UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549Form 10-K  x
ANNUAL REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2008Oro
TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from         to Commission file number: 1-11234 Kinder Morgan
Energy Partners, L.P.(Exact name of registrant as
specified in its charter) Delaware
76-0380342(State or other jurisdiction of
(I.R.S. Employerincorporation or organization)
Identification No.) 500 Dallas,
Suite 1000, Houston, Texas 77002(Address of principal executive
offices)(zip code) Registrants
telephone number, including area code: 713-369-9000
  Securities
registered pursuant to Section 12(b) of the Act:
  Title of each class
Name of each
 exchange on which registeredCommon Units
New York Stock Exchange Securities
registered Pursuant to Section 12(g) of the Act:
None Indicate by check
mark if the registrant is a well-known seasoned issuer, as defined in Rule 405
of the Securities Act of 1933. Yes x No o Indicate by
check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes o No x Indicate by
check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or  15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes x No o Indicate by
check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. x Indicate by
check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company (as defined in
Rule 12b-2 of the Securities Exchange Act of 1934).
 Large accelerated filer x    Accelerated filer o    Non-accelerated filer o    Smaller reporting company o
 Indicate by check
mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Securities
Exchange Act of 1934). Yes o No x Aggregate
market value of the voting and non-voting common equity held by non-affiliates
of the registrant, based on closing prices in the daily composite list for
transactions on the New York Stock Exchange on June 30, 2008 was approximately
$9,043,981,544. As of January 31, 2009, the registrant had 183,169,827 Common
Units outstanding. 1    KINDER MORGAN
ENERGY PARTNERS, L.P.

TABLE OF
CONTENTS

Page
 NumberPART IItems 1 and 2.
Business and Properties

3General
 Development of Business

3Organizational
 Structure

3Recent
 Developments

4Financial
 Information about Segments

9Narrative
 Description of Business

9Business Strategy

9Business Segments

9Products
 Pipelines

10Natural Gas
 Pipelines

15CO2

23Terminals

27Kinder Morgan
 Canada

29Major Customers

31Regulation

32Environmental
 Matters

35Other

37Financial
 Information about Geographic Areas

38Available
 Information

38Item 1A.
Risk Factors

38Item 1B.
Unresolved Staff Comments

51Item 3.
Legal Proceedings

51Item 4.
Submission of Matters to a Vote of Security Holders

51PART
 IIItem 5.
Market for Registrants Common Equity, Related Stockholder Matters and Issuer
 Purchases of Equity Securities

52Item 6.
Selected
 Financial Data

53Item 7.
Managements Discussion and Analysis of Financial Condition and Results of
 Operations

55Critical
 Accounting Policies and Estimates

57Results of
 Operations

60Liquidity and
 Capital Resources

77Recent
 Accounting Pronouncements

91Information
 Regarding Forward-Looking Statements

91Item 7A.
Quantitative and Qualitative Disclosures About Market Risk

93Energy Commodity
 Market Risk

93Interest Rate
 Risk

95Item 8.
Financial
 Statements and Supplementary Data

96Item 9.
Changes in
 and Disagreements with Accountants on Accounting and Financial Disclosure

96Item 9A.
Controls
 and Procedures

96Item 9B.
Other
 Information

97PART
 IIIItem 10.
Directors, Executive Officers and Corporate Governance

98Directors and
 Executive Officers of our General Partner and its Delegate

98Corporate
 Governance

100Section 16(a)
 Beneficial Ownership Reporting Compliance

101Item 11.
Executive Compensation

101Item 12.
Security
 Ownership of Certain Beneficial Owners and Management and Related Stockholder
 Matters

113Item 13.
Certain
 Relationships and Related Transactions, and Director Independence

116Item 14.
Principal Accounting Fees and Services

117PART
 IVItem 15.
Exhibits
 and Financial Statement Schedules

119Index to
 Financial Statements

123Signatures

2162

PART I

Items 1 and 2. Business and Properties.

In this
report, unless the context requires otherwise, references to we, us, our,
KMP or the Partnership are intended to mean Kinder Morgan Energy Partners,
L.P., a Delaware limited partnership formed in August 1992, our operating
limited partnerships and their subsidiaries. Our common units, which represent
limited partner interests in us, trade on the New York Stock Exchange under the
symbol KMP. The address of our principal executive offices is 500 Dallas,
Suite 1000, Houston, Texas 77002, and our telephone number at this address is
(713) 369-9000. You should
read the following discussion and analysis in conjunction with our consolidated
financial statements included elsewhere in this report. All dollars in
this report are United States dollars, except where stated otherwise. Canadian
dollars are designated as C$.

(a) General
Development of Business

Organizational
Structure

Kinder
Morgan Energy Partners, L.P. is a leading pipeline transportation and energy
storage company in North America. We own an interest in or operate more than
26,000 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. As one of the largest publicly traded pipeline
limited partnerships in America, we have an enterprise value of over $20
billion.

Our
general partner is Kinder Morgan G.P., Inc., a Delaware corporation. On July
27, 2007, our general partner issued and sold 100,000 shares of Series A
fixed-to-floating rate term cumulative preferred stock due 2057. The consent of
holders of a majority of these preferred shares is required with respect to a
commencement of or a filing of a voluntary bankruptcy proceeding with respect
to us, or two of our subsidiaries: SFPP, L.P. and Calnev Pipe Line LLC.

Knight
Inc., a Kansas corporation and a private company formerly known as Kinder
Morgan, Inc., indirectly is the sole owner of the common stock of our general
partner. On August 28, 2006, Kinder Morgan, Inc., a Kansas corporation referred
to as KMI in this report, entered into an agreement and plan of merger
whereby generally each share of KMI common stock would be converted into the
right to receive $107.50 in cash without interest. KMI in turn would merge with
a wholly-owned subsidiary of Knight Holdco LLC, a privately owned company in
which Richard D. Kinder, Chairman and Chief Executive Officer of KMI, would be
a major investor. On May 30, 2007, the merger closed, with KMI continuing as
the surviving legal entity and subsequently renamed Knight Inc., referred to
as Knight in this report. This transaction is referred to in this report as
the going-private transaction.

As of
December 31, 2008, Knight and its consolidated subsidiaries owned, through its
general and limited partner interests, an approximate 14.1% interest in us. In
addition to the distributions it receives from its limited and general partner
interests, Knight also receives an incentive distribution from us as a result
of its ownership of our general partner. Including both its general and limited
partner interests in us, at the 2008 distribution level, Knight received
approximately 51% of all quarterly Available Cash distributions (as defined
in our partnership agreement) from us, with approximately 44% and 7% of all
quarterly distributions from us attributable to Knights general partner and
limited partner interests, respectively.

Kinder
Morgan Management, LLC, referred to as KMR in this report, is a Delaware
limited liability company formed in February 2001. KMRs shares represent limited liability company interests and trade on
the New York Stock Exchange under the symbol KMR. Our general partner owns
all of KMRs voting securities and, pursuant to a delegation of control
agreement, our general partner has delegated to KMR, to the fullest extent
permitted under Delaware law and our partnership agreement, all of its power
and authority to manage and control our business and affairs, except that KMR
cannot take certain specified actions without the approval of our general
partner. Under the delegation of control agreement, KMR, as the delegate of our
general partner, manages and controls our business

3

and affairs and the business and affairs of our operating limited partnerships and their
subsidiaries. Furthermore, in accordance with its limited liability company
agreement, KMRs activities are limited to being a limited partner in, and
managing and controlling the business and affairs of us, our operating limited
partnerships and their subsidiaries.

In general,
our limited partner units, consisting of i-units, common units and Class B
units (the Class B units are similar to our common units except
that they are not eligible for trading on the New York Stock Exchange), will vote together as a single class, with each
i-unit, common unit and Class B unit having one vote. We pay our quarterly
distributions from operations and interim capital transactions to our common
and Class B unitholders in cash, and we pay our quarterly distributions to KMR
in additional i-units rather than in cash. As of December 31, 2008, KMR,
through its ownership of our i-units, owned approximately 29.3% of all of our outstanding
limited partner units.

Recent
Developments

The
following is a brief listing of significant developments since December 31,
2007. We begin with developments pertaining to our five reportable business
segments, described more fully below in (c) Narrative Description of
BusinessBusiness Segments. Additional information regarding most of these
items may be found elsewhere in this report. All dollars in this
report are United States dollars, except where stated otherwise. Canadian
dollars are designated as C$.

Products
Pipelines


In October 2008, we 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, we began batching
 denatured ethanol shipments along with gasoline shipments for our customers,
 making our Central Florida Pipeline the first gasoline pipeline in the U.S.
 capable of also handling ethanol in commercial movements.In addition to the Central Florida Pipeline ethanol
project, we have
 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. We plan on offering ethanol blending
 capabilities in twelve of fifteen markets served by our Southeast terminals by
 the end of 2009.
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 expects to be moving forward with investments to provide this
 service during the second quarter of 2009.
In November 2008, our West Coast
Products
 operations 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.
On December 10, 2008, our West
Coast
 Products operations purchased a 200,000 barrel refined petroleum products
 terminal located in Phoenix, Arizona from ConocoPhillips for approximately
 $27.5 million in cash.Natural Gas
Pipelines
Effective April 1, 2008, we sold
our 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. Our investment in net assets, including all transaction
 related accruals, was approximately $37.7 million, and we recognized $13.0
 million of gain on the sale of our investment. We reported the gain within
 the caption4

Other, net on our accompanying
consolidated statements of income. For additional information regarding this
 divestiture, see Note 3 to our consolidated financial statements.
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 our Kinder Morgan Interstate Gas Transmission Pipeline,
 Northern Natural Gas Company, Natural Gas Pipeline Company of America LLC,
 ANR and Panhandle Eastern Pipeline Company.
On May 30, 2008, the Federal
Energy
 Regulatory Commission, referred to in this report as the 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. We are a 51%
 owner in Rockies Express, and we currently estimate the total project cost
 for the entire Rockies Express Pipeline to be approximately $6.2 billion.Construction on Rockies Express-East 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.
In June 2008, our 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, our
 intrastate 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.
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 along with the lease of 272 million cubic feet of
 capacity on the Oklahoma intrastate system of Enogex Inc. We own a 50%
 interest in Midcontinent Express Pipeline LLC, the sole owner of the
 Midcontinent Express Pipeline. Energy Transfer Partners L.P. owns the
 remaining interest.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 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 to be available
 in April of 2009. The second
 construction phaseto the Transco Pipelineis expected to be completed by
 August 1, 2009. The Midcontinent Express capacity is fully subscribed with
 long-term binding commitments from creditworthy shippers.
In September 2008, we completed
 construction on an approximately $75 million natural gas pipeline that
 transports additional East Texas natural gas supplies to markets in the
 Houston and Beaumont, Texas areas. It connects our Kinder Morgan Tejas system
 in Houston County, Texas to our Kinder Morgan Texas Pipeline system in Polk
 County near Goodrich, Texas. We entered into a long-term binding agreement
 with5

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.
On October 1, 2008, we and
Energy Transfer
 Partners, L.P. announced that we have entered into 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.
 This 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.
In October 2008, we completed
construction
 on an approximately $22 million expansion project on our Kinder Morgan
 Interstate Gas Transmission 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.
On November 24, 2008, our Kinder
Morgan
 Interstate Gas Transmission system completed construction and placed into
 service its previously announced Colorado Lateral Pipeline. The approximately
 $39 million expansion project that 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.CO2
As of February 1, 2009, our
CO2
 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 our customers.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, we activated the Blanco pump station on
 the Cortez Pipeline utilizing power from diesel generators, and in January
 2009, we 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. We own a 50% interest in the Cortez
 Pipeline, which currently delivers approximately 1.3 billion cubic feet per
 day of carbon dioxide.Terminals
On January 16, 2008, we
announced plans to
 invest approximately $56 million to construct a petroleum coke terminal at
 the BP refinery located in Whiting, Indiana. We have 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.
On March 20, 2008, we announced
 the completion of several expansion projects representing a 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 our combined Galena Park/Pasadena, Texas
 liquids terminal facilities located on the Houston, Texas Ship Channel; (ii)
 an approximately C$170 million investment to construct our 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 our Pier IX bulk terminal located in Newport
 News, Virginia; and (iv)6

approximately $68 million for the construction of
nine new liquid
 storage tanks at our Perth Amboy, New Jersey liquids terminal located on the
 New York Harbor.The storage expansion at our Galena
 Park/Pasadena terminals brings total capacity of the combined complex to approximately
 25 million barrels. As previously announced, the building of
 our 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.
Effective August 5, 2008, we
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.
In December 2008, we began
operations at
 our approximately $47 million terminal at the Rubicon Plant site located in
 Geismar, Louisiana, which offers liquids storage, transfer and packaging
 facilities. The newly constructed terminal has liquids storage capacity of
 approximately 123,500 barrels and has approximately 144,000 square feet of
 warehouse space.Kinder Morgan
 Canada
Effective August 28, 2008, we
acquired a 33
 1/3% equity ownership interest in the Express and Platte crude oil pipeline
 systems from Knight. We also acquired full ownership of an approximate
 25-mile Jet Fuel pipeline system that serves the Vancouver (Canada)
 International Airport. As consideration for these assets, we paid to Knight
 approximately two million of our common units, valued at $116.0 million. For additional information regarding this
 acquisition, see Note 3 to our consolidated financial statements.
On October 30, 2008, we
completed the
 construction and commissioning of our approximately C$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. In April 2007, we completed
 the first phase of the Trans Mountain Pipeline expansion, which included the
 commissioning of ten new pump stations that boosted pipeline capacity from
 225,000 to approximately 260,000 barrels per day.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 and 36-inch diameter pipe 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 pipe 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 for summer 2009.Debt and Equity
 Offerings, Swap Agreements, Cash Distributions and Debt Retirements
On February 12, 2008, we
completed a public
 offering of senior notes. We issued a total of $900 million in principal
 amount of senior notes, consisting of $600 million of 5.95% notes due
 February 15, 2018, and $300 million of 6.95% notes due January 15, 2038. We
 used the net proceeds to reduce the borrowings under our commercial paper
 program.Also on this date, we completed an offering of
1,080,000 of our
 common units at a price of $55.65 per unit in a privately negotiated
 transaction and we used the net proceeds to reduce the borrowings under our
 commercial paper program.7


