December 31, 2008 were $46.0 million
and $6.7 million, representing a decrease to the carrying value of our long-term
debt and an increase in the value of our interest
129
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
rate
swaps, respectively. Our long-term debt balances at December 31, 2008 and 2007
of $12,126.8 million and $15,297.4 million, respectively, consisted of the
balances shown in the table below.
|
December
31,
|
|||||||
|
2008
|
2007
|
||||||
|
|
(In
millions)
|
||||||
|
Knight
Inc.
|
|||||||
|
Debentures
|
|||||||
|
6.50%
Series, Due 2013
|
$
|
6.1
|
$
|
30.1
|
|||
|
6.67%
Series, Due 2027
|
7.0
|
148.3
|
|||||
|
7.25%
Series, Due 2028
|
32.0
|
494.3
|
|||||
|
7.45%
Series, Due 2098
|
25.9
|
146.3
|
|||||
|
Senior
Notes
|
|||||||
|
6.50%
Series, Due 2012
|
846.2
|
1,010.5
|
|||||
|
5.15%
Series, Due 2015
|
233.3
|
231.2
|
|||||
|
Senior
Secured Credit Term Loan Facilities
|
|||||||
|
Tranche
A Term Loan, Due 2013
|
-
|
997.5
|
|||||
|
Tranche
B Term Loan, Due 2014
|
-
|
3,191.7
|
|||||
|
Deferrable
Interest Debentures Issued to Subsidiary Trusts
|
|||||||
|
8.56%
Junior Subordinated Deferrable Interest Debentures Due
2027
|
15.8
|
106.9
|
|||||
|
7.63%
Junior Subordinated Deferrable Interest Debentures Due
2028
|
19.9
|
176.2
|
|||||
|
Unamortized
Gain on Termination of Interest Rate Swap
|
6.4
|
11.5
|
|||||
|
|
|||||||
|
Kinder
Morgan Finance Company, LLC
|
|||||||
|
5.35%
Series, Due 2011
|
742.0
|
738.5
|
|||||
|
5.70%
Series, Due 2016
|
806.6
|
801.9
|
|||||
|
6.40%
Series, Due 2036
|
33.8
|
503.8
|
|||||
|
Carrying
Value Adjustment for Interest Rate Swap1
|
-
|
23.2
|
|||||
|
Unamortized
Gain on Termination of Interest Rate Swap
|
12.8
|
11.6
|
|||||
|
|
|||||||
|
Kinder
Morgan G.P., Inc.
|
|||||||
|
$1,000
Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative
Preferred Stock
|
100.0
|
100.0
|
|||||
|
|
|||||||
|
Kinder
Morgan Energy Partners
|
|||||||
|
Senior
Notes
|
|||||||
|
6.30%
Series, Due 2009
|
250.1
|
250.9
|
|||||
|
7.50%
Series, Due 2010
|
253.8
|
255.7
|
|||||
|
6.75%
Series, Due 2011
|
707.6
|
710.6
|
|||||
|
7.125%
Series, Due 2012
|
458.7
|
461.1
|
|||||
|
5.85%
Series, Due 2012
|
500.0
|
500.0
|
|||||
|
5.00%
Series, Due 2013
|
491.3
|
489.8
|
|||||
|
5.125%
Series, Due 2014
|
490.2
|
488.9
|
|||||
|
6.00%
Series, Due 2017
|
597.8
|
597.5
|
|||||
|
5.95%
Series Due 2018
|
975.0
|
-
|
|||||
|
9.00%
Series Due 2019
|
500.0
|
-
|
|||||
|
7.40%
Series, Due 2031
|
310.3
|
310.5
|
|||||
|
7.75%
Series, Due 2032
|
316.4
|
316.7
|
|||||
|
7.30%
Series, Due 2033
|
513.9
|
514.1
|
|||||
|
5.80%
Series, Due 2035
|
477.4
|
477.1
|
|||||
|
6.50%
Series, Due 2037
|
395.8
|
395.7
|
|||||
|
6.95%
Series, Due 2038
|
1,175.0
|
550.0
|
|||||
|
Other
|
1.1
|
1.1
|
|||||
|
Carrying
Value Adjustment for Interest Rate Swaps1
|
754.2
|
146.2
|
|||||
|
Unamortized
Gain on Termination of Interest Rate Swap
|
197.6
|
7.2
|
|||||
|
Central
Florida Pipe Line LLC
|
|||||||
|
7.84%
Series, Due 2008
|
-
|
5.0
|
|||||
|
|
|||||||
|
Arrow
Terminals L.P.
|
|||||||
|
Illinois
Development Finance Authority Adjustable Rate Industrial Development
Revenue Bonds, Due 2010, weighted-average interest rate of 2.52% for the
year ended December 31, 2008 (3.77% for the seven months ended December
31, 2007 and 3.87% for the five months ended May 31, 2007)
|
5.3
|
5.3
|
|||||
130
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
|
|
|||||||
|
Kinder
Morgan Operating, L.P. “A” and Kinder Morgan Canada
|
|||||||
|
5.40%
Note, Due 2012
|
36.6
|
44.6
|
|||||
|
|
|||||||
|
Kinder
Morgan Texas Pipeline, L.P.
|
|||||||
|
8.85%
Series, Due 2014
|
37.0
|
43.2
|
|||||
|
|
|||||||
|
Kinder
Morgan Liquids Terminals LLC
|
|||||||
|
New
Jersey Economic Development Revenue Refunding Bonds, Due 2018,
weighted-average interest rate of 1.63% for the year ended December 31,
2008(3.48 % for the seven months ended December 31, 2007 and 3.63%
for the five months ended May 31, 2007)
|
25.0
|
25.0
|
|||||
|
|
|||||||
|
Kinder
Morgan Operating, L.P. “B”
|
|||||||
|
Jackson-Union
Counties, Illinois Regional Port District Tax-exempt Floating Rate Bonds,
Due 2024, weighted-average interest rate of 2.96% for the year ended
December 31, 2008 (3.68% for the seven months ended December 31, 2007 and
3.59% for the five months ended May 31, 2007)
|
23.7
|
23.7
|
|||||
|
Other
|
0.2
|
0.2
|
|||||
|
|
|||||||
|
International
Marine Terminals
|
|||||||
|
Plaquemines
Port, Harbor and Terminal District (Louisiana) Adjustable Rate Annual
Tender Port Facilities Revenue Refunding Bonds, Due 2025, weighted-average
interest rate of 2.50% for the year ended December 31, 2008 (3.65% for the
seven months ended December 31, 2007 and 3.59% for the five months
ended May 31, 2007)
|
40.0
|
40.0
|
|||||
|
|
|||||||
|
Gulf
Opportunity Zone Bonds
|
|||||||
|
Kinder
Morgan Louisiana Pipeline LLC
|
|||||||
|
6.00%
Louisiana Community Development Authority Revenue Bonds Due
2011
|
5.0
|
-
|
|||||
|
Kinder
Morgan Columbus LLC
|
|||||||
|
5.50%
Mississippi Business Finance Corporation Revenue Bonds Due
2022
|
8.2
|
-
|
|||||
|
|
|||||||
|
Unamortized
Debt Discount on Long-term Debt
|
(14.5
|
)
|
(6.4
|
)
|
|||
|
Current
Maturities of Long-term Debt
|
(293.7
|
)
|
(79.8
|
)
|
|||
|
Total
Long-term Debt
|
$
|
12,126.8
|
$
|
15,297.4
|
__________
1 Adjustment
of carrying value of long-term securities subject to outstanding interest rate
swaps; see Note 15.
In
February 2008, approximately $4.6 billion of the proceeds from the completed
sale of an 80% ownership interest in NGPL PipeCo LLC were used to pay off and
retire our senior secured credit facility’s Tranche A and Tranche B term loans
and to pay down amounts outstanding at that time under our $1.0 billion
revolving credit facility as follows:
|
Debt
Paid Down
and/or
Retired
|
|||||
|
(In
millions)
|
|||||
|
Knight
Inc.
|
|||||
|
Senior
Secured Credit Term Loan Facilities
|
|||||
|
Tranche
A Term Loan, Due 2013
|
$
|
995.0
|
|||
|
Tranche
B Term Loan, Due 2014
|
3,183.5
|
||||
|
Credit
Facility
|
|||||
|
$1.0
billion Secured Revolver, Due May 2013
|
375.0
|
||||
|
Total
Paid Down and/or Retired
|
$
|
4,553.5
|
|||
131
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
In
March 2008, using primarily proceeds from the completed sale of an 80% ownership
interest in NGPL PipeCo LLC, along with cash on hand and borrowings under our
$1.0 billion revolving credit facility, we repurchased approximately $1.67
billion par value of our outstanding debt securities for $1.6 billion in cash as
follows:
|
Par
Value of
Debt
Repurchased
|
|||||
|
(In
millions)
|
|||||
|
Knight
Inc.
|
|||||
|
Debentures
|
|||||
|
6.50%
Series, Due 2013
|
$
|
18.9
|
|||
|
6.67%
Series, Due 2027
|
143.0
|
||||
|
7.25%
Series, Due 2028
|
461.0
|
||||
|
7.45%
Series, Due 2098
|
124.1
|
||||
|
Senior
Notes
|
|||||
|
6.50%
Series, Due 2012
|
160.7
|
||||
|
Kinder
Morgan Finance Company, LLC
|
|||||
|
6.40%
Series, Due 2036
|
513.6
|
||||
|
Deferrable
Interest Debentures Issued to Subsidiary Trusts
|
|||||
|
8.56%
Junior Subordinated Deferrable Interest Debentures
Due 2027
|
87.3
|
||||
|
7.63%
Junior Subordinated Deferrable Interest Debentures
Due 2028
|
160.6
|
||||
|
Repurchase
of Outstanding Debt Securities
|
$
|
1,669.2
|
|||
As
of December 31, 2008, maturities of long-term debt (in millions) for the five
years ending December 31, 2013 and thereafter were $293.7, $271.9, $1,471.2,
$2,305.7, $506.5 and $6,647.0, respectively.
Knight
Inc.
The
2013 Debentures are not redeemable prior to maturity. The 2028 and 2098
Debentures and the 2012 senior notes are redeemable in whole or in part, at our
option at any time, at redemption prices defined in the associated prospectus
supplements. The 2015 senior notes are redeemable in whole or in part at our
option, but at redemption prices that generally do not make early redemption an
economically favorable alternative. The 2027 Debentures are redeemable in whole
or in part, at our option after November 1, 2004 at redemption prices defined in
the associated prospectus supplements.
On
September 5, 2008 and September 3, 2007, we made a $5.0 million payment on each
date on our 6.50% Series Debentures, Due 2013.
On
May 7, 2007, we retired our $300 million 6.80% senior notes due March 1, 2008 at
101.39% of the face amount. We paid a premium of $4.2 million in connection with
this early extinguishment of debt.
Kinder
Morgan Finance Company, LLC
The
2011, 2016 and 2036 senior notes issued by Kinder Morgan Finance Company, LLC
are redeemable in whole or in part, at our option at any time, at redemption
prices defined in the associated prospectus supplements. Each series of these
notes is fully and unconditionally guaranteed by Knight Inc. on a senior
unsecured basis as to principal, interest and any additional amounts required to
be paid as a result of any withholding or deduction for Canadian taxes.
Additionally, the 6.40% senior notes due 2016 had an associated
fixed-to-floating interest rate swap agreement with a notional principal amount
of $275 million, which was terminated in 2008. See Note 15 for additional
information on this swap agreement.
Kinder
Morgan Energy Partners
Kinder
Morgan Energy Partners’ fixed rate notes provide for redemption 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. Approximately $2.3 billion of
Kinder Morgan Energy Partners’ senior notes have associated fixed-to-floating
interest rate swap agreements that effectively convert the related interest
expense from fixed rates to floating rates. See Note 15 for additional
information on these swap agreements.
On
December 19, 2008, Kinder Morgan Energy Partners completed a public offering of
senior notes, issuing a total of $500 million in principal amount of 9.00%
senior notes due February 1, 2019. Kinder Morgan Energy Partners used the $498.4
million net proceeds, after underwriting discounts and commissions, to reduce
the borrowings under its revolving credit facility.
132
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
On
June 6, 2008, Kinder Morgan Energy Partners completed a public offering of
senior notes, issuing $700 million in principal amount of senior notes,
consisting of $375 million of 5.95% notes due February 15, 2018 (these notes
constitute a further issuance of the $600 million aggregate principal amount of
5.95% notes Kinder Morgan Energy Partners issued on February 12, 2008 and form a
single series with those notes) and $325 million of 6.95% notes due January 15,
2038 (these notes constitute a further issuance of the combined $850 million
aggregate principal amount of 6.95% notes Kinder Morgan Energy Partners issued
on June 21, 2007 and February 12, 2008, and form a single series with those
notes). Kinder Morgan Energy Partners used the $687.7 million net proceeds,
after underwriting discounts and commissions, to reduce the borrowings under its
commercial paper program.
On
February 12, 2008, Kinder Morgan Energy Partners completed a public offering of
senior notes, issuing a total of $900 million in principal amount of senior
notes, consisting of $600 million of 5.95% notes due February 15, 2018, and $300
million of 6.95% notes due January 15, 2038 (the 6.95% notes constitute a
further issuance of the $550 million aggregate principal amount of 6.95% notes
Kinder Morgan Energy Partners issued on June 21, 2007 and form a single series
with those notes). Kinder Morgan Energy Partners used the $894.1 million net
proceeds to reduce borrowings under its commercial paper program.
On
August 28, 2007, Kinder Morgan Energy Partners issued $500 million of its 5.85%
senior notes due September 15, 2012. Kinder Morgan Energy Partners used the
$497.8 million net proceeds received after underwriting discounts and
commissions to reduce the borrowings under its commercial paper
program.
On
August 15, 2007, Kinder Morgan Energy Partners repaid $250 million of its 5.35%
senior notes that matured on that date.
On
June 21, 2007, Kinder Morgan Energy Partners issued $550 million of its 6.95%
senior notes due January 15, 2038. Kinder Morgan Energy Partners used the $543.9
million net proceeds received after underwriting discounts and commissions to
reduce the borrowings under its commercial paper program.
On
January 30, 2007, Kinder Morgan Energy Partners completed a public offering of
senior notes, issuing 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. Kinder Morgan Energy Partners
received proceeds from the issuance of the notes, after underwriting discounts
and commissions, of approximately $992.8 million, and used the proceeds to
reduce the borrowings under its commercial paper program.
Central
Florida Pipeline LLC Debt
Central
Florida Pipeline LLC was an obligor on an aggregate principal amount of $40
million of senior notes originally issued to a syndicate of eight insurance
companies. The senior notes had a fixed annual interest rate of 7.84% with
repayments in annual installments of $5.0 million beginning July 23, 2001.
Central Florida Pipeline LLC paid the final $5.0 million outstanding principal
amount on July 23, 2008.
Arrow
Terminals L.P. Debt
Arrow
Terminals L.P. is an obligor on Adjustable Rate Industrial Development Revenue
Bonds issued by the Illinois Development Finance Authority. The bonds have a
maturity date of January 1, 2010, and interest on these bonds is paid and
computed quarterly at the Bond Market Association Municipal Swap Index. The
bonds are collateralized by a first mortgage on assets of Arrow’s Chicago
operations and a third mortgage on assets of Arrow’s Pennsylvania operations. As
of December 31, 2008, the interest rate was 1.328%. A $5.4 million letter of
credit issued by JP Morgan Chase 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 Operating L.P. “A” and Kinder Morgan Canada Company Debt
Effective
January 1, 2007, Kinder Morgan Energy Partners acquired the remaining
approximate 50.2% interest in the Cochin pipeline system that it did not already
own (see Note 10). As part of Kinder Morgan Energy Partners’ purchase price, two
of its subsidiaries issued a long-term note payable to the seller having a fair
value of $42.3 million. Kinder Morgan Energy Partners valued the debt equal to
the present value of amounts to be paid, determined using an annual interest
rate of 5.40%. The principal amount of the note, along with interest, is due in
five annual installments of $10.0 million beginning March 31, 2008. Kinder
Morgan Energy Partners paid the first installment on March 31, 2008 and the
final payment is due March 31, 2012. Kinder Morgan Energy Partners’
subsidiaries, Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company,
are the obligors on the note.
133
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Kinder
Morgan Texas Pipeline, L.P. Debt
Kinder
Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes
with a fixed annual stated interest rate 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.
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.
Kinder
Morgan Liquids Terminals LLC Debt
Kinder
Morgan Liquids Terminals LLC is the obligor on $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.
These bonds have a maturity date of January 15, 2018. Interest on these bonds is
computed on the basis of a year of 365 or 366 days, as applicable, for the
actual number of days elapsed during Commercial Paper, Daily or Weekly Rate
Periods and on the basis of a 360-day year consisting of twelve 30-day months
during a Term Rate Period. As of December 31, 2008, the annual interest rate was
0.52%. Kinder Morgan Energy Partners has an outstanding letter of credit issued
by Citibank in the amount of $25.4 million that backs-up the $25.0 million
principal amount of the bonds and $0.4 million of interest on the bonds for up
to 46 days computed at 12% on a per annum basis on the principal
thereof.
Kinder
Morgan Operating L.P. “B” Debt
As
of December 31, 2008, Kinder Morgan Energy Partners’ subsidiary Kinder Morgan
Operating L.P. “B” was the obligor of tax-exempt bonds due April 1, 2024. The
bonds were issued by the Jackson-Union Counties Regional Port District, a
political subdivision embracing the territories of Jackson County and Union
County in the state of Illinois. These variable rate demand bonds bear interest
at a weekly floating market rate and are backed-up by a letter of credit issued
by Wachovia.
The
bond indenture also contains certain standby purchase agreement provisions,
which allow investors to put (sell) back their bonds at par plus accrued
interest. In the fourth quarter of 2008, certain investors elected to sell back
their bonds and Kinder Morgan Energy Partners paid a total principal and
interest amount of $5.2 million according to the letter of credit reimbursement
provisions. However, the bonds were subsequently resold and as of December 31,
2008, Kinder Morgan Energy Partners was fully reimbursed for the prior payments.
As of December 31, 2008, the annual interest rate on these bonds was 3.04%.
Kinder Morgan Energy Partners has an outstanding letter of credit issued by
Wachovia in the amount of $18.0 million that backs-up the principal amount of
$17.7 million the bonds and $0.3 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
Kinder
Morgan Energy Partners owns a 66 2/3% interest in International Marine Terminals
partnership (“IMT”). The principal assets owned by IMT are dock and wharf
facilities financed by the Plaquemines Port, Harbor and Terminal District
(Louisiana) $40.0 million Adjustable Rate Annual Tender Port Facilities Revenue
Refunding Bonds (International Marine Terminals Project) Series 1984A and 1984B.
As of December 31, 2008, the annual interest rate on these bonds was
2.20%.
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, Kinder
Morgan Energy Partners agreed to guarantee the obligations of IMT in proportion
to its ownership interest. Kinder Morgan Energy Partners’ obligation is
approximately $30.3 million for principal, plus interest and other
fees.
Gulf
Opportunity Zone Bonds
To
help fund business growth in the states of Mississippi and Louisiana, Kinder
Morgan Energy Partners completed the purchase of a combined $13.2 million in
principal amount of tax exempt revenue bonds in two separate transactions in
December 2008. The bond offerings were issued under the Gulf Opportunity Zone
Act of 2005 and consisted of the following: (i) $8.2 million in principal amount
of 5.5% Development Revenue Bonds issued by the Mississippi Business Finance
Corporation, a public, non-profit corporation that coordinates a variety of
resources used to assist business and industry in the state of Mississippi and
(ii) $5.0 million in principal amount of 6.0% Development Revenue Bonds issued
by the Louisiana Community Development Authority, a political subdivision of the
state of Louisiana.
The
Mississippi revenue bonds mature on September 1, 2022, and both principal and
interest are due in full at maturity. Kinder Morgan Energy Partners holds an
option to redeem the bonds in full (and settle the note payable to the
Mississippi Business Finance Corporation) without penalty after one year. The
Louisiana revenue bonds have a maturity date of January
134
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
1,
2011 and provide for semi-annual interest payments each July 1 and January
1.
Capital
Trust Securities
Our
business trusts, K N Capital Trust I and K N Capital Trust III, are obligated
for $15.8 million of 8.56% Capital Trust Securities maturing on April 15, 2027
and $19.9 million of 7.63% Capital Trust Securities maturing on April 15, 2028,
respectively, which are guaranteed by us. The 2028 Securities are redeemable in
whole or in part, at our option at any time, at redemption prices as defined in
the associated prospectus. The 2027 Securities are redeemable in whole or in
part at our option and at any time in certain limited circumstances upon the
occurrence of certain events and at prices, all defined in the associated
prospectus supplements. Upon redemption by us or at maturity of the Junior
Subordinated Deferrable Interest Debentures, we must use the proceeds to make
redemptions of the Capital Trust Securities on a pro rata basis.
Common
Stock – Financing of the Going Private Transaction
On
May 30, 2007, investors led by Richard D. Kinder, our Chairman and Chief
Executive Officer, completed the Going Private transaction. As of the closing
date of the Going Private transaction, Kinder Morgan, Inc. had 149,316,603
common shares outstanding, before deducting 15,030,135 shares held in treasury.
The Going Private transaction, including associated fees and expenses, was
financed through (i) $5.0 billion in new equity financing from private equity
funds and other entities providing equity financing, (ii) approximately $2.9
billion from rollover investors, who were certain current or former directors,
officers or other members of management of Kinder Morgan, Inc. (or entities
controlled by such persons) that directly or indirectly reinvested all or a
portion of their equity interests in Kinder Morgan, Inc. and/or cash in exchange
for equity interests in Knight Holdco LLC, the parent of the surviving entity of
the Going Private transaction, (iii) approximately $4.8 billion of new debt
financing, (iv) approximately $4.5 billion of our existing indebtedness
(excluding debt of Terasen Pipelines (Corridor) Inc., which was divested on June
15, 2007) and (v) $1.7 billion of cash on hand resulting principally from the
sale of our U.S.-based and Canada-based retail natural gas distribution
operations (see Note 1).
Kinder
Morgan Energy Partners’ Common Units
On
December 22, 2008, Kinder Morgan Energy Partners issued, in a public offering,
3,900,000 of Kinder Morgan Energy Partners’ common units at a price of $46.75
per unit, less commissions and underwriting expenses. After commissions and
underwriting expenses, Kinder Morgan Energy Partners received net proceeds of
$176.6 million for the issuance of these common units, and used the proceeds to
reduce the borrowings under its bank credit facility. This transaction had the
associated effects of increasing our (i) minority interests associated with
Kinder Morgan Energy Partners by $170.6 million and (ii) associated accumulated
deferred income taxes by $2.2 million and reducing our (i) goodwill by $7.6
million and (ii) paid-in capital by $3.8 million.
On
December 16, 2008, Kinder Morgan Energy Partners furnished to the Securities and
Exchange Commission two Current Reports on Form 8-K and one Current Report on
Form 8-K/A (in each case, containing disclosures under item 7.01 of Form 8-K)
containing certain information with respect to this public offering of Kinder
Morgan Energy Partners’ common units. Kinder Morgan Energy Partners also filed a
prospectus supplement with respect to this common unit offering on December 17,
2008. These Current Reports may have constituted prospectuses not meeting the
requirements of the Securities Act due to the legends used in the Current
Reports. Accordingly, under certain circumstances, purchasers of the common
units from the offering might have the right to require Kinder Morgan Energy
Partners to repurchase the common units they purchased, or if they have sold
those common units, to pay damages. Consequently, Kinder Morgan Energy Partners
could have a potential liability arising out of these possible violations of the
Securities Act. The magnitude of any potential liability is presently impossible
to quantify, and would depend upon whether it is demonstrated Kinder Morgan
Energy Partners violated the Securities Act, the number of common units that
purchasers in the offering sought to require us to repurchase and the treading
price of our common units.
In
connection with the August 28, 2008 sale of our one-third ownership interest in
the Express pipeline system and the full interest in the net assets of the Jet
Fuel pipeline system, Kinder Morgan Energy Partners issued 2,014,693 of its
common units to us. These units, as agreed by Kinder Morgan Energy Partners and
us, were valued at $116.0 million. For more information on this acquisition, see
Note 10.
On
March 3, 2008, Kinder Morgan Energy Partners issued, in a public offering,
5,000,000 of its common units at a price of $57.70 per unit, less commissions
and underwriting expenses. At the time of the offering, Kinder Morgan Energy
Partners granted the underwriters a 30-day option to purchase up to an
additional 750,000 of its common units on the same terms and conditions, and
pursuant to this option, Kinder Morgan Energy Partners issued an additional
750,000 common units on March 10, 2008 upon exercise of this option. After
commissions and underwriting expenses, Kinder Morgan Energy Partners received
net proceeds of $324.2 million for the issuance of these 5,750,000 common units,
and used the proceeds to reduce the borrowings under its commercial paper
program. This transaction had the associated effects of increasing our (i)
minority interests associated with Kinder Morgan Energy Partners by $311.2
million and (ii) associated accumulated deferred income taxes by $4.7 million
and reducing our (i) goodwill by $21.6 million and (ii) paid-in capital by $13.3
million.
135
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
On
February 12, 2008, Kinder Morgan Energy Partners completed an offering of
1,080,000 of its common units at a price of $55.65 per unit in a privately
negotiated transaction. Kinder Morgan Energy Partners received net proceeds of
$60.1 million for the issuance of these 1,080,000 common units, and used the
proceeds to reduce the borrowings under its commercial paper program. This
transaction had the associated effects of increasing our (i) minority interests
associated with Kinder Morgan Energy Partners by $57.6 million and (ii)
associated accumulated deferred income taxes by $0.9 million and reducing our
(i) goodwill by $4.2 million and (ii) paid-in capital by $2.6
million.
On
December 5, 2007, Kinder Morgan Energy Partners issued, in a public offering,
7,130,000 of its common units, including common units sold pursuant to the
underwriters’ over-allotment option, at a price of $48.09 per common unit, less
underwriting expenses, receiving total net proceeds of $342.9 million. This
transaction had the associated effects of increasing our minority interests
associated with Kinder Morgan Energy Partners by $330.1 million and reducing our
(i) goodwill by $33.8 million, (ii) associated accumulated deferred income taxes
by $7.6 million and (iii) paid-in capital by $13.4 million.
In
December 2006, Kinder Morgan Energy Partners issued 34,627 common units as
partial consideration for the acquisition of Devco USA L.L.C. This transaction
had the associated effects of increasing our minority interests associated with
Kinder Morgan Energy Partners by $1.57 million and reducing our (i) goodwill by
$110,000, (ii) associated accumulated deferred income taxes by $11,411 and (iii)
paid-in capital by $18,589.
In
August 2006, Kinder Morgan Energy Partners issued, in a public offering,
5,750,000 common units, including common units sold pursuant to an underwriters’
over-allotment option, at a price of $44.80 per unit, less commissions and
underwriting expenses. Kinder Morgan Energy Partners received net proceeds of
approximately $248.0 million for the issuance of these 5,750,000 common units,
and used the proceeds to reduce the borrowings under its commercial paper
program. This transaction had the associated effects of increasing our minority
interests associated with Kinder Morgan Energy Partners by $236.8 million and
reducing our (i) goodwill by $18.8 million, (ii) associated accumulated deferred
income taxes by $2.8 million and (iii) paid-in capital by $4.7
million.
Kinder
Morgan G.P., Inc. Preferred Shares
On
July 27, 2007, Kinder Morgan G.P., Inc. sold 100,000 shares of its $1,000
Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred
Stock due 2057 to a single purchaser. We used the net proceeds of approximately
$98.6 million after the initial purchaser’s discounts and commissions to reduce
debt. Until August 18, 2012, dividends will accumulate, commencing on the issue
date, at a fixed rate of 8.33% per annum and will be payable quarterly in
arrears, when and if declared by Kinder Morgan G.P., Inc.’s board of directors,
on February 18, May 18, August 18 and November 18 of each year, beginning
November 18, 2007. After August 18, 2012, dividends on the preferred stock will
accumulate at a floating rate of the 3-month LIBOR plus 3.8975% and will be
payable quarterly in arrears, when and if declared by Kinder Morgan G.P., Inc.’s
board of directors, on February 18, May 18, August 18 and November 18 of each
year, beginning November 18, 2012. The preferred stock has approval rights over
a commencement of or filing of voluntary bankruptcy by Kinder Morgan Energy
Partners or its SFPP, L.P. or Calnev Pipe Line LLC subsidiaries.
During
2008, $8.3 million in cash dividends, or $83.3 per share, was paid on our Series
A Fixed-to-Floating Rate Term Cumulative Preferred Stock. On January 21, 2009,
Kinder Morgan G.P., Inc.’s board of directors declared a quarterly cash dividend
on its Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock of
$20.825 per share payable on February 18, 2009 to shareholders of record as of
January 30, 2009.
Kinder
Morgan Management
On
May 15, 2007, Kinder Morgan Management sold 5.7 million listed shares in a
registered offering at a price of $52.26 per share. None of the shares in the
offering were purchased by us. Kinder Morgan Management used the net proceeds
from the sale to purchase 5.7 million i-units from Kinder Morgan Energy
Partners. Kinder Morgan Energy Partners used the net proceeds of approximately
$297.9 million to reduce its outstanding commercial paper debt. This transaction
had the associated effects of increasing our (i) minority interests associated
with Kinder Morgan Energy Partners by $22.7 million, (ii) associated accumulated
deferred income taxes by $1.9 million and (iii) paid-in capital by $3.4 million,
and reducing our goodwill by $17.4 million. Additional information concerning
the business of, and our obligations to, Kinder Morgan Management is contained
in Kinder Morgan Management’s Annual Report on Form 10-K for the year ended
December 31, 2008.
Credit
Ratings
|
Standard
&
Poor’s
|
Moody’s
|
Fitch
|
|||
|
Knight
Inc.
|
|||||
|
$1.0
billion, six-year secured revolver, due May 2013
|
BB
|
Ba1
|
BB+
|
||
|
Kinder
Morgan Energy Partners
|
|||||
|
$1.85
billion, five-year unsecured revolver, due August 2010
|
BBB
|
Baa2
|
BBB
|
136
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
A
securities rating is not a recommendation to buy, sell or hold a security, may
be subject to revision or withdrawal at any time by the issuing ratings agency
in its sole discretion and should be evaluated independently of any other
rating.
In
conjunction with the Going Private transaction, Knight Inc. incurred
approximately $4.8 billion in additional debt. Standard & Poor’s Rating
Services (“Standard & Poor’s”) and Moody’s Investors Service (“Moody’s”)
downgraded the ratings assigned to Knight Inc.’s senior unsecured debt to
BB- and
Ba2, respectively. Upon the February 2008 80% ownership interest sale of our
NGPL business segment, which resulted in Knight Inc.’s repayment of a
substantial amount of debt, Standard & Poor’s and Fitch’s upgraded Knight
Inc.’s senior unsecured debt to BB and BB+, respectively. However, these ratings
are still below investment grade. Since the Going Private transaction, Knight
Inc. has not had access to the commercial paper market and is currently
utilizing its $1.0 billion revolving credit facility for its short-term
borrowing needs.
On
October 13, 2008, Standard & Poor’s revised its outlook on Kinder Morgan
Energy Partners’ long-term credit rating to negative from stable (but affirmed
Kinder Morgan Energy Partners’ long-term credit rating at BBB), due to Kinder
Morgan Energy Partners’ previously announced expected delay and cost increases
associated with the completion of the Rockies Express Pipeline project. At the
same time, Standard & Poor’s lowered Kinder Morgan Energy Partners’
short-term credit rating to A-3 from A-2. As a result of this revision and
current commercial paper market conditions, Kinder Morgan Energy Partners is
unable to access commercial paper borrowings. However, Kinder Morgan Energy
Partners expects that short-term financing and liquidity needs will continue to
be met through borrowings made under its bank credit facility.
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, is based upon prevailing interest
rates available to us as of December 31, 2008 and December 31, 2007 and is
disclosed below (in millions).
|
December
31, 2008
|
December
31, 2007
|
||||||||||||||
|
Carrying
Value
|
Estimated
Fair
Value
|
Carrying
Value
|
Estimated
Fair
Value
|
||||||||||||
|
Total
Debt
|
$
|
12,420.5
|
$
|
10,776.1
|
$
|
15,377.2
|
$
|
15,093.7
|
|||||||
We
adjusted the fair value measurement of our long-term debt as of December 31,
2008 in accordance with SFAS No. 157, and the estimated fair value of our debt
as of December 31, 2008 (presented in the table above) includes a decrease
related to discounting the fair value measurement for the effect of credit
risk.
Interest
Expense, Net
Total
“Interest Expense, Net” as presented in the accompanying Consolidated Statements
of Operations is comprised of the following.
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Interest
Expense, Net
|
$
|
674.3
|
$
|
603.4
|
$
|
253.3
|
$
|
576.1
|
||||||||
|
Capitalized
Interest1
|
(49.3
|
)
|
(25.5
|
)
|
(12.2
|
)
|
(23.3
|
)
|
||||||||
|
Interest
Expense – Preferred Interest in General Partner of
KMP
|
8.4
|
3.6
|
-
|
-
|
||||||||||||
|
Total
Interest Expense, Net
|
$
|
633.4
|
$
|
581.5
|
$
|
241.1
|
$
|
552.8
|
||||||||
__________
|
1
|
Includes
the debt component of the allowance for funds used during construction for
our regulated utility operations, which are accounted for in accordance
with the provisions of SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation.
|
“Interest
Expense–Net” as presented in the accompanying Consolidated Statement of
Operations includes gains and losses from (i) the reacquisition of debt, (ii)
the termination of interest rate swaps designated as fair value hedges for which
the hedged liability has been extinguished and (iii) the termination of interest
rate swaps designated as cash flow hedges for which the forecasted interest
payments will no longer occur. During the year ended December 31, 2008, we
recorded a $34.4 million loss from the early extinguishment of debt in the
caption “Interest Expense, Net,” consisting of an $18.1 million gain on the debt
repurchased in the tender more than offset by a $41.7 million loss from the
write-off of debt issuance costs associated
137
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Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
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with
the $5.755 billion secured credit facility. We also recorded $19.8 million of
gains from the termination of interest rate swaps designated as fair value
hedges, for which the hedged liability was extinguished, in the caption
“Interest Expense, Net” in the accompanying Consolidated Statements of
Operations.
“Interest
Expense-Net” for the seven months ended December 31, 2007 includes approximately
$179.6 million of interest expense related to the increased debt incurred in the
Going Private transaction (See Note 1) and $236.4 million related to Kinder
Morgan Energy Partners. “Interest Expense – Net” for the five months ended May
31, 2007 includes $155.0 million related to Kinder Morgan Energy Partners.
Included in “Interest Expense-Net” in 2006 is $332.0 million of interest expense
relating to Kinder Morgan Energy Partners and $61.3 million of interest expense
related to Terasen.
15.
Risk Management
We
are exposed to risks associated with changes in the market price of natural gas,
natural gas liquids and crude oil as a result of our expected future purchase or
sale of these products. We have exposure to interest rate risk as a result of
the issuance of variable and fixed rate debt and to foreign currency risk from
our investments in businesses owned and operated outside the United States.
