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
|
|||||||||