In March 2008, we completed a
public
 offering of 5,750,000 of our common units at a price of $57.70 per unit, less
 commissions and underwriting expenses and we used the net proceeds to reduce
 the borrowings under our commercial paper program.
On June 6, 2008, we completed a
$700
 million public offering of senior notes and we used the net proceeds to
 reduce the borrowings under our commercial paper program.
On November 24, 2008, we
announced that we
 expect to declare cash distributions of $4.20 per unit for 2009, a 4.5% increase over our cash distributions of
$4.02 per unit for 2008.  Our expected growth in distributions in 2009 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, our average realized price for 2009 is currently projected to be $43
per barrel.  Although the majority of the cash generated by our assets is fee based and is not sensitive to
commodity prices, our CO2 business segment is exposed to commodity price risk related to the price volatility of
crude oil and natural gas liquids.  We hedge the majority of our crude oil production, but do have exposure to
unhedged volumes, the majority of which are natural gas liquids volumes.  For 2009, we expect that every $1
change in the average WTI crude oil price per barrel will impact our CO2 segments cash flows by approximately $6
million (or approximately 0.2% of our combined business segments anticipated distributable cash flow).  This
sensitivity to the average WTI price is very similar to what we experienced in 2008.  Our 2009 cash distribution
expectations do not take into account any capital costs associated with financing any payment we may be required
to make of reparations sought by shippers on our Pacific operations interstate pipelines.
On December 19, 2008, we closed
a public
 offering of $500 million in principal amount of senior notes and we used the
 proceeds to reduce the borrowings under our five-year unsecured revolving
 bank credit facility.
On December 22, 2008, we
completed a public
 offering of 3,900,000 of our common units at a price of $46.75 per unit, less
 commissions and underwriting expenses. We used the net proceeds to reduce the
 borrowings under our bank credit facility.
In December 2008 and January
2009, we
 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 we received combined proceeds of $338.7
 million from the early termination of these swap agreements;
On February 2, 2009, we paid
$250 million
 to retire the principal amount of our 6.3% senior notes that matured on that
 date.Capital
Expansion Projects

Our capital
expansion program in 2008 was approximately $2.9 billion (for
maintenance/sustaining and expansion/discretionary capital spending, and
including our equity contributions to the Rockies Express, Midcontinent
Express, and Fayetteville Express natural gas pipeline projects). In 2009, we
expect our capital expansion program to be approximately $2.8 billion
(including our equity contributions to the Rockies Express and Midcontinent
Express projects), which will help drive earnings and cash flow growth in 2009
and beyond.

In
addition to the ongoing construction of both the Rockies Express-East pipeline
segment and the Midcontinent Express Pipeline discussed above in Natural Gas
Pipelines, construction and/or expansion plans continue on the following major
projects:


Kinder Morgan Louisiana Pipeline.
 Construction continues on our fully-owned Kinder Morgan Louisiana Pipeline
 and our 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 we anticipate the pipeline
 to become fully operational in the second quarter of 2009.
Rockies Express Pipeline.
Rockies Express
 is requesting authorization to construct and operate certain facilities that
 will comprise its Meeker, Colorado to Cheyenne, Wyoming expansion project.
 The proposed expansion will add additional natural gas compression.  The
 expansion is fully contracted and is expected8

to be operational in April 2010.
The total
 estimated cost for the proposed project is approximately $78 million.
Cora Terminal. Construction
continues on an
 approximately $13 million expansion at our 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. We expect the Cora expansion project
 to be completed in the second quarter of 2009.(b) Financial Information About SegmentsFor
 financial information on our five reportable business segments, see Note 15
 to our consolidated financial statements.(c) Narrative Description of BusinessBusiness StrategyThe objective of our business strategy is to grow our portfolio of
 businesses by:
focusing on stable, fee-based
 energy transportation and storage assets that are core to the energy
 infrastructure of growing markets within North America;
increasing utilization of our
 existing assets while controlling costs, operating safely, and employing
 environmentally sound operating practices;
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
maximizing the benefits of our
 financial structure to create and return value to our unitholders.It
is our intention to carry out the above business strategy, modified as
necessary to reflect changing economic conditions and other circumstances.
However, as discussed under Item 1A. Risk
Factors below, there are factors that could affect our ability to carry out
our strategy or affect its level of success even if carried out.

We
regularly consider and enter into discussions regarding potential acquisitions,
including those from Knight or its affiliates, and are currently contemplating
potential acquisitions. Any such transaction would be subject to negotiation of
mutually agreeable terms and conditions, receipt of fairness opinions and
approval of the parties respective boards of directors. While there are
currently no unannounced purchase agreements for the acquisition of any
material business or assets, such transactions can be effected quickly, may
occur at any time and may be significant in size relative to our existing
assets or operations.

Business
Segments

We
own and manage a diversified portfolio of energy transportation and storage
assets. Our operations are conducted through our five operating limited
partnerships and their subsidiaries and are grouped into five reportable
business segments. These segments are as follows:


Products Pipelines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which
 consists of approximately 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;9


CO2 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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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. It also includes a
 one-third interest in an approximately 1,700-mile integrated crude oil
 pipeline connecting Canadian and United States producers to refineries in the
 U.S. Rocky Mountain and Midwest regions, and a 25-mile aviation turbine fuel
 pipeline serving the Vancouver International Airport.Generally,
as utilization of our pipelines and terminals increases, our fee-based revenues
increase. We do not face significant risks relating directly to short-term
movements in commodity prices for two principal reasons. First, we primarily
transport and/or handle products for a fee and are not engaged in significant
unmatched purchases and resales of commodity products. Second, in those areas
of our business where we do face exposure to fluctuations in commodity prices,
primarily oil production in our CO2 business segment, we engage in a
hedging program to mitigate this exposure.

Products
Pipelines

Our
Products Pipelines segment consists of our refined petroleum products and
natural gas liquids pipelines and their associated terminals, our Southeast
terminals and our transmix processing facilities.

West
Coast Products Pipelines

Our West
Coast Products Pipelines operations include our SFPP, L.P. operations, our
Calnev Pipeline operations and our West Coast Terminals operations. The
assets include interstate common carrier pipelines regulated by the FERC, intrastate
pipelines in the state of California regulated by the California Public
Utilities Commission, and certain non rate-regulated operations and terminal
facilities.

Our SFPP,
L.P. operations, also referred to in this report as Pacific operations, serve
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%).

Our Calnev
Pipeline consists of two parallel 248-mile, 14-inch and 8-inch diameter
pipelines that run from our facilities at Colton, California to Las Vegas,
Nevada. 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 Vegas, and also includes approximately 55 miles
of pipeline serving Edwards Air Force Base.

Our West
Coast Products Pipelines operations 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.

Our 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.

10

Markets.Combined, our West
Coast Products Pipelines operations 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, our West Coast Products Pipelines operations
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, and generally, in turn the volumes we transport, depends on such
factors as prevailing economic conditions, vehicular use and purchase patterns
and demographic changes in the markets served. Certain product volumes can also
experience seasonal variations and, consequently, overall volumes may be lower
during the first and fourth quarters of each year.

Supply.The majority of
refined products supplied to our West Coast Product Pipelines operations
pipeline system come from the major refining centers around Los Angeles, San
Francisco, West Texas and Puget Sound, as well as from waterborne terminals and
connecting pipelines located near these refining centers.

Competition.The two most
significant competitors of our West Coast Products Pipelines operations
pipeline system are proprietary pipelines owned and operated by major oil
companies in the area where our pipeline system delivers products and also
refineries with terminals that have trucking arrangements within our market
areas. We believe that high capital costs, tariff regulation, and environmental
and right-of-way permitting considerations make it unlikely that a competing
pipeline system comparable in size and scope to our West Coast Products
Pipelines operations 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. Our West Coast Products Pipelines terminal operations compete with
terminals owned by our 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

We own
approximately 51% of Plantation Pipe Line Company, referred to in this report
as 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. We operate 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 the 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 part 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.

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

11

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

Our Central
Florida pipeline system consists of (i) a 110-mile, 16-inch diameter pipeline
that transports gasoline and beginning in November 2008, ethanol and (ii) an
85-mile, 10-inch diameter pipeline that transports diesel fuel and jet fuel
from Tampa to Orlando, with an intermediate delivery point on the 10-inch
pipeline at Intercession City, Florida. In addition to being connected to our
Tampa terminal, the pipeline system is connected to terminals owned and
operated by TransMontaigne, Citgo, BP, and Marathon Petroleum. The 10-inch
diameter pipeline is connected to our Taft, Florida terminal (located near
Orlando) and is also the sole pipeline supplying jet fuel to the Orlando
International Airport in Orlando, Florida. In 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.

We own
and operate 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 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. We distribute approximately 150,000 barrels of refined petroleum
products per day, including the Tampa terminal truck loadings. The balance of
the market is supplied primarily by trucking firms and marine transportation
firms. Most of the jet fuel used at Orlando International Airport is moved
through our Tampa terminal and the Central Florida pipeline system. The market
in Central Florida is seasonal, with demand peaks in March and April during
spring break and again in the summer vacation season, and is also heavily
influenced by tourism, with Disney World and other attractions located near
Orlando.

Supply.The vast majority
of refined petroleum products consumed in Florida is supplied via marine
vessels from major refining centers in the Gulf Coast of Louisiana and
Mississippi and refineries in the Caribbean basin. A lesser amount of refined
petroleum products is being supplied by refineries in Alabama and by Texas Gulf
Coast refineries via marine vessels and through pipeline networks that extend
to Bainbridge, Georgia. The supply into Florida is generally transported by
ocean-going vessels to the larger metropolitan ports, such as Tampa, Port Everglades
near Miami, and Jacksonville. Individual markets are then supplied from
terminals at these ports and other smaller ports, predominately by trucks,
except the Central Florida region, which is served by a combination of trucks
and pipelines.


Competition.
With respect to our 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

12

marine terminals on the east and west coasts of Florida. We are
utilizing tariff incentives to attract volumes to the pipeline that might
otherwise enter the Orlando market area by truck from Tampa or by marine vessel
into Cape Canaveral. We believe it is unlikely that a new pipeline system
comparable in size and scope to our Central Florida Pipeline system will be
constructed, due to the high cost of pipeline construction, tariff regulation
and environmental and right-of-way permitting in Florida. However, the
possibility of such a pipeline or a smaller capacity pipeline being built is a
continuing competitive factor.

With
respect to our 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

Our 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

Our Cypress
pipeline is an interstate common carrier natural gas liquids pipeline
originating at storage facilities in Mont Belvieu, Texas and extending 104
miles east to a major petrochemical producer in the Lake Charles, Louisiana
area. Mont Belvieu, located approximately 20 miles east of Houston, is the
largest hub for natural gas liquids gathering, transportation, fractionation
and storage in the United States. 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

13

pipelines into ethane and other components. Additionally, pipeline
systems that transport natural gas liquids from major producing areas in Texas,
New Mexico, Louisiana, Oklahoma and the Mid-Continent Region supply ethane and
ethane/propane mix to Mont Belvieu.

Competition.The pipelines
primary competition into the Lake Charles market comes from Louisiana onshore
and offshore natural gas liquids.

Southeast
Terminals

Our
Southeast terminal operations consist of Kinder Morgan Southeast Terminals LLC
and its consolidated affiliate, Guilford County Terminal Company, LLC. Kinder
Morgan Southeast Terminals LLC, a wholly-owned subsidiary referred to in this
report as KMST, was formed 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.

Combined,
our 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.

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 and Doraville, Georgia; North Augusta, South Carolina; Charlotte,
Greensboro, 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

Our
Transmix operations include the processing of petroleum pipeline transmix, a
blend of dissimilar refined petroleum products that have become co-mingled in
the pipeline transportation process. During pipeline transportation, different
products are transported through the pipelines abutting each other, and
generate a volume of different mixed products called transmix. At our transmix
processing facilities, we process and separate pipeline transmix into
pipeline-quality gasoline and light distillate products. We process transmix at
six separate processing facilities located in Colton, California; Richmond,
Virginia; Dorsey Junction, Maryland; Indianola, Pennsylvania; Wood River,
Illinois; and Greensboro, North Carolina. Combined, our 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 our East Coast transmix processing operations.
The Mid-Continent area and the New York Harbor are the target markets for our
Illinois and Pennsylvania assets, respectively. Our West Coast transmix
processing operations support the markets served by our Pacific operations in
Southern California.

14

Supply.Transmix generated
by Plantation, Colonial, Explorer, Sun, Teppco, and our Pacific operations
provide the vast majority of the supply. These suppliers are committed to the
use of our transmix facilities under long-term contracts. Individual shippers
and terminal operators provide additional supply. Shell acquires transmix for
processing at Indianola, Richmond and Wood River; Colton is supplied by pipeline
shippers of our Pacific operations; Dorsey Junction is supplied by Colonial
Pipeline Company and Greensboro is supplied by Plantation.