Pursuant to our risk management policy, we engage in derivative transactions for
the purpose of mitigating these risks, which transactions are accounted for in
accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities and associated amendments (“SFAS No.
133”).
Commodity
Price Risk Management
Our
principal use of energy commodity derivative contracts is to mitigate the risk
associated with market fluctuations in the price of energy commodities. In
accordance with the provisions of SFAS No. 133, we designate these instruments
as hedges of various exposures as discussed following, and we test the
effectiveness of changes in the value of these hedging instruments with the risk
being hedged. Hedge ineffectiveness is recognized in income in the period in
which it occurs. Our over-the-counter swaps and options are entered into with
counterparties outside central trading facilities such as a futures, options or
stock exchange. These contracts are with a number of parties all of which have
investment grade credit ratings. While we enter into derivative transactions
principally with investment grade counterparties and actively monitor their
ratings, it is nevertheless possible that from time to time losses will result
from counterparty credit risk.
Our
normal business activities expose us to risks associated with changes in the
market price of natural gas, natural gas liquids and crude oil. Reflecting the
portion of changes in the value of derivative contracts that were not effective
in offsetting changes in expected cash flows (the ineffective portion of hedges)
and to the extent of our economic ownership, we recognized a pre-tax loss of
$1.5 million during the year ended December 31, 2008. We recognized a pre-tax
gain of approximately $0.5 million and a pre-tax loss of approximately $0.7
million in the seven months ended December 31, 2007 and five months ended May
31, 2007, respectively, and a pre-tax gain of approximately $5.9 million for the
year ended December 31, 2006. The gains and losses for each respective period
were a result of ineffectiveness of these hedges, which amounts are reported
within the captions “Natural Gas Sales,” “Product Sales and Other,” “Gas
Purchases and Other Costs of Sales,” “Earnings of Equity Investees” and
“Minority Interests” in the accompanying Consolidated Statements of Operations,
and for each of the respective periods, we did not exclude any component of the
derivative contracts’ gain or loss from the assessment of hedge
effectiveness.
As
the hedged sales and purchases take place and we record them into earnings, we
also reclassify the associated gains and losses included in accumulated other
comprehensive income into earnings. During the year ended December 31, 2008, we
reclassified $117.1 million of accumulated other comprehensive loss into
earnings, as a result of hedged forecasted transactions occurring during the
period. During the seven months ended December 31, 2007, we did not reclassify
any accumulated other comprehensive income or losses into earnings as a result
of hedged forecasted transactions occurring during the period. During the five
months ended May 31, 2007, we reclassified $11.4 million of accumulated other
comprehensive loss into earnings, and during the year ended December 31, 2006,
we reclassified, $21.7 million of accumulated other comprehensive loss into
earnings, as a result of hedged forecasted transactions occurring during these
periods. Furthermore, during the five months ended May 31, 2007 and year ended
December 31, 2006, we reclassified $1.1 million of net gains and $2.9 million of
net losses, respectively, into earnings as a result of 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. During the
year ended December 31, 2008 and the seven months ended December 31, 2007, we
did not reclassify any of our accumulated other comprehensive loss into earnings
as a result of the discontinuance of cash flow hedges due to a determination
that forecasted transactions would no longer occur by the end of the originally
specified time period. During the next twelve months, we expect to reclassify
approximately $59.0 million of accumulated other comprehensive income into
earnings.
Effective
at the beginning of the second quarter of 2008, Kinder Morgan Energy Partners
determined that the derivative contracts of its Casper and Douglas natural gas
processing operations that previously had been designated as cash flow hedges
for accounting purposes no longer met the hedge effectiveness assessment as
required by SFAS No. 133. Consequently, we discontinued hedge accounting
treatment for these relationships (primarily crude oil hedges of heavy natural
gas liquids sales) effective as of March 31, 2008. Since the forecasted sales of
natural gas liquids volumes (the hedged item) are still expected to
138
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
occur,
all of the accumulated losses through March 31, 2008 on the related derivative
contracts remained in accumulated other comprehensive income, and will not be
reclassified into earnings until the physical transactions occurs. Any changes
in the value of the these derivative contracts subsequent to March 31, 2008 will
no longer be deferred in other comprehensive income, but rather will impact
current period income. As a result, we recognized an increase in income of $5.6
million in 2008 related to the increase in value of derivative contracts
outstanding as of December 31, 2008 for which hedge accounting had been
discontinued.
Derivative
instruments that are entered into for the purpose of mitigating commodity price
risk include swaps, futures and options. Additionally, basis swaps may also be
used in connection with another derivative contract to reduce hedge
ineffectiveness by reducing basis difference between hedged exposure and a
derivative contract. The fair values of these derivative contracts reflect the
amounts that we would receive or pay to terminate the contracts at the reporting
date and are included in the accompanying Consolidated Balance Sheets as of
December 31, 2008 and 2007 within the captions indicated in the following
table:
|
December
31,
2008
|
December
31,
2007
|
||||||
|
(In
millions)
|
|||||||
|
Derivatives
Asset (Liability)
|
|||||||
|
Current
Assets: Fair Value of Derivative Instruments
|
$
|
115.3
|
$
|
37.1
|
|||
|
Current
Assets: Assets Held for Sale
|
$
|
-
|
$
|
8.4
|
|||
|
Assets:
Fair Value of Derivative Instruments, Non-current
|
$
|
48.9
|
$
|
4.4
|
|||
|
Current
Liabilities: Fair Value of Derivative Instruments
|
$
|
(129.5
|
)
|
$
|
(594.7
|
)
|
|
|
Current
Liabilities: Liabilities Held for Sale
|
$
|
-
|
$
|
(0.4
|
)
|
||
|
Liabilities
and Stockholder’s Equity: Fair Value of Derivative Instruments,
Non-current
|
$
|
(92.2
|
)
|
$
|
(836.8
|
)
|
|
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. We use interest
rate swap agreements to manage the interest rate risk associated with the fair
value of our fixed rate borrowings and to effectively convert a portion of the
underlying cash flows related to our long-term fixed rate debt securities into
variable rate cash flows in order to achieve our desired mix of fixed and
variable rate debt.
Prior
to the Going Private transaction, all of our interest rate swaps qualified for,
and since the Going Private transaction, the new interest rate swaps that Kinder
Morgan Energy Partners entered into in February 2008, discussed below, qualify
for the “short-cut” method prescribed in SFAS No. 133 for qualifying fair value
hedges. Under this method, the carrying value of the swap is adjusted to its
fair value as of the end of each reporting period, and an offsetting entry is
made to adjust the carrying value of the debt securities whose fair value is
being hedged. Interest expense is equal to the floating rate payments, which is
accrued monthly and paid semi-annually.
In
connection with the Going Private transaction, all of our debt, including debt
of our subsidiary, Kinder Morgan Energy Partners, was remeasured and recorded on
our balance sheet at fair value to the extent of our economic ownership
interest. Except for Corridor’s outstanding interest rate swap agreements
classified as held for sale, all of our interest rate swaps and swaps of our
subsidiary, Kinder Morgan Energy Partners, were re-designated as fair value
hedges effective June 1, 2007. Because these swaps did not have a fair value of
zero as of June 1, 2007, they did not meet the requirements for the “short-cut”
method of assessing their effectiveness. Accordingly, the carrying value of the
swap is adjusted to its fair value as of the end of each subsequent reporting
period, and an offsetting entry is made to adjust the carrying value of the debt
securities whose fair value is being hedged. Any hedge ineffectiveness resulting
from the difference between the change in fair value of the interest rate swap
and the change in fair value of the hedged debt instrument is recorded as
interest expense in the current period. During the year ended December 31, 2008,
no hedge ineffectiveness related to these hedges was recognized. Interest
expense equal to the floating rate payments is accrued monthly and paid
semi-annually.
As
of December 31, 2007, we, and our subsidiary Kinder Morgan Energy Partners, were
parties to interest rate swap agreements with notional principal amounts of $275
million and $2.3 billion, respectively, for a consolidated total of $2.575
billion. On March 7, 2008, we paid $2.5 million to terminate our remaining
interest rate swap agreement having a notional value of $275 million associated
with Kinder Morgan Finance Company, LLC’s 6.40% senior notes due 2036. In
February 2008, Kinder Morgan Energy Partners entered into two additional
fixed-to-floating interest rate swap agreements having a combined notional
principal amount of $500 million related to its $600 million 5.95% senior notes
issued on February 12, 2008. Additionally, on June 6, 2008, following Kinder
Morgan Energy Partner’s issuance of $700 million in principal amount of senior
notes in two separate series, Kinder Morgan Energy Partners entered into two
additional fixed-to-floating interest rate swap agreements having a combined
notional principal amount of $700 million. In December 2008, Kinder Morgan
Energy Partners took advantage of the general decrease in variable interest
rates since the start of 2008 by terminating two of its existing agreements in
separate transactions having (i) a notional principal amount of $375 million and
a maturity date of
139
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|
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Form 10-K
|
February
15, 2018; and (ii) a notional principal amount of $325 million and a maturity
date of January 15, 2038, in which it received combined proceeds of $194.3
million from the early termination of these swap agreements. Therefore, as of
December 31, 2008, we were not party to any interest rate swap agreements and
Kinder Morgan Energy Partners was a party to fixed-to-floating interest rate
swap agreements with a combined notional principal amount of $2.8 billion;
effectively converting the interest expense associated with certain series of
its senior notes from fixed rates to variable rates based on an interest rate of
LIBOR plus a spread.
The
fair value of interest rate swaps at December 31, 2008 and 2007 of $747.1
million and $139.1 million, respectively, are included in the accompanying
Consolidated Balance Sheets within the captions “Assets: Fair Value of
Derivative Instruments, Non-current.” The total unamortized net gain on the
termination of interest rate swaps of $216.8 million is included within the
caption “Long-term Debt: Value of Interest Rate Swaps” in the accompanying
Consolidated Balance Sheet at December 31, 2008. All of Kinder Morgan Energy
Partners’ swap agreements have termination dates that correspond to the maturity
dates of the related series of senior notes and, as of December 31, 2008, the
maximum length of time over which Kinder Morgan Energy Partners has hedged a
portion of its exposure to the variability in the value of this debt due to
interest rate risk is through January 15, 2038.
Net
Investment Hedges
We
are exposed to foreign currency risk from our investments in businesses owned
and operated outside the United States. To hedge the value of our investment in
Canadian operations, we have entered into various cross-currency interest rate
swap transactions that have been designated as net investment hedges in
accordance with SFAS No. 133. We have recognized no ineffectiveness through the
income statement as a result of these hedging relationships during the year
ended December 31, 2008, seven months ended December 31, 2007, five months ended
May 31, 2007, or year ended December 31, 2006. The effective portion of the
changes in fair value of these swap transactions is reported as a cumulative
translation adjustment under the caption “Accumulated Other Comprehensive Loss”
in the accompanying Consolidated Balance Sheets at December 31, 2008 and
2007.
The
notional value of our remaining cross-currency interest rate swaps at December
31, 2008 and 2007 was approximately C$154.7 and C$281.6 million, respectively.
The fair value of the swaps as of December 31, 2008 was an asset of $32.0
million and at December 31, 2007 was a liability of $51.2 million, which amounts
are included in the caption “Assets: Fair Value of Derivative Instruments,
Non-current” and “Liabilities and Stockholder’s Equity: Fair Value of Derivative
Instruments, Non-current” in the accompanying Consolidated Balance Sheets,
respectively. In October 2008, we received $150,000 for the termination of
cross-currency interest rate swaps with a combined notional amount of C$126.9
million.
SFAS
No. 157
On
September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. In
general, fair value measurements and disclosures are made in accordance with the
provisions of this Statement and, while not requiring material new fair value
measurements, SFAS No. 157 established a single definition of fair value in GAAP
and expanded disclosures about fair value measurements. The provisions of this
Statement apply to other accounting pronouncements that require or permit fair
value measurements; the FASB having previously concluded in those accounting
pronouncements that fair value is the relevant measurement
attribute.
On
February 12, 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No.
157 (“FAS 157-2”). FAS 157-2 delayed the effective date of SFAS No. 157
for all nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually). Accordingly, we adopted SFAS No. 157 for financial
assets and financial liabilities effective January 1, 2008. The adoption did not
have a material impact on our balance sheet, statement of operations, or
statement of cash flows since we already apply its basic concepts in measuring
fair values.
We
adopted SFAS No. 157 for non-financial assets and non-financial liabilities
effective January 1, 2009. This includes applying the provisions of SFAS No. 157
to (i) nonfinancial assets and liabilities initially measured at fair value in
business combinations; (ii) reporting units or nonfinancial assets and
liabilities measured at fair value in conjunction with goodwill impairment
testing; (iii) other nonfinancial assets measured at fair value in conjunction
with impairment assessments; and (iv) asset retirement obligations initially
measured at fair value. The adoption did not have a material impact on our
balance sheet, statement of operations, or statement of cash flows since we
already apply its basic concepts in measuring fair values.
On
October 10, 2008, the FASB issued FASB Staff Position FAS 157-3, Determining the Fair Value of a
Financial Asset When the Market for That Asset Is Not Active, (“FAS
157-3). FAS 157-3 provides clarification regarding the application of SFAS No.
157 in inactive markets. The provisions of FAS 157-3 are effective immediately.
This Staff Position did not have any material effect on our consolidated
financial statements.
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|
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The
degree of judgment utilized in measuring the fair value of financial instruments
generally correlates to the level of pricing observability. Pricing
observability is affected by a number of factors, including the type of
financial instrument, whether the financial instrument is new to the market, and
the characteristics specific to the transaction. Financial instruments with
readily available active quoted prices or for which fair value can be measured
from actively quoted prices generally will have a higher degree of pricing
observability and a lesser degree of judgment utilized in measuring fair value.
Conversely, financial instruments rarely traded or not quoted will generally
have less (or no) pricing observability and a higher degree of judgment utilized
in measuring fair value.
SFAS
No. 157 established a hierarchal disclosure framework associated with the level
of pricing observability utilized in measuring fair value. This framework
defined three levels of inputs to the fair value measurement process, and
requires that each fair value measurement be assigned to a level corresponding
to the lowest level input that is significant to the fair value measurement in
its entirety. The three broad levels of inputs defined by the SFAS No. 157
hierarchy are as follows:
|
|
·
|
Level
1 Inputs—quoted prices (unadjusted) in active markets for identical assets
or liabilities that the reporting entity has the ability to access at the
measurement date;
|
|
|
·
|
Level
2 Inputs—inputs other than quoted prices included within Level 1 that are
observable for the asset or liability, either directly or indirectly. If
the asset or liability has a specified (contractual) term, a Level 2 input
must be observable for substantially the full term of the asset or
liability; and
|
|
|
·
|
Level
3 Inputs—unobservable inputs for the asset or liability. These
unobservable inputs reflect the entity’s own assumptions about the
assumptions that market participants would use in pricing the asset or
liability, and are developed based on the best information available in
the circumstances (which might include the reporting entity’s own
data).
|
Derivative
contracts can be exchange-traded or over-the-counter, referred to in this report
as OTC. Exchange-traded derivative contracts typically fall within Level 1 of
the fair value hierarchy if they are traded in an active market. We and Kinder
Morgan Energy Partners value exchange-traded derivative contracts using quoted
market prices for identical securities.
OTC
derivative contracts are valued using models utilizing a variety of inputs
including contractual terms, commodity, interest rate and foreign currency
curves, and measures of volatility. The selection of a particular model and
particular inputs to value an OTC derivative contract depends upon the
contractual terms of the instrument as well as the availability of pricing
information in the market. We and Kinder Morgan Energy Partners use similar
models to value similar instruments. For OTC derivative contracts that trade in
liquid markets, such as generic forwards and swaps, model inputs can generally
be verified and model selection does not involve significant management
judgment. Such contracts are typically classified within Level 2 of the fair
value hierarchy.
Certain
OTC derivative contracts trade in less liquid markets with limited pricing
information, and the determination of fair value for these derivative contracts
is inherently more difficult. Such contracts are classified within Level 3 of
the fair value hierarchy. The valuations of these less liquid OTC derivative
contracts are typically impacted by Level 1 and/or Level 2 inputs that can be
observed in the market, as well as unobservable Level 3 inputs. Use of a
different valuation model or different valuation input values could produce a
significantly different estimate of fair value. However, derivative contracts
valued using inputs unobservable in active markets are generally not material to
our financial statements.
When
appropriate, valuations are adjusted for various factors including credit
considerations. Such adjustments are generally based on available market
evidence. In the absence of such evidence, management’s best estimate is used.
Our fair value measurements of derivative contracts are adjusted for credit risk
in accordance with SFAS No. 157, and as of December 31, 2008, the net asset
balance associated with these contracts recorded in the accompanying
Consolidated Balance Sheet includes a reduction of $2.2 million related to
discounting the value of our energy commodity derivative liabilities for the
effect of credit risk. We also adjusted the fair value measurements of our
interest rate swap agreements for credit risk in accordance with SFAS No. 157,
and as of December 31, 2008, the value of interest rate swaps included a
decrease (loss) of $10.6 million related to discounting the fair value
measurement of our interest rate swap agreements’ asset value for the effect of
credit risk.
141
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
The
following tables summarize the fair value measurements of our (i) energy
commodity derivative contracts, (ii) interest rate swap agreements and (iii)
cross-currency interest rate swaps as of December 31, 2008, based on the three
levels established by SFAS No. 157, and does not include cash margin deposits,
which are reported in the caption “Current Assets: Restricted Deposits” in the
accompanying Consolidated Balance Sheet.
|
Asset
Fair Value Measurements as of December 31, 2008 Using
|
||||||||||||||||
|
Total
|
Quoted
Prices in Active Markets
for
Identical
Assets
(Level 1)
|
Significant
Other
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs
(Level 3)
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Energy
Commodity Derivative Contracts1
|
$
|
164.2
|
$
|
0.1
|
$
|
108.9
|
$
|
55.2
|
||||||||
|
Interest
Rate Swap Agreements
|
$
|
747.1
|
$
|
-
|
$
|
747.1
|
$
|
-
|
||||||||
|
Cross-currency
Interest Rate Swaps
|
$
|
32.0
|
$
|
-
|
$
|
32.0
|
$
|
-
|
||||||||
|
Liability
Fair Value Measurements as of December 31, 2008 Using
|
||||||||||||||||
|
Total
|
Quoted
Prices in Active Markets
for
Identical
Assets
(Level 1)
|
Significant
Other
Observable
Inputs
(Level 2)
|
Significant
Unobservable
Inputs
(Level 3)
|
|||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Energy
Commodity Derivative Contracts2
|
$
|
(221.7
|
)
|
$
|
-
|
$
|
(210.6
|
)
|
$
|
(11.1
|
)
|
|||||
|
Interest
Rate Swap Agreements
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
||||||||
____________
|
1
|
Level
2 consists primarily of OTC West Texas Intermediate hedges and OTC natural
gas hedges that are settled on the New York Mercantile Exchange (“NYMEX”).
Level 3 consists primarily of West Texas Intermediate options and West
Texas Sour hedges.
|
|
2
|
Level
2 consists primarily of OTC West Texas Intermediate hedges. Level 3
consists primarily of natural gas basis swaps, natural gas options and
West Texas Intermediate options.
|
The
table below provides a summary of changes in the fair value of our Level 3
energy commodity derivative contracts for the year ended December 31,
2008:
Significant Unobservable Inputs
(Level 3)
|
Year
Ended
December
31,
2008
|
|||
|
(In
millions)
|
|||
|
Net
Asset (Liability)
|
|||
|
Beginning
Balance
|
$
|
(100.3
|
)
|
|
Realized
and Unrealized Net Losses
|
69.6
|
||
|
Purchases
and Settlements
|
74.8
|
||
|
Balance
as of December 31, 2008
|
$
|
44.1
|
|
|
Change
in Unrealized Net Losses Relating to Contracts Still Held as of December
31, 2008
|
$
|
88.8
|
|
Credit
Risks
We
and Kinder Morgan Energy Partners have counterparty credit risk as a result of
our use of energy commodity derivative contracts. Our counterparties consist
primarily of financial institutions, major energy companies and local
distribution companies. This concentration of counterparties may impact our
overall exposure to credit risk, either positively or negatively in that the
counterparties may be similarly affected by changes in economic, regulatory or
other conditions.
We
maintain credit policies with regard to our counterparties that we believe
minimize our overall credit risk. These policies include (i) an evaluation of
potential counterparties’ financial condition (including credit ratings), (ii)
collateral requirements under certain circumstances and (iii) the use of
standardized agreements which allow for netting of positive and negative
exposure associated with a single counterparty. Based on our policies, exposure,
credit and other reserves, our management
142
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
does
not anticipate a material adverse effect on our financial position, results of
operations, or cash flows as a result of counterparty performance.
Our
over-the-counter swaps and options are entered into with counterparties outside
central trading organizations such as a futures, options or stock exchange.
These contracts are with a number of parties, all of which have investment grade
credit ratings. While we enter into derivative transactions principally with
investment grade counterparties and actively monitor their 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, 2008 and December 31, 2007, Kinder
Morgan Energy Partners had outstanding letters of credit totaling $40.0 million
and $298.0 million, respectively, in support of its hedging of commodity price
risks associated with the sale of natural gas, natural gas liquids and crude
oil. Additionally, as of December 31, 2008, Kinder Morgan Energy Partners’
counterparties associated with its energy commodity contract positions and
over-the-counter swap agreements had margin deposits with Kinder Morgan Energy
Partners totaling $3.1 million, and we reported this amount in the caption
“Other” within “Current Liabilities” in the accompanying Consolidated Balance
Sheet. As of December 31, 2007, we had cash margin deposits associated with
Kinder Morgan Energy Partners’ commodity contract positions and over-the-counter
swap partners totaling $67.9 million, and we reported this amount in the caption
“Current Assets: Restricted Deposits” in the accompanying Consolidated Balance
Sheet.
We
and Kinder Morgan Energy Partners are also exposed to credit related losses in
the event of nonperformance by counterparties to our interest rate swap
agreements, and while we and Kinder Morgan Energy Partners enter into these
agreements 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 in the future. As of December 31,
2008, all of our and Kinder Morgan Energy Partners’ interest rate swap
agreements were with counterparties with investment grade credit ratings, and
the $747.1 million total fair value of our and Kinder Morgan Energy Partners’
interest rate swap derivative assets at December 31, 2008 (disclosed above)
included amounts of $301.8 million and $249.0 million related to open positions
with Citigroup and Merrill Lynch, respectively.
16.
Employee Benefits
Knight
Inc.
Retirement
Plans
We
have defined benefit pension plans covering eligible full-time employees. These
plans provide pension benefits that are based on the employees’ compensation
during the period of employment, age and years of service. These plans are
tax-qualified subject to the minimum funding requirements of the Employee Retirement Income Security
Act of 1974, as amended. Our funding policy is to contribute annually the
recommended contribution using the actuarial cost method and assumptions used
for determining annual funding requirements. Plan assets consist primarily of
pooled fixed income, equity, bond and money market funds. The Plan did not have
any material investments in our company or affiliates as of December 31, 2008
and 2007.
Total
amounts recognized in net periodic pension cost include the following
components:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended December 31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Net
Periodic Pension Benefit Cost
|
||||||||||||||||
|
Service
Cost
|
$
|
10.8
|
$
|
5.6
|
$
|
4.5
|
$
|
10.6
|
||||||||
|
Interest
Cost
|
14.5
|
8.1
|
5.6
|
12.7
|
||||||||||||
|
Expected
Return on Assets
|
(23.2
|
)
|
(14.0
|
)
|
(9.6
|
)
|
(21.3
|
)
|
||||||||
|
Amortization
of Prior Service Cost
|
0.1
|
-
|
0.1
|
0.2
|
||||||||||||
|
Amortization
of Loss
|
0.3
|
-
|
0.2
|
0.9
|
||||||||||||
|
Net
Periodic Pension Benefit Cost
|
$
|
2.5
|
$
|
(0.3
|
)
|
$
|
0.8
|
$
|
3.1
|
|||||||
143
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
The
following table sets forth the reconciliation of the beginning and ending
balances of the pension benefit obligation:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Benefit
Obligation at Beginning of Period
|
$
|
258.0
|
$
|
236.5
|
$
|
232.0
|
||||||
|
Service
Cost
|
10.8
|
5.6
|
4.5
|
|||||||||
|
Interest
Cost
|
14.5
|
8.1
|
5.6
|
|||||||||
|
Actuarial
Loss (Gain)
|
(14.2
|
)
|
18.5
|
(2.5
|
)
|
|||||||
|
Plan
Amendments
|
0.8
|
-
|
2.7
|
|||||||||
|
Benefits
Paid
|
(14.9
|
)
|
(10.7
|
)
|
(5.8
|
)
|
||||||
|
Benefit
Obligation at End of Period
|
$
|
255.0
|
$
|
258.0
|
$
|
236.5
|
||||||
The
accumulated benefit obligation at December 31, 2008 and 2007 was $248.6 million
and $248.1 million, respectively.
The
following table sets forth the reconciliation of the beginning and ending
balances of the fair value of the plans’ assets and the plans’ funded
status:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Fair
Value of Plan Assets at Beginning of Period
|
$
|
264.7
|
$
|
273.4
|
$
|
261.6
|
||||||
|
Actual
Return on Plan Assets During the Period
|
(70.1
|
)
|
1.9
|
17.6
|
||||||||
|
Benefits
Paid During the Period
|
(14.9
|
)
|
(10.7
|
)
|
(5.8
|
)
|
||||||
|
Fair
Value of Plan Assets at End of Period
|
179.7
|
264.6
|
273.4
|
|||||||||
|
Benefit
Obligation at End of Period
|
(255.0
|
)
|
(258.0
|
)
|
(236.5
|
)
|
||||||
|
Funded
Status at End of Period
|
$
|
(75.3
|
)
|
$
|
6.6
|
$
|
36.9
|
|||||
The
accompanying Consolidated Balance Sheets at December 31, 2008 include a balance
of $75.3 million under the caption “Other Long-term Liabilities and Deferred
Credits” related to our pension plans. At December 31, 2007, the accompanying
Consolidated Balance Sheets include a balance of $7.0 million under the caption
“Deferred Charges and Other Assets,” and a balance of $0.4 million under the
caption “Other Long-term Liabilities and Deferred Credits” related to our
pension plans.
Amounts
recognized in “Accumulated Other Comprehensive Loss” consist of:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Beginning
Balance
|
$
|
30.6
|
$
|
-
|
$
|
19.3
|
||||||
|
Net
(Gain)/Loss Arising During Period
|
79.1
|
30.6
|
(10.5
|
)
|
||||||||
|
Prior
Service Cost Arising During Period
|
0.7
|
-
|
2.7
|
|||||||||
|
Amortization
of (Gain)/Loss
|
(0.4
|
)
|
-
|
(0.2
|
)
|
|||||||
|
Amortization
of Prior Service Cost
|
(0.1
|
)
|
-
|
(0.1
|
)
|
|||||||
|
Ending
Balance
|
$
|
109.9
|
$
|
30.6
|
$
|
11.2
|
||||||
Our
actuarial estimates allocate costs based on projected employee costs. As
experience develops under our plan, actuarial gains (losses) result from
experience more favorable (unfavorable) than assumed.
144
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
The
estimated net loss for the defined benefit pension plans that will be amortized
from accumulated other comprehensive income into net periodic pension benefit
cost over the next fiscal year is $7.4 million.
We
expect to contribute approximately $20 million to the Plan during
2009.
The
following net benefit payments, which reflect expected future service, as
appropriate, are expected to be paid:
|
Fiscal
Year
|
Expected
Net Benefit Payments
|
|||
|
(In
millions)
|
||||
|
2009
|
$
|
14.4
|
||
|
2010
|
$
|
15.3
|
||
|
2011
|
$
|
16.3
|
||
|
2012
|
$
|
17.1
|
||
|
2013
|
$
|
17.6
|
||
|
2014-2017
|
$
|
108.5
|
||
Effective
January 1, 2001, we added a cash balance plan to our retirement plan. Certain
collectively bargained employees and “grandfathered” employees continue to
accrue benefits through the defined pension benefit plan described above. All
other employees accrue benefits through a personal retirement account in the
cash balance plan. All employees converting to the cash balance plan were
credited with the current fair value of any benefits they had previously accrued
through the defined benefit plan. We make contributions on behalf of these
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 three years (five years prior to January 1, 2008) and
they may take a lump sum distribution upon termination of employment or
retirement.
In
addition to our retirement plan described above, we have the Knight Inc. Savings
Plan (the “Plan”), a defined contribution 401(k) plan. The plan permits all
full-time employees to contribute between 1% and 50% of base compensation, on a
pre-tax basis, into participant accounts. In addition to a Company contribution
equal to 4% of base compensation per year for most plan participants, we may
make discretionary contributions. Certain employees’ contributions are based on
collective bargaining agreements. The contributions are made each pay period on
behalf of each eligible employee. Participants may direct the investment of
their contributions and all employer contributions, including discretionary
contributions, into a variety of investments. Plan assets are held and
distributed pursuant to a trust agreement. The total amount contributed for the
year ended December 31, 2008, seven months ended December 31, 2007, five months
ended May 31, 2007 and year ended December 31, 2006 was $20.8 million, $11.0
million, $8.1 million and $18.3 million, respectively.
Employer
contributions for employees vest on the second anniversary of the date of hire.
Effective October 1, 2005, a tiered employer contribution schedule was
implemented for new employees of the Terminals–KMP segment. 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
Terminals–KMP employees hired after October 1, 2005 vest on the fifth
anniversary of the date of hire. Effective January 1, 2008, this five year
anniversary date for Terminals –KMP employees was changed to three years to
comply with changes in federal regulations. Vesting and contributions for
bargaining employees will follow the collective bargaining
agreements.
At
its July 2008 meeting, the compensation committee of our board of directors
approved a special contribution of an additional 1% of base pay into the 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 2008 and continuing through the last pay period
of July 2009. The additional 1% contribution does not change or otherwise
impact, the annual 4% contribution that eligible employees currently receive and
the vesting schedule mirrors the Company’s 4% contribution. Since this
additional 1% Company contribution is discretionary, compensation committee
approval will be required annually for each additional contribution. During the
first quarter of 2009, excluding the 1% additional contribution described above,
we will not make any additional discretionary contributions to individual
accounts for 2008.
Additionally,
participants have an option to make after-tax “Roth” contributions (Roth 401(k)
option) to a separate participant account. 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 ½, death
or disability. The employer contribution will still be considered taxable income
at the time of withdrawal.
145
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
In
2006, we elected not to make any restricted stock awards as a result of the
Going Private transaction. To ensure that certain key employees who had
previously received restricted stock and restricted stock unit awards continued
under a long-term retention and incentive program, the Company implemented the
Long-term Incentive Retention Award plan. The plan provides cash awards approved
by the compensation committees of the Company which are granted in July of each
year to recommended key employees. Senior management is not eligible for these
awards. These grants require the employee to sign a grant agreement. The grants
vest 100% after the third year anniversary of the grant provided the employee
remains with the Company. Grants were made in July of 2006, 2007 and 2008.
During the year ended December 31, 2008, seven months ended December 31, 2007,
five months ended May 31, 2007 and year ended December 31, 2006, we amortized
$6.9 million, $5.3 million, $1.3 million and $1.9 million, respectively, related
to these grants.
Other
Postretirement Employee Benefits
We
have a postretirement plan providing medical and life insurance benefits upon
retirement. For certain eligible employees and their eligible dependents that
are “grandfathered,” we also provide a subsidized premium. All others who are
eligible pay the full cost. We fund a portion of the future expected
postretirement benefit cost under the plan by making payments to Voluntary
Employee Benefit Association trusts. Plan assets are invested in a mix of equity
funds and fixed income instruments similar to the investments in our pension
plans.
Total
amounts recognized in net periodic postretirement benefit cost include the
following components:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended December 31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Net
Periodic Postretirement Benefit Cost
|
||||||||||||||||
|
Service
Cost
|
$
|
0.3
|
$
|
0.2
|
$
|
0.2
|
$
|
0.4
|
||||||||
|
Interest
Cost
|
4.6
|
2.7
|
1.9
|
4.9
|
||||||||||||
|
Expected
Return on Assets
|
(6.5
|
)
|
(3.9
|
)
|
(2.7
|
)
|
(5.8
|
)
|
||||||||
|
Amortization
of Prior Service Credit
|
-
|
-
|
(0.7
|
)
|
(1.6
|
)
|
||||||||||
|
Amortization
of Loss
|
0.5
|
-
|
2.0
|
5.2
|
||||||||||||
|
Net
Periodic Postretirement Benefit Cost
|
$
|
(1.1
|
)
|
$
|
(1.0
|
)
|
$
|
0.7
|
$
|
3.1
|
||||||
The
following table sets forth the reconciliation of the beginning and ending
balances of the accumulated postretirement benefit obligation:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
Year
Ended December 31, 2008
|
Seven
Months
Ended
December
31, 2007
|
Five
Months
Ended
May
31, 2007
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Benefit
Obligation at Beginning of Period
|
$
|
82.0
|
$
|
78.7
|
$
|
84.0
|
||||||
|
Service
Cost
|
0.3
|
0.2
|
0.2
|
|||||||||
|
Interest
Cost
|
4.6
|
2.7
|
1.9
|
|||||||||
|
Actuarial
Loss (Gain)
|
2.0
|
7.5
|
(3.5
|
)
|
||||||||
|
Benefits
Paid
|
(13.8
|
)
|
(8.5
|
)
|
(5.3
|
)
|
||||||
|
Retiree
Contributions
|
2.9
|
1.4
|
1.4
|
|||||||||
|
Benefit
Obligation at End of Period
|
$
|
78.0
|
$
|
82.0
|
$
|
78.7
|
||||||
146
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
The
following table sets forth the reconciliation of the beginning and ending
balances of the fair value of plan assets and the plan’s funded
status:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Fair
Value of Plan Assets at Beginning of Period
|
$
|
69.2
|
$
|
76.9
|
$
|
67.5
|
||||||
|
Actual
Return on Plan Assets
|
(17.5
|
)
|
0.1
|
4.5
|
||||||||
|
Contributions
|
8.7
|
-
|
8.7
|
|||||||||
|
Retiree
Contributions
|
2.9
|
1.6
|
1.2
|
|||||||||
|
Transfers
In
|
-
|
0.1
|
-
|
|||||||||
|
Benefits
Paid
|
(14.2
|
)
|
(9.5
|
)
|
(5.0
|
)
|
||||||
|
Fair
Value of Plan Assets at End of Period
|
49.1
|
69.2
|
76.9
|
|||||||||
|
Benefit
Obligation at End of Period
|
(78.0
|
)
|
(82.0
|
)
|
(78.7
|
)
|
||||||
|
Funded
Status at End of Period
|
$
|
(28.9
|
)
|
$
|
(12.8
|
)
|
$
|
(1.8
|
)
|
|||
The
accompanying Consolidated Balance Sheets at December 31, 2008 and 2007 include
balances of $28.9 million and $12.8 million, respectively, under the caption
“Other Long-term Liabilities and Deferred Credits,” related to our other
postretirement benefit plans.