Competition.Placid Refining is
our main competitor in the Gulf Coast area. There are various processors in the
Mid-Continent area, primarily ConocoPhillips, Gladieux Refining and Williams
Energy Services, who compete with our transmix facilities. Motiva Enterprisess
transmix facility located near Linden, New Jersey is the principal competition
for New York Harbor transmix supply and for our Indianola facility. A number of
smaller organizations operate transmix processing facilities in the West and
Southwest. These operations compete for supply that we envision as the basis
for growth in the West and Southwest. Our Colton processing facility also
competes with major oil company refineries in California.

Natural
Gas Pipelines

Our Natural
Gas Pipelines segment contains both interstate and intrastate pipelines. Its
primary businesses consist of natural gas sales, transportation, storage,
gathering, processing and treating. Within this segment, we own 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. Our transportation network provides access to the major gas supply areas
in the western United States, Texas and the Midwest, as well as major consumer
markets.

Texas
Intrastate Natural Gas Pipeline Group

Our Texas
intrastate natural gas pipeline group, which operates primarily along the Texas
Gulf Coast, consists of the following four natural gas pipeline systems (i) our
Kinder Morgan Texas Pipeline; (ii) our Kinder Morgan Tejas Pipeline; (iii) our
Mier-Monterrey Mexico Pipeline; and (iv) our Kinder Morgan North Texas
Pipeline.

The two
largest systems in the group are our Kinder Morgan Texas Pipeline and our Kinder
Morgan Tejas Pipeline. These pipelines essentially operate as a single pipeline
system, providing customers and suppliers with improved flexibility and
reliability. The combined system includes approximately
6,000 miles of intrastate natural gas pipelines with a peak transport and sales
capacity of approximately 5.2 billion cubic feet per day of natural gas and
approximately 126 billion cubic feet of on-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 of natural gas. The purchases and sales of
natural gas are primarily priced with reference to market prices in the
consuming region of its system. The difference between the purchase and sale prices
is the rough equivalent of a transportation fee and fuel costs.

Included in
the operations of our Kinder Morgan Tejas system is our Kinder Morgan Border
Pipeline system. Kinder Morgan Border Pipeline owns and operates
an approximately 97-mile, 24-inch diameter pipeline that extends from a point
of interconnection with the pipeline facilities of Pemex Gas Y Petroquimica
Basica at the International Border between the United States and Mexico in
Hidalgo County, Texas, 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.

Our
Mier-Monterrey Pipeline consists of a 95-mile natural gas pipeline that
stretches from the International Border between the United States and Mexico in
Starr County, Texas, to Monterrey, Mexico and can transport up to 375 million
cubic feet per day. The pipeline connects to a 1,000-megawatt power plant
complex and to the PEMEX

15

natural gas
transportation system. We have entered into a long-term contract (expiring in
2018) with Pemex, which has subscribed for all of the pipelines capacity.

Our Kinder
Morgan North Texas Pipeline consists of an 82-mile pipeline that transports
natural gas from an interconnect with the facilities of Natural Gas Pipeline
Company of America LLC (a 20% owned equity
investee of Knight and referred to in this report as 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 system is bi-directional,
permitting deliveries of additional supply from the Barnett Shale area to
NGPLs pipeline as well as power plants in the area.

We
also own and operate various gathering systems in South and East Texas. These
systems aggregate natural gas supplies into our main transmission pipelines,
and in certain cases, aggregate natural gas that must be processed or treated at
its own or third-party facilities. We own plants that can process up to 135
million cubic feet per day of natural gas for liquids extraction, and we have
contractual rights to process approximately 550 million cubic feet per day of
natural gas at third-party owned facilities. We also share in gas processing
margins on gas processed at certain third-party owned facilities. Additionally,
we own and operate three natural gas treating plants that provide carbon
dioxide and/or hydrogen sulfide removal. We can treat up to 85 million cubic
feet per day of natural gas for carbon dioxide removal at our Fandango Complex
in Zapata County, Texas, 50 million cubic feet per day of natural gas at our
Indian Rock Plant in Upshur County, Texas and approximately 45 million cubic
feet per day of natural gas at our Thompsonville Facility located in Jim Hogg
County, Texas.

Our
North Dayton natural gas storage facility, located in Liberty County, Texas,
has two existing storage caverns providing approximately 6.3 billion cubic feet
of total capacity, consisting of 4.2 billion cubic feet of working capacity and
2.1 billion cubic feet of cushion gas. We have 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, we announced an expansion project that will significantly increase
natural gas storage capacity at our North Dayton facility. The project is now
expected to cost between $105 million and $115 million and 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.

We
also own 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 America (US), L.P. operates the facility and controls the 96 billion
cubic feet of natural gas working capacity, and we provide transportation
service into and out of the facility.

Additionally,
we lease a salt dome storage facility located near Markham, Texas according to
the provisions of an operating lease that expires in March 2013. We can, at our
sole option, extend the term of this lease for two additional ten-year periods.
The facility 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. We also lease 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, we contract for storage services from third
parties, which we then sell to customers on our pipeline system.

Markets.Texas is one of the largest natural gas consuming
states in the country. The natural gas demand profile in our Texas intrastate
pipeline groups market area is primarily composed of industrial (including
on-site cogeneration facilities), merchant and utility power, and 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, we have successfully attached many of these new
generation facilities to our pipeline systems in order to maintain and grow our
share of natural gas supply for power generation.

16

We
serve the Mexico market through interconnection with the facilities of Pemex at
the United States-Mexico border near Arguellas, Mexico and our Mier-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
which ranged up to 288 million cubic feet per day. Deliveries to Monterrey also
generally ranged from zero to 321 million cubic feet per day. We primarily
provide transport service to these markets on a fee for service basis,
including a significant demand component, which is paid regardless of actual
throughput. Revenues earned from our activities in Mexico are paid in U.S.
dollar equivalent.

Supply. We
purchase our natural gas directly from
producers attached to our system in South Texas, East Texas, West Texas and
along the Texas Gulf Coast. In addition, we also purchase gas at interconnects
with third-party interstate and intrastate pipelines. While our intrastate
group does not produce gas, it does maintain an active well connection program
in order to offset natural declines in production along its system and to
secure supplies for additional demand in its market area. Our intrastate system
has access to both onshore and offshore sources of supply and 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. We compete 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

Our Western
interstate natural gas pipeline 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 (i) our Kinder Morgan Interstate
Gas Transmission Pipeline; (ii) our Trailblazer Pipeline; (iii) our Trans
Colorado Pipeline; and (iv) our 51% ownership interest in the Rockies Express
Pipeline.

Kinder
Morgan Interstate Gas Transmission LLC

Kinder
Morgan Interstate Gas Transmission LLC, referred to in this report as 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 of natural gas per day.

Under
transportation agreements and FERC tariff provisions, KMIGT offers its
customers firm and interruptible transportation and storage services, including
no-notice service and park and loan services. For these services, KMIGT charges rates which
include the retention of fuel and gas lost and unaccounted for in-kind. Under KMIGTs tariffs, firm transportation and
storage customers pay reservation 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

17

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 the November 2008, KMIGT completed the construction of the Colorado Lateral,
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 gas pipelines transporting gas from the supply sources in the Rocky
Mountain and Hugoton Basins to mid-continent pipelines and market centers.

Trailblazer
Pipeline Company LLC

Our
subsidiary, Trailblazer Pipeline Company LLC, referred to in this report as
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
and Northern Natural Gas Companys pipeline systems. NGPL manages, maintains
and operates Trailblazer for us, for which it is reimbursed at cost.
Trailblazer offers its customers firm and interruptible transportation.

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 before 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
Gas Transmission Company LLC

Our
subsidiary, TransColorado Gas Transmission Company LLC, referred to in this
report as 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 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.

18

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 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 within one to five years, 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.

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 that TransColorados
transport business to be sustainable and not significantly impacted by any new
entry of competition.

Rockies
Express Pipeline

We operate
and currently own 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.

Our
ownership is through our 51% interest in West2East Pipeline LLC., the sole
owner of Rockies Express Pipeline LLC. Sempra Pipelines & Storage, a unit
of Sempra Energy, and ConocoPhillips hold the remaining ownership interests in
the Rockies Express project. We account for our investment under the equity
method of accounting because our 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 our 50%
economics in the project.

19

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 included the construction of
three compressor stations referred to as the Meeker, Big Hole 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 of 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 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 REX-East Project, the third
segment of the Rockies Express pipeline system. The REX-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 REX-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 can deliver gas to TransColorado Gas Transmission Company LLC
in northwestern Colorado, which can in turn transport the gas further 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 further east
through either Rockies Express Pipelines Zone 2 and Zone 3 facilities into
other pipeline systems.

Rockies
Express Pipelines Zone 2 extends from the Cheyenne Hub to an interconnect with
the Panhandle Eastern Pipeline in Audrain County, Missouri. Through the Zone 2
facilities, Rockies Express facilitates the delivery of natural gas into the
Midcontinent 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 capacity is capable of delivering 1.5
billion cubic feet per day through these interconnects to the Midcontinent
market.

The Zone 3
facilities covered by the REX-East project extend eastward from the REX-West
facilities and will permit delivery to pipelines and local distribution companies
providing service on the southern, midwestern and

20

eastern seaboards. 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. 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
Midcontinent markets. The REX-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.

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

Kinder
Morgan Louisiana Pipeline

In September
2006, we filed an application with the FERC requesting approval to construct
and operate our Kinder Morgan Louisiana Pipeline. The natural gas pipeline
project is expected to cost approximately $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.We
anticipate the Kinder Morgan Louisiana Pipeline will be fully operational
during the third quarter of 2009. We designed and are constructing the Kinder
Morgan Louisiana Pipeline in a manner that minimizes environmental impacts, and
where possible, existing pipeline corridors are being 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.

21

Midcontinent
Express Pipeline LLC

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. We currently own
a 50% interest in Midcontinent Express Pipeline LLC and we account for our
investment under the equity method of accounting. Energy Transfer Partners,
L.P. owns the remaining 50% interest. The Midcontinent Express Pipeline 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 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
January 2008, in conjunction with the signing of additional binding
transportation commitments, Midcontinent Express and MarkWest Energy Partners,
L.P. entered into an option agreement which provides MarkWest a one-time right
to purchase a 10% ownership interest in Midcontinent Express after the pipeline
is fully constructed and placed into service. If the option is exercised, we
and Energy Transfer Partners will each own 45% of Midcontinent Express, while
MarkWest will own the remaining 10%.

Fayetteville
Express Pipeline LLC

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 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.

Upstream

Casper
and Douglas Natural Gas Processing Systems

We own and
operate our Casper and Douglas, Wyoming natural gas processing plants, 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 our
Casper plant are sold into local markets consisting primarily of retail propane
dealers and oil refiners. Natural gas liquids processed by our Douglas plant
are sold to ConocoPhillips via their Powder River natural gas liquids pipeline
for either ultimate consumption at the Borger refinery or for further
disposition to the natural gas liquids trading hubs located in Conway, Kansas
and Mont Belvieu, Texas.

Competition.Other regional facilities in the Greater Powder River
Basin include the Hilight plant (80 million cubic feet per day) owned and
operated by Anadarko, the Sage Creek plant (50 million cubic feet per day)
owned and operated by Merit Energy, and the Rawlins plant (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.

22

Red
Cedar Gathering Company

We own a
49% equity interest in the Red Cedar Gathering Company, a joint venture
organized in August 1994 and referred to in this report as Red Cedar. The
remaining 51% interest in Red Cedar is owned by the Southern Ute Indian Tribe.
Red Cedar owns and operates natural gas gathering, compression and treating
facilities in the Ignacio Blanco Field in La Plata County, Colorado. The
Ignacio Blanco Field lies within the Colorado portion of the San Juan Basin,
most of which is located within the exterior boundaries of the Southern Ute
Indian Tribe Reservation. Red Cedar gathers coal seam and conventional natural
gas at wellheads and several central delivery points, for treating, compression
and delivery into any one of 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 Gas
Transmission pipeline for transport to the Blanco, New Mexico-San Juan Basin
Hub.

Red Cedars
gas gathering system currently consists of over 1,100 miles of gathering
pipeline connecting more than 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.

CO2

Our CO2
segment consists of Kinder Morgan CO2 Company, L.P. and its
consolidated affiliates, referred to in this report as KMCO2. Carbon
dioxide is used in enhanced oil recovery projects as a flooding medium for
recovering crude oil from mature oil fields. Our carbon dioxide pipelines and
related assets allow us to market a complete package of carbon dioxide supply,
transportation and technical expertise to the customer. Together, our CO2
business segment produces, transports and markets carbon dioxide for use in
enhanced oil recovery operations. We also hold ownership
interests in several oil-producing fields and own a 450-mile crude oil pipeline,
all located in the Permian Basin region of West Texas.

Carbon
Dioxide Reserves

We own
approximately 45% of, and operate, the McElmo Dome unit in Colorado, which
contains more than nine trillion cubic feet of recoverable carbon dioxide.
Deliverability and compression capacity exceeds one billion cubic feet per day.
In 2008, we completed the installation of facilities and drilled eight wells
that increased the production capacity from McElmo Dome by over 200 million
cubic feet per day. We also own 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.