Amounts
recognized in “Accumulated Other Comprehensive Loss” consist of:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Beginning
Balance
|
$
|
12.0
|
$
|
-
|
$
|
44.0
|
||||||
|
Net
(Gain)/Loss Arising During Period
|
26.4
|
12.0
|
(5.4
|
)
|
||||||||
|
Amortization
of (Gain)/Loss
|
(0.5
|
)
|
-
|
(2.0
|
)
|
|||||||
|
Amortization
of Prior Service Cost
|
-
|
-
|
0.7
|
|||||||||
|
Ending
Balance
|
$
|
37.9
|
$
|
12.0
|
$
|
37.3
|
||||||
The
estimated net loss for the postretirement benefit plans that will be amortized
from accumulated other comprehensive income into net periodic postretirement
benefit cost over the next fiscal year is $3.0 million. NGPL PipeCo LLC expects
to make contributions of approximately $8.7 million to the plan in
2009.
A
one-percentage-point increase (decrease) in the assumed health care cost trend
rate for each future year would have increased (decreased) the aggregate of the
service and interest cost components of the 2008 net periodic postretirement
benefit cost by approximately $5 $(4) thousand and would have increased
(decreased) the accumulated postretirement benefit obligation as of December 31,
2008 by approximately $77 $(72) thousand.
The
following net benefit payments, which reflect expected future service, as
appropriate, are expected to be paid:
|
Fiscal
Year
|
Expected
Net Benefit Payments
|
|||
|
(In
millions)
|
||||
|
2009
|
$
|
7.6
|
||
|
2010
|
$
|
7.3
|
||
|
2011
|
$
|
7.2
|
||
|
2012
|
$
|
6.9
|
||
|
2013
|
$
|
6.8
|
||
|
2014-2017
|
$
|
31.2
|
||
147
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Actuarial
Assumptions
The
assumptions used to determine benefit obligations for the pension and
postretirement benefit plans were:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||||||||||
|
Year
Ended December 31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||||||||||
|
Discount
Rate
|
6.25
|
%
|
5.75
|
%
|
6.00
|
%
|
6.00
|
%
|
||||||||||||||||
|
Expected
Long-term Return on Assets
|
8.75
|
%
|
9.00
|
%
|
9.00
|
%
|
9.00
|
%
|
||||||||||||||||
|
Rate
of Compensation Increase (Pension Plan Only)
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
||||||||||||||||
The
assumptions used to determine net periodic benefit cost for the pension and
postretirement benefits were:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||||||||||
|
Year
Ended December 31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||||||||||
|
Discount
Rate
|
5.75
|
%
|
6.00
|
%
|
6.00
|
%
|
5.75
|
%
|
||||||||||||||||
|
Expected
Long-term Return on Assets
|
9.00
|
%
|
9.00
|
%
|
9.00
|
%
|
9.00
|
%
|
||||||||||||||||
|
Rate
of Compensation Increase (Pension Plan Only)
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
3.50
|
%
|
||||||||||||||||
The
assumed healthcare cost trend rates for the postretirement plan
were:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||||||||||
|
Year
Ended December 31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||||||||||
|
Healthcare
Cost Trend Rate Assumed for Next Year
|
3.0%
|
3.0%
|
3.0%
|
3.0%
|
||||||||||||||||||||
|
Rate
to which the Cost Trend Rate is Assumed to Decline (Ultimate Trend
Rate)
|
3.0%
|
3.0%
|
3.0%
|
3.0%
|
||||||||||||||||||||
|
Year
the Rate Reaches the Ultimate Trend Rate
|
2008
|
2007
|
2007
|
2006
|
||||||||||||||||||||
Plan
Investment Policies
The
investment policies and strategies for the assets of our pension and retiree
medical and retiree life insurance plans are established by the Fiduciary
Committee (the “Committee”), which is responsible for investment decisions and
management oversight of each plan. The stated philosophy of the Committee is to
manage these assets in a manner consistent with the purpose for which the plans
were established and the time frame over which the plans’ obligations need to be
met. The objectives of the investment management program are to (1) meet or
exceed plan actuarial earnings assumptions over the long term and (2) provide a
reasonable return on assets within established risk tolerance guidelines and
liquidity needs of the plans with the goal of paying benefit and expense
obligations when due. In seeking to meet these objectives, the Committee
recognizes that prudent investing requires taking reasonable risks in order to
raise the likelihood of achieving the targeted investment returns. In order to
reduce portfolio risk and volatility, the Committee has adopted a strategy of
using multiple asset classes.
As
of December 31, 2008, the following target asset allocation ranges were in
effect for our pension plans (Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed
Income –20%/30%/40%; Equity – 55%/65%/75% and Alternative Investments –
0%/5%/10%. As of December 31, 2008, the following target asset allocation ranges
were in effect for our retiree medical and retiree life insurance plans
(Minimum/Target/Maximum): Cash – 0%/0%/5%; Fixed Income –20%/30%/40% and Equity
– 60%/70%/80%. In order to achieve enhanced diversification, the equity category
is further subdivided into sub-categories with respect to small cap vs. large
cap, value vs. growth and international vs. domestic, each with its own target
asset allocation.
In
implementing its investment policies and strategies, the Committee has engaged a
professional investment advisor to assist with its decision making process and
has engaged professional money managers to manage plan assets. The Committee
believes that such active investment management will achieve superior returns
with comparable risk in comparison to passive management. Consistent with its
goal of reasonable diversification, no manager of an equity portfolio for the
plan is allowed to have more than 10% of the market value of the portfolio in a
single security or weight a single economic sector more than twice the weighting
of that sector in the appropriate market index. Finally, investment managers are
not permitted to invest or engage in the following equity transactions unless
specific permission is given in writing (which permission has not been requested
or granted by the Committee to-date): derivative instruments, except for the
purpose of asset value protection (such
148
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
as
the purchase of protective puts), direct ownership of letter stock, restricted
stock, limited partnership units (unless the security is registered and listed
on a domestic exchange), venture capital, short sales, margin purchases or
borrowing money, stock loans and commodities. In addition, fixed income holdings
in the following investments are prohibited without written permission: private
placements, except medium-term notes and securities issued under SEC Rule 144a;
foreign bonds (non-dollar denominated); municipal or other tax exempt
securities, except taxable municipals; margin purchases or borrowing money to
effect leverage in the portfolio; inverse floaters, interest only and principle
only mortgage structures; and derivative investments (futures or option
contracts) used for speculative purposes. Certain other types of investments
such as hedge funds and land purchases are not prohibited as a matter of policy
but have not, as yet, been adopted as an asset class or received any allocation
of fund assets.
Return
on Plan Assets
For
the year ending December 31, 2008, our defined benefit pension plan yielded a
weighted-average rate of return of (27.87%), below the expected rate of return
on assets of 9.00%. Investment performance for a balanced fund comprised of a
similar mix of assets yielded a weighted-average return of (25.45%), so our
plans underperformed the benchmark balanced fund index. For the year ending
December 31, 2008, our retiree medical and retiree life insurance plans yielded
a weighted-average rate of return of (26.04%), below the expected rate of return
on assets of 9.00%. Investment performance for a balanced fund comprised of a
similar mix of assets yielded a weighted-average return of (22.55%), so our
plans underperformed the benchmark balanced fund index.
At
December 31, 2008, our pension plan assets consisted of 60.6% equity, 34.4%
fixed income and 5.0% cash and cash equivalents, and our retiree medical and
retiree life insurance plan assets consisted of 54.1% equity, 38.8% fixed income
and 7.1% cash and cash equivalents. Historically over long periods of time,
widely traded large cap equity securities have provided a return of 10%, while
fixed income securities have provided a return of 6%, indicating that a long
term expected return predicated on the asset allocation as of December 31, 2008
would be approximately 8.75% to 9.31% if investments were made in the broad
indexes for our defined benefit pension plan, and 8.36% to 8.88% for our retiree
medical and retiree life insurance plan. As reported in our 2007 Annual Report
on Form 10-K, these expected returns as of December 31, 2007 were 9.6% to 9.8%.
We arrived at an overall expected return of 9.0% for our periodic benefit cost
calculations for 2008 and an overall expected return of 8.75% for our benefit
obligation calculations as of December 31, 2008.
Kinder
Morgan Energy Partners
Kinder
Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partners of
Trans Mountain Pipeline, L.P.) are sponsors of pension plans for eligible Trans
Mountain employees. The plans include registered defined benefit pension plans,
supplemental unfunded arrangements, which provide pension benefits in excess of
statutory limits, and defined contributory plans. Kinder Morgan Energy Partners
also provides postretirement benefits other than pensions for retired employees.
Kinder Morgan Energy Partners’ combined net periodic benefit costs for these
Trans Mountain pension and postretirement benefit plans for the year ended
December 31, 2008, seven months ended December 31, 2007 and five months ended
May 31, 2007 were approximately $3.5 million, $1.9 million and $1.3 million,
respectively. As of December 31, 2008, Kinder Morgan Energy Partners estimates
its overall net periodic pension and postretirement benefit costs for these
plans for the year 2009 will be approximately $3.1 million, although this
estimate could change if there is a significant event, such as a plan amendment
or a plan curtailment, which would require a remeasurement of liabilities.
Kinder Morgan Energy Partners expects to contribute approximately $7.7 million
to these benefit plans in 2009. Prior to the sale of Trans Mountain to Kinder
Morgan Energy Partners on April 30, 2007 (refer to Note 10) the pension plans of
Trans Mountain were part of the Terasen pension plans. Refer to the following
discussion on the Terasen pension plans for 2006.
In
connection with Kinder Morgan Energy Partners’ acquisition of SFPP, L.P.,
(“SFPP”) and Kinder Morgan Bulk Terminals, Inc. in 1998, Kinder Morgan Energy
Partners acquired certain liabilities for pension and postretirement benefits.
Kinder Morgan Energy Partners provides medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and Kinder
Morgan Bulk Terminals. Kinder Morgan Energy Partners also provides the same
benefits to former salaried employees of SFPP. Additionally, Kinder Morgan
Energy Partners will continue to fund these costs for those employees currently
in the plan during their retirement years. SFPP’s postretirement 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 Knight 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.
The
net periodic benefit cost for the SFPP postretirement benefit plan was less than
$0.1 million for the year ended December 31, 2008, and credits of $0.1 million,
$0.1 million and $0.3 million for the seven months ended December 31, 2007, five
months ended May 31, 2007 and year ended December 31, 2006, respectively. The
credits in 2006 and 2007 resulted in increases to income, largely due to
amortizations of an actuarial gain and a negative prior service cost. As of
December 31, 2008, Kinder Morgan Energy Partners estimates its overall net
periodic postretirement benefit cost for the SFPP postretirement benefit plan
for the year 2009 will be a credit of approximately $0.1 million, however, this
estimate could
149
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
change
if a future significant event would require a remeasurement of liabilities. In
addition, Kinder Morgan Energy Partners expects to contribute approximately $0.3
million to this postretirement benefit plan in 2009.
As
of December 31, 2008 and 2007, the recorded value of Kinder Morgan Energy
Partners’ pension and postretirement benefit obligations for these plans was a
combined $33.4 million and $37.5 million, respectively.
Multiemployer
Plans
As
a result of acquiring several terminal operations, primarily the acquisition of
Kinder Morgan Bulk Terminals, Inc. effective July 1, 1998, Kinder Morgan Energy
Partners participates in several multi-employer pension plans for the benefit of
employees who are union members. Kinder Morgan Energy Partners does not
administer these plans and contributes 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 totaled $7.8 million, $2.5 million, $4.2 million and $6.3
million for the year ended December 31, 2008, seven months ended December 31,
2007, five months ended May 31, 2007 and year ended December 31, 2006,
respectively.
Terasen
Prior
to the sale of Terasen Inc. and Terasen Pipelines (Corridor) Inc. on May 17,
2007 and June 15, 2007, respectively, (see Note 19) we were a sponsor of pension
plans for eligible employees. Our expense for the Terasen Inc. and Corridor
pension and other postretirement benefits plans for the period from January 1 to
May 15, 2007 was $3.7 million and $11.1 million for the year ended December 31,
2006. After the sale of Terasen and Corridor we no longer had expenses or
obligations related to these pension and other postretirement plans. The Terasen
and Corridor plans included registered defined benefit pension plans,
supplemental unfunded arrangements, which provide pension benefits in excess of
statutory limits, and defined contributory plans. We also provided
postretirement benefits other than pensions for retired employees.
17.
Share-based Compensation
Knight
Inc.
In
March 2007, all stock options and restricted stock held by employees of our
discontinued U.S. Retail operations became fully vested. In May 2007, all
restricted stock units held by employees of our discontinued Terasen gas
operations became fully vested and any contingent stock unit grants were fully
expensed. Finally, on May 30, 2007, all remaining stock options and restricted
stock became fully vested and were exercised upon the closing of the Going
Private transaction. We recorded expense of $25.7 million during the five months
ended May 31, 2007 related to the accelerated vesting of these
awards.
Restricted
stock and restricted stock unit grants issued in the periods presented below
were under the following plans: The 1992 Non-Qualified Stock Option Plan for
Non-Employee Directors (which plan has expired), the 1994 Kinder Morgan, Inc.
Long-term Incentive Plan (which plan has expired), the Kinder Morgan, Inc.
Amended and Restated 1999 Stock Plan and the Non-Employee Directors Stock Awards
Plan. The 1994 plan, and the 1999 plan and the Non-Employee Directors Stock
Awards Plan provided for the issuance of restricted stock. There were also two
employee stock purchase plans, one for U.S. employees and one for Canada-based
employees.
Over
the years, the 1999 Stock Plan had been amended to increase shares available to
grant, to allow for granting of restricted shares and effective January 18,
2006, had been amended to allow for the granting of restricted stock units to
employees residing outside the United States. We stopped granting stock options
after July 2004 and replaced option grants with grants of restricted stock and
restricted stock units to fewer people and in smaller amounts. Our restricted
stock and restricted stock unit grants generally had either a three-year or
five-year cliff vesting.
For
the five months ended May 31, 2007 and year ended December 31, 2006, we
recognized stock option expense of $0.8 million and $5.0 million,
respectively.
During
2006, we made restricted common stock grants to employees of 10,000 shares.
These grants were valued at $1.0 million, based on the closing market price of
our common stock on either the date of grant or the measurement date, if
different. Restricted stock grants made to employees vest over three or five
year periods. During 2006, we made restricted common stock grants to our
non-employee directors of 17,600 shares. These grants were valued at $1.7
million. All of the restricted stock grants made to non-employee directors
vested during a six-month period. Expense related to restricted stock grants was
recognized on a straight-line basis over the respective vesting periods. During
the five months ended May 31, 2007 and year ended December 31, 2006, we
amortized $5.0 million and $14.9 million, respectively, related to restricted
stock grants.
During
2006, we made restricted stock unit grants of 61,800 units. These grants were
valued at $6.0 million, based on the closing market price of our common stock on
either the date of grant or the measurement date, if different. During the five
150
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
months
ended May 31, 2007 and year ended December 31, 2006, we amortized $1.6 million
and $3.4 million, respectively, related to restricted stock unit grants.
A
summary of the status of our restricted stock and restricted stock unit plans at
May 31, 2007 and December 31, 2006, and changes during the periods then ended is
presented in the table below:
|
Predecessor
Company
|
|||||||||||||
|
Five
Months Ended
May 31, 20071
|
Year
Ended
December
31, 2006
|
||||||||||||
|
Shares
|
Weighted
Average
Grant
Date
Fair
Value
|
Shares
|
Weighted
Average
Grant
Date
Fair
Value
|
||||||||||
|
(Dollars
in millions)
|
|||||||||||||
|
Outstanding
at Beginning of Period
|
812,240
|
$
|
55.6
|
880,310
|
$
|
56.6
|
|||||||
|
Granted
|
-
|
-
|
89,400
|
8.7
|
|||||||||
|
Reinstated
|
-
|
-
|
50,000
|
2.7
|
|||||||||
|
Vested
|
(59,117
|
)
|
(4.8
|
)
|
(193,620
|
)
|
(11.3
|
)
|
|||||
|
Forfeited
|
(12,016
|
)
|
(1.0
|
)
|
(13,850
|
)
|
(1.1
|
)
|
|||||
|
Outstanding
at End of Period
|
741,107
|
$
|
49.8
|
812,240
|
$
|
55.6
|
|||||||
|
Intrinsic
Value of Restricted Stock Vested
During the Period
|
$
|
3.6
|
$
|
19.2
|
|||||||||
_____________
|
1
|
As
discussed above, all remaining restricted stock at the end of the period
became fully vested and was exercised upon the closing of the Going
Private transaction.
|
Contingent
grants totaling an additional 178,000 shares of restricted common stock and
65,650 restricted stock units were granted in July 2006. Upon the closing of the
Going Private transaction, these grants were replaced with the Long-term
Incentive Retention Award plan (see Note 16).
A
summary of the status of our stock option plans at May 31, 2007 and December 31,
2006, and changes during the periods then ended is presented as
follows:
|
Predecessor
Company
|
|||||||||||||
|
Five
Months Ended
May 31, 20071
|
Year
Ended
December
31, 2006
|
||||||||||||
|
Shares
|
Weighted
Average
Exercise
Price
|
Shares
|
Weighted
Average
Exercise
Price
|
||||||||||
|
Outstanding
at Beginning of Period
|
2,604,217
|
$
|
46.02
|
3,421,849
|
$
|
45.21
|
|||||||
|
Granted
|
-
|
$
|
-
|
-
|
$
|
-
|
|||||||
|
Exercised
|
(160,838
|
)
|
$
|
44.67
|
(618,746
|
)
|
$
|
44.82
|
|||||
|
Forfeited
|
(35,975
|
)
|
$
|
50.10
|
(198,886
|
)
|
$
|
41.95
|
|||||
|
Outstanding
at End of Period
|
2,407,404
|
$
|
46.06
|
2,604,217
|
$
|
46.02
|
|||||||
|
Exercisable
at End of Period
|
2,183,379
|
$
|
44.55
|
2,310,392
|
$
|
44.49
|
|||||||
|
Weighted-Average
Fair Value of Options Granted
|
$
|
-
|
$
|
-
|
|||||||||
|
Aggregate
Intrinsic Value of Options Exercisable at End of Period (in
millions)
|
$
|
142.0
|
$
|
147.9
|
|||||||||
|
Intrinsic
Value of Options Exercised During the Period (In millions)
|
$
|
9.9
|
$
|
34.1
|
|||||||||
|
Cash
Received from Exercise of Options During the Period (In
millions)
|
$
|
7.2
|
$
|
27.7
|
|||||||||
____________
|
1
|
As
discussed above, all remaining stock options became fully vested and were
exercised upon the closing of the Going Private transaction on May 31,
2007.
|
Beginning
March 31, 2005, employees could purchase our common stock at a 5% discount, thus
making the employee stock purchase plan a non-compensatory plan. Employees
purchased 7,605 shares and 36,772 shares for the five months ended May 31, 2007
and year ended December 31, 2006, respectively. We also had a Foreign Subsidiary
Employees Stock Purchase Plan for our employees working in Canada. This plan
mirrored the Employee Stock Purchase Plan for our United States employees.
Employees were eligible to participate in the program beginning April 1, 2006.
Employees purchased 545 shares and 2,098 shares during the five months ended May
31, 2007 and year ended December 31, 2006.
151
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Kinder
Morgan Energy Partners
Kinder
Morgan Energy Partners has three common unit-based compensation plans: A common
unit option plan, the Directors’ Unit Appreciation Rights Plan and the Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan.
The
common unit option plan was established in 1998. The plan was authorized to
grant up to 500,000 options to key personnel and terminated 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. No grants have been made under this plan since May
2000. 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, 2007
and 2008, there were no outstanding options under this plan.
The
Directors’ Unit Appreciation Rights Plan was established on April 1, 2003.
Pursuant to this plan, each of Kinder Morgan Management’s three non-employee
directors was eligible to receive common unit appreciation rights. Upon the
exercise of unit appreciation rights, Kinder Morgan Energy Partners 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. All unit appreciation rights
granted vest on the six-month anniversary of the date of grant and have a
ten-year term. During 2008, 10,000 unit appreciation rights were exercised by
one director at an aggregate fair value of $60.32 per unit. During 2007, 7,500
unit appreciation rights were exercised by one director at an aggregate fair
value of $53.00 per unit. No unit appreciation rights were exercised during
2006. As of December 31, 2008, 35,000 unit appreciation rights had been granted,
vested and remained outstanding. In 2005, this plan was replaced with the Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors, discussed following.
The
Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan recognizes
that the compensation to be paid to each non-employee director is fixed by the
Kinder Morgan Management board, generally annually, and that the compensation is
expected to include an annual retainer payable in cash. Pursuant to the plan, in
lieu of receiving cash compensation, each non-employee director may elect to
receive common units. 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. All common units issued under this plan are
subject to forfeiture restrictions that expire six months from the date of
issuance. A total of 16,868 common units were issued to non-employee directors
in 2006, 2007 and 2008 as a result of their elections to receive common units in
lieu of cash compensation.
18.
Commitments and Contingent Liabilities
Operating
Leases and Purchase Obligations
Expenses
incurred under operating leases were $84.2 million for the year ended December
31, 2008, $43.8 million for the seven months ended December 31, 2007, $32.2
million for the five months ended May 31, 2007 and $53.5 million in 2006, of
which $0.1 million in the seven months ended December 31, 2007, $1.2 million in
the five months ended May 31, 2007 and $3.1 million in 2006 were associated with
our discontinued operations. Future minimum commitments under major operating
leases as of December 31, 2008 are as follows:
|
Year
|
Operating
Leases
|
|||
|
(In
millions)
|
||||
|
2009
|
$
|
57.5
|
||
|
2010
|
54.5
|
|||
|
2011
|
48.9
|
|||
|
2012
|
44.8
|
|||
|
2013
|
40.6
|
|||
|
Thereafter
|
418.4
|
|||
|
Total
|
$
|
664.7
|
||
We
have not reduced our total minimum payments for future minimum sublease rentals,
aggregating approximately $5.2 million. The remaining terms on our operating
leases range from one to 61 years.
Guarantee
As
a result of our December 1999 sale of assets to ONEOK, Inc., ONEOK, Inc. became
primarily obligated for the lease of the Bushton gas processing facility. We
remain secondarily liable for the lease, which had a remaining minimum
obligation of
152
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
approximately
$78.8 million at December 31, 2008, with remaining payments that average
approximately $26.3 million per year through 2011.
Capital
Expenditures Budget
Approximately
$581.0 million of our consolidated capital expenditure budget for 2009 had been
committed for the purchase of plant and equipment at December 31,
2008.
Commitments
for Incremental Investment
We
could be obligated (i) based on operational performance of the equipment at the
Jackson, Michigan power generation facility to invest up to an additional $3 to
$8 million per year for the next 10 years and (ii) based on cash flows generated
by the facility, to invest up to an additional $25 million beginning in 2018, in
each case in the form of an incremental preferred interest.
Contingent
Debt
Cortez Pipeline Company Debt.
Pursuant to a certain Throughput and Deficiency Agreement, the partners of
Cortez Pipeline Company (Kinder Morgan CO2 Company,
L.P. – 50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and
Cortez Vickers Pipeline Company – 13% partner) are required, on a several,
proportional percentage ownership basis, to contribute capital to Cortez
Pipeline Company in the event of a cash deficiency. Furthermore, due to Kinder
Morgan Energy Partners’ indirect ownership of Cortez Pipeline Company through
Kinder Morgan CO2 Company,
L.P., Kinder Morgan Energy Partners severally guarantees 50% of the debt of
Cortez Capital Corporation, a wholly owned subsidiary of Cortez Pipeline
Company.
As
of December 31, 2008, the debt facilities of Cortez Capital Corporation
consisted of (i) $53.6 million of Series D notes due May 15, 2013; (ii) a $125
million short-term commercial paper program; and (iii) 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, 2008,
Cortez Capital Corporation had outstanding borrowings of $116.0 million under
its five-year credit facility. The average interest rate on the Series D notes
was 7.14% in 2008.
In
October 2008, Standard & Poor’s Rating Services lowered Cortez Capital
Corporation’s short-term credit rating to A-3 from A-2. As a result of this
revision and current commercial paper market conditions, Cortez Capital
Corporation is unable to access commercial paper borrowings; however, Kinder
Morgan Energy Partners expects that its financing and liquidity needs will
continue to be met through borrowings made under its long-term bank credit
facility.
With
respect to Cortez Capital Corporation’s Series D notes, Shell Oil Company shares
Kinder Morgan Energy Partners’ several guaranty obligations jointly and
severally; however, Kinder Morgan Energy Partners is obligated to indemnify
Shell for liabilities it incurs in connection with such guaranty. Kinder Morgan
Energy Partners has an outstanding letter of credit issued by JP Morgan Chase in
the amount of $26.8 million to secure Kinder Morgan Energy Partners’
indemnification obligations to Shell for 50% of the $53.6 million in principal
amount of Series D notes outstanding as of December 31, 2008.
Nassau County, Florida Ocean Highway
and Port Authority Debt – Kinder Morgan Energy Partners has posted a
letter of credit as security for borrowings under Adjustable Demand Revenue
Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority. The
bonds were issued for the purpose of constructing certain port improvements
located in Fernandino Beach, Nassau County, Florida, where Kinder Morgan Energy
Partners’ subsidiary, Nassau Terminals LLC, is the operator of the marine port
facilities. The bond indenture is for 30 years and allows the bonds to remain
outstanding until December 1, 2020. Principal payments on the bonds are made on
the first of December each year and corresponding reductions are made to the
letter of credit.
In
October 2008, pursuant to the standby purchase agreement provisions contained in
the bond indenture—which require the sellers of those guarantees to buy the debt
back—certain investors elected to put (sell) back their bonds at par plus
accrued interest. A total principal and interest amount of $11.8 million was
tendered and drawn against Kinder Morgan Energy Partners’ letter of credit and
accordingly, Kinder Morgan Energy Partners paid this amount pursuant to the
letter of credit reimbursement provisions. This payment reduced the face amount
of Kinder Morgan Energy Partners’ letter of credit from $22.5 million to $10.7
million. However, the bonds were subsequently resold and as of December 31,
2008, Kinder Morgan Energy Partners was fully reimbursed for the prior letter of
credit payments. As of December 31, 2008, this letter of credit had a face
amount of $10.2 million.
Rockies Express Pipeline LLC
Debt – Pursuant to certain guaranty agreements, all three member owners
of West2East Pipeline LLC (which owns all of the member interests in Rockies
Express Pipeline LLC) have agreed to guarantee, severally in the same proportion
as their percentage ownership of the member interests in West2East Pipeline LLC,
borrowings under Rockies Express Pipeline LLC’s (i) $2.0 billion five-year,
unsecured revolving credit facility due April 28, 2011; (ii) $2.0 billion
commercial paper program; and (iii) $600 million in principal amount of floating
rate senior notes due August 20,
153
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
2009.
The three member owners and their respective ownership interests consist of the
following: Kinder Morgan Energy Partners’ subsidiary Kinder Morgan W2E Pipeline
LLC – 51%, a subsidiary of Sempra Energy – 25%, and a subsidiary of
ConocoPhillips – 24%.
Borrowings
under the Rockies Express Pipeline LLC commercial paper program and/or its
credit facility are primarily used to finance the construction of the Rockies
Express interstate natural gas pipeline and to pay related expenses. The credit
facility, which can be amended to allow for borrowings up to $2.5 billion,
supports borrowings under the commercial paper program, and borrowings under the
commercial paper program reduce the borrowings allowed under the credit
facility. The $600 million in principal amount of senior notes were issued on
September 20, 2007. The notes are unsecured and are not redeemable prior to
maturity. Interest on the notes is paid and computed quarterly at an interest
rate of three-month LIBOR (with a floor of 4.25%) plus a spread of
0.85%.
Upon
issuance of the notes, Rockies Express Pipeline LLC entered into two
floating-to-fixed interest rate swap agreements having a combined notional
principal amount of $600 million and maturity dates of August 20, 2009. On
September 24, 2008, Rockies Express Pipeline LLC terminated one of the
aforementioned interest rate swaps that had Lehman Brothers as the counterparty.
The notional principal amount of the terminated swap agreement was $300 million.
The remaining interest rate swap agreement effectively converts the interest
expense associated with $300 million of these senior notes from its stated
variable rate to a fixed rate of 5.47%.
In
October 2008, Standard & Poor’s lowered Rockies Express Pipeline LLC’s
short-term credit rating to A-3 from A-2. As a result of this revision and
current commercial paper market conditions, Rockies Express Pipeline LLC is
unable to access commercial paper borrowings, and as of December 31, 2008, there
were no borrowings under its commercial paper program. However, Rockies Express
Pipeline LLC expects that its financing and liquidity needs will continue to be
met through borrowings made under its long-term bank credit facility and
contributions by its equity investors.
As
of December 31, 2008, in addition to the $600 million in floating rate senior
notes, Rockies Express Pipeline LLC had outstanding borrowings of $1,561.0
million under its five-year credit facility. Accordingly, as of December 31,
2008, Kinder Morgan Energy Partners’ contingent share of Rockies Express
Pipeline LLC’s debt was $1,102.1 million (51% of total guaranteed borrowings).
In addition, there is a letter of credit outstanding to support the construction
of the Rockies Express pipeline. As of December 31, 2008, this letter of credit,
issued by JPMorgan Chase, had a face amount of $31.4 million. Kinder Morgan
Energy Partners’ contingent responsibility with regard to this outstanding
letter of credit was $16.0 million (51% of the total face amount).
One
of the Lehman entities was a lending bank with an approximate $41 million
commitment to the Rockies Express Pipeline LLC $2.0 billion credit facility. The
credit facility has been reduced by this amount. The commitments of the other
banks remain unchanged and the facility is not defaulted.
Midcontinent Express Pipeline LLC
Debt – Pursuant to certain guaranty agreements, each of the two member
owners of Midcontinent Express Pipeline LLC have agreed to guarantee, severally
in the same proportion as their percentage ownership of the member interests in
Midcontinent Express Pipeline LLC, borrowings under Midcontinent Express
Pipeline LLC’s $1.4 billion three-year, unsecured revolving credit facility,
entered into on February 29, 2008 and due February 28, 2011. The facility is
with a syndicate of financial institutions with The Royal Bank of Scotland plc
as the administrative agent. Borrowings under the credit agreement will be used
to finance the construction of the Midcontinent Express Pipeline and to pay
related expenses. One of the Lehman entities was a lending bank with an
approximately $100 million commitment to the Midcontinent Express $1.4 billion
credit facility. Since declaring bankruptcy, Lehman has not met its obligations
to lend under the credit facility and our credit facility has effectively been
reduced by its commitment. The commitments of the other banks remain unchanged
and the facility is not defaulted.
Midcontinent
Express Pipeline LLC is an equity method investee of Kinder Morgan Energy
Partners, and the two member owners and their respective ownership interests
consist of the following: Kinder Morgan Energy Partners’ subsidiary Kinder
Morgan Operating L.P. “A” – 50%, and Energy Transfer Partners, L.P. – 50%. As of
December 31, 2008, Midcontinent Express Pipeline LLC had $837.5 million borrowed
under its three-year credit facility. Accordingly, as of December 31, 2008,
Kinder Morgan Energy Partners’ contingent share of Midcontinent Express Pipeline
LLC’s debt was $418.8 million (50% of total borrowings). Furthermore, the
revolving credit facility can be used for the issuance of letters of credit to
support the construction of the Midcontinent Express Pipeline LLC, and as of
December 31, 2008, a letter of credit having a face amount of $33.3 million was
issued under the credit facility. Accordingly, as of December 31, 2008, Kinder
Morgan Energy Partners’ contingent responsibility with regard to this
outstanding letter of credit was $16.7 million (50% of total face
amount).
Standby
Letters of Credit
Letters
of credit totaling $405.8 outstanding as of December 31, 2008 consisted of the
following: (i) a $100.0 million letter of credit that supports certain
proceedings with the California Public Utilities Commission involving refined
products tariff charges on the intrastate common carrier operations of Kinder
Morgan Energy Partners’ West Coast Products Pipelines in the state of
California; (ii) a $55.9 million letter of credit supporting Kinder Morgan
Energy Partners’ pipeline and terminal
154
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
operations
in Canada; (iii) a combined $40.0 million in two letters of credit supporting
Kinder Morgan Energy Partners’ hedging of energy commodity price risks; (iv)
Kinder Morgan Energy Partners’ $30.3 million guarantee under letters of credit
totaling $45.5 million supporting our International Marine Terminals Partnership
Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (v) a $26.8
million letter of credit supporting Kinder Morgan Energy Partners’
indemnification obligations on the Series D note borrowings of Cortez Capital
Corporation; (vi) four letters of credit totaling $25.8 million, required under
provisions of our property and casualty, worker’s compensation and general
liability insurance policies; (vii) a $25.4 million letter of credit supporting
Kinder Morgan Energy Partners’ Kinder Morgan Liquids Terminals LLC New Jersey
Economic Development Revenue Bonds; (viii) two letters of credit totaling $20.3
million supporting the subordination of operating fees payable to us for
operation of the Jackson, Michigan power generation facility to payments due
under the operating lease of the facilities; (ix) a $18.0 million letter of
credit supporting Kinder Morgan Energy Partners’ Kinder Morgan Operating L.P.
“B” tax-exempt bonds; (x) a combined $17.2 million in eight letters of credit
supporting environmental and other obligations of Kinder Morgan Energy Partners
and its subsidiaries; (xi) a $15.3 million letter of credit to fund the Debt
Service Reserve Account required under Kinder Morgan Energy Partners’ Express
pipeline system’s trust indenture; (xii) a $10.2 million letter of credit
supporting Nassau County, Florida Ocean Highway and Port Authority tax-exempt
bonds; and (xiii), a $5.4 million letter of credit supporting Kinder Morgan
Energy Partners’ Arrow Terminals, L.P. Illinois Development Revenue
Bonds.
|
19.
Business Segment Information
|
In
accordance with the manner in which we manage our businesses, including the
allocation of capital and evaluation of business segment performance, we report
our operations in the following segments:
|
|
·
|
Natural Gas Pipeline Company
of America—after February 15, 2008, this segment consists of our
20% interest in NGPL PipeCo LLC, the owner of Natural Gas Pipeline Company
of America and certain affiliates, collectively referred to as Natural Gas
Pipeline Company of America or NGPL, a major interstate natural gas
pipeline and storage system which we
operate;
|
|
|
·
|
Power—which consists of
two natural gas-fired electric generation
facilities;
|
|
|
·
|
Products
Pipelines–KMP—which consists of approximately 8,300 miles of
refined petroleum products pipelines that deliver gasoline, diesel fuel,
jet fuel and natural gas liquids to various markets; plus approximately 60
associated product terminals and petroleum pipeline transmix processing
facilities serving customers across the United
States;
|
|
|
·
|
Natural Gas
Pipelines–KMP—which consists of over 14,300 miles of natural gas
transmission pipelines and gathering lines, plus natural gas storage,
treating and processing facilities, through which natural gas is gathered,
transported, stored, treated, processed and
sold;
|
|
|
·
|
CO2–KMP—which produces,
markets and transports, through approximately 1,300 miles of pipelines,
carbon dioxide 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 450-mile crude oil pipeline system in
West Texas;
|
|
|
·
|
Terminals–KMP—which
consists of approximately 110 owned or operated liquids and bulk terminal
facilities and more than 45 rail transloading and materials handling
facilities located throughout the United States and portions of Canada,
which together transload, store and deliver a wide variety of bulk,
petroleum, petrochemical and other liquids products for customers across
the United States and Canada; and
|
|
|
·
|
Kinder Morgan
Canada–KMP—which consists of over 700 miles of common carrier
pipelines, originating at Edmonton, Alberta, for the transportation of
crude oil and refined petroleum to the interior of British Columbia and to
marketing terminals and refineries located in the greater Vancouver,
British Columbia area and Puget Sound in Washington State; plus five
associated product terminals. This segment also includes a one-third
interest in an approximately 1,700-mile integrated crude oil pipeline and
a 25-mile aviation turbine fuel pipeline serving the Vancouver
International Airport.
|
On
August 28, 2008, we sold our one-third interest in the net assets of the Express
pipeline system (“Express”), as well as our full ownership of the net assets of
the Jet Fuel pipeline system (“Jet Fuel”), to Kinder Morgan Energy Partners. We
accounted for this transaction as a transfer of net assets between entities
under common control. Therefore, following our sale of Express and Jet Fuel to
Kinder Morgan Energy Partners, Kinder Morgan Energy Partners recognized the
assets and liabilities acquired at our carrying amounts (historical cost) at the
date of transfer. The results of Express and Jet Fuel are now reported in the
segment referred to as Kinder Morgan Canada–KMP. Previously, we reported the
results of the equity investment in Express pipeline system in the Express
segment and the results of Jet Fuel in the “Other” caption in the following
tables.
On
February 15, 2008, we sold an 80% ownership interest in our NGPL business
segment to Myria (see Note 10). We continue to operate NGPL’s assets pursuant to
a 15-year operating agreement. Effective February 15, 2008, we began to account
for the results of operations of the NGPL segment as an equity
investment.
In
November 2007, we signed a definitive agreement to sell our interests in three
natural gas-fired power plants in Colorado to Bear Stearns. The sale was
effective January 1, 2008.
155
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
On
October 5, 2007, Kinder Morgan Energy Partners announced that it had completed
the sale of the North System and also its 50% ownership interest in the
Heartland Pipeline Company to ONEOK Partners, L.P. for approximately $295.7
million in cash. Prior to its sale, the North System and the equity
investment in the Heartland Pipeline were reported in the Products Pipelines–KMP
business segment.
On
April 30, 2007, we sold the Trans Mountain pipeline system to Kinder Morgan
Energy Partners for approximately $550 million. The transaction was
approved by the independent members of our board of directors and those of
Kinder Morgan Management following the receipt, by each board, of separate
fairness opinions from different investment banks. Due to the inclusion of
Kinder Morgan Energy Partners and its subsidiaries in our consolidated financial
statements, we accounted for this transaction as a transfer of net assets
between entities under common control, Kinder Morgan Energy Partners recognized
the Trans Mountain assets and liabilities acquired at our carrying amounts
(historical cost) at the date of transfer. As discussed in Note 3, based on an
evaluation of the fair value of the Trans Mountain pipeline system, a goodwill
impairment charge of approximately $377.1 million was recorded in 2007. The
results of Trans Mountain are now reported in the segment referred to as Kinder
Morgan Canada–KMP. In prior filings, the Trans Mountain pipeline system was
reported in the Trans Mountain–KMP business segment.
In
March 2007, we completed the sale of our U.S. retail natural gas distribution
and related operations to GE Energy Financial Services, a subsidiary of General
Electric Company, and Alinda Investments LLC. Prior to its sale, we referred to
these operations as the Kinder Morgan Retail business segment.
On
March 5, 2007, we entered into a definitive agreement to sell Terasen Pipelines
(Corridor) Inc. to Inter Pipeline Fund, a Canada-based company. This transaction
closed on June 15, 2007 (see Note 11).
In
February 2007, we entered into a definitive agreement, which closed on May 17,
2007 (see Note 11) to sell Terasen Inc. to Fortis, Inc., a Canada-based company
with investments in regulated distribution utilities. Execution of this sale
agreement constituted a subsequent event of the type that, under GAAP, required
us to consider the market value indicated by the definitive sales agreement in
our 2006 goodwill impairment evaluation. Accordingly, based on the fair values
of these reporting unit(s) derived principally from this definitive sales
agreement, an estimated goodwill impairment charge of approximately $650.5
million was recorded in 2006.
The
financial results of Terasen Gas, Corridor, Kinder Morgan Retail, the North
System and the equity investment in the Heartland Pipeline Company have been
reclassified to discontinued operations for all periods presented. See Note 11
for additional information regarding discontinued operations.
The
accounting policies we apply in the generation of business segment earnings are
generally the same as those applied to our consolidated operations and described
in Note 1, except that (i) certain items below the “Operating Income” line (such
as interest expense) are either not allocated to business segments or are not
considered by management in its evaluation of business segment performance, (ii)
equity in earnings of equity method investees are included in segment earnings
(these equity method earnings are included in “Other Income and (Expenses)” in
the accompanying Consolidated Statements of Operations), (iii) certain items
included in operating income (such as general and administrative expenses and
depreciation, depletion and amortization (“DD&A”)) are not considered by
management in its evaluation of business segment performance and, thus, are not
included in reported performance measures, (iv) gains and losses from incidental
sales of assets are included in segment earnings and (v) our business segments
that are also segments of Kinder Morgan Energy Partners include certain other
income and expenses and income taxes in their segment earnings. With adjustment
for these items, we currently evaluate business segment performance primarily
based on segment earnings before DD&A (sometimes referred to in this report
as EBDA) in relation to the level of capital employed. Beginning in 2007, the
segment earnings measure was changed from segment earnings to segment earnings
before DD&A for segments not also segments of Kinder Morgan Energy Partners.
This change was made to conform our disclosure to the internal reporting we use
as a result of the Going Private transaction.
This
segment measure change has been reflected in the prior periods shown in this
document in order to achieve comparability. Because Kinder Morgan Energy
Partners’ partnership agreement requires it to distribute 100% of its available
cash to its partners on a quarterly basis (Kinder Morgan Energy Partners’
available cash consists primarily of all of its cash receipts, less cash
disbursements and changes in reserves), we consider each period’s earnings
before all non-cash depreciation, depletion and amortization expenses to be an
important measure of business segment performance for our segments that are also
segments of Kinder Morgan Energy Partners. We account for intersegment sales at
market prices, while we account for asset transfers at either market value or,
in some instances, book value.
During
2008, 2007 and 2006, we did not have revenues from any single customer that
exceeded 10% of our consolidated operating revenues.
156
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Financial
information by segment follows (in millions):
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months Ended
December
31,
2007
|
Five
Months Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Segment
Earnings (Loss) before Depreciation, Depletion, Amortization and
Amortization of Excess Cost of Equity Investments
|
||||||||||||||||
|
NGPL1
|
$
|
129.8
|
$
|
422.8
|
$
|
267.4
|
$
|
603.5
|
||||||||
|
Power
|
5.7
|
13.4
|
8.9
|
23.2
|
||||||||||||
|
Products
Pipelines–KMP2,3
|
(722.0
|
)
|
162.5
|
224.4
|
467.9
|
|||||||||||
|
Natural
Gas Pipelines–KMP2,3
|
(1,344.3
|
)
|
373.3
|
228.5
|
574.8
|
|||||||||||
|
CO2–KMP2
|
896.1
|
433.0
|
210.0
|
488.2
|
||||||||||||
|
Terminals–KMP2,3
|
(156.5
|
)
|
243.7
|
172.3
|
408.1
|
|||||||||||
|
Kinder
Morgan Canada–KMP2,4
|
152.0
|
58.8
|
(332.0
|
)
|
95.1
|
|||||||||||
|
Total
Segment Earnings (Loss) Before DD&A
|
(1,039.2
|
)
|
1,707.5
|
779.5
|
2,660.8
|
|||||||||||
|
Depreciation,
Depletion and Amortization
|
(918.4
|
)
|
(472.3
|
)
|
(261.0
|
)
|
(531.4
|
)
|
||||||||
|
Amortization
of Excess Cost of Equity Investments
|
(5.7
|
)
|
(3.4
|
)
|
(2.4
|
)
|
(5.6
|
)
|
||||||||
|
Other
Operating Income (Loss)
|
39.0
|
(0.3
|
)
|
2.9
|
6.8
|
|||||||||||
|
General
and Administrative Expenses
|
(352.5
|
)
|
(175.6
|
)
|
(283.6
|
)
|
(305.1
|
)
|
||||||||
|
Interest
and Other, Net5,6
|
(1,019.7
|
)
|
(624.0
|
)
|
(348.2
|
)
|
(968.2
|
)
|
||||||||
|
Add
Back Income Tax Expense Included in Segments Above2
|
2.4
|
44.0
|
15.6
|
29.0
|
||||||||||||
|
Income
(Loss) from Continuing Operations Before Income Taxes
|
$
|
(3,294.1
|
)
|
$
|
475.9
|
$
|
(97.2
|
)
|
$
|
886.3
|
||||||
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Revenues
from External Customers
|
||||||||||||||||
|
NGPL1
|
$
|
132.1
|
$
|
752.4
|
$
|
424.5
|
$
|
1,114.4
|
||||||||
|
Power
|
44.0
|
40.2
|
19.9
|
60.0
|
||||||||||||
|
Products
Pipelines–KMP
|
815.9
|
471.5
|
331.8
|
732.5
|
||||||||||||
|
Natural
Gas Pipelines–KMP
|
8,422.0
|
3,825.9
|
2,637.6
|
6,558.4
|
||||||||||||
|
CO2–KMP
|
1,269.2
|
605.9
|
324.2
|
736.5
|
||||||||||||
|
Terminals–KMP
|
1,172.7
|
598.8
|
364.2
|
864.1
|
||||||||||||
|
Kinder
Morgan Canada–KMP
|
198.9
|
100.0
|
62.9
|
140.8
|
||||||||||||
|
Other
|
40.0
|
-
|
-
|
1.9
|
||||||||||||
|
Total
Revenues
|
$
|
12,094.8
|
$
|
6,394.7
|
$
|
4,165.1
|
$
|
10,208.6
|
||||||||
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Intersegment
Revenues
|
||||||||||||||||
|
NGPL1
|
$
|
0.9
|
$
|
4.8
|
$
|
2.0
|
$
|
3.6
|
||||||||
|
Natural
Gas Pipelines–KMP
|
-
|
-
|
3.0
|
19.3
|
||||||||||||
|
Terminals–KMP
|
0.9
|
0.4
|
0.3
|
0.7
|
||||||||||||
|
Other
|
(0.9
|
)
|
-
|
-
|
-
|
|||||||||||
|
Total
Intersegment Revenues
|
$
|
0.9
|
$
|
5.2
|
$
|
5.3
|
$
|
23.6
|
||||||||
157
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Depreciation,
Depletion and Amortization
|
||||||||||||||||
|
NGPL1
|
$
|
9.3
|
$
|
42.3
|
$
|
45.3
|
$
|
104.5
|
||||||||
|
Power
|
-
|
0.2
|
(4.2
|
)
|
2.1
|
|||||||||||
|
Products
Pipelines–KMP
|
116.9
|
58.1
|
33.6
|
74.0
|
||||||||||||
|
Natural
Gas Pipelines–KMP
|
99.9
|
52.3
|
26.8
|
65.4
|
||||||||||||
|
CO2–KMP
|
498.1
|
243.5
|
116.3
|
190.9
|
||||||||||||
|
Terminals–KMP
|
157.4
|
62.1
|
34.4
|
74.6
|
||||||||||||
|
Kinder
Morgan Canada–KMP
|
36.7
|
13.5
|
8.2
|
19.4
|
||||||||||||
|
Other
|
0.1
|
0.3
|
0.6
|
0.5
|
||||||||||||
|
Total
Consolidated Depreciation, Depletion and Amortization
|
$
|
918.4
|
$
|
472.3
|
$
|
261.0
|
$
|
531.4
|
||||||||
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Capital
Expenditures
|
||||||||||||||||
|
NGPL1
|
$
|
10.3
|
$
|
152.0
|
$
|
77.3
|
$
|
193.4
|
||||||||
|
Power
|
-
|
-
|
-
|
-
|
||||||||||||
|
Products
Pipelines–KMP
|
221.7
|
179.9
|
79.5
|
196.0
|
||||||||||||
|
Natural
Gas Pipelines–KMP
|
946.5
|
197.4
|
66.6
|
271.6
|
||||||||||||
|
CO2–KMP
|
542.6
|
249.2
|
133.3
|
283.0
|
||||||||||||
|
Terminals–KMP
|
454.1
|
310.1
|
169.9
|
307.7
|
||||||||||||
|
Kinder
Morgan Canada–KMP
|
368.1
|
196.7
|
109.0
|
123.8
|
||||||||||||
|
Other
|
2.0
|
1.7
|
17.2
|
0.1
|
||||||||||||
|
Total
Consolidated Capital Expenditures
|
$
|
2,545.3
|
$
|
1,287.0
|
$
|
652.8
|
$
|
1,375.6
|
||||||||
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Assets
at December 31
|
||||||||||||
|
NGPL1
|
$
|
717.3
|
$
|
720.0
|
$
|
5,728.9
|
||||||
|
Power
|
58.9
|
120.6
|
387.4
|
|||||||||
|
Products
Pipelines–KMP
|
5,526.4
|
6,941.4
|
4,812.9
|
|||||||||
|
Natural
Gas Pipelines–KMP
|
7,748.1
|
8,439.8
|
3,796.6
|
|||||||||
|
CO2–KMP
|
4,478.7
|
3,919.2
|
1,875.6
|
|||||||||
|
Terminals–KMP
|
4,327.8
|
4,643.3
|
2,564.1
|
|||||||||
|
Kinder
Morgan Canada–KMP
|
1,583.9
|
1,888.3
|
2,555.1
|
|||||||||
|
Total
segment assets
|
24,441.1
|
26,672.6
|
21,720.6
|
|||||||||
|
Assets
Held for Sale
|
-
|
8,987.9
|
510.2
|
|||||||||
|
Other7
|
1,003.8
|
440.5
|
4,564.8
|
|||||||||
|
Total
Consolidated Assets
|
$
|
25,444.9
|
$
|
36,101.0
|
$
|
26,795.6
|
||||||
___________
|
1
|
Effective
February 15, 2008, we sold an 80% ownership interest in NGPL PipeCo LLC to
Myria. As a result of the sale, beginning February 15, 2008, we account
for our 20% ownership interest in NGPL PipeCo LLC as an equity method
investment and 100% of NGPL revenues, earnings and assets prior to the
sale, are included in the above
tables.
|
|
2
|
Kinder
Morgan Energy Partners’ income taxes expenses for the year ended December
31, 2008, seven months ended December 31, 2007, five months ended May 31,
2007 and year ended December 31, 2006 were $2.4 million, $44.0 million,
$15.6 million and $29.0 million, respectively, and are included in segment
earnings.
|
|
3
|
2008
includes non-cash goodwill impairment charges (see Note
3).
|
|
4
|
Five
months ended May 31, 2007 includes a non-cash goodwill impairment charge
(see Note 3).
|
|
5
|
Includes
(i) interest expense, (ii) minority interests and (iii) miscellaneous
other income and expenses not allocated to business
segments.
|
|
6
|
Results
for 2006 include a reduction in pre-tax income of $22.3 million ($14.1
million after tax) resulting from non-cash charges to mark to market
certain interest rate swaps
|
|
7
|
Includes
assets of discontinued operations, cash, restricted deposits, market value
of derivative instruments (including interest rate swaps) and
miscellaneous corporate assets (such as information technology and
telecommunications equipment) not allocated to individual
segments.
|
158
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
|
Geographic
Information
|
Prior
to 2005, all but an insignificant amount of our assets and operations were
located in the continental United States. Upon our acquisition of Terasen on
November 30, 2005, we obtained significant assets and operations in Canada.
However, that percent has declined in 2007 relative to 2006 with the sale of two
significant portions of our Canadian assets during the year. Following is
geographic information regarding the revenues and long-lived assets of our
business segments (in millions).
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
Revenues
from External Customers
|
||||||||||||||||
|
United
States
|
$
|
11,804.2
|
$
|
6,239.7
|
$
|
4,086.6
|
$
|
10,045.9
|
||||||||
|
Canada
|
269.3
|
143.5
|
70.5
|
143.2
|
||||||||||||
|
Mexico
and the Netherlands
|
21.3
|
11.5
|
8.0
|
19.5
|
||||||||||||
|
Total
Consolidated Revenues from External Customers
|
$
|
12,094.8
|
$
|
6,394.7
|
$
|
4,165.1
|
$
|
10,208.6
|
||||||||
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
Long-lived
Assets at December 311
|
||||||||||||
|
United
States
|
$
|
17,511.1
|
$
|
16,051.9
|
$
|
16,779.7
|
||||||
|
Canada
|
1,568.7
|
1,565.8
|
4,605.8
|
|||||||||
|
Mexico
and the Netherlands
|
97.7
|
88.2
|
117.0
|
|||||||||
|
Total
Consolidated Long-lived Assets
|
$
|
19,177.5
|
$
|
17,705.9
|
$
|
21,502.5
|
||||||
____________
|
1
|
Long-lived
assets exclude goodwill and other intangibles,
net.
|
20. Regulatory
Matters
The
tariffs we charge for transportation on our interstate common carrier pipelines
are subject to rate regulation by 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, 2008, 2007 and 2006, the application of the indexing methodology
did not significantly affect tariff rates on our interstate petroleum products
pipelines.
Below
is a brief description of our ongoing regulatory matters, including any material
developments that occurred during 2008. This note also contains a description of
any material regulatory matters initiated during 2008 in which we are
involved.
FERC
Order No. 2004/717
Since
November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C and
2004-D, adopting new Standards of Conduct as applied to natural gas pipelines.
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”). 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.
However,
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
October 16, 2008, the FERC issued a Final Rule in Order 717 revising the FERC
Standards of Conduct for natural gas and electric transmission providers by
eliminating Order No. 2004’s concept of Energy Affiliates and corporate
separation in favor of an employee functional approach as used in Order No. 497.
A transmission provider is prohibited from disclosing to a marketing function
employee non-public information about the transmission system or a transmission
customer. The final rule also retains the long-standing no-conduit rule, which
prohibits a transmission function provider from disclosing non-public
information to marketing function employees by using a third party conduit.
Additionally, the final rule requires that a transmission provider provide
annual training on the Standards of Conduct to all transmission function
employees, marketing function employees, officers, directors, supervisory
employees, and any other employees likely to become privy to
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|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
transmission
function information. This rule became effective on November 26,
2008.
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. Initial
comments were filed by numerous parties on March 27, 2007, and reply comments
were filed on April 27, 2007.
On
September 20, 2007, the FERC issued for public comment in Docket No. RM07-9 a
proposed rule that would revise its financial forms to require that additional
information be reported by natural gas companies. The proposed rule would
require, among other things, that natural gas companies (i) submit additional
revenue information, including revenue from shipper-supplied gas, (ii) identify
the costs associated with affiliate transactions and (iii) provide additional
information on incremental facilities and on discounted and negotiated rates.
The FERC proposed an effective date of January 1, 2008, which means that forms
reflecting the new requirements for 2008 would be filed in early 2009. Comments
on the proposed rule were filed by numerous parties on November 13,
2007.
On
March 21, 2008, the FERC issued a Final Rule regarding changes to the Form 2,
2-A and 3Q. The revisions were designed to enhance the forms’ usefulness by
updating them to reflect current market and cost information relevant to
interstate pipelines and their customers. The rule is effective January 1, 2008
with the filing of the revised Form 3-Q beginning with the first quarter of
2009. The revised Form 2 and 2-A for calendar year 2008 material would be filed
by April 18, 2009. On June 20, 2008, the FERC issued an Order Granting in Part
and Denying in Part Rehearing and Granting Request for Clarification. No
substantive changes were made to the March 21, 2008 Final Rule.
Notice
of Inquiry – Fuel Retention Practices
On
September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on
whether it should change its current policy and prescribe a uniform method for
all interstate gas pipelines to use in recovering fuel gas and gas lost and
unaccounted for. The Notice of Inquiry included numerous questions regarding
fuel recovery issues and the effects of fixed fuel percentages as compared with
tracking provisions. Comments on the Notice of Inquiry were filed by numerous
parties on November 30, 2007. On November 20, 2008, the FERC issued an order
terminating the inquiry.
Notice
of Proposed Rulemaking – Promotion of a More Efficient Capacity Release
Market-Order 712
On
November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket No.
RM 08-1-000 regarding proposed modifications to its Part 284 regulations
concerning the release of firm capacity by shippers on interstate natural gas
pipelines. The FERC proposes to remove, on a permanent basis, the rate ceiling
on capacity release transactions of one year or less. Additionally, the FERC
proposes to exempt capacity releases made as part of an asset management
arrangement from the prohibition on tying and from the bidding requirements of
Section 284.8. Initial comments were filed by numerous parties on January 25,
2008. On June 19, 2008, the FERC issued a final rule in Order 712 regarding
changes to the capacity release program. The FERC permitted market based pricing
for short-term capacity releases of a year or less. Long-term capacity releases
and a pipeline’s sale of its own capacity remain subject to a price cap. The
ruling would facilitate asset management arrangements by relaxing the FERC’s
prohibitions on tying and on its bidding requirements for certain capacity
releases. The FERC further clarified that its prohibition on tying does not
apply to conditions associated with gas inventory held in storage for releases
for firm storage capacity. Finally, the FERC waived the prohibition on tying and
bidding requirements for capacity releases made as part of state-approved retail
open access programs. The final rule became effective on July 30,
2008.
On
November 20, 2008, the FERC issued an order generally denying requests for
rehearing and/or clarification that had been filed. The FERC reaffirmed its
final rule, Order 712, and denied requests for rehearing stating the removal of
the rate ceiling for short-term capacity release transactions is designed to
extend to capacity release transactions, the pricing flexibility already
available to pipelines through negotiated rates without compromising the
fundamental protection provided by the availability of recourse rate service.
Additionally, the FERC clarified several areas of the rule as it relates to
asset management arrangements.
Notice
of Proposed Rulemaking – Natural Gas Price Transparency
On
April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos.
RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section
23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC
proposed to revise its regulations to (i) require that intrastate pipelines post
daily the capacities of, and volumes flowing through, their major receipt and
delivery points and mainline segments in order to make available the information
to track daily flows of natural gas throughout the United States; and (ii)
require that buyers and sellers of more than a de minimis volume of natural gas
report annual numbers and volumes of relevant transactions to the FERC in order
to make possible an estimate of the size of the physical U.S. natural gas
market, assess the importance of the use of index pricing in that market and
determine the size of the fixed-price trading market that produces the
information. The FERC believes these revisions to
160
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
its
regulations will facilitate price transparency in markets for the sale or
transportation of physical natural gas in interstate commerce. Initial comments
were filed on July 11, 2007 and reply comments were filed on August 23, 2007. In
addition, the FERC conducted an informal workshop in this proceeding on July 24,
2007, to discuss implementation and other technical issues associated with the
proposals set forth in the notice of proposed rulemaking.
In
addition, on December 21, 2007, the FERC issued a new notice of proposed
rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that
were contained in Docket Nos. RM07-10-000 and AD06-11-000. The new notice of
proposed rulemaking proposes to exempt from the daily posting requirements those
non-interstate pipelines that (i) flow less than ten million MMBtus of natural
gas per year, (ii) fall entirely upstream of a processing plant and (iii)
deliver more than ninety-five percent (95%) of the natural gas volumes they flow
directly to end-users. However, the new notice of proposed rulemaking expands
the proposal to require that both interstate and non-exempt non-interstate
pipelines post daily the capacities of, volumes scheduled at, and actual volumes
flowing through, their major receipt and delivery points and mainline segments.
Initial comments were filed by numerous parties on March 13, 2008. A Technical
Conference was held on April 3, 2008. Numerous reply comments were received on
April 14, 2008.
On
December 26, 2007, the FERC issued Order No. 704 in this docket implementing
only the annual reporting provisions of the notice of proposed rulemaking with
minimal changes to the original proposal. The order became effective February 4,
2008. The initial report is due May 1, 2009 for calendar year 2008. Subsequent
reports are due by May 1 of each year for the previous calendar year. Order 704
will require most, if not all Kinder Morgan natural gas pipelines to report
annual volumes of relevant transactions to the FERC. Technical workshops were
held on April 22, 2008 and May 19, 2008. The FERC issued Order 704-A on
September 18, 2008. This order generally affirmed the rule, while clarifying
what information certain natural gas market participants must report in Form
552. The revisions pertain to the reporting of transactions occurring in
calendar year 2008. Order 704-A became effective October 27, 2008.
On
November 20, 2008, the FERC issued Order 720, which is the final rule in the
Docket No. RM08-2-000 proceeding. The final rule established new reporting
requirements for interstate and major non-interstate pipelines. A major
non-interstate pipeline is defined as a pipeline who delivers annually more than
50 million MMBtus of natural gas measured in average deliveries for the previous
three calendar years. Interstate pipelines will be required to post no-notice
activity at each receipt and delivery point three days after the day of gas
flow. Major non-interstate pipelines will be required to post design capacity,
scheduled volumes and available capacity at each receipt or delivery point with
a design capacity of 15,000 MMbtus of natural gas per day or greater when gas is
scheduled at the point. The final rule became effective January 27, 2009 for
interstate pipelines. Non-major interstate pipelines must comply with the
requirements of Order 720 within 150 days following the issuance of an order
addressing the pending request for rehearing.
FERC
Equity Return Allowance
On
April 17, 2008, the FERC adopted a new policy under Docket No. PL07-2-000 that
allows master limited partnerships to be included in proxy groups for the
purpose of determining rates of return for both interstate natural gas and oil
pipelines. Additionally, the policy statement concluded that (i) there should be
no cap on the level of distributions included in the FERC’s current discounted
cash flow methodology, (ii) the Institutional Brokers Estimated System forecasts
should remain the basis for the short-term growth forecast used in the
discounted cash flow calculation, (iii) there should be an adjustment to the
long-term growth rate used to calculate the equity cost of capital for a master
limited partnership, specifically the long-term growth rate would be set at 50%
of the gross domestic product and (iv) there should be no modification to the
current respective two-thirds and one-third weightings of the short-term and
long-term growth factors. Additionally, the FERC decided not to explore other
methods for determining a pipeline’s equity cost of capital at this time. The
policy statement governs all future gas and oil rate proceedings involving the
establishment of a return on equity, as well as those cases that are currently
pending before either the FERC or an administrative law judge. On May 19, 2008,
an application for rehearing was filed by The American Public Gas Association.
On June 13, 2008, the FERC dismissed the request for rehearing.
Notice
of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids
Pipelines
On
September 6, 2006, the U.S. Department of Transportation Pipeline and Hazardous
Materials Safety Administration, referred to in this report as the PHMSA,
published a notice of proposed rulemaking (PHMSA 71 FR 52504) that proposed to
extend certain threat-focused pipeline safety regulations to rural onshore
low-stress hazardous liquid pipelines within a prescribed buffer of previously
defined U.S. states. Low-stress hazardous liquid pipelines, except those in
populated areas or that cross commercially navigable waterways, have not been
subject to the safety regulations in PHMSA 49 C.F.R. Part 195.1. According to
the PHMSA, unusually sensitive areas are areas requiring extra protection
because of the presence of sole-source drinking water resources, endangered
species, or other ecological resources that could be adversely affected by
accidents or leaks occurring on hazardous liquid pipelines.
The
notice proposed to define a category of “regulated rural onshore low-stress
lines” (rural lines operating at or below 20% of specified minimum yield
strength, with a diameter of eight and five-eighths inches or greater, located
in or within a quarter-mile of a U.S. state) and to require operators of these
lines to comply with a threat-focused set of requirements in Part 195 that
already apply to other hazardous liquid pipelines. The proposed safety
requirements addressed the most common threats—
161
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
corrosion
and third party damage—to the integrity of these rural lines. The proposal is
intended to provide additional integrity protection, to avoid significant
adverse environmental consequences, and to improve public confidence in the
safety of unregulated low-stress lines.
Since
the new notice is a proposed rulemaking in which the PHMSA will consider initial
and reply comments from industry participants, it is not clear what impact the
final rule will have on the business of our intrastate and interstate liquids
pipeline companies.
Kinder
Morgan Liquid Terminals – U.S. Department of Transportation
Jurisdiction
With
regard to several of our liquids terminals, we are working with the U.S.
Department of Transportation, referred to in this report as the DOT, to
supplement our compliance program for certain of our tanks and internal piping.
We anticipate the program will call for incremental capital spending over the
next several years to improve and/or add to our facilities. These improvements
will enhance the tanks and piping previously considered outside the jurisdiction
of DOT to conduct DOT jurisdictional transfers of products. Our original
estimate called for an incremental $3 million to $5 million of annual capital
spending over the next six to ten years for this work; however, we continue to
assess the amount of capital that will be required and the amount may exceed our
original estimate.
Natural
Gas Pipeline Expansion Filings
TransColorado
Pipeline
On
April 19, 2007, the FERC issued an order approving TransColorado Gas
Transmission Company LLC’s application for authorization to construct and
operate certain facilities comprising its proposed “Blanco-Meeker Expansion
Project.” This project provides for 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. Construction commenced
on May 9, 2007, and the project was completed and entered service January 1,
2008.
Rockies
Express Pipeline-Currently Certificated Facilities
Kinder
Morgan Energy Partners operates and owns a 51% ownership interest in West2East
Pipeline LLC, a limited liability company that is the sole owner of Rockies
Express Pipeline LLC, and operates Rockies Express Pipeline. ConocoPhillips owns
a 24% ownership interest in West2East Pipeline LLC and Sempra Energy holds the
remaining 25% interest. When construction of the entire Rockies Express Pipeline
project is completed, Kinder Morgan Energy Partners’ ownership interest will be
reduced to 50% at which time the capital accounts of West2East Pipeline LLC will
be trued up to reflect Kinder Morgan Energy Partners’ 50% economics in the
project. According to the provisions of current accounting standards, because
Kinder Morgan Energy Partners will receive 50% of the economic benefits from the
Rockies Express project on an ongoing basis, Kinder Morgan Energy Partners is
not considered the primary beneficiary of West2East Pipeline LLC and thus,
accounts for its investment under the equity method of accounting.
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 pipeline
segments), Rockies Express Pipeline LLC was granted authorization to construct
and operate approximately 136 miles of pipeline extending northward from the
Meeker Hub, located at the northern end of Kinder Morgan Energy Partners’
TransColorado pipeline system in 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 segments 1 and 2 has been completed, with interim
service commencing on segment 1 on February 24, 2006, and full in-service of
both segments on February 14, 2007. For phase II, Rockies Express Pipeline LLC
was authorized to construct three compressor stations, referred to as the
Meeker, Big Hole and Wamsutter compressor stations. The Meeker and Wamsutter
stations went into service in January 2008. Construction of the Big Hole
compressor station commenced in the second quarter of 2008, and the expected in
service date for the compressor station is in the second quarter of
2009.
Rockies
Express Pipeline-West Project
On
April 19, 2007, the FERC issued a final order approving the Rockies Express
Pipeline LLC 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’ facilities
described above, and it is 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 project
also includes certain improvements to existing Rockies Express facilities
located to the west of the Cheyenne Hub. Construction on Rockies Express-West
commenced on May 21, 2007. Rockies Express-West began interim service for up to
1.4 billion cubic feet per day of natural gas on the segment’s first 503 miles
of pipe on January 12, 2008. The project commenced deliveries to Panhandle
Eastern Pipe Line, at Audrain County, Missouri, on
162
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
the
remaining 210 miles of pipe on May 20, 2008. The Rockies Express-West pipeline
segment transports approximately 1.5 million cubic feet per day of natural gas
across five states: Wyoming, Colorado, Nebraska, Kansas and
Missouri.
Rockies
Express Meeker to Cheyenne Expansion Project
Pursuant
to certain rights exercised by Encana Gas Marketing USA as a result of its
foundation shipper status on the former Entrega Gas Pipeline LLC facilities,
Rockies Express Pipeline LLC is requesting authorization to construct and
operate certain facilities that will comprise its Meeker, Colorado to Cheyenne,
Wyoming expansion project. The proposed expansion will consist of additional
natural gas compression at its Big Hole compressor station located in Moffat
County, Colorado and its Arlington compressor station located in Carbon County,
Wyoming. Upon completion, the additional compression will permit the
transportation of an additional 200 million cubic feet per day of natural gas
from (i) the Meeker Hub located in Rio Blanco County, Colorado northward to the
Wamsutter Hub located in Sweetwater County, Wyoming; and (ii) from the Wamsutter
Hub eastward to the Cheyenne Hub located in Weld County, Colorado. The expansion
is fully contracted and is expected to be operational in April 2010. The total
estimated cost for the proposed project is approximately $78 million. Rockies
Express Pipeline LLC submitted a FERC application seeking approval to construct
and operate this expansion on February 3, 2009.
Rockies
Express Pipeline-East Project
On
April 30, 2007, Rockies Express Pipeline LLC filed an application with the FERC
requesting a certificate of public convenience and necessity that would
authorize construction and operation of the Rockies Express-East Project. The
Rockies Express-East Project will be comprised of approximately 639 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 and will be capable of transporting approximately 1.8 billion cubic
feet per day of natural gas.
By
order issued May 30, 2008, the FERC authorized the certificate to construct the
Rockies Express Pipeline-East Project. Construction commenced on the Rockies
Express-East pipeline segment on June 26, 2008. Delays in securing permits and
regulatory approvals, as well as weather-related delays, have caused Rockies
Express Pipeline LLC to set revised project completion dates. Rockies
Express-East is currently projected to commence service on April 1, 2009 to
interconnects upstream of Lebanon, followed by service to the Lebanon Hub in
Warren County, Ohio beginning June 15, 2009, with final completion and
deliveries to Clarington, Ohio commencing by November 1, 2009.
On
October 31, 2008, Rockies Express Pipeline LLC filed an amendment to its
certificate application, seeking authorization to revise its tariff-based
recourse rates for transportation service on the Rockies Express Pipeline-East
Project facilities to reflect updated construction costs for the project. The
proposed amendment is pending FERC approval.
Current
market conditions for consumables, labor and construction equipment along with
certain provisions in the final regulatory orders have resulted in increased
costs for the project and have impacted certain projected completion dates. Our
current estimate of total completed costs on the Rockies Express Pipeline
Project is approximately $6.3 billion including expansion (consistent with
Kinder Morgan Energy Partners’ January 21, 2009 fourth quarter earnings
release).