We also own
approximately 87% of the Doe Canyon Deep unit in Colorado, which contains more
than 1.5 trillion cubic feet of carbon dioxide. In 2008, we completed the
installation of facilities and drilled six wells to produce over 100 million
cubic feet per day of carbon dioxide.

Markets.Our principal
market for carbon dioxide is for injection into mature oil fields in the
Permian Basin, where industry demand is expected to grow modestly for
the next several years. We are exploring
additional potential markets, including enhanced oil recovery targets in
California, Wyoming, the Gulf Coast, Mexico, and Canada, and coal bed methane
production in the San Juan Basin of New Mexico.

Competition.Our primary
competitors for the sale of carbon dioxide include suppliers that have an ownership
interest in McElmo Dome, Bravo Dome and Sheep Mountain carbon dioxide reserves,
and PetroSource Energy Company,
L.P., 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

23

sources will not be discovered or developed, which could compete with
us or that new methodologies for enhanced oil recovery will not replace carbon
dioxide flooding.

Carbon
Dioxide Pipelines

As
a result of our 50% ownership interest in Cortez Pipeline Company, we own a 50%
equity interest in and operate the approximate 500-mile Cortez pipeline. The
pipeline carries carbon dioxide from the McElmo Dome and Doe Canyon source
fields near Cortez, Colorado to the Denver City, Texas hub. The Cortez pipeline
currently transports over 1.2 billion cubic feet of carbon dioxide per day,
including approximately 99% of the carbon dioxide transported downstream on our
Central Basin pipeline and our Centerline pipeline. The tariffs charged by
Cortez Pipeline are not regulated.

Our 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, our Central Basin pipeline
interconnects with all three major carbon dioxide supply pipelines from
Colorado and New Mexico, namely the Cortez pipeline (operated by KMCO2)
and the Bravo and Sheep Mountain pipelines (operated by 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.

Our
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.

We own 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, we own approximately 98% of the Canyon Reef Carriers pipeline and
approximately 69% of the Pecos pipeline. The Canyon Reef Carriers pipeline
extends 139 miles from McCamey, Texas, to the SACROC unit. The pipeline has a
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 our carbon dioxide pipelines is to
customers, including ourselves, using carbon dioxide for enhanced recovery
operations in mature oil fields in the Permian Basin, where industry demand is
expected to grow modestly for the next several years.

Competition.
Our ownership interests in the Central Basin,
Cortez and Bravo pipelines are in direct competition with other carbon dioxide
pipelines. We also compete with other interest owners in McElmo Dome and Bravo
Dome for transportation of carbon dioxide to the Denver City, Texas market
area.

Oil
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.

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

24

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.

Our plan
has been to increase the production rate and ultimate oil recovery from Yates
by combining horizontal drilling with carbon dioxide injection to ensure a
relatively steady production profile over the next several years. We are
implementing our 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 during 2007. Unlike our operations at SACROC, where we use carbon
dioxide and water to drive oil to the producing wells, we are using carbon
dioxide injection to replace nitrogen injection at Yates in order to enhance
the gravity drainage process, as well as to maintain reservoir pressure. The
differences in geology and reservoir mechanics between the two fields mean that
substantially less capital will be needed to develop the reserves at Yates than
is required at SACROC.

We
also operate and own an approximate 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 the unit produced 235 barrels of oil per day during 2008, up from an average of 218 barrels of oil per day
during 2007. We are presently evaluating operating and subsurface
technical data from the Claytonville unit to further assess redevelopment
opportunities including carbon dioxide flood operations.

We
also operate and own 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, the field produced 425 barrels of oil per day, up from an average of 408
barrels of oil per day during 2007. We are presently evaluating
operating and subsurface technical data to further assess redevelopment
opportunities for the Katz field including the potential for carbon dioxide
flood operations.

The
following table sets forth productive wells, service wells and drilling wells
in the oil and gas fields in which we own interests as of December 31, 2008. When
used with respect to acres or wells, gross refers to the total acres or wells
in which we have a working interest; net refers to gross acres or wells
multiplied, in each case, by the percentage working interest owned by us:

Productive
 Wells (a)

Service
 Wells (b)

Drilling
 Wells (c)Gross

Net

Gross

Net

Gross

NetCrude Oil


2,906


2,029


895


700


4


4Natural Gas


6


3


36


18





Total Wells


2,912


2,032


931


718


4


4(a)
Includes active wells and
 wells temporarily shut-in. As of December 31, 2008, we did not operate any
 productive wells with multiple completions.(b)
Consists of injection,
 water supply, disposal wells and service wells temporarily shut-in. A
 disposal well is used
 for disposal of saltwater into an underground formation; a service well is a well drilled in a known
 oil field in order to inject liquids that enhance recovery or dispose of salt
 water.(c)
Consists of development
 wells in the process of being drilled as of December 31, 2008. A
 development well is a well drilled in an already discovered oil field.The
oil and gas producing fields in which we own interests are located in the
Permian Basin area of West Texas. The following table reflects our net
productive and dry wells that were completed in each of the three years ended
December 31, 2008, 2007 and 2006:

25

2008

2007

2006ProductiveDevelopment

47

31

37Exploratory





DryDevelopment





Exploratory





Total Wells

47

31

37Notes:
The
 above table includes wells
 that were completed during each year regardless of the year in which drilling
 was initiated, and does not include any wells where drilling operations were
 not completed as of the end of the applicable year. Development wells include
 wells drilled in the proved area of an oil or gas resevoir.The
following table reflects the developed and undeveloped oil and gas acreage that
we held as of December 31, 2008:

Gross

NetDeveloped Acres

72,435

67,731Undeveloped Acres

9,555

8,896Total

81,990

76,627Operating
Statistics

Operating
statistics from our 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 CostsYear Ended December 31,2008

2007

2006Consolidated
 Companies(a)Production costs per barrel of
oil
 equivalent(b)(c)(d)

$
20.44

$
16.22

$
13.30Crude oil production
(MBbl/d)


36.2


35.6


37.8Natural gas liquids production
(MBbl/d)(d)


4.8


5.5


5.0Natural gas liquids production
from gas
 plants(MBbl/d)(e)


3.5


4.1


3.9Total natural gas liquids
 production(MBbl/d)


8.3


9.6


8.9Natural gas production
(MMcf/d)(d)(f)


1.4


0.8


1.3Natural gas production from gas
 plants(MMcf/d)(e)(f)


0.2


0.3


0.3Total natural gas
production(MMcf/d)(f)


1.6


1.1


1.6Average sales prices including
hedge gains/losses:Crude oil price per
Bbl(g)

$
49.42

$
36.05

$
31.42Natural gas liquids price per
Bbl(g)

$
63.48

$
52.22

$
43.52Natural gas price per
Mcf(h)

$
7.73

$
6.08

$
6.36Total natural gas liquids price
per Bbl(e)

$
63.00

$
52.91

$
43.90Total natural gas price per
Mcf(e)

$
7.63

$
5.89

$
7.02Average sales prices excluding
hedge
 gains/losses:Crude oil price per
Bbl(g)

$
97.70

$
69.63

$
63.27Natural gas liquids price per
Bbl(g)

$
63.48

$
52.22

$
43.52Natural gas price per
Mcf(h)

$
7.73

$
6.08

$
6.36(a)
Amounts
 relate to Kinder Morgan CO2 Company, L.P. and its consolidated
 subsidaries.(b)
Computed using production
 costs, excluding transportation costs, as defined by the United States
 Securities and Exchange Commisson. Natural gas volumes were converted to
 barrels of oil equivalent using a conversion factor of six mcf of natural gas
 to one barrel of oil.(c)
Production
 costs include labor, repairs and maintenance, materials, supplies, fuel and
 power, property taxes, severance taxes, and general and administrative expenses
 directly related to oil and gas producing activities.(d)
Includes
 only production attributable to leasehold ownership.26

(e)
Includes
 production attributable to our ownership in processing plants and third party
 processing agreements.(f)
Excludes
 natural gas production used as fuel.(g)
Hedge
 gains/losses for crude oil and natural gas liquids are included with crude
 oil.(h)
Natural
 gas sales were not hedged.See Note 20
to our consolidated financial statements included in this report for additional
information with respect to operating statistics and supplemental information
on our oil and gas producing activities.

Gas
and Gasoline Plant Interests

We operate
and own an approximate 22% working interest plus an additional 28% net profits
interest in the Snyder gasoline plant. We also operate and own a 51% ownership
interest in the Diamond M gas plant and a 100% ownership interest in the North
Snyder plant, all of which are located in the Permian Basin of West Texas. The
Snyder gasoline plant processes gas produced from the SACROC unit and
neighboring carbon dioxide projects, specifically the Sharon Ridge and Cogdell
units, all of which are located in the Permian Basin area of West Texas. The Diamond
M and the North Snyder plants contract with the Snyder plant to process gas.
Production of natural gas liquids at the Snyder gasoline plant as of December
2008 was approximately 13,900 barrels per day as compared to 15,500 barrels per
day as of December 2007.

Crude
Oil Pipeline

Our
Kinder Morgan Wink Pipeline is 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 us to better manage crude oil deliveries from our oil field interests in
West Texas, and we have entered into a long-term throughput agreement with Western
Refining Company, L.P. to transport crude oil into Westerns 120,000 barrel per
day refinery in El Paso. The 20-inch pipeline segment transported approximately 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.

Terminals

Our
Terminals segment includes the operations of our petroleum, chemical and other
liquids terminal facilities (other than those included in our Products
Pipelines segment) and all of our coal, petroleum coke, fertilizer, steel, ores
and dry-bulk material services, including all transload, engineering, conveying
and other in-plant services. Combined, the segment is composed of approximately 117
owned or operated liquids and bulk terminal facilities, and more than 32 rail
transloading and materials handling facilities located throughout the United
States, Canada, and the Netherlands.

Liquids
Terminals

Our
liquids terminals operations primarily store refined petroleum products,
petrochemicals, industrial chemicals and vegetable oil products in aboveground
storage tanks and transfer products to and from pipelines, vessels, tank
trucks, tank barges, and tank railcars. Combined, our 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, we completed the Phase III expansions at our
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 our Pasadena and Galena Park terminals; (ii) an additional cross-channel
pipeline to increase the connectivity between the two terminals; (iii) a new
ship dock at Galena Park; and (iv) an additional loading bay at our fully
automated truck loading rack with ethanol handling infrastructure located at
our 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.

27

In
2008, we announced additional expansions at our Pasadena and Galena Park
terminal facilities. The investment of approximately $114 million includes the
construction of the following: (i) 12 new storage tanks at our Pasadena and
Galena Park terminals; (ii) a barge dock that will be capable of handling two 300-foot
barges with an 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, we completed and put into service approximately
2.15 million barrels of new crude oil capacity at our 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, our 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 our 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, we completed construction and placed into service
nine new storage tanks at our 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. Our total investment for this expansion was approximately $68 million.

In the
third quarter of 2008, we completed and put into service approximately 320,000
barrels of additional gasoline capacity at our 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.

In
September 2008 we 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.We are one of the largest
independent operators of liquids terminals in North America. Our primary
competitors are IMTT, Magellan, Morgan Stanley, NuStar, Oil Tanking, Teppco,
and Vopak.

Bulk
Terminals

Our bulk
terminal operations primarily involve dry-bulk material handling services;
however, we also provide 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, our 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. We own or operate approximately 100
dry-bulk terminals in the United States, Canada and the Netherlands.

In
May 2007, we 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, we gave 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 liquid 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 our original purchase price, we plan 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.

28

Effective
September 1, 2007, we 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, we completed and put into service a barge unloading
terminal located on 30 acres in Columbus, Mississippi. Our 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.

In
the first quarter of 2008, we also completed and put into service our Pier X
expansion at our 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, we acquired certain terminal assets from LPC Packaging, a
California corporation, for an aggregate consideration of $5.1 million. These
acquired assets included state of the art packaging machinery, conveyors and
mobile equipment. LPC consists 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.
Our bulk terminals compete with numerous independent
terminal operators, other terminals owned by oil companies, stevedoring
companies, and other industrials opting not to outsource terminal services.
Many of our bulk terminals were constructed pursuant to long-term contracts for
specific customers. As a result, we believe other terminal operators would face
a significant disadvantage in competing for this business.

Materials
Services (rail transloading)

Our
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. We also design and build
transloading facilities, perform inventory management services, and provide
value-added services such as blending, heating and sparging. In 2008, our materials services operations
handled approximately 348,000 railcars.

Competition
Our 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.

Kinder Morgan Canada

Our Kinder Morgan Canada business segment
includes our Trans Mountain pipeline system, our ownership of a one-third
interest in the Express pipeline
system, and our 25-mile Jet Fuel pipeline system.

Trans
Mountain Pipeline System

Our 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 us
delivers petroleum to refineries in the state of Washington.

29

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, on October 30, 2008,
we completed the construction of our Anchor Loop expansion project, which
increased pipeline capacity from approximately 260,000 to 300,000 barrels of
crude oil per day. 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 us. 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. In April 2007, we commissioned ten new
pump stations 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 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 on May 1, 2008, and the remaining 15,000
barrels per day increase began on November 1, 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.

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.

CompetitionTrans Mountains pipeline to the West Coast of North
America is one of several pipeline alternatives for Western Canadian petroleum
production. This pipeline, like all our petroleum pipelines, competes against
other pipeline companies who could be in a position to offer different tolling
structures.

Express
and Jet Fuel Pipeline Systems

We own a
one-third ownership interest in the Express pipeline system and we own a
long-term investment 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. We operate the
Express pipeline system and we account for our 33 1/3% investment 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, 24-inch diameter pipeline that begins at the
crude oil pipeline hub at Hardisty, Alberta and terminates at the Casper,
Wyoming facilities of the Platte Pipeline.

30

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, 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, Express 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.

We
also own and operate 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.

Competition:
The Express Pipeline System pipeline to 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.

Major
Customers

Our total
operating revenues are derived from a wide customer base. For each of the years ended
December 31, 2008, 2007 and 2006, no revenues from transactions with a single
external customer accounted for 10% or more of our total consolidated revenues.
Our 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,
our CO2 business segment also sells natural gas. Combined, total
revenues from the sales of natural gas from our Natural Gas Pipelines and CO2
business segments in 2008, 2007 and 2006 accounted for 65.6%, 63.3% and 66.8%,
respectively, of our total consolidated revenues.

31

As a result
of our Texas intrastate group selling natural gas in the same price environment
in which it is purchased, both our total consolidated revenues and our total
consolidated purchases (cost of sales) increase considerably due to the inclusion
of the cost of gas in both financial statement line items. However, these
higher revenues and higher purchased gas costs do not necessarily translate
into increased margins, in comparison to those situations in which we charge a
fee to transport gas owned by others. To the extent possible, we attempt to
balance the pricing and timing of our natural gas purchases to our 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.

Regulation

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 we charged for transportation service on our Cypress Pipeline
were not suspended or subject to protest or complaint during the relevant
365-day period established by the Energy Policy Act. For this reason, we
believe these rates should be grandfathered under the Energy Policy Act.
Certain rates on our Pacific operations pipeline system were subject to
protest during the 365-day period established by the Energy Policy Act.
Accordingly, certain of the Pacific pipelines rates have been, and continue to
be, subject to complaints with the FERC, as is more fully described in Note 16 to our consolidated financial statements
included elsewhere in this report.

Petroleum
products pipelines may change their rates within prescribed ceiling levels that
are tied to an inflation index. Shippers may protest rate increases made within
the ceiling levels, but such protests must show that the portion of the rate
increase resulting from application of the index is substantially in excess of
the pipelines increase in costs from the previous year. A pipeline must, as a
general rule, utilize the indexing methodology to change its rates. The FERC,
however, uses cost-of-service ratemaking, market-based rates and settlement
rates as alternatives to the indexing approach in certain specified
circumstances.

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,

32

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 project
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 and Oil Pipeline Rate Regulation  U.S. Operations.

Express
Pipeline System. The Canadian segment of the Express
Pipeline 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
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 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:

Order No. 436 (1985) which required open-access, nondiscriminatory
 transportation of natural gas;Order No. 497 (1988) which set forth new standards and guidelines
 imposing certain constraints on the interaction between interstate natural
 gas pipelines and their marketing affiliates and imposing certain disclosure
 requirements regarding that interaction; andOrder No. 636 (1992) which required interstate natural gas pipelines
 that perform open-access transportation under blanket certificates to
 unbundle or separate their traditional merchant sales services from their
 transportation and storage services and to provide comparable transportation
 and storage services with respect to all natural gas supplies.Natural gas
pipelines must now separately state the applicable rates for each unbundled
service they provide (i.e., for the natural gas commodity, transportation and
storage). Order No. 636 contains a number of procedures designed to increase
competition in the interstate natural gas industry, including: (i) requiring
the unbundling of sales services from other services; (ii) 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 (iii) 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 our unbundling plans are final and not subject to any
pending judicial review.

On
November 25, 2003, the FERC issued Order No. 2004, adopting revised Standards
of Conduct that apply uniformly to interstate natural gas pipelines and public
utilities. In light of the changing structure of the energy

33

industry,
these Standards of Conduct govern relationships between regulated interstate
natural gas pipelines and all of their energy affiliates. These new Standards
of Conduct were designed to eliminate the loophole in the previous regulations
that did not cover an interstate natural gas pipelines relationship with
energy affiliates that are not marketers. The rule is designed to prevent
interstate natural gas pipelines from giving an undue preference to any of
their energy affiliates and to ensure that transmission is provided on a
nondiscriminatory basis. In addition, unlike the prior regulations, these
requirements apply even if the energy affiliate is not a customer of its
affiliated interstate pipeline.

On November
17, 2006, the D.C. Circuit vacated Order No. 2004, as applied to natural gas
pipelines, and remanded the Order back to the FERC. On January 9, 2007, the
FERC issued an interim rule regarding standards of conduct in Order No. 690 to
be effective immediately. The interim rule repromulgated the standards of
conduct that were not challenged before the court. On January 18, 2007, the
FERC issued a notice of proposed rulemaking, referred to as a NOPR, soliciting
comments on whether or not the interim rule should be made permanent for natural
gas transmission providers. On March 21, 2008, the FERC issued a NOPR modifying
the approach proposed in the January 18, 2007 NOPR, and on October
16, 2008, the FERC issued a Final Rule in Order 717 revising the FERC Standards
of Conduct for natural gas and electric transmission providers by eliminating
Order No. 2004s concept of Energy Affiliates and corporate separation in favor
of an employee functional approach as used in Order No. 497. Please refer to Note 17 to our consolidated
financial statements included elsewhere in this report for additional
information regarding FERC Order No. 2004 and the Standards of Conduct.

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 or Midcontinent Express pipelines, 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 our Pacific operations pipelines 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 our Pacific operations business. Tariff rates with
respect to intrastate pipeline service in California are subject to challenge
by complaint by interested parties or by independent action of the CPUC. A
variety of factors can affect the rates of return permitted by the CPUC, and
certain other issues similar to those which have arisen with respect to our
FERC regulated rates could also arise with respect to our intrastate rates.
Certain of our Pacific operations pipeline rates have been, and continue to
be, subject to complaints with the CPUC, as is more fully described in Note 16 to our consolidated financial statements
included elsewhere in this report.

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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, referred to in this report as 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 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, human
health and safety.

Environmental
Matters

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

35

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 $78.9 million as of December 31, 2008. Our reserve estimates range in value from
approximately $78.9 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 16 to our consolidated
financial statements included elsewhere in this report.

Hazardous
and Non-Hazardous Waste

We generate
both hazardous and non-hazardous 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 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.

36

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, also known as the Clean Water Act,
and analogous state laws impose restrictions and controls regarding the
discharge of pollutants into state waters or waters of the United States. The
discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by applicable federal or state
authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of
the Clean Water Act as they pertain to prevention and response to oil spills.
Spill prevention control and countermeasure requirements of the Clean Water Act
and some state laws require containment and similar structures to help prevent
contamination of navigable waters in the event of an overflow or release.

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 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, or comparable state regulatory
commissions, and the provisions of any final legislation.

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, referred to in this
report as 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 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.

Other

KMGP
Services Company, Inc., Knight and Kinder Morgan Canada Inc. employ all persons
necessary for the operation of our business. Generally, we reimburse these
entities for the services of their employees. As of

37

December 31, 2008, KMGP Services Company, Inc., Knight and Kinder
Morgan Canada Inc. had, in the aggregate, approximately 7,800 full-time
employees. 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 and Kinder Morgan Canada Inc. each consider relations with their
employees to be good. For more information on our related party transactions,
see Note 12 of the notes to our consolidated financial statements included
elsewhere in this report.

We believe
that we have generally satisfactory title to the properties we own and use in
our businesses, subject to liens for current taxes, liens incident to minor
encumbrances, and easements and restrictions, which do not materially detract
from the value of such property or the interests in those properties or the use
of such properties in our businesses. We generally do not own the land on which
our pipelines are constructed. Instead, we obtain the right to construct and
operate the pipelines on other peoples land for a period of time. Substantially
all of our pipelines are constructed on rights-of-way granted by the apparent
record owners of such property. In many instances, lands over which
rights-of-way have been obtained are subject to prior liens, which have not
been subordinated to the right-of-way grants. In some cases, not all of the
apparent record owners have joined in the right-of-way grants, but in
substantially all such cases, signatures of the owners of majority interests
have been obtained. Permits have been obtained from public authorities to cross
over or under, or to lay facilities in or along, water courses, county roads,
municipal streets and state highways, and in some instances, such permits are
revocable at the election of the grantor, or, the pipeline may be required to
move its facilities at its own expense. Permits have also been obtained from
railroad companies to cross over or under lands or rights-of-way, many of which
are also revocable at the grantors election. Some such permits require annual
or other periodic payments. In a few minor cases, property for pipeline purposes
was purchased in fee.

(d)
Financial Information about Geographic Areas

For
geographic information concerning our assets and operations, see Note 15 to our
consolidated financial statements.

(e)
Available Information

We make
available free of charge on or through our Internet website, at www.kindermorgan.com,
our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports
on Form 8-K, and amendments to those reports filed or furnished pursuant to Section
13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably
practicable after we electronically file such material with, or furnish it to,
the Securities and Exchange Commission.

Item
1A. Risk
Factors.

You should
carefully consider the risks described below, in addition to the other
information contained in this document. Realization of any of the following
risks could have a material adverse effect on our business, financial
condition, cash flows and results of operations. There are also risks
associated with being an owner of common units in a partnership that are
different than being an owner of common stock in a corporation. Investors in
our common units must be aware that the realization of any of those risks could
result in a decline in the trading price of our common units, and they might
lose all or part of their investment.

Risks
Related to Our Business

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, provincial 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.

38

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 and California Public Utilities Commission
proceedings seek substantial refunds and reductions in tariff rates on some of
our pipelines. If the proceedings are determined adversely to us, they could
have a material adverse impact on us.

Regulators
and shippers on our pipelines have rights to challenge the rates we charge
under certain circumstances prescribed by applicable regulations. Some shippers
on our pipelines have filed complaints with the 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
our Pacific operations pipeline system. We may face challenges,
similar to those described in Note 16 to our
consolidated financial statements included elsewhere in this report, to the
rates we receive on our pipelines in the future. Any successful challenge could
adversely and materially affect our future earnings and cash flows.

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, including unexpected policy
changes that sometimes occur following a change of presidential administration,
applicable to our assets could have a material adverse impact on our business,
financial condition and results of operations.

Increased
regulatory requirements relating to the integrity of our pipelines will require
us to spend additional money to comply with these requirements.

Through our
regulated pipeline subsidiaries, we are subject to extensive laws and
regulations related to pipeline integrity. There are, for example, federal 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.

39

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 material adverse effect on our
business, financial position, results of operations and prospects.

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

40

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 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.

Cost
overruns and delays on our expansion and new build projects could adversely
affect our business.

We
currently have several major expansion and new build projects planned or underway, including the
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
project).  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.

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:
(i) demands on management related to the increase in our size after an
acquisition, an expansion, or a completed construction project; (ii) the
diversion of our managements attention from the management of daily
operations; (iii) difficulties in implementing or unanticipated costs of
accounting, estimating, reporting and other systems; (iv) difficulties in the
assimilation and retention of necessary employees; and (v) potential adverse
effects on operating results.

We may not
be able to maintain the levels of operating efficiency that acquired companies
have achieved or might achieve separately. Successful integration of each
acquisition, expansion, or construction project will depend upon our ability to
manage those operations and to eliminate redundant and excess costs. Because of
difficulties in combining and expanding operations, we may not be able to
achieve the cost savings and other size-related benefits that we hoped to
achieve after these acquisitions, which would harm our financial condition and
results of operations.

Our
acquisition strategy and expansion programs require access to new capital.
Tightened 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

41

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 our CO2 business
segment and the carrying value of our 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, natural gas liquids 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 our proved reserves. In the event prices fall
substantially, we may not be able to realize a profit from our production and
would operate at a loss. In recent decades, there have been periods of both
worldwide overproduction and underproduction of hydrocarbons and periods of
both increased and relaxed energy conservation efforts. Such conditions have
resulted in periods of excess supply of, and reduced demand for, crude oil on a
worldwide basis and for natural gas on a domestic basis. These periods have
been followed by periods of short supply of, and increased demand for, crude
oil and natural gas. The excess or short supply of crude oil or natural gas has
placed pressures on prices and has resulted in dramatic price fluctuations even
during relatively short periods of seasonal market demand. These fluctuations
necessarily impact the accuracy of assumptions used in our budgeting process.

42

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 floating interest rates) that are effective economically,
these transactions may not be considered effective for accounting purposes.
Accordingly, our financial statements may reflect some volatility due to these
hedges, even when there is no underlying economic impact at that point. In
addition, it is not always possible for us to engage in a hedging transaction
that completely mitigates our exposure to commodity prices. Our financial
statements may reflect a gain or loss arising from an exposure to commodity
prices for which we are unable to enter into a completely effective hedge.

We
must either obtain the right from landowners or exercise the power of eminent
domain in order to use most of the land on which our pipelines are constructed,
and we are subject to the possibility of increased costs to retain necessary
land use.

We obtain
the right to construct and operate pipelines on other owners land for a period
of time. If we were to lose these rights or be required to relocate our
pipelines, our business could be affected negatively. In addition, we are
subject to the possibility of increased costs under our rental agreements with
landowners, primarily through rental increases and renewals of expired
agreements.

Whether we
have the power of eminent domain for our 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. Our interstate natural gas pipelines have federal eminent
domain authority. In either case, we must compensate landowners for the use of
their property and, in eminent domain actions, such compensation may be
determined by a court. Our inability to exercise the power of eminent domain
could negatively affect our business if we were to lose the right to use or
occupy the property on which our pipelines are located.