Kinder
Morgan Interstate Gas Transmission Pipeline
On
August 6, 2007, Kinder Morgan Interstate Gas Transmission Pipeline LLC (referred
to in this report as KMIGT) filed in FERC Docket CP07-430, for regulatory
approval to construct and operate a 41-mile natural gas pipeline from the
Cheyenne Hub to markets in and around Greeley, Colorado, referred to in this
report as the Colorado Lateral. When completed, the Colorado Lateral will
provide firm transportation of up to 55 million cubic feet per day to a local
utility under long-term contract. The FERC issued a draft environmental
assessment on the project on January 11, 2008, and comments on the project were
received February 11, 2008. On February 21, 2008, the FERC granted the
certificate application. On July 8, 2008, in response to a rehearing request by
Public Service Company of Colorado (referred to in this report as PSCo) the FERC
granted rehearing and denied KMIGT recovery in initial transportation rates $6.2
million in costs associated with non-jurisdictional laterals constructed by
KMIGT to serve Atmos. The recourse rate adjustment does not have any material
effect on the negotiated rate paid by Atmos to KMIGT or the economics of the
project. On July 25, 2008, KMIGT filed an amendment to its certification
application seeking authorization to revise its initial rates for transportation
service on the Colorado Lateral to reflect updated construction costs for
jurisdictional mainline facilities. The FERC approved the revised initial
recourse rates on August 22, 2008.
PSCo,
a competitor serving markets off the Colorado Lateral, also filed a complaint
before the State of Colorado Public Utilities Commission (“CoPUC”) against
Atmos, the anchor shipper on the project. The CoPUC conducted a hearing on April
14, 2008 on the complaint. On June 9, 2008, PSCo also filed before the CoPUC
seeking a temporary cease and desist order to halt construction of the lateral
facilities being constructed by KMIGT to serve Atmos. Atmos filed a response to
that motion on June 24, 2008. By order dated June 27, 2008 an administrative law
judge for the CoPUC denied PSCo’s request for a cease and desist order. On
September 4, 2008, an administrative law judge for the CoPUC issued an order
wherein it denied PSCo’s claim to exclusivity to serve Atmos and the Greeley
market area but affirmed PSCo’s claim that Atmos’ acquisition of
the
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delivery
laterals is not in the ordinary course of business and requires separate
approvals. Accordingly, Atmos may require a certificate of public convenience
and necessity (“CPCN”) related to the delivery lateral facilities from KMIGT.
While the need for approvals by Atmos before the CoPUC remains pending, service
on the subject facilities commenced in November 2008.
On
December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its
system in Nebraska to serve incremental ethanol and industrial load. No protests
to the application were filed and the project was approved by the FERC.
Construction commenced on April 9, 2008. These facilities went into service in
October 2008.
Kinder
Morgan Louisiana Pipeline
On
September 8, 2006, in FERC Docket No. CP06-449-000, Kinder Morgan Louisiana
Pipeline LLC filed an application with the FERC requesting approval to construct
and operate the Kinder Morgan Louisiana Pipeline. The natural gas 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
NGPL. The project is supported by fully subscribed capacity and long-term customer
commitments with Chevron and Total. The entire estimated project cost is now
expected to be approximately $950 million (consistent with Kinder Morgan Energy
Partners’ January 21, 2009 fourth quarter earnings press release), and it is
expected to be fully operational during the third quarter of 2009.
On
March 15, 2007, the FERC issued a preliminary determination that the
authorizations requested, subject to some minor modifications, will be in the
public interest. This order does not consider or evaluate any of the
environmental issues in this proceeding. On April 19, 2007, the FERC issued the
final environmental impact statement, or (“EIS”), which addressed the potential
environmental effects of the construction and operation of the Kinder Morgan
Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of
the National Environmental Policy Act. It concluded that approval of the Kinder
Morgan Louisiana Pipeline project would have limited adverse environmental
impacts. On June 22, 2007, the FERC issued an order granting construction and
operation of the project. Kinder Morgan Louisiana Pipeline officially accepted
the order on July 10, 2007.
On
July 11, 2008, Kinder Morgan Louisiana Pipeline filed an amendment to its
certificate application, seeking authorization to revise its initial rates for
transportation service on the Kinder Morgan Louisiana Pipeline system to reflect
updated construction costs for the project. The amendment was accepted by the
FERC on August 14, 2008. On December 30, 2008, KMLP filed a second amendment to
its certificate application, seeking authorization to revise its initial rates
for transportation service on the KMLP system to reflect an additional increase
in projected construction costs for the project. The filing is still
pending.
Midcontinent
Express Pipeline LLC
On
October 9, 2007, in Docket No. CP08-6-000, Midcontinent Express Pipeline LLC
(“Midcontinent Express Pipeline”) filed an application with the FERC requesting
a certificate of public convenience and necessity that would authorize
construction and operation of the approximately 500-mile Midcontinent Express
Pipeline natural gas transmission system.
The
Midcontinent Express Pipeline will create long-haul, firm transportation
takeaway capacity either directly or indirectly connected to natural gas
producing regions located in Texas, Oklahoma and Arkansas. The pipeline will
originate in southeastern Oklahoma and traverse east through Texas, Louisiana,
Mississippi, and terminate at an interconnection with the Transco Pipeline near
Butler, Alabama. The Midcontinent Express Pipeline is a 50/50 joint venture
between Kinder Morgan Energy Partners and Energy Transfer Partners, L.P., and it
has a total capital cost of approximately $2.2 billion including the expansion
capacity.
On
July 25, 2008, the FERC approved the application made by Midcontinent Express
Pipeline to construct and operate the 500-mile Midcontinent Express Pipeline
natural gas transmission system along with the lease of 272 Mcf of capacity on
the Oklahoma intrastate system of Enogex Inc. Initial design capacity for the
pipeline was 1.5 Bcf of natural gas per day, which was fully subscribed with
long-term binding commitments from creditworthy shippers. A successful binding
open season was completed in July 2008, which will increase the main segment of
the pipeline’s capacity to 1.8 Bcf per day, subject to regulatory
approval.
Midcontinent
Express Pipeline accepted the FERC Certificate on July 30, 2008. Mobilization
for construction of the pipeline began in the third quarter of 2008, and subject
to the receipt of regulatory approvals, interim service on the first portion of
the pipeline is expected to be available by the second quarter of 2009 with full
in service in the third quarter of 2009. On January 9, 2009, Midcontinent
Express filed an amendment to its original certificate application requesting
authorization to revise its initial rates for transportation service on the
pipeline system to reflect an increase in projected construction costs for the
project. The filing is still pending.
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On
January 30, 2009, Midcontinent Express Pipeline filed a certificate application
in Docket No. CP09-56-000 requesting authorization to increase the capacity in
Zone 1 from 1.5 Bcf to 1.8 Bcf/d. The Application is still pending.
Kinder
Morgan Texas Pipeline LLC
On
May 30, 2008, Kinder Morgan Texas Pipeline LLC filed in Docket No. PR08-25-000 a
petition seeking market-based rate authority for firm and interruptible storage
services performed under section 311 of the Natural Gas Policy Act of 1978
(NGPA) at the North Dayton Gas Storage Facility in Liberty County, Texas, and at
the Markham Gas Storage Facility in Matagorda County, Texas. On October 3, 2008,
the FERC approved this petition effective May 30, 2008.
21. Litigation,
Environmental and Other Contingencies
Below
is a brief description of our ongoing material legal proceedings, including any
material developments that occurred in such proceedings during 2008. This note
also contains a description of any material legal proceeding initiated during
2008 in which we are involved.
Following
is a listing of certain current FERC proceedings pertaining to Kinder Morgan
Energy Partners’ operations:
|
Proceedings
|
Complainants/Protestants
|
Defendants
|
|
FERC
Docket No. OR92-8, et
al.
|
Chevron;
Navajo; ARCO; BP WCP; Western Refining; ExxonMobil; Tosco; and Texaco
(Ultramar is an intervenor)
|
SFPP
|
|
FERC
Docket No. OR92-8-025
|
BP
WCP; ExxonMobil ; Chevron; ConocoPhillips; and Ultramar
|
SFPP
|
|
FERC
Docket No. OR96-2, et
al.
|
All
Shippers except Chevron (which is an intervenor)
|
SFPP
|
|
FERC
Docket Nos. OR02-4 and OR03-5
|
Chevron
|
SFPP
|
|
FERC
Docket No. OR04-3
|
America
West Airlines; Southwest Airlines; Northwest Airlines; and Continental
Airlines
|
SFPP
|
|
FERC
Docket Nos. OR03-5, OR05-4 and OR05-5
|
BP
WCP; ExxonMobil; and ConocoPhillips (other shippers
intervened)
|
SFPP
|
|
FERC
Docket No. OR03-5-001
|
BP
WCP; ExxonMobil; and ConocoPhillips (other shippers
intervened)
|
SFPP
|
|
FERC
Docket No. OR07-1
|
Tesoro
|
SFPP
|
|
FERC
Docket No. OR07-2
|
Tesoro
|
SFPP
|
|
FERC
Docket No. OR07-3
|
BP
WCP; Chevron; ExxonMobil; Tesoro; and Valero Marketing
|
SFPP
|
|
FERC
Docket No. OR07-4
|
BP
WCP; Chevron; and ExxonMobil
|
SFPP;
Kinder Morgan G.P., Inc.; and Knight Inc.
|
|
FERC
Docket Nos. OR07-5 and OR07-7 (consolidated)
|
ExxonMobil
and Tesoro
|
Calnev;
Kinder Morgan G.P., Inc.; and Knight Inc.
|
|
FERC
Docket No. OR07-6
|
ConocoPhillips
|
SFPP
|
|
FERC
Docket Nos. OR07-8 and OR07-11 (consolidated)
|
BP
WCP and ExxonMobil
|
SFPP
|
|
FERC
Docket No. OR07-9
|
BP
WCP
|
SFPP
|
|
FERC
Docket No. OR07-14
|
BP
WCP and Chevron
|
SFPP;
Calnev; and several affiliates
|
|
FERC
Docket No. OR07-16
|
Tesoro
|
Calnev
|
|
FERC
Docket No. OR07-18
|
Airline
Complainants; Chevron; and Valero Marketing
|
Calnev
|
|
FERC
Docket No. OR07-19
|
ConocoPhillips
|
Calnev
|
|
FERC
Docket No. OR07-20
|
BP
WCP
|
SFPP
|
|
FERC
Docket No. OR07-22
|
BP
WCP
|
Calnev
|
|
FERC
Docket No. OR08-13
|
BP
WCP and ExxonMobil
|
SFPP
|
|
FERC
Docket No. OR08-15
|
BP
WCP and ExxonMobil
|
SFPP
|
|
FERC
Docket No. IS05-230 (North Line rate case)
|
Shippers
|
SFPP
|
|
FERC
Docket No. IS05-327
|
Shippers
|
SFPP
|
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FERC
Docket No. IS06-283 (East Line rate case)
|
Shippers
|
SFPP
|
|
FERC
Docket No. IS06-296
|
ExxonMobil
|
Calnev
|
|
FERC
Docket No. IS06-356
|
Shippers
|
SFPP
|
|
FERC
Docket No. IS07-137 (Ultra Low Sulfur Diesel (ULSD)
surcharge)
|
Shippers
|
SFPP
|
|
FERC
Docket No. IS07-229
|
BP
WCP and ExxonMobil
|
SFPP
|
|
FERC
Docket No. IS07-234
|
BP
WCP and ExxonMobil
|
Calnev
|
|
FERC
Docket No. IS08-28
|
ConocoPhillips;
Chevron; BP WCP; ExxonMobil ; Southwest Airlines; Western; and
Valero
|
SFPP
|
|
FERC
Docket No. IS08-302
|
Chevron;
BP WCP; ExxonMobil; and Tesoro
|
SFPP
|
|
FERC
Docket No. IS08-389
|
ConocoPhillips;
Valero; Southwest Airlines Co.; Navajo; and Western
|
SFPP
|
|
FERC
Docket No. IS08-390
|
BP
WCP; ExxonMobil; ConocoPhillips; Valero; Chevron; and the
Airlines
|
SFPP
|
|
Motions
to compel payment of interim damages (various dockets)
|
Shippers
|
SFPP;
Kinder Morgan G.P., Inc.; and Knight Inc.
|
|
Motion
for resolution on the merits (various dockets)
|
BP
WCP and ExxonMobil
|
SFPP
and Calnev.
|
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; ConocoPhillips Company as
ConocoPhillips; Ultramar Diamond Shamrock Corporation/Ultramar Inc. as Ultramar;
Valero Energy Corporation as Valero; Valero Marketing and Supply Company as
Valero Marketing; America West Airlines, Inc., Continental Airlines, Inc.,
Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc.,
collectively, as the Airline Complainants; and the Federal Energy Regulatory
Commission, as FERC.
The
tariffs and rates charged by SFPP and Calnev (Kinder Morgan Energy Partners
subsidiaries) are subject to numerous ongoing proceedings at the FERC, including
the above listed shippers’ complaints and protests regarding interstate rates on
these pipeline systems. These complaints have been filed over numerous years
beginning in 1992 through and including 2008. In general, these complaints
allege the rates and tariffs charged by SFPP and Calnev are not just and
reasonable. If the shippers are successful in proving their claims, they are
entitled to seek reparations (which may reach up to two years prior to the
filing of their complaint) or refunds of any excess rates paid, and SFPP and
Calnev may be required to reduce their rates going forward. These proceedings
tend to be protracted, with decisions of the FERC often appealed to the federal
courts.
As
to SFPP, the issues involved in these proceedings include, among others: (i)
whether certain of SFPP operations’ rates are “grandfathered” under the Energy
Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether
“substantially changed circumstances” have occurred with respect to any
grandfathered rates such that those rates could be challenged; (iii) whether
indexed rate increases are justified; and (iv) the appropriate level of return
and income tax allowance it may include in its rates. The issues involving
Calnev are similar.
In
May 2005, the FERC issued a statement of general policy stating it will permit
pipelines to include in cost of service a tax allowance to reflect actual or
potential tax liability on their public utility income attributable to all
partnership or limited liability company interests, if the ultimate owner of the
interest has an actual or potential income tax liability on such income. Whether
a pipeline’s owners have such actual or potential income tax liability will be
reviewed by the FERC on a case-by-case basis; consequently, the level of income
tax allowance to which SFPP will ultimately be entitled is not certain. In May
of 2007, the D.C. Court upheld the FERC’s tax allowance policy.
In
December 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it
to submit compliance filings and revised tariffs. In accordance with the FERC’s
December 2005 order and its February 2006 order on rehearing, SFPP submitted a
compliance filing to the FERC in March 2006, and rate reductions were
implemented on May 1, 2006. In addition, in December 2005, Kinder Morgan Energy
Partners recorded accruals of $105.0 million for expenses attributable to an
increase in its reserves related to its rate case liability.
In
December 2007, as a follow-up to a March 2006 SFPP compliance filing to FERC,
SFPP received a FERC order that directed Kinder Morgan Energy Partners to submit
revised compliance filings and revised tariffs. In conjunction with FERC’s
December 2007 order, Kinder Morgan Energy Partners’ other FERC and CPUC rate
cases, and other unrelated litigation matters, it increased its litigation
reserves by $140.0 million in the fourth quarter of 2007. And, in accordance
with FERC’s
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December
2007 order and its February 2008 order on rehearing, SFPP submitted a compliance
filing to FERC in February 2008, and further rate reductions were implemented on
March 1, 2008.
During
2008, SFPP and Calnev made combined settlement payments to various shippers
totaling approximately $30 million. In October 2008 in connection with
OR92-8-025, IS6-283 and OR07-5, SFPP entered into a settlement resolving
disputes regarding its East Line rates filed in Docket No. IS08-28 and related
dockets. In January 2009, the FERC approved the settlement. Upon the finality of
FERC’s approval, reduced settlement rates are expected to go into effect on May
1, 2009, and SFPP will make refunds and settlement payments shortly thereafter
estimated to total approximately $16.0 million.
Based
on our review of these FERC proceedings, we estimate that as of December 31,
2008, shippers are seeking approximately $355 million in reparation and refund
payments and approximately $30 to $35 million in additional annual rate
reductions. We assume that, with respect to our SFPP litigation reserves, any
reparations and accrued interest thereon will be paid no earlier than the second
quarter of 2009.
California
Public Utilities Commission Proceedings
On
April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the
California Public Utilities Commission, referred to in this note as the CPUC.
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 and refunds with respect to
previously untariffed charges for certain pipeline transportation and related
services.
In
October 2002, the CPUC issued a resolution, referred to in this note as the
Power Surcharge Resolution, approving a 2001 request by SFPP to raise its
California rates to reflect increased power costs. 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
December 26, 2006, Tesoro filed a complaint challenging the reasonableness of
SFPP’s intrastate rates for the three-year period from December 2003 through
December 2006 and requesting approximately $8 million in reparations. As a
result of previous SFPP rate filings and related protests, the rates that are
the subject of the Tesoro complaint are being collected subject to
refund.
SFPP
also has various, pending ratemaking matters before the CPUC that are unrelated
to the above-referenced complaints and the Power Surcharge Resolution. Protests
to these rate increase applications have been filed by various shippers. As a
consequence of the protests, the related rate increases are being collected
subject to refund.
All
of the above matters have been consolidated and assigned to a single
administrative law judge. At the time of this report, it is unknown when a
decision from the CPUC regarding the CPUC complaints and the Power Surcharge
Resolution will be received. No schedule has been established for hearing and
resolution of the consolidated proceedings other than the 1997 CPUC complaint
and the Power Surcharge Resolution. Based on our review of these CPUC
proceedings, we estimate that shippers are seeking approximately $100 million in
reparation and refund payments and approximately $35 million in annual rate
reductions.
On
June 6, 2008, as required by CPUC order, SFPP and Calnev Pipe Line Company filed
separate general rate case applications, neither of which request a change in
existing pipeline rates and both of which assert that existing pipeline rates
are reasonable. On September 26, 2008, SFPP filed an amendment to its general
rate case application, requesting CPUC approval of a $5 million rate increase
for intrastate transportation services that became effective November 1, 2008.
Protests to the amended rate increase application have been
filed by various shippers and, as a consequence, the related rate increase is
being collected subject to refund. The CPUC has issued a ruling suspending
further activity with respect to the SFPP and Calnev Pipe Line Company general
rate case applications, pending CPUC resolution of the 1997 CPUC complaint and
Power Surcharge proceedings. Consequently, no action has been taken by the CPUC
with respect to either the SFPP amended general rate case filing or the Calnev
general rate case filing.
Carbon
Dioxide Litigation
Gerald
O. Bailey et al. v. Shell Oil Co. et al/Southern District of Texas
Lawsuit
Kinder
Morgan CO2 Company,
L.P. (referred to in this note as Kinder Morgan CO2), Kinder
Morgan Energy Partners, L.P. and Cortez Pipeline Company are among the
defendants in a proceeding in the federal courts for the southern district of
Texas. Gerald O. Bailey et al.
v. Shell Oil Company et al., (Civil Action Nos. 05-1029 and 05-1829 in
the U.S. District Court for the Southern District of Texas—consolidated by Order
dated July 18, 2005). The plaintiffs are asserting claims for the underpayment
of royalties on carbon dioxide produced from the McElmo Dome Unit. The
plaintiffs 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.
Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray & Co. have also
asserted claims
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as
private relators under the False Claims Act and for violation of federal and
Colorado antitrust laws. The plaintiffs seek actual damages, treble damages,
punitive damages, a constructive trust and accounting, and declaratory relief.
The defendants filed motions for summary judgment on all claims.
Effective
March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia
Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed a final
settlement agreement which provides for the dismissal of these plaintiffs’
claims with prejudice to being refiled. On June 10, 2007, the Houston federal
district court entered an order of partial dismissal by which the claims by and
against the settling plaintiffs were dismissed with prejudice. The claims
asserted by Bailey, Ptasynski, and Gray are not included within the settlement
or the order of partial dismissal. Effective April 8, 2008, the Shell and Kinder
Morgan defendants and plaintiff Gray entered into an indemnification agreement
that provides for the dismissal of Gray’s claims with prejudice.
On
April 22, 2008, the federal district court granted defendants’ motions for
summary judgment and ruled that plaintiffs Bailey, Ptasynski, and Gray take
nothing on their claims. The court entered final judgment in favor of defendants
on April 30, 2008. Defendants have filed a motion seeking sanctions against
plaintiff Bailey. The plaintiffs have appealed the final judgment to the United
States Fifth Circuit Court of Appeals. In October 2008, plaintiffs filed their
brief in the Fifth Circuit Court of Appeals. Defendants filed their brief in the
Fifth Circuit in December 2008.
CO2 Claims
Arbitration
Cortez
Pipeline Company and Kinder Morgan CO2, 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. The settlement imposed certain future obligations on the defendants in the
underlying litigation. 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. On August 7, 2006, the arbitration panel issued its
opinion finding that defendants did not breach the settlement agreement. On June
21, 2007, the New Mexico federal district court entered final judgment
confirming the August 7, 2006 arbitration decision.
On
October 2, 2007, the plaintiff initiated a second arbitration (CO2 Committee,
Inc. v. Shell CO2 Company,
Ltd., aka Kinder Morgan CO2 Company,
L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and an
ExxonMobil entity. The second arbitration asserts claims similar to those
asserted in the first arbitration. On June 3, 2008, the plaintiff filed a
request with the American Arbitration Association seeking administration of the
arbitration. In October 2008, the New Mexico federal district court entered an
order declaring that the panel in the first arbitration should decide whether
the claims in the second arbitration are barred by res judicata. The plaintiff
filed a motion for reconsideration of that order, which was denied by the New
Mexico federal district court in January 2009. Plaintiff has appealed to the
Tenth Circuit Court of Appeals and continues to seek administration of the
second arbitration by the American Arbitration Association.
MMS
Notice of Noncompliance and Civil Penalty
On
December 20, 2006, Kinder Morgan CO2 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, referred to in this note as the MMS. This Notice, and the
MMS’s position that Kinder Morgan CO2 has
violated certain reporting obligations, relates to a disagreement between the
MMS and Kinder Morgan CO2 concerning
the approved transportation allowance to be used in valuing McElmo Dome carbon
dioxide for purposes of calculating federal royalties. 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 17 alleged violations) for Kinder Morgan CO2’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
stated that civil penalties will continue to accrue at the same rate until the
alleged violations are corrected.
The parties have reached a
settlement of the Notice of Noncompliance and Civil Penalty. The settlement
agreement is subject to final MMS approval and upon approval will be
funded from existing reserves and indemnity payments by Shell CO2 General
LLC and Shell CO2 LLC
pursuant to a royalty claim indemnification agreement.
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MMS
Order to Report and Pay
On
March 20, 2007, Kinder Morgan CO2 received
an “Order to Report and Pay” from the MMS. The MMS contends that Kinder Morgan
CO2
has over-reported transportation allowances and underpaid royalties in the
amount of approximately $4.6 million for the period from January 1, 2005 through
December 31, 2006 as a result of its use of the Cortez Pipeline tariff as the
transportation allowance in calculating federal royalties. The MMS claims that
the Cortez Pipeline Company tariff is not the proper transportation allowance
and that Kinder Morgan CO2 must use
its “reasonable actual costs” calculated in accordance with certain federal
product valuation regulations. The MMS set a due date of April 13, 2007 for
Kinder Morgan CO2’s payment
of the $4.6 million in claimed additional royalties, with possible late payment
charges and civil penalties for failure to pay the assessed amount. Kinder
Morgan CO2 has not
paid the $4.6 million, and on April 19, 2007, it submitted a notice of appeal
and statement of reasons in response to the Order to Report and Pay, challenging
the Order and appealing it to the Director of the MMS in accordance with 30
C.F.R. Sec. 290.100, et seq.
In
addition to the March 2007 Order to Report and Pay, in April 2007, Kinder Morgan
CO2
received an “Audit Issue Letter” sent by the Colorado Department of Revenue on
behalf of the U.S. Department of the Interior. In the letter, the Department of
Revenue states that Kinder Morgan CO2 has
over-reported transportation allowances and underpaid royalties (due to the use
of the Cortez Pipeline Company tariff as the transportation allowance for
purposes of federal royalties) in the amount of $8.5 million for the period from
April 2000 through December 2004.
The
MMS and Kinder Morgan CO2 reached a
settlement of the March 2007 and August 2007 Orders to Report and Pay. The
settlement agreement is subject to final MMS approval. The settlement is subject
to final MMS approval and upon approval will be funded from existing reserves
and indemnity payments from Shell CO2 General
LLC and Shell CO2 LLC
pursuant to a royalty claim indemnification agreement.
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 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 during 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 case was tried
in the trial court in September 2008. The plaintiffs sought $6.8 million
in actual damages as well as punitive damages. The jury returned a verdict
finding that Kinder Morgan did not breach the settlement agreement and did not
breach the claimed duty to market carbon dioxide. The jury also found that
Kinder Morgan breached a duty of good faith and fair dealing and found
compensatory damages of $0.3 million and punitive damages of $1.2 million. On
October 16, 2008, the trial court entered judgment on the verdict.
On
January 6, 2009, the district court entered orders vacating the judgment and
granting a new trial in the case, which is scheduled a new trial to occur
beginning on October 19, 2009.
In
addition to the matters listed above, audits and administrative inquiries
concerning Kinder Morgan CO2’s payments
on carbon dioxide produced from the McElmo Dome and Bravo Dome Units are
currently ongoing. These audits and inquiries involve federal agencies and the
States of Colorado and New Mexico.
Commercial
Litigation Matters
Union Pacific Railroad Company
Easements
SFPP
and Union Pacific Railroad Company (the successor to Southern Pacific
Transportation Company and referred to in this note as UPRR) are engaged in a
proceeding to determine the extent, if any, to which the rent payable by SFPP
for the use of pipeline easements on rights-of-way held by UPRR should be
adjusted pursuant to existing contractual arrangements for the ten-year period
beginning January 1, 2004 (Union Pacific Railroad Company vs.
Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”,
Kinder Morgan G.P., Inc., et al., Superior Court of the State of
California for the County of Los Angeles, filed July 28, 2004). In February
2007, a trial began to determine the amount payable for easements on UPRR
rights-of-way. The trial is ongoing and is expected to conclude in the second
quarter of 2009.
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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. In July 2006, a
trial before a judge regarding the circumstances under which SFPP must pay for
relocations concluded, and the judge determined that SFPP must pay for any
relocations resulting from any legitimate business purpose of the UPRR. SFPP has
appealed this decision and in December 2008, the appellate court affirmed the
decision. 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.
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
multi-district litigation proceeding involves four lawsuits filed in 1997
against numerous Kinder Morgan companies. These suits were filed pursuant to the
federal False Claims Act and allege underpayment of royalties due to
mismeasurement of natural gas produced from federal and Indian lands. The
complaints are part of a larger series of similar complaints filed by Mr.
Grynberg against 77 natural gas pipelines (approximately 330 other defendants)
in various courts throughout the country that were consolidated and transferred
to the District of Wyoming.
In
May 2005, a Special Master appointed in this litigation found that because there
was a prior public disclosure of the allegations and that Grynberg was not an
original source, the Court lacked subject matter jurisdiction. As a result, the
Special Master recommended that the Court dismiss all the Kinder Morgan
defendants. In October 2006, the United States District Court for the District
of Wyoming upheld the dismissal of each case against the Kinder Morgan
defendants on jurisdictional grounds. Grynberg has appealed this Order to the
Tenth Circuit Court of Appeals. Briefing was completed and oral argument was
held on September 25, 2008. No decision has yet been issued.
Prior
to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants
filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his
Complaint without evidentiary support and for an improper purpose. On January 8,
2007, after the dismissal order, the Kinder Morgan defendants also filed a
Motion for Attorney Fees under the False Claim Act. On April 24, 2007, the Court
held a hearing on the Motions to Dismiss and for Sanctions and the Requests for
Attorney Fees. A decision is still pending on the Motions to Dismiss and for
Sanctions and the Requests for Attorney Fees.
Leukemia
Cluster Litigation
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”).
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
May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a
civil action in the Nevada State trial court against Kinder Morgan Energy
Partners and several Kinder Morgan related entities and individuals and
additional unrelated defendants. Plaintiffs in the Jernee matter claim that
defendants negligently and intentionally failed to inspect, repair and replace
unidentified segments of their pipeline and facilities, allowing “harmful
substances and emissions and gases” to damage “the environment and health of
human beings.” Plaintiffs claim that “Adam Jernee’s death was caused by leukemia
that, in turn, is believed to be due to exposure to industrial chemicals and
toxins.” Plaintiffs purport to assert claims for wrongful death, premises
liability, negligence, negligence per se, intentional infliction of emotional
distress, negligent infliction of emotional distress, assault and battery,
nuisance, fraud, strict liability (ultra hazardous acts), and aiding and
abetting, and seek unspecified special, general and punitive damages. 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 the same
defendants and alleging the same claims as in the Jernee case with respect to
Stephanie Suzanne Sands. The Jernee case has been consolidated for pretrial
purposes with the Sands case. In May 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 portions of the complaint. 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.
Plaintiff has also filed a motion to dismiss the United States and/or to remand
the case back to state court. By order dated September 25, 2007, the United
States District Court granted the motion to dismiss the United States from the
case and remanded the Jernee and Sands cases back to the
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Second
Judicial District Court, State of Nevada, County of Washoe. The cases will now
proceed in the State Court. 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 remaining claims against
Kinder Morgan Energy Partners in these matters are without merit and intend to
defend against them vigorously.
Pipeline
Integrity and Releases
From
time to time, our pipelines experience leaks and ruptures. These leaks and
ruptures may cause explosions, fire, damage to the environment, damage to
property and/or personal injury or death. In connection with these incidents, we
may be sued for damages caused by an alleged failure to properly mark the
locations of our pipelines and/or to properly maintain our pipelines. Depending
upon the facts and circumstances of a particular incident, state and federal
regulatory authorities may seek civil and/or criminal fines and
penalties.
Pasadena
Terminal Fire
On
September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena,
Texas terminal facility. One of our employees was injured and subsequently died.
In addition, the pit 3 manifold was severely damaged. The cause of the incident
is currently under investigation by the Railroad Commission of Texas and the
United States Occupational Safety and Health Administration. The remainder of
the facility returned to normal operations within twenty-four hours of the
incident.
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, struck and ruptured an underground petroleum
pipeline owned and operated by SFPP 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, Inc. Following
court ordered mediation, we have settled with plaintiffs in all of the wrongful
death cases and the personal injury and property damages cases. On January 12,
2009, the Contra Costa Superior Court granted summary judgment in favor of
Kinder Morgan G.P. Services Co., Inc. in the last remaining civil suit – a claim
for indemnity brought by co-defendant Camp, Dresser & McKee, Inc. The only
remaining pending matter is our appeal of a civil fine of $140,000 issued by the
California Division of Occupational Safety and Health.
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 note as REX), struck an existing subsurface natural gas
pipeline owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline
Group. The 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
was investigated by the U.S. Department of Transportation Pipeline and Hazardous
Materials Safety Administration, referred to in this report as the PHMSA. In
March 2008, the PHMSA issued a Notice of Probable Violation, Proposed Civil
Penalty and Proposed Compliance Order (“NOPV”) to El Paso Corporation in which
it concluded that El Paso failed to comply with federal law and its internal
policies and procedures regarding protection of its pipeline, resulting in this
incident. To date, the PHMSA has not issued any NOPV’s to REX, and we do not
expect that it will do so. 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.
In
September 2007, the family of the deceased bulldozer operator filed a wrongful
death action against Kinder Morgan Energy Partners, REX and several other
parties in the District Court of Harris County, Texas, 189th
Judicial District, at case number 2007-57916. The plaintiffs seek unspecified
compensatory and exemplary damages plus interest, attorney’s fees and costs of
suit. Kinder Morgan Energy Partners has asserted contractual claims for complete
indemnification for any and all costs arising from this incident, including any
costs related to this lawsuit, against third parties and their insurers. On
March 25, 2008, the defendants entered into a settlement agreement with one of
the plaintiffs, the decedent’s daughter, resolving any and all of her claims
against Kinder Morgan Energy Partners, REX and its contractors. Kinder Morgan
Energy Partners was indemnified for the full amount of this settlement by one of
REX’s contractors. On October 17, 2008, the remaining plaintiffs
filed a Notice of Nonsuit, which dismissed the remaining claims against all
defendants without prejudice to the plaintiffs’ ability to re-file their claims
at a later date. The remaining plaintiffs re-filed their Complaint against REX,
Kinder Morgan Energy Partners and several other parties on November 7, 2008,
Cause No. 2008-66788, currently pending in the District Court of Harris County,
Texas, 189th
Judicial District. The parties are currently engaged in discovery.
Charlotte,
North Carolina
On
November 27, 2006, the Plantation Pipeline experienced a release of
approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company
block valve on a delivery line into a terminal owned by a third party company.
The line was
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repaired
and put back into service within a few days. Remediation efforts are continuing
under the direction of the North Carolina Department of Environment and Natural
Resources (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.
Although
Plantation does not believe that penalties are warranted, it has engaged in
settlement discussions with the EPA regarding a potential civil penalty for the
November 2006 release as part of broader settlement negotiations with the EPA
regarding this spill and three other historic releases from Plantation,
including a February 2003 release near Hull, Georgia. Plantation has entered
into a consent decree with the Department of Justice and the EPA for all four
releases for approximately $0.7 million, plus some additional work to be
performed to prevent future releases. The proposed consent decree was filed in
U.S. District Court and is awaiting entry by the court.
In
addition, in April 2007, during pipeline maintenance activities near Charlotte,
North Carolina, Plantation discovered the presence of historical soil
contamination near the pipeline, and reported the presence of impacted soils to
the NCDENR. Subsequently, Plantation contacted the owner of the property to
request access to the property to investigate the potential contamination. The
results of that investigation indicate that there is soil and groundwater
contamination, which appears to be from an historical turbine fuel release.
The groundwater contamination is underneath at least two lots on which there is
current construction of single-family homes as part of a new residential
development. Further investigation and remediation are being conducted under the
oversight of the NCDENR. Plantation reached a settlement with the builder of the
residential subdivision. Plantation continues to negotiate with the owner of the
property to address any potential claims that it may bring.
Barstow,
California
The
United States Department of Navy has alleged that historic releases of methyl
tertiary-butyl ether, referred to in this report as MTBE, from Calnev’s Barstow
terminal has (i) migrated underneath the Navy’s Marine Corps Logistics Base (the
“MCLB”) in Barstow, (ii) impacted the Navy’s existing groundwater treatment
system for unrelated groundwater contamination not alleged to have been caused
by Calnev, and (iii) affected the MCLB’s water supply system. Although
Calnev believes that it has certain meritorious defenses to the Navy’s
claims, it is working with the Navy to agree upon an Administrative Settlement
Agreement and Order on Consent for CERCLA Removal Action to reimburse the Navy
for $0.5 million in past response actions, plus perform other work to ensure
protection of the Navy’s existing treatment system and water
supply.
Oil
Spill Near Westridge Terminal, Burnaby, British Columbia
On
July 24, 2007, a third-party contractor installing a sewer line for the City of
Burnaby struck a crude oil pipeline segment included within Kinder Morgan Energy
Partners’ Trans Mountain pipeline system near its Westridge terminal in Burnaby,
BC, resulting in a release of approximately 1,400 barrels of crude oil. The
release impacted the surrounding neighborhood, several homes and nearby Burrard
Inlet. No injuries were reported. To address the release, Kinder Morgan Energy
Partners initiated a comprehensive emergency response in collaboration with,
among others, the City of Burnaby, the BC Ministry of Environment, the National
Energy Board, and the National Transportation Safety Board. Cleanup and
environmental remediation is near completion. The incident is currently under
investigation by Federal and Provincial agencies. We do not expect this matter
to have a material adverse impact on our financial position, results of
operations or cash flows.
On
December 20, 2007, Kinder Morgan Energy Partners initiated a lawsuit entitled
Trans Mountain Pipeline LP,
Trans Mountain Pipeline Inc. and Kinder Morgan Canada Inc. v. The City of
Burnaby, et al., Supreme Court of British Columbia, Vancouver Registry
No. S078716. The suit alleges that the City of Burnaby and its agents are liable
for damages including, but not limited to, all costs and expenses incurred by
Kinder Morgan Energy Partners as a result of the rupture of the pipeline and
subsequent release of crude oil. Defendants have denied liability and discovery
has begun.
Litigation
Relating to the “Going Private” Transaction
Beginning
on May 29, 2006, the day after the proposal for the Going Private transaction
was announced, and in the days following, eight putative Class Action lawsuits
were filed in Harris County (Houston), Texas and seven putative Class Action
lawsuits were filed in Shawnee County (Topeka), Kansas against, among others,
Kinder Morgan, Inc., its Board of Directors, the Special Committee of the Board
of Directors, and several corporate officers.
By
order of the Harris County District Court dated June 26, 2006, each of the eight
Harris County cases were consolidated into the Crescente v. Kinder Morgan, Inc. et
al case, Cause No. 2006-33011, in the 164th
Judicial District Court, Harris County, Texas, which challenges the proposed
transaction as inadequate and unfair to Kinder Morgan, Inc.’s public
stockholders. On September 8, 2006, interim class counsel filed their
Consolidated Petition for Breach of Fiduciary Duty and Aiding and Abetting in
which they alleged that Kinder Morgan, Inc.’s board of directors and certain
members of senior management breached their fiduciary duties and the Sponsor
Investors aided and abetted the alleged breaches of fiduciary duty in entering
into the merger agreement. They sought, among other things, to enjoin the
merger, rescission of the merger agreement, disgorgement of any improper profits
received by the defendants, and attorneys’ fees. Defendants filed Answers
to
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the
Consolidated Petition on October 9, 2006, denying the plaintiffs’ substantive
allegations and denying that the plaintiffs are entitled to relief.
By
order of the District Court of Shawnee County, Kansas dated June 26, 2006, each
of the seven Kansas cases were consolidated into the Consol. Case No. 06 C 801;
In Re Kinder Morgan, Inc.
Shareholder Litigation; in the District Court of Shawnee County, Kansas,
Division 12. On August 28, 2006, the plaintiffs filed their Consolidated
and Amended Class Action Petition in which they alleged that Kinder Morgan’s
board of directors and certain members of senior management breached their
fiduciary duties and the Sponsor Investors aided and abetted the alleged
breaches of fiduciary duty in entering into the merger agreement. They sought,
among other things, to enjoin the stockholder vote on the merger agreement and
any action taken to effect the acquisition of Kinder Morgan and its assets by
the buyout group, damages, disgorgement of any improper profits received by the
defendants, and attorney’s fees.
In
late 2006, the Kansas and Texas Courts appointed the Honorable Joseph T. Walsh
to serve as Special Master in both consolidated cases “to control all of the
pretrial proceedings in both the Kansas and Texas Class Actions arising out of
the proposed private offer to purchase the stock of the public shareholders of
Kinder Morgan, Inc.” On November 21, 2006, the plaintiffs in In Re Kinder Morgan, Inc.
Shareholder Litigation filed a Third Amended Class Action Petition with
Special Master Walsh. This Petition was later filed under seal with the Kansas
District Court on December 27, 2006.
Following
extensive expedited discovery, the Plaintiffs in both consolidated actions filed
an application for a preliminary injunction to prevent the holding of a special
meeting of shareholders for the purposes of voting on the proposed merger, which
was scheduled for December 19, 2006.
On
December 18, 2006, Special Master Walsh issued a Report and Recommendation
concluding, among other things, that “plaintiffs have failed to demonstrate the
probability of ultimate success on the merits of their claims in this joint
litigation.” Accordingly, the Special Master concluded that the plaintiffs were
“not entitled to injunctive relief to prevent the holding of the special meeting
of KMI shareholders scheduled for December 19, 2006.”
Plaintiffs
moved for class certification in January, 2008. Defendants opposed this motion,
which is currently pending.
On January 9, 2009,
Special Master Walsh issued a Report recommending that the class should be
comprised of all holders of Kinder Morgan, Inc. common stock, during the
period August 28, 2006 (the date the merger agreement was signed) through May
30, 2007 (the date the merger closed) and their transferees, successors and
assigns. Excluded from the Class are defendants and any person, firm, trust,
corporation or other entity related to or affiliated with any defendant. Special
Master Walsh also recommended that Dr. Geiger and Mr. Wilson, but not Mr. Land,
be appointed as Class Representatives. The Special Master’s recommendation is
currently pending before the Kansas trial court.
In
August, September and October, 2008, the Plaintiffs in both consolidated cases
voluntarily dismissed without prejudice the claims against those Kinder Morgan,
Inc.’s directors who did not participate in the buyout (including the dismissal
of the members of the special committee of the board of directors), Kinder
Morgan, Inc. and Knight Acquisition, Inc. In addition, on November 19, 2008, by
agreement of the parties, the Texas trial court issued an order staying all
proceedings in the Texas actions until such time as a final judgment shall be
issued in the Kansas actions. The effect of this stay is that the consolidated
matters will proceed only in the Kansas trial court.
The
parties are currently engaged in consolidated discovery in these
matters.
On
August 24, 2006, a civil action entitled City of Inkster Policeman and
Fireman Retirement System, Derivatively on Behalf of Kinder Morgan, Inc.,
Plaintiffs v. Richard D. Kinder, Michael C. Morgan, William v. Morgan, Fayez
Sarofim, Edward H. Austin, Jr., William J. Hybl, Ted A. Gardner, Charles W.
Battey, H.A. True, III, James M. Stanford, Stewart A. Bliss, Edward Randall,
III, Douglas W.G. Whitehead, Goldman Sachs Capital Partners, American
International Group, Inc., The Carlyle Group, Riverstone Holdings LLC, C. Park
Shaper, Steven J. Kean, Scott E. Parker and R. Tim Bradley, Defendants and
Kinder Morgan, Inc., Nominal Defendant; Case 2006-52653, was filed in the
270th
Judicial District Court, Harris County, Texas. This putative derivative lawsuit
was brought against certain of Kinder Morgan, Inc.’s senior officers and
directors, alleging that the proposal constituted a breach of fiduciary duties
owed to Kinder Morgan, Inc. Plaintiff also contends that the Sponsor Investors
aided and abetted the alleged breaches of fiduciary duty. Plaintiff seeks, among
other things, to enjoin the defendants from consummating the proposal, a
declaration that the proposal is unlawful and unenforceable, the imposition of a
constructive trust upon any benefits improperly received by the defendants, and
attorney’s fees. In November 2007, defendants filed a Joint Motion to
Dismiss for Lack of Jurisdiction, or in the Alternative, Motion for Final
Summary Judgment. Plaintiffs opposed the motion. In February 2008, the court
entered a Final Order granting defendants’ motion in full, ordering that
plaintiff, the City of Inkster Policeman and Fireman Retirement System, take
nothing on any and all of its claims against any and all defendants. In April
2008, Plaintiffs filed an appeal of the judgment in favor of all defendants in
the Texas Court of Appeal, First District. The appeal is currently
pending.
Defendants
believe that the claims asserted in the litigations regarding the Going Private
transaction are legally and factually without merit and intend to vigorously
defend against them.
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Litigation
Reserves
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.
Additionally,
although it is not possible to predict the ultimate outcomes, we believe, based
on our experiences to date, that the ultimate resolution of these matters will
not have a material adverse impact on our business, financial position, results
of operations or cash flows. As of December 31, 2008 and December 31, 2007, we
have recorded a total reserve for legal fees, transportation rate cases and
other litigation liabilities in the amount of $234.8 million and $249.4 million,
respectively. The reserve is primarily related to various claims from lawsuits
related to SFPP and the contingent amount is based on both probability of
realization and our ability to reasonably estimate liability dollar amounts. We
regularly assess the likelihood of adverse outcomes resulting from these claims
in order to determine the adequacy of our liability provision.
Environmental
Matters
ExxonMobil
Corporation v. GATX Terminals Corporation, Kinder Morgan Liquids Terminals LLC
and Support Terminals Services, Inc.
On
April 23, 2003, Exxon Mobil Corporation (“ExxonMobil”) filed a complaint in the
Superior Court of New Jersey, Gloucester County. 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 Corporation (“GATX”). from 1989 through September 2000, later owned by
Support Terminals Services, Inc. (“Support Terminals”). The terminal is now
owned by Pacific Atlantic Terminals, LLC, (PAT) and it too is a party to the
lawsuit.
The
complaint seeks any and all damages related to remediating all environmental
contamination 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. The parties are
currently involved in mandatory mediation and met in June and October 2008. No
progress was made at any of the mediations. The mediation judge will now refer
the case back to the litigation court room.
On
June 25, 2007, the New Jersey Department of Environmental Protection, the
Commissioner of the New Jersey Department of Environmental Protection and the
Administrator of the New Jersey Spill Compensation Fund, referred to
collectively as the plaintiffs, filed a complaint against ExxonMobil and Kinder
Morgan Liquids Terminals LLC, f/k/a GATX. The complaint was filed in Gloucester
County, New Jersey. Both ExxonMobil and Kinder Morgan Liquids Terminals LLC
filed third party complaints against Support Terminals seeking to bring Support
Terminals into the case. Support Terminals filed motions to dismiss the third
party complaints, which were denied. Support Terminals is now joined in the case
and it filed an Answer denying all claims.
The
plaintiffs seek the costs and damages that the plaintiffs allegedly have
incurred or will incur as a result of the discharge of pollutants and hazardous
substances at the Paulsboro, New Jersey facility. The costs and damages
that the plaintiffs seek include cleanup costs and damages to natural resources.
In addition, the plaintiffs seek an order compelling the defendants to perform
or fund the assessment and restoration of those natural resource
damages that are the result of the defendants’ actions. As in the case
brought by ExxonMobil against GATX, the issue is whether the plaintiffs’ claims
are within the scope of the indemnity obligations between GATX (and
therefore, Kinder Morgan Liquids Terminals LLC) and Support Terminals. The court
may consolidate the two cases.
Mission
Valley Terminal Lawsuit
In
August 2007, the City of San Diego, on its own behalf and purporting to act
on behalf of the People of the state of California, filed a lawsuit against
Kinder Morgan Energy Partners and several affiliates seeking injunctive relief
and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted
soils and groundwater beneath the city’s stadium property in San Diego arising
from historic operations at the Mission Valley terminal facility. The case was
filed in the Superior Court of California, San Diego County, case number
37-2007-00073033-CU-OR-CTL. On September 26, 2007, Kinder Morgan Energy Partners
removed the case to the United States District Court, Southern District of
California, case number 07CV1883WCAB. On October 3, 2007, Kinder Morgan Energy
Partners filed a Motion to Dismiss all counts of the Complaint. The court denied
in part and granted in part the Motion to Dismiss and gave the City leave to
amend their complaint. The City submitted its Amended Complaint and we filed an
Answer. The parties have commenced with discovery. This site has been, and
currently is, under the regulatory oversight and order of the California
Regional Water Quality Control Board.
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|
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Form 10-K
|
In
June 2008, we received an Administrative Civil Liability Complaint from the
California Regional Water Quality Control Board for violations and penalties
associated with permitted surface water discharge from the remediation system
operating at the Mission Valley terminal facility. In December 2008, we settled
the Administrative Civil Liability Complaint with the RWQCB, paying a civil
penalty of $0.2 million.
State
of Texas v. Kinder Morgan Petcoke, L.P.
Harris
County, Texas Criminal Court No. 11, Cause No. 1571148. On February 24, 2009 a
subsidiary of Kinder Morgan Energy Partners, Kinder Morgan Petcoke, L.P., was
served with a misdemeanor summons alleging the unintentional discharge of
petcoke into the Houston Ship Channel during maintenance activities. The maximum
potential fine for the alleged violation is $0.2 million. The allegations in the
summons are currently under investigation.
Other
Environmental
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.
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 Releases,”
above for additional information with respect to ruptures and leaks from our
pipelines.
General
Although
it is not possible to predict the ultimate outcomes, we believe that the
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 and changing circumstances
could cause these matters to have a material adverse impact. As of December 31,
2008 and December 31, 2007, we have accrued an environmental reserve of $85.0 million and $102.6
million, respectively, and we believe the establishment of this environmental
reserve is adequate such that the resolution of pending environmental matters
will not have a material adverse impact on our business, cash flows, financial
position or results of operation. Additionally, many factors may change in the
future affecting our reserve estimates, such as (i) regulatory changes, (ii)
groundwater and land use near our sites, and (iii) changes in cleanup
technology. Associated with the environmental reserve, we have recorded a
receivable of $20.9 million as of both December 31, 2008 and December 31, 2007
for expected cost recoveries that have been deemed probable.
22.
Recent Accounting Pronouncements
SFAS
No. 157 and associated pronouncements
For
information on SFAS No. 157 and associated pronouncements, see Note 15 under the
heading “SFAS No. 157.”
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 liabilities at fair value.
The
175
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Financial
Statements and Supplementary Data. (continued)
|
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Form 10-K
|
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 in Note 15, “SFAS No. 157,” and
SFAS No. 107 Disclosures about
Fair Value of Financial Instruments.
This
Statement was adopted by us effective January 1, 2008, at which time no
financial assets or liabilities, not previously required to be recorded at fair
value by other authoritative literature, were designated to be recorded at fair
value. As such, the adoption of this Statement did not have any impact on our
consolidated financial statements.
SFAS
No. 141(R)
On
December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), Business Combinations.
Although this Statement amends and replaces SFAS No. 141, it retains the
fundamental requirements in SFAS No. 141 that (i) the purchase method of
accounting be used for all business combinations and (ii) an acquirer be
identified for each business combination. SFAS No. 141R defines the acquirer as
the entity that obtains control of one or more businesses in the business
combination and establishes the acquisition date as the date that the acquirer
achieves control. This Statement applies to all transactions or other events in
which an entity (the acquirer) obtains control of one or more businesses (the
acquiree), including combinations achieved without the transfer of
consideration; however, this Statement does not apply to a combination between
entities or businesses under common control.
Significant
provisions of SFAS No. 141R concern principles and requirements for how an
acquirer (i) recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, and any noncontrolling
interest in the acquiree, (ii) recognizes and measures the goodwill acquired in
the business combination or a gain from a bargain purchase and (iii) determines
what information to disclose to enable users of the financial statements to
evaluate the nature and financial effects of the business
combination.
This
Statement applies prospectively to business combinations for which the
acquisition date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008 (January 1, 2009 for us). The
adoption of this Statement did not have any impact on our consolidated financial
statements.
SFAS
No. 160
On
December 4, 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements – an amendment of ARB No. 51. This
Statement changes the accounting and reporting for noncontrolling interests in
consolidated financial statements. A noncontrolling interest, sometimes referred
to as a minority interest, is the portion of equity in a subsidiary not
attributable, directly or indirectly, to a parent.
Specifically,
SFAS No. 160 establishes accounting and reporting standards that require (i) the
ownership interests in subsidiaries held by parties other than the parent to be
clearly identified, labeled, and presented in the consolidated balance sheet
within equity, but separate from the parent’s equity, (ii) the equity amount of
consolidated net income attributable to the parent and to the noncontrolling
interest to be clearly identified and presented on the face of the consolidated
income statement (consolidated net income and comprehensive income will be
determined without deducting minority interest, however, earnings-per-share
information will continue to be calculated on the basis of the net income
attributable to the parent’s shareholders); and (iii) changes in a parent’s
ownership interest while the parent retains its controlling financial interest
in its subsidiary to be accounted for consistently and similarly—as equity
transactions.
This
Statement is effective for fiscal years, and interim periods within those fiscal
years, beginning on or after December 15, 2008 (January 1, 2009 for us). SFAS
No. 160 is to be applied prospectively as of the beginning of the fiscal year in
which it is initially applied, except for its presentation and disclosure
requirements, which are to be applied retrospectively for all periods presented.
The adoption of this Statement did not have a material impact on our
consolidated financial statements, but it did change our consolidated financial
statements’ presentation and disclosures of noncontrolling
interests.
SFAS
No. 161
On
March 19, 2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities. This Statement amends SFAS No. 133,
Accounting for Derivative
Instruments and Hedging Activities and is intended to help investors
better understand how derivative instruments and hedging activities affect an
entity’s financial position, financial
176
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Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
performance
and cash flows through enhanced disclosure requirements. The enhanced
disclosures include, among other things, (i) a tabular summary of the fair value
of derivative instruments and their gains and losses, (ii) disclosure of
derivative features that are credit-risk–related to provide more information
regarding an entity’s liquidity and (iii) cross-referencing within footnotes to
make it easier for financial statement users to locate important information
about derivative instruments.
This
Statement is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008 (January 1, 2009 for us). This
Statement expands and enhances disclosure requirements only, and as such, the
adoption of this Statement did not have any impact on our consolidated financial
statements.
FSP
No. FAS 142-3
On
April 25, 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 142-3, Determination of the Useful Life of
Intangible Assets. This FSP amends the factors that should be considered
in developing renewal or extension assumptions used to determine the useful life
of a recognized intangible asset under SFAS No.
142, Goodwill and Other Intangible
Assets. This FSP is effective for financial statements issued for fiscal
years beginning after December 15, 2008 (January 1, 2009 for us), and interim
periods within those fiscal years. The adoption of this FSP did not have a
material impact on our consolidated financial statements.
SFAS
No. 162
On
May 9, 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles. This Statement is intended to improve financial
reporting by identifying a consistent framework, or hierarchy, for selecting
accounting principles to be used in preparing financial statements that are
presented in conformity with GAAP for nongovernmental entities.
SFAS
No. 162 establishes that the GAAP hierarchy should be directed to entities
because it is the entity (not its auditor) that is responsible for selecting
accounting principles for financial statements that are presented in conformity
with GAAP. SFAS No. 162 is effective 60 days following the U.S. Securities and
Exchange Commission’s approval of the Public Company Accounting Oversight Board
Auditing amendments to AU Section 411, The Meaning of Present Fairly in
Conformity with Generally Accepted Accounting Principles, and is only
effective for nongovernmental entities. We expect the adoption of this Statement
will have no effect on our consolidated financial statements.
EITF
08-6
On
November 24, 2008, the Financial Accounting Standards Board ratified the
consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 08-6,
or EITF 08-6, Equity Method
Investment Accounting Considerations. EITF 08-6 clarifies certain
accounting and impairment considerations involving equity method investments.
This Issue is effective for fiscal years beginning on or after December 15, 2008
(January 1, 2009 for us), and interim periods within those fiscal years. The
guidance in this Issue is to be applied prospectively for all financial
statements presented. The adoption of this Issue did not have any impact on our
consolidated financial statements.
FSP
No. FAS 140-4 and FIN 46(R)-8
On
December 11, 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8 Disclosures by Public Entities
(Enterprises) about Transfers of Financial Assets and Interests in Variable
Interest Entities. These two pronouncements require enhanced disclosure
and transparency by public entities about their involvement with variable
interest entities and their continuing involvement with transferred financial
assets. The disclosure requirements in these two pronouncements are effective
for annual and interim periods ending after December 15, 2008 (December 31, 2008
for us). The adoption of these two pronouncements did not have any impact
on our consolidated financial statements.
FSP
No. FAS 132(R)-1
On
December 30, 2008, the FASB issued FSP No. FAS 132(R)-1, Employer’s Disclosures About Postretirement
Benefit Plan Assets, effective for financial statements ending after
December 15, 2009 (December 31, 2009 for us). This FSP requires additional
disclosure of pension and postretirement plan holdings regarding (i) investment
asset classes, (ii) fair value measurement of assets, (iii) investment
strategies, (iv) asset risk and (v) rate-of-return assumptions. We do not expect
this FSP to have a material impact on our consolidated financial
statements.
Securities
and Exchange Commission’s Final Rule on Oil and Gas Disclosure
Requirements
On
December 31, 2008, the Securities and Exchange Commission (“SEC”) issued its
final rule, Modernization of
Oil and Gas Reporting, which revises the disclosures required by oil and
gas companies. The SEC disclosure requirements for oil and gas companies have
been updated to include expanded disclosure for oil and gas activities, and
certain definitions have also been changed that will impact the determination of
oil and gas reserve quantities. The provisions of this final rule are effective
for
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Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
registration
statements filed on or after January 1, 2010, and for annual reports for fiscal
years ending on or after December 31, 2009. We are currently reviewing the
effects of this SEC final rule.
23. Subsequent
Event
On
February 2, 2009, Kinder Morgan Energy Partners paid $250 million to retire the
principal amount of its 6.30% senior notes that matured on that
date.
In
February and March 2009, Kinder Morgan Energy Partners sold 5,666,000
of its common units in a public offering at a price of $46.95 per unit. Kinder
Morgan Energy Partners received net proceeds, after commissions and underwriting
expenses, of approximately $260 million for the issuance of these 5,666,000
common units and used the proceeds to reduce the borrowings under its bank
credit facility.
On
February 25, 2009, Kinder Morgan Energy Partners entered
into four additional fixed-to-floating interest rate swap agreements
having a combined notional principal amount of $1.0 billion related to (i)
$200 million 6.00% senior notes due 2017, (ii) $300 million of 5.125%
senior notes due 2014, (iii) $25 million 5.00% senior notes due 2013 and (iv)
$475 million of 5.95% senior notes due 2018.
Quarterly
Operating Results for 2008 and 2007
|
Successor
Company
|
||||||||||||
|
Three
Months Ended
|
||||||||||||
|
March
31,
2008
|
June
30,
2008
|
September
30,
2008
|
December
31,
2008
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Operating
Revenues
|
$
|
2,895.0
|
$
|
3,560.5
|
$
|
3,296.6
|
$
|
2,342.7
|
||||
|
Gas
Purchases and Other Costs of Sales
|
1,760.6
|
2,494.1
|
2,179.2
|
1,310.1
|
||||||||
|
Other
Operating Expenses
|
658.2
|
4,704.5
|
719.1
|
741.1
|
||||||||
|
Operating
Income (Loss)
|
476.2
|
(3,638.1
|
)
|
398.3
|
291.5
|
|||||||
|
Other
Income and (Expenses)
|
(283.3
|
)
|
(202.8
|
)
|
(201.5
|
)
|
(134.4
|
)
|
||||
|
Income
(Loss) from Continuing Operations Before Income Taxes
|
192.9
|
(3,840.9
|
)
|
196.8
|
157.1
|
|||||||
|
Income
Taxes
|
87.1
|
19.4
|
87.9
|
109.9
|
||||||||
|
Income
(Loss) from Continuing Operations
|
105.8
|
(3,860.3
|
)
|
108.9
|
47.2
|
|||||||
|
Income
(Loss) from Discontinued Operations, Net of Tax
|
(0.1
|
)
|
(0.3
|
)
|
(0.2
|
)
|
(0.3
|
)
|
||||
|
Net
Income (Loss)
|
$
|
105.7
|
$
|
(3,860.6
|
)
|
$
|
108.7
|
$
|
46.9
|
|||
|
Predecessor
Company
|
Successor
Company
|
||||||||||||||||
|
Three
Months
Ended
|
Two
Months
Ended
|
One
Month
Ended
|
Three
Months Ended
|
||||||||||||||
|
March
31,
2007
|
May
31,
2007
|
June
30,
2007
|
September
30,
2007
|
December
31,
2007
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
||||||||||||||||
|
Operating
Revenues
|
$
|
2,444.4
|
$
|
1,720.7
|
$
|
936.9
|
$
|
2,609.0
|
$
|
2,848.8
|
|||||||
|
Gas
Purchases and Other Costs of Sales
|
1,452.5
|
1,037.9
|
557.2
|
1,482.8
|
1,616.6
|
||||||||||||
|
Other
Operating Expenses
|
968.0
|
501.9
|
220.5
|
683.2
|
791.6
|
||||||||||||
|
Operating
Income
|
23.9
|
180.9
|
159.2
|
443.0
|
440.6
|
||||||||||||
|
Other
Income and (Expenses)
|
(181.8
|
)
|
(120.2
|
)
|
(110.0
|
)
|
(278.3
|
)
|
(178.6
|
)
|
|||||||
|
Income
(Loss) from Continuing Operations Before Income Taxes
|
(157.9
|
)
|
60.7
|
49.2
|
164.7
|
262.0
|
|||||||||||
|
Income
Taxes
|
87.7
|
47.8
|
21.3
|
74.6
|
131.5
|
||||||||||||
|
Income
(Loss) from Continuing Operations
|
(245.6
|
)
|
12.9
|
27.9
|
90.1
|
130.5
|
|||||||||||
|
Income
(Loss) from Discontinued Operations, Net of Tax
|
233.2
|
65.4
|
2.3
|
(4.4
|
)
|
0.6
|
|||||||||||
|
Net
Income (Loss)
|
$
|
(12.4
|
)
|
$
|
78.3
|
$
|
30.2
|
$
|
85.7
|
$
|
131.1
|
||||||
178
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
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:
Capitalized
Costs Related to Oil and Gas Producing Activities
|
Successor
Company
|
Predecessor
Company
|
|||||||||||
|
December
31,
|
December
31,
|
|||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Consolidated
Companies1
|
||||||||||||
|
Wells
and equipment, facilities and other
|
$
|
2,595.4
|
$
|
2,081.3
|
$
|
1,369.5
|
||||||
|
Leasehold
|
429.8
|
449.3
|
347.4
|
|||||||||
|
Total
proved oil and gas properties
|
3,025.2
|
2,530.6
|
1,716.9
|
|||||||||
|
Accumulated
depreciation and depletion
|
(1,155.6
|
)
|
(787.6
|
)
|
(470.2
|
)
|
||||||
|
Net
capitalized costs
|
$
|
1,869.6
|
$
|
1,743.0
|
$
|
1,246.7
|
||||||
__________
|
1
|
Amounts
relate to Kinder Morgan CO2
Company, L.P. and its consolidated subsidiaries.
|
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:
Costs
Incurred in Exploration, Property Acquisitions and Development
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31,
2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Consolidated
Companies1
|
||||||||||||||||
|
Property
Acquisition
|
||||||||||||||||
|
Proved
oil and gas properties
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
36.6
|
||||||||
|
Development
|
495.2
|
156.9
|
87.5
|
261.8
|
||||||||||||
__________
|
1
|
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.
179
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Our
results of operations from oil and gas producing activities for the year ended
December 31, 2008, seven months ended December 31, 2007, five months ended May
31, 2007 and year ended December 31, 2006 are shown in the following
table:
|
Successor
Company
|
Predecessor
Company
|
|||||||||||||||
|
Year
Ended
December
31,
2008
|
Seven
Months
Ended
December
31,
2007
|
Five
Months
Ended
May
31, 2007
|
Year
Ended
December
31,
2006
|
|||||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||||||
|
Consolidated
Companies1
|
||||||||||||||||
|
Revenues2
|
$
|
785.5
|
$
|
352.0
|
$
|
237.7
|
524.7
|
|||||||||
|
Expenses:
|
||||||||||||||||
|
Production
costs
|
308.4
|
147.2
|
96.7
|
208.9
|
||||||||||||
|
Other
operating expenses3
|
99.0
|
34.9
|
22.0
|
66.4
|
||||||||||||
|
Depreciation,
depletion and amortization expenses
|
342.2
|
151.9
|
106.6
|
169.4
|
||||||||||||
|
Total
expenses
|
749.6
|
334.0
|
225.3
|
444.7
|
||||||||||||
|
Results
of operations for oil and gas producing activities
|
$
|
35.9
|
$
|
18.0
|
$
|
12.4
|
$
|
80.0
|
||||||||
__________
|
1
|
Amounts
relate to Kinder Morgan CO2
Company, L.P. and its consolidated
subsidaries.
|
|
2
|
Revenues
include losses attributable to our hedging contracts of $693.3 million,
$311.5 million, $122.7 million and $441.7 million for the year ended
December 31, 2008, seven months ended December 31, 2007, five months ended
May 31, 2007 and year ended December 31, 2006,
respectively.
|
|
3
|
Consists
primarily of carbon dioxide
expense.
|
The
table below represents estimates, as of December 31, 2008, 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 infrastructure
under current operating conditions. Proved undeveloped reserves require
additional investments in wells and related infrastructure in order to recover
the production.
During
2008, we filed estimates of our oil and gas reserves for the year 2007 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 and gas reserves reported on
Form EIA-23 and those reported in this report exceeds 5%.
180
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Reserve
Quantity Information
|
Consolidated
Companies
|
||||||||
|
Crude
Oil
(MBbls)
|
NGLs
(MBbls)
|
Nat.
Gas
(MMcf)1
|
||||||
|
Proved
developed and undeveloped reserves as of
|
||||||||
|
December
31, 20052
|
21,567
|
2,884
|
327
|
|||||
|
December
31, 20063
|
123,978
|
10,333
|
291
|
|||||
|
Revisions
of Previous Estimates3,4
|
10,361
|
2,784
|
1,077
|
|||||
|
Production3
|
(12,984
|
)
|
(2,005
|
)
|
(290
|
)
|
||
|
December
31, 20073
|
121,355
|
11,112
|
1,078
|
|||||
|
Revisions
of Previous Estimates3,5
|
(29,536
|
)
|
(2,490
|
)
|
695
|
|||
|
Production3
|
(13,240
|
)
|
(1,762
|
)
|
(499
|
)
|
||
|
December
31, 20083
|
78,579
|
6,860
|
1,274
|
|||||
|
|
||||||||
|
Proved
developed reserves as of
|
||||||||
|
December
31, 20052
|
11,965
|
1,507
|
251
|
|||||
|
December
31, 20063
|
69,073
|
5,877
|
291
|
|||||
|
December
31, 20073
|
70,868
|
5,517
|
1,078
|
|||||
|
December
31, 20083
|
53,346
|
4,308
|
1,274
|
|||||
__________
|
1
|
Natural
gas reserves are computed at 14.65 pounds per square inch absolute and 60
degrees Fahrenheit.
|
|
2
|
For
the period presented, we accounted for Kinder Morgan Energy Partners under
the equity method, therefore, amounts reflect our proportionate share of
Kinder Morgan Energy Partners’ proved
reserves.
|
|
3
|
Amounts
relate to Kinder Morgan CO2
Company, L.P. and its consolidated
subsidaries.
|
|
4
|
Associated
with an expansion of the carbon dioxide flood project area of the SACROC
unit.
|
|
5
|
Predominately
due to lower product prices used to determine reserve
volumes.
|
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 underlie the computation of the
standardized measure of discounted cash flows may be summarized as
follows:
|
|
·
|
the
standardized measure includes our estimate of proved crude oil, natural
gas liquids and natural gas reserves and projected future production
volumes based upon year-end economic
conditions;
|
|
|
·
|
pricing
is applied based upon year-end market prices adjusted for fixed or
determinable contracts that are in existence at
year-end;
|
|
|
·
|
future
development and production costs are determined based upon actual cost at
year-end;
|
|
|
·
|
the
standardized measure includes projections of future abandonment costs
based upon actual costs at year-end;
and
|
|
|
·
|
a
discount factor of 10% per year is applied annually to the future net cash
flows.
|
Our
standardized measure of discounted future net cash flows from proved reserves
were as follows:
Standardized
Measure of Discounted Future Net Cash Flows From
Proved
Oil and Gas Reserves
|
December
31,
|
December
31,
|
|||||||||||
|
2008
|
2007
|
2006
|
||||||||||
|
(In
millions)
|
(In
millions)
|
|||||||||||
|
Consolidated
Companies1
|
||||||||||||
|
Future
Cash Inflows from Production
|
$
|
3,498.0
|
$
|
12,099.5
|
$
|
7,534.7
|
||||||
|
Future
Production Costs
|
(1,671.6
|
)
|
(3,536.2
|
)
|
(2,617.9
|
)
|
||||||
|
Future
Development Costs2
|
(910.3
|
)
|
(1,919.2
|
)
|
(1,256.8
|
)
|
||||||
|
Undiscounted
Future Net Cash Flows
|
916.1
|
6,644.1
|
3,660.0
|
|||||||||
|
10%
Annual Discount
|
(257.7
|
)
|
(2,565.7
|
)
|
(1,452.2
|
)
|
||||||
|
Standardized
Measure of Discounted Future Net Cash Flows
|
$
|
658.4
|
$
|
4,078.4
|
$
|
2,207.8
|
||||||
__________
|
1
|
Amounts
relate to Kinder Morgan CO2
Company, L.P. and its consolidated
subsidaries.
|
|
2
|
Includes
abandonment costs.
|
The following table represents our
estimate of changes in the standardized measure of discounted future net cash
flows from proved reserves:
181
|
Item 8:
Financial
Statements and Supplementary Data. (continued)
|
Knight
Form 10-K
|
Changes
in the Standardized Measure of Discounted Future Net Cash Flows
From
Proved
Oil and Gas Reserves
|
Year
Ended December 31,
|
|||||||||||
|
2008
|
2007
|
2006
|
|||||||||
|
(In
millions)
|
|||||||||||
|
Consolidated
Companies1
|
|||||||||||
|
Present
Value as of January
|
$
|
4,078.4
|
$
|
2,207.8
|
3,075.0
|
||||||
|
Changes
During the Year
|
|||||||||||
|
Revenues
Less Production and Other Costs2
|
(1,012.4
|
)
|
(722.1
|
)
|
(690.0
|
)
|
|||||
|
Net
Changes in Prices, Production and Other Costs2
|
(3,076.9
|
)
|
2,153.2
|
(123.0
|
)
|
||||||
|
Development
Costs Incurred
|
495.2
|
244.5
|
261.8
|
||||||||
|
Net
Changes in Future Development Costs
|
231.1
|
(547.8
|
)
|
(446.0
|
)
|
||||||
|
Purchases
of Reserves in Place
|
—
|
-
|
3.2
|
||||||||
|
Revisions
of Previous Quantity Estimates3
|
(417.1
|
)
|
510.8
|
(179.5
|
)
|
||||||
|
Accretion
of Discount
|
392.9
|
198.1
|
307.4
|
||||||||
|
Timing
Differences and Other
|
(32.8
|
)
|
33.9
|
(1.1
|
)
|
||||||
|
Net
Change For the Year
|
(3,420.0
|
)
|
1,870.6
|
(867.2
|
)
|
||||||
|
Present
Value as of December 31
|
$
|
658.4
|
$
|
4,078.4
|
$
|
2,207.8
|
|||||
__________
|
1
|
Amounts
relate to Kinder Morgan CO2
Company, L.P. and its consolidated
subsidaries.
|
|
2
|
Excludes
the effect of losses attributable to our hedging contracts of $639.3
million, $434.2 million and $441.7 million for the years ended December
31, 2008, 2007 and 2006,
respectively.
|
|
3
|
2008
revisions are predominantly due to lower product prices used to determine
reserve volumes. 2007 revisions are associated with an expansion of the
carbon dioxide flood project area for the SACROC unit. 2006 revisions are
based on lower than expected recoveries from a section of the SACROC unit
carbon dioxide flood project.
|
None.