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 approximately $8.6 billion of consolidated debt
(excluding the fair value of interest rate swaps). This level of debt could
have important consequences, such as (i) limiting our ability to obtain
additional financing to fund our working capital, capital expenditures, debt
service requirements or potential growth or for other purposes; (ii) 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; (iii) placing us at a competitive disadvantage compared to competitors
with less debt; and (iv) 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 $8.6 billion of consolidated debt
(excluding the fair value of interest rate swaps). Of this amount, approximately $2.9 billion (34%) 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. 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.

43

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
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.

Current
levels of market volatility are unprecedented.

The
capital and credit markets have been experiencing extreme volatility and
disruption for more than 12 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 our CO2 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 our
short-term credit ratings by Standard & Poors Rating Services, we are
currently unable to access commercial paper borrowings and instead are meeting
our short-term financing and liquidity needs through borrowings under our bank
credit facility. The negative impact on the tightening of the credit markets may
have a material adverse effect on us resulting from, but not limited to, an
inability to expand facilities or finance the

44

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 we have available for operations, to pay distributions and to make
additional investments.

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 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 we have available to distribute or invest and could result in a decline in
the value of your investment.

There
can be no assurance as to the impact on the financial markets of the U.S.
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 U.S. government will have on the financial markets.  Although we are not one of the institutions that would
sell securities to the U.S. 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, or the trading price of our common units.

Knights
May 2007 going-private transaction resulted in a downgrade of the ratings of
our debt securities, which has increased our cost of capital.

On
May 30, 2007, Knight completed its going-private transaction. In
connection with the transaction, Standard & Poors Rating Services and
Moodys Investor Service, Inc. downgraded the ratings assigned to our senior
unsecured debt to BBB and Baa2, respectively. Additionally, our rating was
downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007. Though
steps have been taken which are intended to allow our senior unsecured
indebtedness to continue to be rated investment grade, we can provide no
assurance that that will be the case.

The
future success of our oil and gas development and production operations depends
in part upon our ability to develop additional oil and gas reserves that are
economically recoverable.

The rate of
production from oil and natural gas properties declines as reserves are
depleted. Without successful development activities, the reserves and revenues
of the oil producing assets within our CO2 business segment will
decline. We may not be able to develop or acquire additional reserves at an
acceptable cost or have necessary financing for these activities in the future.
Additionally, if we do not realize production volumes greater than, or equal
to, our hedged volumes, we 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.

45

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 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 our Kinder Morgan Canada 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
partners capital 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.

Hurricanes
and other natural disasters could have a material adverse effect on our business, financial condition
and results of operations.

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.



Risks
Related to Our Common Units

The
interests of Knight may differ from our interests and the interests of our
unitholders.

Knight
indirectly owns all of the common stock of our general partner and elects all
of its directors. Our general partner owns all of KMRs voting shares and
elects all of its directors. Furthermore, some of KMRs directors and officers
are also directors and officers of Knight and our general partner and have
fiduciary duties to manage the businesses of Knight in a manner that may not be
in the best interests of our unitholders. Knight has a number of

46

interests that
differ from the interests of our unitholders. As a result, there is a risk that
important business decisions will not be made in the best interests of our
unitholders.

Common
unitholders have limited voting rights and limited control.

Holders
of common units have only limited voting rights on matters affecting us. Our
general partner manages partnership activities. Under a delegation of control
agreement, our general partner has delegated the management and control of our
and our subsidiaries business and affairs to KMR. Holders of common units have
no right to elect the general partner on an annual or other ongoing basis. If
the general partner withdraws, however, its successor may be elected by the
holders of a majority of the outstanding common units (excluding units owned by
the departing general partner and its affiliates).

The
limited partners may remove the general partner only if (i) the holders of at
least 66 2/3% of the outstanding common units, excluding common
units owned by the departing general partner and its affiliates, vote to remove
the general partner; (ii) a successor general partner is approved by at least
66 2/3% of the outstanding common units, excluding common units
owned by the departing general partner and its affiliates; and (iii) we
receive an opinion of counsel opining that the removal would not result in the
loss of limited liability to any limited partner, or the limited partner of an
operating partnership, or cause us or the operating partnership to be taxed
other than as a partnership for federal income tax purposes.

A
person or group owning 20% or more of the common units cannot vote.

Any
common units held by a person or group that owns 20% or more of the common
units cannot be voted. This limitation does not apply to the general partner
and its affiliates. This provision may (i) discourage a person or group from
attempting to remove the general partner or otherwise change
management; and (ii) reduce the price at which the common units will trade
under certain circumstances. For example, a third party will probably not
attempt to take over our management by making a tender offer for the common
units at a price above their trading market price without removing the general
partner and substituting an affiliate of its own.

The
general partners liability to us and our unitholders may be limited.

Our
partnership agreement contains language limiting the liability of the general
partner to us or the holders of common units. For example, our partnership
agreement provides that (i) the general partner does not breach any duty to us
or the holders of common units by borrowing funds or approving any borrowing
(the general partner is protected even if the purpose or effect of the
borrowing is to increase incentive distributions to the general partner); (ii)
the general partner does not breach any duty to us or the holders of common
units by taking any actions consistent with the standards of reasonable
discretion outlined in the definitions of available cash and cash from
operations contained in our partnership agreement; and (iii) the general
partner does not breach any standard of care or duty by resolving conflicts of
interest unless the general partner acts in bad faith.

Unitholders
may have liability to repay distributions.

Unitholders
will not be liable for assessments in addition to their initial capital
investment in the common units. Under certain circumstances, however, holders
of common units may have to repay us amounts wrongfully returned or distributed
to them. Under Delaware law, we may not make a distribution to unitholders if
the distribution causes our liabilities to exceed the fair value of our assets.
Liabilities to partners on account of their partnership interests and
non-recourse liabilities are not counted for purposes of determining whether a
distribution is permitted. Delaware law provides that for a period of three
years from the date of such a distribution, a limited partner who receives the
distribution and knew at the time of the distribution that the distribution
violated Delaware law will be liable to the limited partnership for the
distribution amount. Under Delaware law, an assignee who becomes a substituted
limited partner of a limited partnership is liable for the obligations of the
assignor to make contributions to the partnership. However, such an assignee is
not obligated for liabilities unknown to the assignee at the time the assignee
became a limited partner if the liabilities could not be determined from the
partnership agreement.

47

Unitholders
may be liable if we have not complied with state partnership law.

We
conduct our business in a number of states. In some of those states the
limitations on the liability of limited partners for the obligations of a
limited partnership have not been clearly established. The unitholders might be
held liable for the partnerships obligations as if they were a general partner
if (i) a court or government agency determined that we were conducting business
in the state but had not complied with the states partnership statute; or
(ii) unitholders rights to act together to remove or replace the general
partner or take other actions under our partnership agreement constitute
control of our business.

The general
partner may buy out minority unitholders
if it owns 80% of the units.

If
at any time the general partner and its affiliates own 80% or more of the
issued and outstanding common units, the general partner will have the right to
purchase all, and only all, of the remaining common units. Because of this
right, a unitholder could have to sell its common units at a time or price that
may be undesirable. The purchase price for such a purchase will be the greater
of (i) the 20-day average trading price for the common units as of the date
five days prior to the date the notice of purchase is mailed; or (ii) the
highest purchase price paid by the general partner or its affiliates to acquire
common units during the prior 90 days. The general partner can assign this
right to its affiliates or to us.

We may sell
additional limited partner interests,
diluting existing interests of unitholders.

Our
partnership agreement allows the general partner to cause us to issue
additional common units and other equity securities. When we issue additional
equity securities, including additional i-units to KMR when it issues
additional shares, unitholders proportionate partnership interest in us will
decrease. Such an issuance could negatively affect the amount of cash
distributed to unitholders and the market price of common units. Issuance of
additional common units will also diminish the relative voting strength of the
previously outstanding common units. Our partnership agreement does not limit
the total number of common units or other equity securities we may issue.

The general
partner can protect itself against
dilution.

Whenever
we issue equity securities to any person other than the general partner and its
affiliates, the general partner has the right to purchase additional limited
partnership interests on the same terms. This allows the general partner to
maintain its proportionate partnership interest in us. No other unitholder has
a similar right. Therefore, only the general partner may protect itself against
dilution caused by issuance of additional equity securities.

Our partnership
agreement and the KMR limited
liability company agreement restrict or eliminate a number of the fiduciary
duties that would otherwise be owed by our general partner and/or its delegate
to our unitholders.

Modifications
of state law standards of fiduciary duties may significantly limit the ability
of our unitholders to successfully challenge the actions of our general partner
in the event of a breach of fiduciary duties. These state law standards include
the duties of care and loyalty. The duty of loyalty, in the absence of a
provision in the limited partnership agreement to the contrary, would generally
prohibit our general partner from taking any action or engaging in any
transaction as to which it has a conflict of interest. Our limited partnership
agreement contains provisions that prohibit limited partners from advancing
claims that otherwise might raise issues as to compliance with fiduciary duties
or applicable law. For example, that agreement provides that the general
partner may take into account the interests of parties other than us in
resolving conflicts of interest. It also provides that in the absence of bad
faith by the general partner, the resolution of a conflict by the general
partner will not be a breach of any duty. The provisions relating to the
general partner apply equally to KMR as its delegate. It is not necessary for a
limited partner to sign our limited partnership agreement in order for the
limited partnership agreement to be enforceable against that person.

48

We adopted
certain valuation methodologies that may
result in a shift of income, gain, loss and deduction between our general
partner and our unitholders. The IRS may challenge this treatment, which could
adversely affect the value of the common units.

When
we issue additional units or engage in certain other transactions, we determine
the fair market value of our assets and allocate any unrealized gain or loss
attributable to our assets to the capital accounts of our unitholders and our
general partner. This methodology may be viewed as understating the value of
our assets. In that case, there may be a shift of income, gain, loss and
deduction between certain unitholders and our general partner, which may be
unfavorable to such unitholders. Moreover, under our current valuation methods,
subsequent purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated to our tangible
assets and a lesser portion allocated to our intangible assets. The IRS may
challenge these valuation methods, or our allocation of the Section 743(b)
adjustment attributable to our tangible and intangible assets, and allocations
of income, gain, loss and deduction between our general partner and certain of
our unitholders.

A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our partners. It also
could affect the amount of gain from our unitholders sale of common units and
could have a negative impact on the value of the common units or result in
audit adjustments to our unitholders tax returns without the benefit of
additional deductions.

Our 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
we cannot match transferors and transferees of common units, we are 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. We do 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.

Our tax treatment
depends on our status as a
partnership for United States federal income tax purposes, as well as our not being subject
to a material amount of entity-level taxation by individual states. If the
Internal Revenue Service treats us as a corporation or if we become 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 our
partners.

The
anticipated after-tax economic benefit of an investment in us depends largely
on our being treated as a partnership for United States federal income tax purposes. In order
for us to be treated as a partnership for United States federal income tax purposes, current
law requires that 90% or more of our gross income for every taxable year
consist of qualifying income, as defined in Section 7704 of the Internal
Revenue Code. We may not meet this requirement or current law may change so as
to cause, in either event, us to be treated as a corporation for United States federal income
tax purposes or otherwise subject to federal income tax. We have not requested,
and do not plan to request, a ruling from the Internal Revenue Service on this
or any other matter affecting us.

If
we were to be treated as a corporation for United States federal income tax purposes, we
would pay United States federal income tax on our income at the corporate tax rate, which is
currently a maximum of 35%, and would pay state income taxes at varying rates.
Under current law, distributions to our partners would generally be taxed again
as corporate distributions, and no income, gain, losses or deductions would
flow through to our partners. Because a tax would be imposed on us as a
corporation, our cash available for distribution would be substantially
reduced. Therefore, treatment of us as a corporation would result in a material
reduction in the anticipated cash flow and after-tax return to our partners,
likely causing substantial reduction in the value of our units.

Current
law or our business may change so as to cause us to be treated as a corporation
for United States federal income tax purposes or otherwise subject us 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 our tax treatment as a

49

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 an investment in
our common units.

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, we are now subject to an entity-level tax on the
portion of our total revenue that is generated in Texas. Specifically, the Texas
margin tax is imposed at a maximum effective rate of 0.7% of our total revenue
that is apportioned to Texas.  This tax reduces, and the imposition of such a
tax on us by any other state will reduce our cash available for
distribution to our partners.

Our
partnership agreement provides that if a law is enacted that subjects us to
taxation as a corporation or otherwise subjects us to entity-level taxation for
federal income tax purposes, the minimum quarterly distribution and the target
distribution levels will be adjusted to reflect the impact on us of that law.

The issuance of
additional i-units may cause more
taxable income to be allocated to the common units.

The
i-units we issue to KMR generally are not allocated income, gain, loss or
deduction for federal income tax purposes until such time as we are liquidated.
Therefore, the issuance of additional i-units may cause more taxable income and
gain to be allocated to the common unitholders.

We may have
potential liability arising out of a possible
dissemination of one or more prospectuses (in the form of Current Reports on
Form 8-K and 8-K/A) not meeting the requirements of the Securities Act.