As
of December 31, 2008, 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 our
Chief Financial Officer, to allow timely decisions regarding required
disclosure.
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. 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. 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, 2008. The effectiveness of
our internal control over financial reporting as of December 31, 2008, has been
audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which appears herein.
182
|
Item 9A. Controls
and Procedures. (continued)
|
Knight
Form 10-K
|
Certain
businesses we acquired during 2008 were excluded from the scope of our
management’s assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2008. The excluded businesses consisted
of the following:
|
|
·
|
the
bulk terminal assets we acquired from Chemserve, Inc., effective August
15, 2008; and
|
|
|
·
|
the
refined petroleum products storage terminal we acquired from
ConocoPhillips, effective December 10,
2008.
|
These
businesses, in the aggregate, constituted 0.01% of our total operating revenues
for 2008 and 0.16% of our total assets as of December 31, 2008.
There
has been no change in our internal control over financial reporting during the
fourth quarter of 2008 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
None
183
|
Knight
Form 10-K
|
PART
III
Directors
and Executive Officers
Set
forth below is certain information concerning our directors and executive
officers. Our directors are elected annually by, and may be removed by, Knight
Midco Inc., as our sole common shareholder. Knight Midco Inc. is indirectly
wholly owned by Knight Holdco LLC. All of our officers serve at the discretion
of our board of directors. The ages set forth below are as of December 31,
2008.
|
Name
|
Age
|
Position
|
|
Richard
D. Kinder
|
64
|
Director,
Chairman and Chief Executive Officer
|
|
C.
Park Shaper
|
40
|
Director
and President
|
|
Steven
J. Kean
|
47
|
Executive
Vice President and Chief Operating Officer
|
|
Kenneth
A. Pontarelli
|
45
|
Director
|
|
Kimberly
A. Dang
|
39
|
Vice
President and Chief Financial Officer
|
|
David
D. Kinder
|
34
|
Vice
President, Corporate Development and Treasurer
|
|
Joseph
Listengart
|
40
|
Vice
President, General Counsel and Secretary
|
|
James
E. Street
|
52
|
Vice
President, Human Resources and
Administration
|
Richard D. Kinder is
Director, Chairman and Chief Executive Officer of Kinder Morgan Management,
Kinder Morgan G.P., Inc. and Knight Inc. Mr. Kinder has served as Director,
Chairman and Chief Executive Officer of Kinder Morgan Management since its
formation in February 2001. He was elected Director, Chairman and Chief
Executive Officer of Knight Inc. 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 Kinder Morgan Management, Kinder
Morgan G.P., Inc. and Knight Inc. in July 2004 and served as President until May
2005. He has also served as Chief Manager, and as a member of the Board of
Managers, of Knight Holdco LLC since May 2007. Mr. Kinder is the uncle of David
Kinder, Vice President, Corporate Development and Treasurer of Kinder Morgan
Management, Kinder Morgan G.P., Inc. and Knight Inc.
C. Park Shaper is Director
and President of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight
Inc. Mr. Shaper was elected President of Kinder Morgan Management, Kinder Morgan
G.P., Inc. and Knight Inc. in May 2005. He served as Executive Vice President of
Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. from July
2004 until May 2005. Mr. Shaper was elected Director of Kinder Morgan Management
and Kinder Morgan G.P., Inc. in January 2003 and of Knight Inc. in May 2007. He
was elected Vice President, Treasurer and Chief Financial Officer of Kinder
Morgan Management 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 Knight Inc.
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 has also served as President, and as a member of the
Board of Managers, of Knight Holdco LLC since May 2007. 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. Mr. Shaper is also a trust manager of
Weingarten Realty Investors.
Steven J. Kean is Executive
Vice President and Chief Operating Officer of Kinder Morgan Management, Kinder
Morgan G.P., Inc. and Knight Inc. Mr. Kean was elected Executive Vice President
and Chief Operating Officer of Kinder Morgan Management, Kinder Morgan G.P.,
Inc. and Knight Inc. in January 2006. He served as Executive Vice President,
Operations of Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc.
from May 2005 to January 2006. He served as President, Texas Intrastate Pipeline
Group from June 2002 until May 2005. He served as Vice President of Strategic
Planning for the Kinder Morgan Gas Pipeline Group from January 2002 until June
2002. He has also served as Chief Operating Officer, and as a member of the
Board of Managers, of Knight Holdco LLC since May 2007. 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.
Kenneth A. Pontarelli is a
Director of Knight Inc. Mr. Pontarelli is a
Managing Director of Goldman Sachs & Co. See Item 12, “Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder Matters” for
details regarding Goldman Sachs’ ownership of Knight Holdco LLC units. Mr.
Pontarelli was elected Director of Knight Inc. upon the consummation of the
Going Private transaction in May 2007. He has also served as member of the Board
of Managers of Knight Holdco LLC since May 2007. He joined Goldman Sachs &
Co. in 1997 and was appointed Managing Director in 2004. Mr. Pontarelli
currently serves on the board of directors of CVR Energy, Inc., CCS Inc., Cobalt
International Energy, L.P. and Energy Future Holdings Corp. He received a B.A.
from Syracuse University and an M.B.A. from Harvard Business
School.
184
|
Item 10.
Directors,
Executive Officers and Corporate
Governance.(continued)
|
Knight
Form 10-K
|
Kimberly A. Dang is Vice
President and Chief Financial Officer of Kinder Morgan Management, Kinder Morgan
G.P., Inc. and Knight Inc. Mrs. Dang was elected Chief Financial Officer of
Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in May 2005.
She served as Treasurer of Kinder Morgan Management, Kinder Morgan G.P., Inc.
and Knight Inc. from January 2004 to May 2005. She was elected Vice President,
Investor Relations of Kinder Morgan Management, Kinder Morgan G.P., Inc. and
Knight Inc. in July 2002 and served in that role until January 2009. From
November 2001 to July 2002, she served as Director, Investor Relations of Kinder
Morgan Management, Kinder Morgan G.P., and Knight Inc. She has also served as
Chief Financial Officer of Knight Holdco LLC since May 2007. 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.
David D. Kinder is Vice
President, Corporate Development and Treasurer of Kinder Morgan Management,
Kinder Morgan G.P., Inc. and Knight Inc. Mr. Kinder was elected Treasurer of
Kinder Morgan Management, Kinder Morgan G.P., Inc. and Knight Inc. in May 2005.
He was elected Vice President, Corporate Development of Kinder Morgan
Management, Kinder Morgan G.P., Inc. and Knight Inc. in October 2002. He served
as manager of corporate development for Knight Inc. and Kinder Morgan G.P., Inc.
from January 2000 to October 2002. He has also served as Treasurer of Knight
Holdco LLC since May 2007. 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 Kinder Morgan Management, Kinder
Morgan G.P., Inc. and Knight Inc. Mr. Listengart was elected Vice President,
General Counsel and Secretary of Kinder Morgan Management 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 Knight
Inc. 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. He has also served as General Counsel and Secretary of Knight
Holdco LLC since May 2007. 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.
James E. Street is Vice
President, Human Resources and Administration of Kinder Morgan Management,
Kinder Morgan G.P., Inc. and Knight Inc. Mr. Street was elected Vice President,
Human Resources and Administration of Kinder Morgan Management upon its
formation in February 2001. He was elected Vice President, Human Resources and
Administration of Kinder Morgan G.P., Inc. and Knight Inc. 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.
Compensation
Committee Interlocks and Insider Participation
Our
board has no separate compensation committee. Mr. Richard D. Kinder as
Chief Manager of Knight Holdco makes compensation decisions with respect to our
executive officers. None of our executive officers served during 2008 on a board
of directors of another entity which has employed any of the members of our
board.
Corporate
Governance
Knight
Midco Inc. is our sole common shareholder. As a result, Knight
Midco Inc. elects all of our directors and our board of directors does not
have a nominating and governance committee or a committee that serves a similar
purpose.
Mr. Shaper
and Mr. Pontarelli comprise our audit committee as specified in
Section 3(a)(58)(A) of the Securities Exchange Act of 1934. Our board has
determined that C. Park Shaper is an “audit committee financial expert.”
Mr. Shaper is also our President and is therefore not
independent.
We
make available free of charge within the “Investors” section of our Internet
website, at www.kindermorgan.com, our
code of business conduct and ethics (which applies to our senior financial and
accounting officers and our chief executive officer, among others). Requests for
copies may be directed to Investor Relations, Knight Inc., 500 Dallas
Street, Suite 1000, Houston, Texas 77002 or telephone (713) 369-9490.
We intend to disclose any amendments to our code of business conduct and ethics,
and any waiver from a provision of that code granted to our executive officers
or directors, that otherwise would be required to be disclosed on a
Form 8-K, on our 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 report and should not be considered part
of any report that we file with or furnish to the Securities and Exchange
Commission.
185
|
Knight
Form 10-K
|
Our
executive officers also serve in the same capacities as executive officers of
Kinder Morgan G.P., Inc., the general partner of Kinder Morgan Energy
Partners, and of Kinder Morgan Management, the delegate of Kinder
Morgan G.P., Inc. Certain of our executive officers also serve in the
same capacities as officers of Knight Holdco LLC, our privately owned
parent company. Except as identified otherwise, all information in this Item 11
with respect to compensation of executive officers describes the total
compensation received by those persons in all capacities for services rendered
to us and our affiliates, including Kinder Morgan Energy Partners, Kinder
Morgan G.P., Inc., Kinder Morgan Management and Knight
Holdco LLC. In this Item 11, “we,” “our” or “us” refers to Knight Inc. and,
where appropriate, Kinder Morgan Energy Partners, Kinder
Morgan G.P., Inc. and Kinder Morgan Management.
Our
board does not have a separately designated compensation committee.
Mr. Richard D. Kinder as Chief Manager of Knight Holdco makes compensation
decisions with respect to our executive officers; however, increases in the
compensation of our officers and other management personnel who own units of
Knight Holdco LLC have to be further approved by Knight Holdco’s board of
managers.
The
compensation committee of the board of directors of Kinder Morgan Management,
which committee is generally composed of three independent directors, determines
the compensation to be paid by Kinder Morgan Energy Partners to KMGP Services
Company, Inc.’s employees and Kinder Morgan Management’s and Kinder
Morgan G.P., Inc.’s executive officers. For further information
regarding KMGP Services Company, Inc., see “Description of
Business—Employees” within Items 1 and 2 of this report. As described below,
Kinder Morgan Management’s compensation committee is aware of the compensation
paid to such officers by entities such as us and Knight Holdco LLC, but
makes its compensation determinations at its sole discretion.
Compensation
Discussion and Analysis
Program
Objectives
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.
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.
The
key objectives of our executive compensation program are to attract, motivate
and retain executives who will advance our overall business strategies and
objectives of growing the value of our portfolio of businesses. 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.
Currently,
our executive compensation program is principally composed of two elements:
(i) base cash salary; and (ii) possible annual cash bonus (reflected
in the Summary Compensation Table below as Non-Equity Incentive Plan
Compensation). Until October 2008, we paid our executive officers a base salary
not to exceed $200,000, which we believe is below annual base salaries for
comparable positions in the marketplace, based upon independent salary surveys
in which we participate. The cap for our executive officers’ base salaries was
raised to an annual amount not to exceed $300,000. We believe the base salaries
paid to our executive officers continue to be below the industry average for
similarly positioned executives. While not awarded by us, Mr. Richard D. Kinder
was aware of the units awarded by Knight Holdco LLC (as discussed more
fully below) and took these awards into account as components of the total
compensation received by our executive officers.
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 Kinder Morgan Energy Partners and us.
Therefore, the majority of our named executive officers’ compensation is
allocated to the “at risk” portion of our compensation program—the annual cash
bonus. Accordingly, for 2008, our executive compensation was weighted toward the
cash bonus, payable on the basis of achieving (i) an earnings before
interest, taxes, depreciation, depletion and amortization (referred to as
EBITDA) less capital spending target by us; and (ii) a cash distribution
per common unit target by Kinder Morgan Energy Partners.
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
186
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
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 paid to our executive officers are paid under our Annual Incentive
Plan as a result of reaching designated financial targets established by
Mr. Richard D. Kinder and Kinder Morgan Management’s compensation
committee, we expect that all compensation paid to our executives would qualify
for deductibility under federal income tax rules. Though we are advised that
limited partnerships such as Kinder Morgan Energy Partners, and private
companies, such as us, are not subject to section 162(m), we and Kinder
Morgan Energy Partners have chosen to generally operate as if this code section
does apply to us and Kinder Morgan Energy Partners as a measure of appropriate
governance.
Prior
to 2006, long-term equity awards comprised a third element of our executive
compensation program. These awards primarily consisted of grants of restricted
Kinder Morgan, Inc., or KMI stock, and grants of non-qualified options to
acquire shares of KMI common stock, both pursuant to the provisions of KMI’s
Amended and Restated 1999 Stock Plan, referred to as the KMI stock plan. 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. For each of the years ended December 31,
2007 and 2008, no restricted stock or options to purchase shares of KMI, Kinder
Morgan Energy Partners or Kinder Morgan Management were granted to any of our
named executive officers.
Additionally,
in connection with the Going Private transaction, Knight Holdco LLC awarded
members of our management Class A-1 and Class B units of Knight
Holdco LLC. In accordance with SFAS No. 123R, Knight Holdco LLC
is required to recognize compensation expense in connection with the
Class A-1 and Class B units over the expected life of such units. As a
subsidiary of Knight Holdco LLC, we are, under accounting rules, allocated
a portion of this compensation expense, although none of us or any of our
subsidiaries have any obligation, nor do we expect to pay any amounts in respect
of such units. The Class A-1 and Class B units awarded to members of
our management may be viewed as a replacement of restricted stock as a component
of long-term executive compensation. For more information concerning the Knight
Holdco LLC units, see “Elements of Compensation—Other Compensation—Knight
Holdco LLC Units” below.
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, supplemental executive
retirement, non-qualified supplemental defined benefit/contribution, deferred
compensation or split dollar life insurance programs for our executive officers.
Additionally, we do not have employment agreements (other than with our Chairman
and Chief Executive Officer, Richard D. Kinder), special severance agreements or
change of control agreements for our executive officers. Our executives are
eligible for the same severance policy as our workforce, which caps severance
payments to an amount equal to six months of salary. We have no executive
company cars or executive car allowances nor do we 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 believe that we are currently below
competitive levels for comparable companies in this area of our overall
compensation package; however, we have no current plans to change our policy of
not offering such executive benefits, perquisite programs or special executive
severance arrangements.
At
his request, Mr. Richard D. 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, unit grants, or other compensation
from us. Mr. Kinder does not have any deferred compensation, supplemental
retirement or any other special benefit, compensation or perquisite arrangement
with us. Each year Mr. Kinder reimburses us for his portion of health care
premiums and parking expenses. Mr. Kinder was awarded Class B units by
and in Knight Holdco LLC in connection with the Going Private transaction,
and while we are, under accounting rules, allocated compensation expense
attributable to such Class B units, we have no obligation, nor do we
expect, to pay any amounts in connection with the Class B
units.
Elements
of Compensation
As
outlined above, our executive compensation program currently is principally
composed of two elements: (i) a base cash salary; and (ii) a possible
annual cash bonus. Mr. Richard D. Kinder reviews and approves annually the
financial goals and
187
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
objectives
of both us and Kinder Morgan Energy Partners that are relevant to the
compensation of our named executive officers, other than himself.
Information
is solicited from relevant members of senior management regarding the
performance of our named executive officers and determinations and
recommendations are made at the regularly scheduled first quarter board
meeting.
If
any of our executive officers is also an executive officer of Kinder
Morgan G.P., Inc. or Kinder Morgan Management, the compensation
determination or recommendation (i) may be with respect to the aggregate
compensation to be received by such officer from us, Kinder Morgan Management,
and Kinder Morgan G.P., Inc. that is to be allocated among them, or
alternatively (ii) may be with respect to the compensation to be received
by such executive officers from us, Kinder Morgan Management or Kinder
Morgan G.P., Inc., as the case may be, in which case such compensation
will not be allocated among us, on the one hand, and Kinder Morgan Management,
and Kinder Morgan G.P., on the other.
Base
Salary
Base
salary is paid in cash. Until October 2008, all of our named executive officers,
with the exception of our Chairman and Chief Executive Officer who receives $1
of base salary per year as described above, were paid a base salary of $200,000
per year. The cap for our executive officers’ base salaries was raised to an
annual amount not to exceed $300,000. Generally, we believe that our executive
officers’ base salaries are below base salaries for executives in similar
positions and with similar responsibilities at companies of comparable size and
scope, based upon independent salary surveys in which we
participate.
Possible
Annual Cash Bonus (Non-Equity Cash Incentive)
Our
possible annual cash bonuses are provided for under our Annual Incentive Plan,
which became effective January 18, 2005. The overall purpose of our Annual
Incentive Plan is to increase our executive officers’ and our employees’
personal stake in the continued success of Kinder Morgan Energy Partners and us
by providing to them additional incentives through the possible payment of
annual cash bonuses. Under the plan, annual cash bonuses are budgeted for at the
beginning of each year and may be paid to our executive officers and other
employees depending on whether we and our subsidiaries (including Kinder Morgan
Energy Partners) meet certain performance objectives. Assuming the performance
objectives are met, the budgeted pool of bonus dollars is further assessed and
potentially decreased or increased based on our and our subsidiaries’ (including
Kinder Morgan Energy Partners’) overall performance in a variety of areas,
including safety and environmental goals and regulatory compliance.
Once
the aggregate pool of bonus dollars is determined, further assessment is done at
the business segment level. Each business segment’s financial performance as
well as its safety and environmental goals and regulatory compliance are
assessed and factored, positively or negatively, into the amount of bonus
dollars allocated to that business segment. The business unit’s safety and
environmental goals and regulatory compliance are assessed against its
performance in these areas in previous years and industry benchmarks. These
assessments as well as individual performance factor into bonus awards at the
business segment level.
Our
and our subsidiaries’ (including Kinder Morgan Energy Partners) overall
performance, including whether we have met the performance objectives as well as
how, on an overall basis, we have performed with respect to a variety of areas
such as safety and environmental goals and regulatory compliance, negatively or
positively, impacts the bonuses of our named executive officers. Also, with
respect to our named executive officers, individual performance impacts their
bonuses. Our named executive officers have different areas of responsibility
that require different skill sets. Consequently, many of the skills and aspects
of performance taken into account in determining the bonus awards for the
respective named executive officers differ based on their areas of
responsibility. However, some skills, such as working within a budget, are
applicable for all of the executive officers. While no formula is used in
assessing individual performance, the process of assessing the performance of
each of the named executive officers is consistent, with each such officer being
assessed relative to the officer’s performance of his or her job in preceding
years as well as with respect to specific matters assigned to the officer over
the course of the year. Individual performance, as described above, as well as
safety and environmental goals and regulatory compliance were taken into account
with respect to the 2008 awards.
All
of our employees and the employees of our 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 Mr. Richard D.
Kinder and Kinder Morgan Management’s 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 “Compensation Discussion
and Analysis”, Mr. Richard D. Kinder, our Chairman and Chief Executive
Officer, has elected to not participate under the plan. As of December 31,
2008, excluding
188
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
Mr. Richard
D. Kinder, ten of our current officers were eligible to participate in the
executive plan component. All other U.S. eligible employees were eligible for
the non-executive plan component.
Following
recommendations and determinations, Mr. Richard D. Kinder establishes which
of our eligible employees will be eligible to participate under the executive
plan component of the plan. 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. A bonus
opportunity is established for each executive officer, which is the bonus the
executive officer could earn if the performance objectives are fully satisfied.
A minimum acceptable level of achievement of each performance objective may be
set, below which no bonus is payable with respect to that objective. Additional
levels may be set 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 plan for any year is
$2.0 million, and Mr. Richard D. Kinder has the discretion to reduce the
bonus amounts payable by us in any performance period.
Performance
objectives may be based on one or more of the following criteria:
|
|
·
|
our
EBITDA less capital spending, or the EBITDA less capital spending of one
of our subsidiaries or business
units;
|
|
|
·
|
our
net income or the net income of one of our subsidiaries or business
units;
|
|
|
·
|
our
revenues or the revenues of one of our subsidiaries or business
units;
|
|
|
·
|
our
unit revenues minus unit variable costs or the unit revenues minus unit
variable costs of one of our subsidiaries or business
units;
|
|
|
·
|
our
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 our subsidiaries or
business units;
|
|
|
·
|
our
free cash flow, 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 our subsidiaries or business
units;
|
|
|
·
|
our
capital expenditures or the capital expenditures of one of our
subsidiaries or business units;
|
|
|
·
|
our
operations and maintenance expense or general and administrative expense,
or the operations and maintenance expense or general and administrative
expense of one of our subsidiaries or business
units;
|
|
|
·
|
our
debt-equity ratios and key profitability ratios, or the debt-equity ratios
and key profitability ratios of one of our subsidiaries or business units;
or
|
|
|
·
|
Kinder
Morgan Energy Partners’ distribution per
unit
|
Two
financial performance objectives were set for 2008 under both the executive plan
component and the non-executive plan component. The 2008 financial performance
objectives were $4.02 in cash distributions per common unit by Kinder Morgan
Energy Partners, and $1,056 million of EBITDA less capital spending by us.
Kinder Morgan Energy Partners’ targets were the same as its previously disclosed
2008 budget expectations. At the end of 2008 the extent to which the financial
performance objectives had been attained and the extent to which the bonus
opportunity had been earned under the formula previously established by Mr.
Richard D. Kinder was determined.
The
2008 bonuses for our executive officers were overwhelmingly based on whether the
established financial performance objectives were met. Other factors, such as
individual over performance or under performance, were considered. With respect
to using these other factors in assessing performance, Mr. Richard D. Kinder did
not find it practicable to, and did not, use a “score card”, or quantify or
assign relative weight to the specific criteria considered. The amount of a
downward or upward adjustment, subject to the maximum bonus opportunity that was
established at the beginning of the year, was not subject to a formula. Specific
aspects of an individual’s performance were not identified in advance. Rather,
the adjustment was based on Mr. Richard D. Kinder’s judgment, giving
consideration to the totality of the record presented, including the
individual’s performance, and the magnitude of any positive or negative
factors.
The
table below sets forth the bonus opportunities that could be payable by us and
Kinder Morgan Energy Partners to our executive officers if the performance
objectives established for 2008 are 100% achieved. The amount of the portion of
the bonus actually paid by us to any executive officer under the plan may be
reduced from the amount of any bonus opportunity open to such executive officer.
Because payments under the plan for our executive officers are determined by
comparing actual performance to the performance objectives established 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.
Mr. Richard D. Kinder set bonus opportunities under the plan for 2008
for the executive officers at dollar amounts in excess of that which were
expected to actually be paid under the plan. The actual payout amounts under the
Non-Equity Incentive Plan Awards made in 2008 are set forth in the Summary
Compensation Table included in this report in the column entitled “Non-Equity
Incentive Plan Compensation.”
189
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
Knight
Inc. Annual Incentive Plan
Bonus
Opportunities for 2008
|
Name
and Principal Position
|
Dollar
Value
|
|||
|
Richard
D. Kinder, Chairman and Chief Executive Officer
|
$
|
-
|
1
|
|
|
Kimberly
A. Dang, Vice President and Chief Financial Officer
|
1,000,000
|
2
|
||
|
Steven
J. Kean, Executive Vice President and Chief Operating
Officer
|
1,500,000
|
3
|
||
|
Joseph
Listengart, Vice President, General Counsel and Secretary
|
1,000,000
|
2
|
||
|
C.
Park Shaper, Director and President
|
1,500,000
|
3
|
||
____________
|
1
|
Declined
to participate.
|
|
2
|
Under
the plan, for 2008, 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 available; if both of the
targets had been exceeded by 10%, $1,500,000 in bonus opportunities would
have been available. Mr. Richard D. Kinder may reduce the award
payable by us to any participant for any
reason.
|
|
3
|
Under
the plan, for 2008, 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 available; if both of the
targets had been exceeded by 10%, $2,000,000 in bonus opportunities would
have been available. Mr. Richard D. Kinder may reduce the award
payable by us to any participant for any
reason.
|
We
may amend the plan from time to time without shareholder 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 year 2009,
unless the plan is terminated earlier by us. 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.
Other
Compensation
Knight Inc. Savings
Plan. The Knight Inc. Savings Plan is a defined contribution 401(k)
plan. The plan permits all full-time employees of Knight 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 contribution equal to 4% of base compensation per
year for most plan participants, Kinder Morgan G.P., Inc. may make special
discretionary contributions. Certain employees’ contributions are based on
collective bargaining agreements. The contributions are made each pay period on
behalf of each eligible employee. Participants may direct the investment of both
their contributions and employer contributions into a variety of investments at
the employee’s discretion. Plan assets are held and distributed pursuant to a
trust agreement. Employer contributions for employees vest on the second
anniversary of the date of hire.
In
July 2008, Mr. Richard D. Kinder and Kinder Morgan Management’s
compensation committee approved a special contribution through July 2009 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
2008 and continuing through the last pay period of July 2009. The additional 1%
contribution 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, Mr. Kinder’s and the Kinder Morgan
Management compensation committee’s approvals will be required annually for each
additional contribution. During the first quarter of 2009, excluding our portion
of the 1% additional contribution described above, we will not make any
additional discretionary contributions to individual accounts for
2008.
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 591/2,
death or disability. The employer contribution will still be considered taxable
income at the time of withdrawal.
Knight Inc. Cash Balance
Retirement Plan. Employees of ours and KMGP Services Company, Inc.,
including our 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 credit each participating
employee’s personal retirement account an amount 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 three years,
and they may take a lump sum distribution upon termination of employment or
retirement.
190
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
The
following table sets forth the estimated actuarial present value of each named
executive officer’s accumulated pension benefit as of December 31, 2008,
under the provisions of the Cash Balance Retirement Plan. With respect to our
named 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
|
||||||||||||||
|
Name
|
Plan
Name
|
Current
Credited
Yrs
of
Service
|
Present
Value of
Accumulated
Benefit1
|
Contributions
During
2008
|
||||||||||
|
Richard
D. Kinder
|
Cash
Balance
|
8
|
$
|
-
|
$
|
-
|
||||||||
|
Kimberly
A. Dang
|
Cash
Balance
|
7
|
39,693
|
8,285
|
||||||||||
|
Steven
J. Kean
|
Cash
Balance
|
7
|
50,479
|
8,755
|
||||||||||
|
Joseph
Listengart
|
Cash
Balance
|
8
|
60,267
|
9,188
|
||||||||||
|
C.
Park Shaper
|
Cash
Balance
|
8
|
60,267
|
9,188
|
||||||||||
____________
|
1
|
The
present values in the Pension Benefits table are based on certain
assumptions, including a 6.25% discount rate, 5.0% cash balance interest
crediting rate, and a lump sum calculated using the IRS 2009 Mortality
Tables. We assumed benefits would commence at normal retirement age, which
is 65.
|
Knight Holdco LLC Units. In
connection with the Going Private transaction, some of our directors and
executive officers received Class A-1 and Class B units of Knight Holdco LLC,
our parent company. Mr. Pontarelli did not receive Knight Holdco LLC units.
Generally, Knight Holdco LLC has three classes of units—Class A units, Class A-1
units and Class B units.
The
Class B units were awarded by Knight Holdco LLC to members of Knight Inc.’s
management in consideration of their services to or for the benefit of Knight
Holdco LLC. The Class B units represent interests in the profits of Knight
Holdco LLC following the return of capital for the holders of Class A units and
the achievement of predetermined performance targets over time. The Class B
units will performance vest in increments of 5% of profits distributions up to a
maximum of 20% of all profits distributions that would otherwise be payable with
respect to the Class A units and Class A-1 units, based on the achievement of
predetermined performance targets. The Class B units are subject to time based
vesting, and with respect to any holder thereof, will vest 33 1/3% on each of
the third, fourth and fifth year anniversary of the issuance of such Class B
units to such holder. The amended and restated limited liability company
agreement of Knight Holdco LLC also includes provisions with respect to
forfeiture of Class B units upon termination for cause, Knight Holdco LLC’s call
rights upon termination and other related provisions relating to an employee’s
tenure. The allocation of the Class B units among our management was determined
prior to closing by Mr. Richard D. Kinder, and approved by other, non-management
investors in Knight Holdco LLC.
The
Class A-1 units were awarded by Knight Holdco LLC to members of our management
(other than Mr. Richard D. Kinder) who reinvested their equity interests in
Knight Holdco LLC in connection with the Going Private transaction in
consideration of their services to or for the benefit of Knight Holdco LLC.
Class A-1 units entitle a holder thereof to receive distributions from Knight
Holdco LLC in an amount equal to distributions paid on Class A units (other than
distributions on the Class A units that represent a return of the capital
contributed in respect of such Class A units), but only after the Class A units
have received aggregate distributions in an amount equal to the amount of
capital contributed in respect of the Class A units.
Other Potential Post-Employment
Benefits. On October 7, 1999, Mr. Richard D. Kinder entered
into an employment agreement with us pursuant to which he agreed to serve as our
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 Kinder Morgan Energy Partners’ long term
viability. Mr. Kinder continues to accept an annual salary of $1, and he
receives no other compensation from us. Mr. Kinder was awarded Class B
units by and in Knight Holdco LLC in connection with the Going Private
transaction, and while we, as a subsidiary of Knight Holdco LLC, are
allocated compensation expense attributable to such Class B units, we have
no obligation, nor do we expect, to pay any amounts in connection with the
Class B units.
We
believe that Mr. Kinder’s employment agreement contains provisions that are
beneficial to us and our subsidiaries and accordingly, Mr. Kinder’s
employment agreement is extended annually at the request of our and Kinder
Morgan Management’s board of directors. For example, with limited exceptions,
Mr. Kinder is prevented from competing in any manner with us or any of our
subsidiaries, while he is employed by us and for 12 months following the
termination of his employment with us. 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
191
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
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 us without cause or if Mr. Kinder terminated his
employment with us as a result of a 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.
Summary
Compensation Table
The
following table shows compensation paid or otherwise awarded to (i) our
principal executive officer; (ii) our principal financial officer; and
(iii) our three most highly compensated executive officers (other than our
principal executive officer and principal financial officer) serving at fiscal
year end 2008 (collectively referred to as the “named executive officers”) for
services rendered to us, our subsidiaries or our affiliates, including Kinder
Morgan Energy Partners and Knight Holdco LLC (collectively referred to as
the “Knight affiliated entities”), during fiscal years 2008, 2007 and 2006. The
amounts in the columns below, except the column entitled “Unit Awards by Knight
Holdco LLC”, represent the total compensation paid or awarded to the named
executive officers by all the Knight affiliated entities, and as a result the
amounts are in excess of the compensation expense allocated to and recognized by
us for services rendered to us. The amounts in the column entitled “Unit Awards
by Knight Holdco LLC” consist of compensation expense calculated in
accordance with SFAS No. 123R and allocated to Knight Inc. (excluding
any corresponding compensation expense allocated to Kinder Morgan Energy
Partners and consolidated into Knight Inc.) for the Knight Holdco LLC
Class A-1 and Class B units awarded by Knight Holdco LLC to the
named executive officers. As a subsidiary of Knight Holdco LLC, we are
allocated a portion of the compensation expense recognized by Knight
Holdco LLC with respect to such units, although none of us or any of our
subsidiaries have any obligation, nor do we expect, to pay any amounts in
respect of such units and none of the named executive officers has received any
payments in respect of such units.
|
(1)
|
(2)
|
(3)
|
(4)
|
(5)
|
(6)
|
||||||||||||||||||||||
|
Name
and
Principal
Position
|
Year
|
Salary
|
Bonus
|
Stock
Awards
by
KMI
|
Option
Awards
by
KMI
|
Non-Equity
Incentive
Plan
Compensation
|
Change
in
Pension
Value
|
All
Other
Compensation
|
Unit
Awards
by
Knight
Holdco
LLC
|
Total
|
|||||||||||||||||
|
Richard
D. Kinder
|
2008
|
$
|
1
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
660,388
|
$
|
660,389
|
||||||||
|
Director,
Chairman and
|
2007
|
1
|
-
|
-
|
-
|
-
|
-
|
-
|
385,200
|
385,201
|
|||||||||||||||||
|
Chief
Executive Officer
|
2006
|
1
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
1
|
|||||||||||||||||
|
Kimberly
A. Dang
|
2008
|
223,077
|
-
|
-
|
-
|
440,000
|
8,285
|
11,863
|
47,963
|
731,188
|
|||||||||||||||||
|
Vice
President and
|
2007
|
200,000
|
-
|
338,095
|
-
|
400,000
|
7,294
|
32,253
|
27,980
|
1,005,622
|
|||||||||||||||||
|
Chief
Financial Officer
|
2006
|
200,000
|
-
|
139,296
|
37,023
|
270,000
|
6,968
|
46,253
|
-
|
699,540
|
|||||||||||||||||
|
Steven
J. Kean
|
2008
|
223,077
|
-
|
-
|
-
|
1,150,000
|
8,755
|
13,007
|
191,720
|
1,586,559
|
|||||||||||||||||
|
Executive
Vice President
|
2007
|
200,000
|
-
|
4,397,080
|
-
|
1,100,000
|
7,767
|
147,130
|
111,820
|
5,963,797
|
|||||||||||||||||
|
And
|
2006
|
200,000
|
-
|
1,591,192
|
147,943
|
-
|
7,422
|
284,919
|
-
|
2,231,476
|
|||||||||||||||||
|
Chief
Operating Officer
|
|||||||||||||||||||||||||||
|
Joseph
Listengart
|
2008
|
223,077
|
-
|
-
|
-
|
900,000
|
9,188
|
11,629
|
120,107
|
1,264,001
|
|||||||||||||||||
|
Vice
President, General
|
2007
|
200,000
|
-
|
847,350
|
-
|
1,000,000
|
8,194
|
102,253
|
70,063
|
2,227,860
|
|||||||||||||||||
|
Counsel
and Secretary
|
2006
|
200,000
|
-
|
721,817
|
-
|
-
|
7,835
|
224,753
|
-
|
1,154,405
|
|||||||||||||||||
|
C.
Park Shaper
|
2008
|
223,077
|
-
|
-
|
-
|
1,200,000
|
9,188
|
12,769
|
302,906
|
1,747,940
|
|||||||||||||||||
|
Director
and President
|
2007
|
200,000
|
-
|
1,950,300
|
-
|
1,200,000
|
8,194
|
155,953
|
176,660
|
3,691,107
|
|||||||||||||||||
|
2006
|
200,000
|
-
|
1,134,283
|
24,952
|
-
|
7,835
|
348,542
|
-
|
1,715,612
|
||||||||||||||||||
____________
|
1
|
Consists
of expense calculated in accordance with SFAS No. 123R attributable
to restricted KMI stock awarded in 2003, 2004 and 2005 according to the
provisions of the KMI Stock Plan. No restricted stock was awarded in 2008,
2007 or 2006. 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. As a
result of the Going Private transaction, all outstanding restricted shares
vested in 2007 and therefore all remaining compensation expense with
respect to restricted stock was recognized in 2007 in accordance with SFAS
No. 123R. We bore all of the costs associated with this
acceleration.
|
|
2
|
Consists
of expense calculated in accordance with SFAS No. 123R attributable
to options to purchase KMI shares awarded in 2002 and 2003 according to
the provisions of the KMI Stock Plan. No options were granted in 2008,
2007 or 2006. 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.
As a result of the Going Private transaction, all outstanding options
vested in 2007 and therefore all remaining compensation expense with
respect to options was recognized in 2007 in accordance with SFAS
No. 123R. As a condition to their being permitted to participate in
the Going Private transaction, Messrs. Kean and Shaper agreed to the
cancellation of 10,467 and 22,031 options, respectively.
These
|
192
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
|
|
cancelled
options had weighted-average exercise prices of $39.12 and $24.75 per
share, respectively. We bore all of the costs associated with this
acceleration.
|
|
3
|
Represents
amounts paid according to the provisions of our Annual Incentive Plan.
Amounts were earned in the fiscal year indicated but were paid in the next
fiscal year. Messrs. Kean, Listengart and Shaper refused to accept a
bonus for 2006. The committee agreed that this was not a reflection of
performance on these individuals.
|
|
4
|
Represents
the 2008, 2007 and 2006, as applicable, change in the actuarial present
value of accumulated defined pension benefit (including unvested benefits)
according to the provisions of our Cash Balance Retirement
Plan.
|
|
5
|
Amounts
include value of contributions to the Knight Inc. Savings Plan (a 401(k)
plan), value of group-term life insurance exceeding $50,000, taxable
parking subsidy and, for 2006 and 2007 only, dividends paid on unvested
restricted stock awards. Amounts in 2006 and 2007 include $10,000 and in
2008 include $11,154 representing the value of contributions to the Knight
Inc. Savings Plan. Amounts representing the value of dividends paid on
unvested restricted stock awards are as follows: for 2007—Mrs. Dang
$21,875; Mr. Kean $136,500; Mr. Listengart $91,875; and Mr. Shaper
$144,375; and for 2006—Mrs. Dang $35,875; Mr. Kean $273,000; Mr.
Listengart $214,375; and Mr. Shaper
$336,875.
|
|
6
|
Such
amounts represent the amount of the non-cash compensation expense
calculated in accordance with SFAS No. 123R attributable to the
Class A-1 and Class B units of Knight Holdco LLC and
allocated to us for financial reporting purposes but does not include any
such expense allocated to any of our subsidiaries. None of the named
executive officers has received any payments in connection with such
units, and none of us or our subsidiaries are obligated, nor do we expect,
to pay any amounts in respect of such units. See “Elements of
Compensation—Other Compensation—Knight Holdco LLC Units” above for further
discussion of these units.
|
Grants
of Plan-Based Awards
The
following supplemental compensation table shows compensation details on the
value of all non-guaranteed and non-discretionary incentive awards granted
during 2008 to our named executive officers. The table includes awards made
during or for 2008. The information in the table under the caption “Estimated
Future Payments Under Non-Equity Incentive Plan Awards” represents the
threshold, target and maximum amounts payable under the Knight Inc. Annual
Incentive Plan for performance in 2008. Amounts actually paid under that plan
for 2008 are set forth in the Summary Compensation Table under the caption
“Non-Equity Incentive Plan Compensation.” There will not be any additional
payouts under the Annual Incentive Plan for 2008.
|
Estimated
Future Payouts Under
Non-Equity Incentive Plan
Awards1
|
All
Other Stock
Awards
|
Grant
Date Fair Value of
|
||||||||||||||
|
Name
|
Grant
Date
|
Threshold
|
Target
|
Maximum
|
Number
of Units
|
Stock
Awards
|
||||||||||
|
Richard
D. Kinder
|
—
|
$
|
-
|
$
|
-
|
$
|
-
|
-
|
$
|
-
|
||||||
|
Kimberly
A. Dang
|
January 16,
2008
|
$500,000
|
$1,000,000
|
$1,500,000
|
-
|
-
|
||||||||||
|
Steven
J. Kean
|
January 16,
2008
|
750,000
|
1,500,000
|
2,000,000
|
-
|
-
|
||||||||||
|
Joseph
Listengart
|
January 16,
2008
|
500,000
|
1,000,000
|
1,500,000
|
-
|
-
|
||||||||||
|
C.
Park Shaper
|
January 16,
2008
|
750,000
|
1,500,000
|
2,000,000
|
-
|
-
|
||||||||||
____________
|
1
|
See
“Elements of Compensation—Possible Annual Cash Bonus (Non-Equity Cash
Incentive)” above for further discussion of these
awards.
|
Outstanding
Equity Awards at Fiscal Year-End
The
only unvested equity awards outstanding at the end of fiscal 2008 were the
Class B units of Knight Holdco LLC awarded in 2007 by Knight
Holdco LLC to the named executive officers. As a subsidiary of Knight
Holdco LLC, we are allocated a portion of the compensation expense
recognized by Knight Holdco LLC with respect to such units, although none
of us or any of our subsidiaries have any obligation, nor do we expect to pay
any amounts in respect of such units.
|
Stock
Awards
|
||||||
|
Name
|
Type
of Units
|
Number
of Units
that
Have Not Vested
|
Market
Value of
Units
of Stock that
Have Not Vested1
|
|||
|
Richard
D. Kinder
|
Class
B units
|
791,405,452
|
N/A
|
|||
|
Kimberly
A. Dang
|
Class
B units
|
49,462,841
|
N/A
|
|||
|
Steven
J. Kean
|
Class
B units
|
158,281,090
|
N/A
|
|||
|
Joseph
Listengart
|
Class
B units
|
79,140,545
|
N/A
|
|||
|
C.
Park Shaper
|
Class
B units
|
217,636,499
|
N/A
|
|||
____________
|
1
|
Because
the Class B units are equity interests of Knight Holdco LLC, a
private limited liability company, the market value of such interests is
not readily determinable. None of the named executive officers has
received any payments in connection with such units, and none of us or our
subsidiaries are obligated, nor do we expect, to pay any amounts in
respect of such
|
193
|
Item 11. Executive
Compensation (continued)
|
Knight
Form 10-K
|
|
|
units.
See “Elements of Compensation—Other Compensation—Knight Holdco LLC Units”
above for further discussion of these
units.
|
Director
Compensation
Compensation Committee Interlocks
and Insider Participation. Our board has no separate compensation
committee. Mr. Richard D. Kinder as Chief Manager of Knight Holdco makes
compensation decisions with respect to our executive officers. Mr. Kinder
has not served during 2008 on a board of directors of another entity which has
employed any of the members of our current board.
Directors Fees. None of our
directors receive compensation in their capacity as directors. All directors are
reimbursed for reasonable travel and other expenses incurred in attending all
board and/or committee meetings.
Compensation
Committee Report
Because
our board of directors does not have a separate compensation committee or other
committee performing equivalent functions, our board of directors has reviewed
and discussed the above Compensation Discussion and Analysis for fiscal year
2008 with management. Based on this review and discussion, the board has
concluded that this Compensation Discussion and Analysis should be included in
this annual report on Form 10-K for the fiscal year 2008.
Board of
Directors:
Richard
D. Kinder
Kenneth
A. Pontarelli
C.
Park Shaper
194
|
Knight
Form 10-K
|
Security
Ownership
Knight
Midco Inc., an indirect wholly owned subsidiary of Knight Holdco LLC,
owns 100% of our outstanding common stock. The following tables set forth
information as of January 31,
2009, regarding the beneficial ownership of Kinder Morgan Energy
Partners’ common units, Kinder Morgan Management’s shares and Knight Holdco
LLC's units by all of our directors, each of the named executive officers
identified in Item 11 “Executive Compensation” and by all of our directors and
executive officers as a group. Unless otherwise noted, the address of
each person below is c/o Knight Inc., 500 Dallas Street, Suite 1000, Houston,
Texas 77002.
Amount and Nature of Beneficial
Ownership1
|
Kinder
Morgan Energy Partners Common Units
|
Kinder
Morgan Management Shares
|
||||||
|
Number
of
Units
|
Percent
of Class2
|
Number
of Shares
|
Percent
of Class3
|
||||
|
Richard
D. Kinder4
|
315,979
|
*
|
111,782
|
*
|
|||
|
C.
Park Shaper
|
4,000
|
*
|
25,618
|
*
|
|||
|
Kenneth
A. Pontarelli
|
1,000
|
*
|
—
|
—
|
|||
|
Steven
J. Kean
|
—
|
—
|
—
|
—
|
|||
|
Joseph
Listengart
|
4,198
|
*
|
—
|
—
|
|||
|
Kimberly
A. Dang
|
121
|
*
|
473
|
*
|
|||
|
Directors
and Executive Officers as a group (8 persons)5
|
337,484
|
*
|
158,878
|
*
|
|||
____________
*Less than 1%
|
1
|
Except
as noted otherwise, each individual has sole voting power and sole
disposition power over the units and shares
listed.
|
|
2
|
As
of January 31, 2009, Kinder Morgan Energy Partners had 183,169,827 common
units issued and outstanding.
|
|
3
|
As
of January 31, 2009, Kinder Morgan Management had 77,997,906 issued and
outstanding shares representing limited liability company interests,
including two voting shares owned by Kinder
Morgan G.P., Inc.
|
|
4
|
Includes
7,879 common units owned by Mr. Kinder’s spouse. Mr. Kinder
disclaims any and all beneficial or pecuniary interest in these
units.
|
|
5
|
Includes
9,090 common units owned by spouses of our executives and 719 Kinder
Morgan Management shares owned by one of our executives for the benefit of
his children. The executives disclaim any beneficial ownership in such
common units and
shares.
|
Amount and Nature of Beneficial
Ownership1
|
Knight
Holdco LLC
Class
A Units
|
% of Class
A Units2
|
Knight
Holdco LLC Class A-1 Units
|
% of Class
A-1 Units3
|
Knight
Holdco LLC Class B Units
|
% of Class
B Units4
|
|||||||
|
Current
Directors and Executive Officers
|
||||||||||||
|
Richard
D. Kinder5
|
2,424,000,000
|
30.6
|
—
|
—
|
791,405,452
|
40.0
|
||||||
|
C.
Park Shaper6
|
13,598,785
|
*
|
7,799,775
|
28.3
|
217,636,499
|
11.0
|
||||||
|
Steven
J. Kean7
|
6,684,149
|
*
|
3,833,788
|
13.9
|
158,281,090
|
8.0
|
||||||
|
Kimberly
A. Dang8
|
750,032
|
*
|
430,191
|
1.6
|
49,462,841
|
2.5
|
||||||
|
Joseph
Listengart9
|
6,059,449
|
*
|
3,475,483
|
12.6
|
79,140,545
|
4.0
|
||||||
|
Kenneth
A. Pontarelli10
|
1,997,795,088
|
25.2
|
—
|
—
|
—
|
—
|
||||||
|
Directors
and Executive Officers as a group (8 persons)
|
4,453,776,489
|
56.3
|
18,343,384
|
66.5
|
1,400,787,650
|
70.8
|
__________
*Less
than 1%.
|
1
|
Except
as noted otherwise, each individual has sole voting power and sole
disposition power over the units and shares
listed.
|
|
2
|
As
of January 31, 2009,
Knight Holdco LLC had 7,914,367,913 Class A Units issued and
outstanding.
|
|
3
|
As
of January 31, 2009,
Knight Holdco LLC had 27,225,694 Class A-1 Units issued and
outstanding and 345,042 phantom Class A-1 Units issued and
outstanding. The phantom Class A-1 Units were issued to Canadian
management employees.
|
|
4
|
As
of January 31, 2009,
Knight Holdco LLC had 1,927,566,908 Class B Units issued and
outstanding and 50,946,724 phantom Class B Units issued and
outstanding. The phantom Class B Units were issued to Canadian
management employees.
|
195
|
Item
12.Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder
Matters.
(continued)
|
Knight
Form 10-K
|
|
5
|
Includes
522,372 Class A units owned by Mr. Kinder’s wife.
Mr. Kinder disclaims any and all beneficial or pecuniary interest in
the Class A units held by his wife. Also includes 263,801,817
Class B Units that Mr. Kinder transferred to a limited
partnership. Mr. Kinder may be deemed to be the beneficial owner of
these transferred Class B Units, because Mr. Kinder controls the
voting and disposition power of these Class B Units, but he disclaims
ninety-nine percent of any beneficial and pecuniary interest in them.
Mr. Kinder contributed 23,994,827 shares of KMI common stock and his
wife contributed 5,173 shares of KMI common stock to Knight
Holdco LLC that were valued for purposes of Knight Holdco LLC’s
limited liability agreement at $2,423,477,628 and $522,372, respectively,
in exchange for their respective Class A units. The Class B
units received by Mr. Kinder had a grant date fair value as
calculated in accordance with SFAS No. 123R of
$9,200,000.
|
|
6
|
Includes
217,636,499 Class B Units that Mr. Shaper transferred to a
limited partnership. Mr. Shaper may be deemed to be the beneficial
owner of these transferred Class B Units, because Mr. Shaper
controls the voting and disposition power of these Class B Units, but
he disclaims approximately twenty-two percent of any beneficial and
pecuniary interest in them. Mr. Shaper made a cash investment of
$13,598,785 of his after-tax proceeds from the conversion in the Going
Private transaction of 82,500 shares of KMI restricted stock and options
to acquire 197,969 shares of KMI common stock in exchange for his
Class A units. The Class A-1 units and Class B units
received by Mr. Shaper had an aggregate grant date fair value as
calculated in accordance with SFAS No. 123R of
$4,296,125.
|
|
7
|
Mr. Kean
made a cash investment of $6,684,149 of his after-tax proceeds from the
conversion in the Going Private transaction of 78,000 shares of KMI
restricted stock and options to acquire 25,533 shares of KMI common stock
in exchange for his Class A units. The Class A-1 units and
Class B units received by Mr. Kean had an aggregate grant date
fair value as calculated in accordance with SFAS No. 123R of
$2,708,095.
|
|
8
|
Includes
49,462,841 Class B Units that Mrs. Dang transferred to a limited
partnership. Mrs. Dang may be deemed to be the beneficial owner of
these transferred Class B Units, because Mrs. Dang has voting
and disposition power of these Class B Units, but she disclaims ten
percent of any beneficial and pecuniary interest in them. Mrs. Dang
made a cash investment of $750,032 of her after-tax proceeds from the
conversion in the Going Private transaction of 8,000 shares of KMI
restricted stock and options to acquire 24,750 shares of KMI common stock
in exchange for her Class A units. The Class A-1 units and
Class B units received by Mrs. Dang had an aggregate grant date
fair value as calculated in accordance with SFAS No. 123R of
$672,409.
|
|
9
|
Mr. Listengart
made a cash investment of $6,059,449 of his after-tax proceeds from the
conversion in the Going Private transaction of 52,500 shares of KMI
restricted stock and options to acquire 48,459 shares of KMI common stock
in exchange for his Class A units. The Class A-1 units and
Class B units received by Mr. Listengart had an aggregate grant
date fair value as calculated in accordance with SFAS No. 123R of
$1,706,963.
|
|
10
|
Consists
of 240,454,180 units owned by GS Capital Partners V Fund, L.P.; a
Delaware limited partnership; 124,208,587 units owned by GS Capital
Partners V Offshore Fund, L.P., a Cayman Islands exempted limited
partnership; 82,455,031 units owned by GS Capital Partners V
Institutional, L.P., a Delaware limited partnership; 9,533,193 units
owned by GS Capital Partners V GmbH & Co. KG, a German
limited partnership; 233,596,750 units owned by GS Capital Partners VI
Fund, L.P., a Delaware limited partnership; 194,297,556 units owned
by GS Capital Partners VI Offshore Fund, L.P., a Cayman Islands
exempted limited partnership; 64,235,126 units owned by GS Capital
Partners VI Parallel, L.P., a Delaware limited partnership; 8,302,031
units owned by GS Capital Partners VI GmbH & Co. KG, a
German limited partnership; 250,215,732 units owned by Goldman Sachs KMI
Investors, L.P., a Delaware limited partnership; 344,448,791 units
owned by GSCP KMI Investors, L.P., a Delaware limited partnership;
49,873,203 units owned by GSCP KMI Investors Offshore, L.P., a Cayman
Islands exempted limited partnership; 100,534,014 units owned by GS Global
Infrastructure Partners I, L.P., a Delaware limited partnership;
10,740,192 units owned by GS Institutional Infrastructure Partners
I, L.P., a Delaware limited partnership; and 284,900,702 units owned
by GS Infrastructure Knight Holdings, L.P., a Delaware limited
partnership (collectively the “GS Entities”). The GS Entities, of which
affiliates of The Goldman Sachs Group, Inc. (“GSG”) are the general
partner, managing general partner or investment manager, share voting and
investment power with certain of its respective affiliates.
Mr. Pontarelli is a managing director of Goldman,
Sachs & Co. (“GS”), which is a direct and indirect wholly
owned subsidiary of GSG. Each of GS, GSG and Mr. Pontarelli disclaims
beneficial ownership of the equity interests and the units held directly
or indirectly by the GS Entities except to the extent of their pecuniary
interest therein, if any. GS, a NASD member, is an investment banking firm
that regularly performs services such as acting as a financial advisor and
serving as principal or agent in the purchase and sale of securities. In
the future, GS may be called upon to provide similar or other services for
us or our affiliates. Each of Mr. Pontarelli, GS and GSG has a
mailing address of c/o Goldman, Sachs & Co., 85 Broad
Street, 10th Floor, New York, NY 10004. GSG’s affiliates that are
registered broker-dealers (including specialists and market makers) may
from time to time engage in brokerage and trading activities with respect
to our securities or those of our
affiliates.
|
Equity
Compensation Plan Information
The
following table sets forth information regarding our equity compensation
plans as of December 31, 2008. Specifically, the table provides information
regarding our Common Unit Compensation Plan for Non-Employee Directors,
described in Note 17 of the accompanying Notes to the Consolidated Financial
Statements.
196
|
Item
12.Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder
Matters.
(continued)
|
Knight
Form 10-K
|
|
Plan
category
|
Number
of Securities
Remaining
Available for
Future
Issuance Under Equity
Compensation
Plans
|
|||
|
Equity
Compensation Plans Approved by Security Holders
|
─
|
|||
|
Equity
Compensation Plans Not Approved by Security Holders
|
77,882
|
|||
|
Total
|
77,882
|
|||
Policy
Regarding Related Transactions
Our
policy is that (1) employees must obtain authorization from the appropriate
business unit president of the relevant company or head of corporate function
and (2) 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 is
$1.0 million. Any related party transactions that would bring the total
value of such transactions to greater than $1.0 million must be referred to
the audit committee of the appropriate board of directors for approval or to
determine the procedure for approval.
For
information regarding related transactions, see Note 7 of the accompanying
Notes to Consolidated Financial Statements.
Director
Independence
Subsequent
to the Going Private transaction, our common stock is no longer registered with
the SEC or traded on any national securities exchange. However, based upon the
listing standards of the New York Stock Exchange, Mr. Pontarelli would be
considered an “independent” director. Mr. Richard Kinder, our Chairman and
Chief Executive Officer, in his role as Chief Manager of Knight Holdco LLC,
makes compensation decisions with respect to our executive officers. We do not
have a nominating committee or a committee that serves a similar
purpose.
The
following sets forth fees billed for the audit and other services provided by
PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2008 and
2007:
|
Year
Ended December 31,
|
|||||
|
2008
|
2007
|
||||
|
Audit
fees1
|
$
|
4,875,799
|
$
|
5,689,710
|
|
|
Tax
fees2
|
2,568,523
|
2,974,126
|
|||
|
Total
|
$
|
7,444,322
|
$
|
8,663,836
|
|
____________
|
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 professional services rendered for tax return review services and
for federal, state, local and foreign income tax compliance and consulting
services. For 2008 and 2007, amounts include fees of 2,113,318 and
$2,352,533, respectively, billed to Kinder Morgan Energy Partners for
professional services rendered for tax processing and preparation of Forms
K-1 for its unitholders.
|
All
services rendered by PricewaterhouseCoopers LLP are permissible under applicable
laws and regulations, and were pre-approved by our audit committee. Pursuant to
the charter of our audit committee, the committee’s primary purposes include the
following: (i) to select, appoint, engage, oversee, retain, evaluate and
terminate our external auditors; (ii) 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 (iii) 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 2008. The audit committee has also considered whether such non audit
services are compatible with maintaining the external auditors’ independence and
has concluded that they are compatible at this time.
197
|
Item 14. Principal
Accounting Fees and Services (continued)
|
Knight
Form 10-K
|
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): (i) the
auditors’ internal quality-control procedures; (ii) any material issues raised
by the most recent internal quality-control review, or peer review, of the
external auditors; (iii) the independence of the external auditors; and (iv) the
aggregate fees billed by our external auditors for each of the previous two
fiscal years.
198
|
Knight
Form 10-K
|
|
(a)
|
(1)
|
Financial
Statements
|
Reference
is made to the index of financial statements and supplementary data under Item 8
in Part II.
|
(2)
|
Financial
Statement Schedules
|
Schedule
II - Valuation and Qualifying Accounts is omitted because the required
information is shown in Note 1 of the accompanying Notes to Consolidated
Financial Statements.
The
financial statements, including the notes thereto, of Kinder Morgan Energy
Partners, an equity method investee of Knight Inc., are incorporated herein by
reference to pages 123 through 215 of Kinder Morgan Energy Partners’ Annual
Report on Form 10-K for the year ended December 31, 2008.
|
(3)
|
Exhibits
|
In
reviewing the documents included or incorporated by reference as exhibits to
this report, please remember they are included to provide you with information
regarding their terms and are not intended to provide any other factual or
disclosure information about us or any other parties to the documents. Some of
the documents are agreements that contain representations and warranties by one
or more of the parties of the applicable agreement. These representations and
warranties were made solely for the benefit of the other parties to the
applicable agreement and:
|
|
·
|
should
not be treated as categorical statements of fact, but rather as a way of
allocating the risk to one of the parties if those statements prove to be
inaccurate;
|
|
|
·
|
may
have been qualified by disclosures that were made to the other party in
connection with the negotiation of the applicable agreement, which
disclosures are not necessarily reflected in the
agreement;
|
|
|
·
|
may
apply standards of materiality in a way that is different from what may be
viewed as material to you or other readers;
and
|
|
|
·
|
may
apply only as of the date of the applicable agreement or such other date
or dates as may be specified in the agreement and are subject to more
recent developments.
|
Accordingly,
these representations and warranties may not describe the actual state of
affairs as of the date they were made or at any other time.
Any
references made to K N Energy, Inc. or Kinder Morgan, Inc. in the exhibit
listing that follows are references to the former names of Knight Inc. and are
made because the exhibit being listed and incorporated by reference was
originally filed before the respective date of the change in Knight Inc.’s
name.
Exhibit
Number Description
|
|
2.1
|
—
|
Agreement
and Plan of Merger dated August 28, 2006, among Kinder Morgan, Inc.,
Knight Holdco LLC and Knight Acquisition Co. (filed as Exhibit 2.1 to
Knight Inc.’s Current Report on Form 8-K filed on August 28, 2006 and
incorporated herein by reference)
|
|
|
3.1
|
—
|
Amended
and Restated Articles of Incorporation of Knight Inc. and amendments
thereto (filed as Exhibit 3.1 to Knight Inc.’s Quarterly Report on Form
10-Q for the quarter ended June 30, 2007 and incorporated herein by
reference)
|
|
|
3.2
|
—
|
Bylaws
of Kinder Morgan, Inc. (filed as Exhibit 3.2 to Knight Inc.’s Current
Report on Form 8-K filed on June 5, 2007 and incorporated herein by
reference)
|
|
|
4.1
|
—
|
Indenture
dated as of September 1, 1988, between K N Energy, Inc. and Continental
Illinois National Bank and Trust Company of Chicago (filed as Exhibit 4(a)
to Knight Inc.’s Annual Report on Form 10-K/A, Amendment No. 1 filed on
May 22, 2000 and incorporated herein by
reference)
|
|
|
4.2
|
—
|
First
supplemental indenture dated as of January 15, 1992, between
K N Energy, Inc. and Continental Illinois National Bank and
Trust Company of Chicago (filed as Exhibit 4.2 to the Registration
Statement on Form S-3 (File No. 33-45091) of K N Energy, Inc. filed on
January 17, 1992 and incorporated herein by
reference)
|
|
|
4.3
|
—
|
Second
supplemental indenture dated as of December 15, 1992, between
K N Energy, Inc. and Continental Bank, National Association
(filed as Exhibit 4(c) to Knight Inc.’s Annual Report on Form 10-K/A,
Amendment No. 1 filed on May 22, 2000 and incorporated herein by
reference)
|
199
|
Item 15. Exhibits,
Financial Statement Schedules. (continued)
|
Knight
Form 10-K
|
Exhibit
Number Description
|
|
4.4
|
—
|
Indenture
dated as of November 20, 1993, between K N Energy, Inc. and Continental
Bank, National Association (filed as Exhibit 4.1 to the Registration
Statement on Form S-3 (File No. 33-51115) of K N Energy, Inc. filed on
November 19, 1993 and incorporated herein by
reference)
|
|
|
4.5
|
—
|
Registration
Rights Agreement among Kinder Morgan Management, LLC, Kinder Morgan Energy
Partners, L.P. and Kinder Morgan, Inc. dated May 18, 2001 (filed as
Exhibit 4.7 to Knight Inc.’s Annual Report on Form 10-K for the year ended
December 31, 2002 and incorporated herein by
reference)
|
|
|
4.6
|
—
|
Form
of Indenture dated as of August 27, 2002 between Kinder Morgan, Inc. and
Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to
Knight Inc.’s Registration Statement on Form S-4 (File No. 333-100338)
filed on October 4, 2002 and incorporated herein by
reference)
|
|
|
4.7
|
—
|
Form
of First Supplemental Indenture dated as of December 6, 2002 between
Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee
(filed as Exhibit 4.2 to Knight Inc.’s Registration Statement on Form S-4
(File No. 333-102873) filed on January 31, 2003 and incorporated herein by
reference)
|
|
|
4.8
|
—
|
Form
of 6.50% Note (included in the Indenture filed as Exhibit 4.6 hereto and
incorporated herein by reference)
|
|
|
4.9
|
—
|
Form
of Senior Indenture between Kinder Morgan, Inc. and Wachovia Bank,
National Association, as Trustee (filed as Exhibit 4.2 to Knight Inc.’s
Registration Statement on Form S-3 (File No. 333-102963) filed on February
4, 2003 and incorporated herein by
reference)
|
|
|
4.10
|
—
|
Form
of Senior Note of Kinder Morgan, Inc. (included in the Form of Senior
Indenture filed as Exhibit 4.9 hereto and incorporated herein by
reference)
|
|
|
4.11
|
—
|
Form
of Subordinated Indenture between Kinder Morgan, Inc. and Wachovia Bank,
National Association, as Trustee (filed as Exhibit 4.4 to Knight Inc.’s
Registration Statement on Form S-3 (File No. 333-102963) filed on February
4, 2003 and incorporated herein by
reference)
|
|
|
4.12
|
—
|
Form
of Subordinated Note of Kinder Morgan, Inc. (included in the Form of
Subordinated Indenture filed as Exhibit 4.11 hereto and incorporated
herein by reference)
|
|
|
4.13
|
—
|
Indenture
dated as of December 9, 2005, among Kinder Morgan Finance Company, LLC,
Kinder Morgan, Inc. and Wachovia Bank, National Association, as Trustee
(filed as Exhibit 4.1 to Knight Inc.’s Current Report on Form 8-K filed on
December 15, 2005 and incorporated herein by
reference)
|
|
|
4.14
|
—
|
Forms
of Kinder Morgan Finance Company, LLC notes (included in the Indenture
filed as Exhibit 4.13 hereto and incorporated herein by
reference)
|
|
|
4.15
|
—
|
Certificate
of the President and the 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 (filed as Exhibit
1.01 to Kinder Morgan Energy Partners, L.P.’s Quarterly Report on Form
10-Q for the quarter ended March 31, 2007 and incorporated herein by
reference)
|
|
|
4.16
|
—
|
Certificate
of the Vice President and Treasurer and the 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 5.85% senior notes due 2012 (filed as Exhibit 4.2 to Kinder
Morgan Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2007 and incorporated herein by
reference)
|
|
|
4.17
|
—
|
Certificate
of the Vice President and Treasurer and the 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 6.95% Senior Notes due 2038 (filed as Exhibit 4.2 to Kinder
Morgan Energy Partners, L.P.'s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2007 and incorporated herein by
reference)
|
|
|
4.18
|
—
|
Certificate
of the Vice President and Treasurer and the 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 5.95% Senior Notes due 2018 (filed as Exhibit 4.28 to Kinder
Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for 2007 and
incorporated herein by reference)
|
|
|
4.19
|
—
|
Indenture
dated as of December 21, 2007, between NGPL PipeCo LLC and U.S. Bank
National Association, as Trustee (filed as Exhibit 4.1 to Knight Inc.’s
Current Report on Form 8-K filed on December 21, 2007 and incorporated
herein by reference)
|
|
|
4.20
|
—
|
Forms
of notes of NGPL PipeCo LLC (included in the Indenture filed as Exhibit
4.19 hereto and incorporated herein by
reference)
|
200
|
Item 15. Exhibits,
Financial Statement Schedules. (continued)
|
Knight
Form 10-K
|
Exhibit
Number Description
|
|
4.21
|
—
|
Certificate
of the Vice President and Treasurer and the 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 9.00% Senior Notes due 2019 (filed as Exhibit 4.29 to Kinder
Morgan Energy Partners, L.P.'s Annual Report on Form 10-K for 2008 and
incorporated herein by reference)
|
|
|
4.22
|
—
|
Certain
instruments with respect to the long-term debt of Knight Inc. and its
consolidated subsidiaries that relate to debt that does not exceed 10% of
the total assets of Knight Inc. 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. Knight Inc. hereby agrees to furnish supplementally to the
Securities and Exchange Commission a copy of each such instrument upon
request.
|
|
|
10.1
|
—
|
2005
Annual Incentive Plan of Kinder Morgan, Inc. (filed as Appendix D to
Kinder Morgan, Inc.’s 2006 Proxy Statement on Schedule 14A and
incorporated herein by reference)
|
|
|
10.2
|
—
|
Employment
Agreement dated October 7, 1999, between the Company and Richard D. Kinder
(filed as Exhibit 99.D of the Schedule 13D filed by Mr. Kinder on November
16, 1999 and incorporated herein by
reference)
|
|
|
10.3
|
—
|
Form
of Purchase Provisions between Kinder Morgan Management, LLC and Knight
Inc. (included as Annex B to the Second Amended and Restated Limited
Liability Company Agreement of Kinder Morgan Management, LLC filed as
Exhibit 3.1 to Kinder Morgan Management, LLC’s Current Report on Form 8-K
filed on May 30, 2007 and incorporated herein by
reference)
|
|
|
10.4
|
—
|
Credit
Agreement, dated as of May 30, 2007, among Kinder Morgan, Inc. and Knight
Acquisition Co., as the borrower, the several lenders from time to time
parties thereto, and Citibank, N.A., as administrative agent and
collateral agent (filed as Exhibit 4.1 to Kinder Morgan, Inc.’s Current
Report on Form 8-K, filed on June 5, 2007 and incorporated herein by
reference)
|
|
|
10.5
|
—
|
Form
of Indemnification Agreement between Knight Inc. and each member of the
Special Committee of the Board of Directors (filed as Exhibit 10.1 to
Knight Inc.’s Current Report on Form 8-K filed on June 16, 2006 and
incorporated herein by reference)
|
|
|
10.6
|
—
|
Acquisition
Agreement dated as of February 26, 2007, by and among Kinder Morgan, Inc.,
3211953 Nova Scotia Company and Fortis Inc. (filed as Exhibit 1.01 to
Kinder Morgan, Inc.’s Current Report on Form 8-K filed on March 1, 2007
and incorporated herein by
reference)
|
|
|
10.7
|
—
|
Retention
and Relocation Agreement, dated as of March 5, 2007, between Kinder
Morgan, Inc. and Scott E. Parker (filed as Exhibit 10.2 to Kinder Morgan,
Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007
and incorporated herein by
reference)
|
|
|
10.8
|
—
|
Purchase
Agreement, dated as of December 10, 2007, between Knight Inc. and Myria
Acquisition Inc. (filed as Exhibit 10.1 to Knight Inc.’s Current Report on
Form 8-K filed on December 11, 2007 and incorporated herein by
reference)
|
|
|
10.9
|
—
|
First
Amendment to Retention and Relocation Agreement dated as of July 16, 2008,
between Knight Inc. and Scott E. Parker (filed as Exhibit 10.1 to Knight
Inc.'s Current Report on Form 8-K filed on July 25, 2008 and incorporated
herein by reference)
|
|
|
21.1*
|
—
|
Subsidiaries
of the Registrant
|
|
|
31.1*
|
—
|
Certification
of Chief Executive Officer 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
of Chief Financial Officer 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
of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
|
|
32.2*
|
—
|
Certification
of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
|
|
99.1
|
—
|
The
financial statements of Kinder Morgan Energy Partners, L.P. and
subsidiaries (incorporated by reference to pages 123 through 215 of the
Annual Report on Form 10-K of Kinder Morgan Energy Partners, L.P. for the
year ended December 31, 2008)
|
__________
*Filed
herewith.
|
|
201
|
Knight
Form 10-K
|
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.
|
|
KNIGHT
INC.
(Registrant)
|
||
|
By
|
/s/
Kimberly A. Dang
|
||
|
|
Kimberly
A. Dang
Vice
President and Chief Financial Officer
|
||
|
Date:
March 31, 2009
|
|
||
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities set forth below and as of the date set forth above.
|
|
||
|
/s/
Kimberly A. Dang
|
Vice
President and Chief Financial Officer (Principal
|
|
|
Kimberly
A. Dang
|
Financial
Officer and Principal Accounting Officer)
|
|
|
|
||
|
/s/
Richard D. Kinder
|
Director,
Chairman and Chief Executive Officer
|
|
|
Richard
D. Kinder
|
(Principal
Executive Officer)
|
|
|
|
||
|
/s/
Kenneth A. Pontarelli
|
Director
|
|
|
Kenneth
A. Pontarelli
|
||
|
|
||
|
/s/
C. Park Shaper
|
Director
|
|
|
C.
Park Shaper
|
||
|
|
202