On
December 16, 2008, we furnished to the Securities and Exchange Commission two
Current Reports on Form 8-K and one Current Report on Form 8-K/A (in each case,
containing disclosures under item 7.01 of Form 8-K) containing certain
information with respect to a public offering of our common units. We filed a
prospectus supplement with respect to this 3,900,000 common unit offering on
December 17, 2008, and the common units were sold at a public offering price of
$46.75 per common unit for total gross proceeds of $182,325,000. These Current
Reports may have constituted prospectuses not meeting the requirements of the
Securities Act due to the legends used in the Current Reports. Accordingly,
under certain circumstances, purchasers of the common units from us in the
offering might have the right to require us to repurchase the common units they
purchased or, if they have sold those common units, to pay damages.
Consequently, we could have a potential liability arising out of these possible
violations of the Securities Act. The magnitude of any potential liability is
presently impossible to quantify, and would depend upon whether it is
demonstrated we violated the Securities Act, the number of common units that
purchasers in the offering sought to require us to repurchase and the trading
price of our common units.

Risks Related to
Ownership of Our Common Units if We
or Knight Defaults on Debt

Unitholders may
have negative tax consequences if we
default on our debt or sell assets.

If
we default on any of our debt, the lenders will have the right to sue us for
non-payment. Such an action could cause an investment loss and cause negative
tax consequences for unitholders through the realization of taxable income by
unitholders without a corresponding cash distribution. Likewise, if we were to
dispose of assets and realize a taxable gain while there is substantial debt
outstanding and proceeds of the sale were applied to the debt, unitholders
could have increased taxable income without a corresponding cash distribution.

There is the
potential for a change of control if
Knight defaults on debt.

Knight owns
all of the outstanding capital stock of our general partner. Knight has
operations which provide cash independent of dividends that Knight receives
from our general partner. Nevertheless, if Knight defaults on its debt, in
exercising their rights as lenders, Knights lenders could acquire control of
our general partner or otherwise influence our general partner through control
of Knight.

50

Item 1B. Unresolved
Staff Comments.

None.

Item 3. Legal
Proceedings.

See Note 16
of the notes to our consolidated financial statements included elsewhere in
this report.

Item 4. Submission
of Matters to a Vote of Security Holders.

There were
no matters submitted to a vote of our unitholders during the fourth quarter of
2008.

51

PART II

Item 5. Market
for Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.

The
following table sets forth, for the periods indicated, the high and low sale
prices per common unit, as reported on the New York Stock Exchange, the
principal market in which our common units are traded, the amount of cash
distributions declared per common and Class B unit, and the fractional i-unit
distribution declared per i-unit.

Price RangeHigh

Low

Cash
 Distributions

i-unit
 Distributions2008First Quarter

$
60.62

$
50.80

$
0.9600


0.017716Second Quarter


60.89


53.81


0.9900


0.018124Third Quarter


59.48


48.67


1.0200


0.021570Fourth Quarter


56.00


35.59


1.0500


0.0245802007First Quarter

$
53.50

$
47.28

$
0.8300


0.015378Second Quarter


57.35


52.11


0.8500


0.016331Third Quarter


56.70


46.61


0.8800


0.017686Fourth Quarter


54.71


48.51


0.9200


0.017312Distribution
information is for distributions declared with respect to that quarter. The
declared distributions were paid within 45 days after the end of the quarter.
We currently expect to declare cash distributions of at least $4.20 per unit
for 2009; however, no assurance can be given that we will be able to achieve
this level of distribution, and our expectation does not take into account any
capital costs associated with financing the payment of reparations sought by
shippers on our Pacific operations interstate pipelines.

As of
January 31, 2009, there were approximately 255,000 holders of our common units
(based on the number of record holders and individual participants in security
position listings), one holder of our Class B units and one holder of our
i-units.

For
information on our equity compensation plans, see Item 12 Security Ownership
of Certain Beneficial Owners and Management and Related Stockholder
MattersEquity Compensation Plan Information.

We
did not repurchase any units during 2008 or sell any unregistered units in the
fourth quarter of 2008.

52

Item 6. Selected
Financial Data

The
following tables set forth, for the periods and at the dates indicated, our
summary historical financial and operating data. The table is derived from our
consolidated financial statements and notes thereto, and should be read in
conjunction with those audited financial statements. See also Item 7
Managements Discussion and Analysis of Financial Condition and Results of
Operations in this report for more information.

Year Ended December 31,2008(6)

2007(7)

2006(8)

2005(9)

2004(10)(In millions, except per unit and ratio
 data)Income and Cash Flow
Data:Revenues

$
11,740.3

$
9,217.7

$
9,048.7

$
9,745.9

$
7,893.0Costs, Expenses and
Other:Gas purchases and other costs
 of sales


7,716.1


5,809.8


5,990.9


7,167.3


5,767.0Operations and
maintenance


1,010.2


1,024.6


777.0


719.5


488.6Fuel and power


272.6


237.5


223.7


178.5


146.4Depreciation, depletion and
 amortization


702.7


540.0


423.9


341.6


281.1General and
administrative


297.9


278.7


238.4


216.7


170.5Taxes, other than income
taxes


186.7


153.8


134.4


106.5


79.1Other expense (income)


2.6


365.6


(31.2
)




10,188.8


8,410.0


7,757.1


8,730.1


6,932.7Operating income


1,551.5


807.7


1,291.6


1,015.8


960.3Other
income/(expense):Earnings from equity
 investments


160.8


69.7


74.0


89.6


81.8Amortization of excess cost of
 equity investments


(5.7
)

(5.8
)

(5.6
)

(5.5
)

(5.6
)Interest, net


(388.2
)

(391.4
)

(337.8
)

(259.0
)

(192.9
)Other, net


19.2


14.2


12.0


3.3


2.2Minority interest


(13.7
)

(7.0
)

(15.4
)

(7.3
)

(9.6
)Income tax provision


(20.4
)

(71.0
)

(29.0
)

(24.5
)

(19.7
)Income from continuing
 operations


1,303.5


416.4


989.8


812.4


816.5Income (loss) from discontinued
 operations(1)


1.3


173.9


14.3


(0.2
)

15.1Net income

$
1,304.8

$
590.3

$
1,004.1

$
812.2

$
831.6Less: General Partners
 interest in net income


(805.8
)

(611.6
)

(513.3
)

(477.3
)

(395.1
)Limited Partners interest
in
 net income (loss)

$
499.0

$
(21.3
)
$
490.8

$
334.9

$
436.5Basic Limited Partners net
 income (loss) per unit:Income (loss) per unit from
 continuing operations(2)

$
1.94

$
(0.82
)
$
2.12

$
1.58

$
2.14Income from discontinued
 operations





0.73


0.07





0.08Net income (loss) per
unit

$
1.94

$
(0.09
)
$
2.19

$
1.58

$
2.22Diluted Limited Partners
net income
 (loss) per unit:Income (loss) per unit from
 continuing operations(2)

$
1.94

$
(0.82
)
$
2.12

$
1.58

$
2.14Income from discontinued
 operations





0.73


0.06





0.08Net income (loss) per
unit

$
1.94

$
(0.09
)
$
2.18

$
1.58

$
2.22Per unit cash distribution
 declared(3)

$
4.02

$
3.48

$
3.26

$
3.13

$
2.87Ratio of earnings to fixed
 charges(4)

$
3.77

$
2.13

$
3.64


3.76


4.84Additions to property, plant
 and equipment

$
2,533.0

$
1,691.6

$
1,182.1

$
863.1

$
747.3Balance Sheet Data (at end of
period):Net property, plant and
 equipment

$
13,241.4

$
11,591.3

$
10,106.1

$
8,864.6

$
8,168.9Total assets

$
17,885.8

$
15,177.8

$
13,542.2

$
11,923.5

$
10,552.9Long-term debt(5)

$
8,274.9

$
6,455.9

$
4,384.3

$
5,220.9

$
4,722.4(1)
Represents income or loss
 from the operations of our North System natural gas liquids pipeline system.
 2008 and 2007 amounts include gains of $1.3 million and $152.8 million,
 respectively, on disposal of our North System. For more information on our
 discontinued operations, see Note 3 to our consolidated financial
 statements included elsewhere in this report.(2)
Represents income from continuing operations per unit. Basic Limited
 Partners income per unit from continuing operations was computed by dividing
 the interest of our unitholders in income from continuing operations by the
 weighted average53

number of units outstanding during the period. Diluted Limited
 Partners income per unit from continuing operations reflects the maximum
 potential dilution that could occur if units whose issuance depends on the
 market price of the units at a future date were considered outstanding, or
 if, by application of the treasury stock method, options to issue units were
 exercised, both of which would result in the issuance of additional units
 that would then share in our net income.(3)
Represents the amount of cash distributions declared with respect to
 that year.(4)
For the purpose of
 computing the ratio of earnings to fixed charges, earnings are defined as
 income from continuing operations before income taxes, and before minority interest in consolidated subsidiaries,
 equity earnings (including amortization of excess cost of equity investments)
 and unamortized capitalized interest, plus fixed charges and distributed
 income of equity investees. Fixed charges are defined as the sum of interest
 on all indebtedness (excluding capitalized interest), amortization of debt
 issuance costs and that portion of rental expense which we believe to be
 representative of an interest factor.(5)
Excludes value of interest rate swaps. Increases to long-term debt
 for value of interest rate swaps totaled $951.3 million as of December 31,
 2008, $152.2 million as of December 31, 2007, $42.6 million as of December
 31, 2006, $98.5 million as of December 31, 2005 and $130.2 million as of
 December 31, 2004.(6)
Includes
 results of operations for the terminal assets acquired from Chemserve, Inc.
 and the Phoenix, Arizona refined
 petroleum products storage terminal acquired from ConocoPhillips since effective dates of acquisition. We
 acquired the terminal assets from Chemserve effective August 15, 2008, and we
 acquired the Phoenix, Arizona products terminal effective December 10, 2008.(7)
Includes results of operations for an approximate 50.2%
 interest in the Cochin pipeline system, the Vancouver Wharves marine
 terminal, and terminal assets acquired from Marine Terminals, Inc. since effective dates of acquisition. We acquired
 the remaining 50.2% interest in Cochin that we did not already own from
 affiliates of BP effective January
 1, 2007. We acquired the Vancouver Wharves bulk marine terminal operations
 from British Columbia Railway Company effective May 30, 2007, and we acquired
 certain bulk terminal assets from Marine Terminals, Inc. effective September
 1, 2007. Also includes Trans Mountain since January 1, 2007 as discussed
 below in note (8).(8)
Includes
 results of operations for the net assets of Trans Mountain acquired on April
 30, 2007 from Knight Inc. (formerly Kinder Morgan, Inc.) since January 1,
 2006. Also includes results of operations for the oil and gas properties
 acquired from Journey Acquisition-I, L.P. and Journey 2000, L.P., the
 terminal assets and operations acquired from A&L Trucking, L.P. and U.S.
 Development Group, Transload Services, LLC, and Devco USA L.L.C. since effective
 dates of acquisition. The April 5, 2006 acquisition of the Journey oil and
 gas properties were made effective March 1, 2006. The assets and operations
 acquired from A&L Trucking and U.S. Development Group were acquired in
 three separate transactions in April 2006. We acquired all of the membership
 interests in Transload Services, LLC effective November 20, 2006, and we
 acquired all of the membership interests in Devco USA L.L.C. effective
 December 1, 2006. We also acquired a 66 2/3% ownership interest in Entrega
 Pipeline LLC effective February 23, 2006, however, our earnings were not materially
 impacted during 2006 because regulatory accounting provisions required
 capitalization of revenues and expenses until the second segment of the
 Entrega Pipeline was complete and in-service.(9)
Includes
 results of operations for the 64.5% interest in the Claytonville unit, the
 seven bulk terminal operations acquired from Trans-Global Solutions, Inc., the Kinder Morgan Staten
 Island terminal, the terminal facilities located in Hawesville, Kentucky and
 Blytheville, Arkansas, General Stevedores, L.P., the North Dayton natural gas
 storage facility, the Kinder Morgan Blackhawk terminal, the terminal repair
 shop acquired from Trans-Global Solutions, Inc., and the terminal assets
 acquired from Allied Terminals, Inc. since effective dates of acquisition. We
 acquired the 64.5% interest in the Claytonville unit effective January 31,
 2005. We acquired the seven bulk terminal operations from Trans-Global
 Solutions, Inc. effective April 29, 2005. The Kinder Morgan Staten Island
 terminal, the Hawesville, Kentucky terminal and the Blytheville, Arkansas
 terminal were each acquired separately in July 2005. We acquired all of the
 partnership interests in General Stevedores, L.P. effective July 31, 2005. We
 acquired the North Dayton natural gas storage facility effective August 1,
 2005. We acquired the Kinder Morgan Blackhawk terminal in August 2005 and the
 terminal repair shop in September 2005. We acquired the terminal assets from
 Allied Terminals, Inc. effective November 4, 2005.(10)
Includes results of operations for the seven refined petroleum
 products terminals acquired from ExxonMobil, Kinder Morgan Wink Pipeline,
 L.P., an additional 5% interest in the Cochin Pipeline System, Kinder Morgan
 River Terminals LLC and its consolidated subsidiaries, TransColorado Gas
 Transmission Company LLC, interests in nine refined petroleum products
 terminals acquired from Charter Terminal Company and Charter-Triad Terminals,
 LLC, and the Kinder Morgan Fairless Hills terminal since effective dates of
 acquisition. We acquired the seven refined petroleum products terminals from
 ExxonMobil effective March 9, 2004. We acquired Kinder Morgan Wink Pipeline,
 L.P. effective August 31, 2004. The additional interest in Cochin was
 acquired effective October 1, 2004. We acquired Kinder Morgan River Terminals
 LLC and its consolidated subsidiaries effective October 6, 2004. We acquired
 TransColorado effective November 1, 2004,54

the interests in the nine Charter Terminal Company and Charter-Triad
 Terminals, LLC refined petroleum products terminals effective November 5,
 2004, and the Kinder Morgan Fairless Hills terminal effective December 1,
 2004.Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations.

The
following discussion and analysis should be read in conjunction with our
consolidated financial statements included elsewhere in this report. Additional
sections in this report which should be helpful to the reading of our
discussion and analysis include the following: (i) a description of our
business strategy found in Items 1 and 2 Business and Properties(c) Narrative
Description of BusinessBusiness Strategy; (ii) a description of developments
during 2008, found in Items 1 and 2 Business and Properties(a) General
Development of BusinessRecent Developments; and (iii) a description of risk
factors affecting us and our business, found in Item 1A Risk Factors. In addition to any uncertainties
described in this discussion and analysis, our Risk Factors disclosure
provides a more detailed description of a variety of risks that could have a
material adverse effect on our business, financial condition, cash flows and
results of operations.

General

Our
business model is built to support two principal components:

helping customers by providing
 energy, bulk commodity and liquids products transportation, storage and
 distribution; andcreating long-term value for
 our unitholders.To achieve
these objectives, we focus on providing fee-based services to customers from a
business portfolio consisting of energy-related pipelines, bulk and liquids
terminal facilities, and carbon dioxide and petroleum reserves. Our reportable
business segments are based on the way our management organizes our enterprise,
and each of our five segments represents a component of our enterprise that
engages in a separate business activity and for which discrete financial
information is available.

Our
five reportable business segments are:

Products Pipelinesthe
ownership and
 operation of refined petroleum products pipelines that deliver gasoline,
 diesel fuel, jet fuel and natural gas liquids to various markets, plus the ownership
 and/or operation of associated product terminals and petroleum pipeline
 transmix facilities;Natural Gas Pipelinesthe
ownership and
 operation of major interstate and intrastate natural gas pipeline and storage
 systems;CO2(i) the
production, transportation and marketing of carbon dioxide, referred to as CO2,
 to oil fields that use CO2 to increase production of oil, (ii)
 ownership interests in and/or operation of oil fields in West Texas, and
 (iii) the ownership and operation of a crude oil pipeline system in West
 Texas;Terminalsthe ownership
and/or operation of
 liquids and bulk terminal facilities and rail transloading and materials
 handling facilities located throughout the United States; andKinder Morgan Canada(i)
the ownership and
 operation of the Trans Mountain pipeline system that transports crude oil and
 refined petroleum products from Edmonton, Alberta, Canada to marketing
 terminals and refineries in British Columbia, Canada and the state of
 Washington; and (ii) the 33 1/3% interest in the Express pipeline system and
 the Jet Fuel pipeline system we acquired from Knight effective August 28,
 2008. Following the acquisition of these two businesses, the operations of
 our Trans Mountain, Express and Jet Fuel pipeline systems have been combined
 to represent our Kinder Morgan Canada segment.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

55

current
performance and our prospects for the future. Many of our operations are
regulated by various U.S. and Canadian regulatory bodies. 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, and
the prices for shipping are generally based on regulated tariffs that are
adjusted annually based on changes in the U.S. 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.

Our
CO2 sales and transportation business, like our natural gas
pipelines business, generally has take-or-pay contracts, although the contracts
in our CO2business typically have minimum volume requirements. In
the long term, our success in this business is driven by the demand for CO2.
However, short-term changes in the demand for CO2 typically do not
have a significant impact on us due to the required minimum transport volumes
under many of our contracts. In the oil and gas producing activities within our
CO2business 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
oil and gas 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 derivative contracts,
particularly for crude oil.

As
with our 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 our terminals
businesses 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 which 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. We believe that we have a
history of making accretive acquisitions and economically advantageous
expansions of existing businesses. Our ability to increase earnings and
increase distributions to our unitholders will, to some extent, be a function
of completing successful acquisitions and expansions. We continue to have
opportunities for expansion of our facilities in many markets, and we expect to
continue to have such opportunities in the future, although the level of such
opportunities is difficult to predict.

56

Our
ability to make accretive acquisitions is a function of the availability of
suitable acquisition candidates and, to some extent, our ability to raise
necessary capital to fund such acquisitions, factors over which we have limited
or no control. Thus, we have no way to determine the extent to which we will be
able to identify accretive acquisition candidates, or the number or size of
such candidates in the future, or whether we will complete the acquisition of
any such candidates.

On
November 24, 2008, we announced that we expect to declare cash distributions of $4.20 per unit for
2009, a 4.5% increase over our cash distributions of $4.02 per unit for 2008.  Our expected growth in
distributions in 2009 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, our average realized price for 2009 is currently projected to be $43 per barrel.  Although
the majority of the cash generated by our assets is fee based and is not sensitive to commodity prices,
our CO2 business segment is exposed to commodity price risk related to the price volatility of crude oil
and natural gas liquids.  We hedge the majority of our crude oil production, but do have exposure to
unhedged volumes, the majority of which are natural gas liquids volumes.  For 2009, we expect that every
$1 change in the average WTI crude oil price per barrel will impact our CO2 segments cash flows by
approximately $6 million (or approximately 0.2% of our combined business segments anticipated
distributable cash flow).  This sensitivity to the average WTI price is very similar to what we
experienced in 2008.  Our 2009 cash distribution expectations do not take into account any capital costs
associated with financing any payment we may be required to make of reparations sought by shippers on
our Pacific operations interstate pipelines.

Basis
of Presentation

As
discussed in Note 3 of the accompanying notes to our consolidated financial
statements, our financial statements and the financial information contained in
this Managements Discussion and Analysis of Financial Condition and Results of
Operations reflect the August 28, 2008 transfer of both the 33 1/3% interest in
the Express pipeline system net assets and the Jet Fuel pipeline system net
assets from Knight as of the date of transfer. Accordingly, we
have included the financial results of the Express and Jet Fuel pipeline
systems within our Kinder Morgan Canada business segment disclosures presented
in this report for all periods subsequent to August 28, 2008.

Critical Accounting Policies and Estimates

Accounting
standards require information in financial statements about the risks and
uncertainties inherent in significant estimates, and the application of
generally accepted accounting principles involves the exercise of varying
degrees of judgment. Certain amounts included in or affecting our consolidated
financial statements and related disclosures must be estimated, requiring us to
make certain assumptions with respect to values or conditions that cannot be
known with certainty at the time the financial statements are prepared. These
estimates and assumptions affect the amounts we report for our assets and
liabilities, our revenues and expenses during the reporting period and our
disclosure of contingent assets and liabilities at the date of our financial
statements.

We
routinely evaluate these estimates, utilizing historical experience,
consultation with experts and other methods we consider reasonable in the
particular circumstances. Nevertheless, actual results may differ significantly
from our estimates. Any effects on our business, financial position or results
of operations resulting from revisions to these estimates are recorded in the
period in which the facts that give rise to the revision become known.

In
preparing our consolidated financial statements and related disclosures,
examples of certain areas that require more judgment relative to others include
our use of estimates in determining:

 the economic useful
lives of
 our assets; the fair values
used to
 allocate purchase price and to determine possible asset impairment charges; reserves for
environmental
 claims, legal fees, transportation rate cases and other litigation
 liabilities; provisions for
uncollectible
 accounts receivables; exposures under
contractual
 indemnifications; and unbilled revenues.For a summary of our
significant accounting policies, see Note 2 to our consolidated
financial statements included elsewhere in this report. We believe that certain accounting policies are of more significance in
our consolidated financial statement preparation process than others, which
policies are discussed as follows.

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

57

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.

Our
recording of our environmental accruals often coincides with our completion of
a feasibility study or our commitment to a formal plan of action, but
generally, we recognize and/or adjust our environmental liabilities following
routine reviews of potential environmental issues and claims that could impact
our assets or operations. These adjustments may result in increases in
environmental expenses and are primarily related to quarterly reviews of
potential environmental issues and resulting environmental liability estimates.

These
environmental liability adjustments are recorded pursuant to our managements
requirement to recognize contingent environmental liabilities whenever the
associated environmental issue is likely to occur and the amount of our
liability can be reasonably estimated. In making these liability estimations,
we 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 16 to our consolidated
financial statements included elsewhere in this report.

Legal
Matters

We are
subject to litigation and regulatory proceedings as a result of our business
operations and transactions. We utilize both internal and external counsel in
evaluating our potential exposure to adverse outcomes from orders, judgments or
settlements. To the extent that actual outcomes differ from our estimates, or
additional facts and circumstances cause us to revise our estimates, our
earnings will be affected. 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. Generally, 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, our most significant ongoing litigation proceedings
involved our West Coast Products pipelines. Tariffs charged by certain of these
pipeline systems are subject to certain proceedings at the FERC involving
shippers complaints regarding the interstate rates, as well as practices and
the jurisdictional nature of certain facilities and services. Generally, the
interstate rates on our product pipeline systems are grandfathered under the
Energy Policy Act of 1992 unless substantially changed circumstances are
found to exist. To the extent substantially changed circumstances are found
to exist, our West Coast Products pipeline operations 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 our FERC regulatory
proceedings, see Note 16 to our consolidated financial statements included
elsewhere in this report.

Intangible
Assets

Intangible
assets are those assets which provide future economic benefit but have no
physical substance. We account for our intangible assets according to the
provisions of Statement of Financial Accounting Standards No.
141, Business Combinations and Statement
of Financial Accounting Standards No. 142, Goodwill and Other Intangible
Assets. These accounting pronouncements introduced the concept of
indefinite life intangible assets and provided that all identifiable intangible
assets having indefinite useful economic lives, including goodwill, will not be
subject to regular periodic amortization. Such assets are not to be amortized
until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset
with an indefinite useful life must be tested for impairment annually or on an
interim basis if events or circumstances indicate that the fair value of the
asset has decreased below its carrying value.

There
have not been any significant changes in these policies and estimates during
2008; however, during the second quarter of 2008, we changed the date of our
annual goodwill impairment test date to May 31 of each year (from January 1),
and we have determined that our goodwill was not impaired as of May 31, 2008.
Although our change to a new testing date, when applied to prior periods, does
not yield different financial statement results, this change constitutes a
change in the method of applying an accounting principle, as discussed in
paragraph 4 of SFAS

58

No. 154,
Accounting Changes and Error Corrections. For more information on this
change, see Note 2 to our consolidated financial statements included elsewhere
in this report.

As
of December 31, 2008 and 2007, our goodwill was $1,058.9 million and $1,077.8
million, respectively. Included in our December 31, 2008 goodwill balance is
$203.6 million related to our Trans Mountain pipeline system, which we acquired
from Knight on April 30, 2007. Following the provisions of generally accepted
accounting principles, this transaction caused Knight to consider the fair
value of the Trans Mountain pipeline system and to determine whether goodwill
related to these assets was impaired. Knight recorded a goodwill impairment
charge of $377.1 million in the first quarter of 2007. This impairment is also
reflected on our books due to the accounting principles for transfers of assets
between entities under common control, which require us to account for Trans
Mountain as if the transfer had taken place on January 1, 2006.

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 our accompanying consolidated balance
sheets. As of December 31, 2008 and 2007, these intangibles totaled $205.8
million and $238.6 million, respectively.  For more information on our goodwill
and other intangible assets, see Note 8 to our consolidated financial statements
included elsewhere in this report.

Estimated Net
Recoverable Quantities of Oil and Gas

We use the
successful efforts method of accounting for our oil and gas producing
activities. The successful efforts method inherently relies on the estimation
of proved reserves, both developed and undeveloped. The existence and the
estimated amount of proved reserves affect, among other things, whether certain
costs are capitalized or expensed, the amount and timing of costs depleted or
amortized into income and the presentation of supplemental information on oil
and gas producing activities. The expected future cash flows to be generated by
oil and gas producing properties used in testing for impairment of such
properties also rely in part on estimates of net recoverable quantities of oil
and gas.

Proved
reserves are the estimated quantities of oil and gas that geologic and
engineering data demonstrates with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either positively or
negatively, as additional information becomes available and as contractual,
economic and political conditions change.

Hedging
Activities

We engage
in a hedging program that utilizes derivative contracts to mitigate (offset)
our exposure to fluctuations in energy commodity prices 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.

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 because 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

59

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.

2008
Hurricanes and Fires

In
September 2008, two hurricanes struck the Gulf Coast communities of southern
Texas and Louisiana and a third hurricane made U.S. landfall near the South
Carolina-North Carolina border. The three named hurricanesHanna, Gustav, and
Ikecaused wide-spread damage to residential and commercial property, but our
primary assets in those areas experienced only relatively minor damage. Our
Terminals, Products Pipelines, Natural Gas Pipelines and CO2
business segments were negatively impacted by these hurricanes and we realized
a combined $11.1 million decrease in net income due to incremental expenses
associated with the clean-up and asset damage from these storms (but excluding
estimates for lost business and lost revenues). This decrease is described in
the footnotes to the tables below.

Additionally,
in the third quarter of 2008, we experienced fire damage at three separate
terminal locations. The largest was an explosion and fire at our Pasadena,
Texas liquids terminal facility on September 23, 2008. The fire primarily
damaged a manifold system used for liquids distribution. We intend to repair
the damaged portions of each separate terminal facility, and we recognized a
combined $7.2 million decrease in net income from our Terminals business
segment due to incremental expenses and asset damage associated with these
fires (excluding estimates for lost business and lost revenues). This decrease
is described in the footnotes to the tables below.

Results of Operations

Consolidated

Year Ended
 December 31,2008

2007

2006(In
 millions)Earnings before depreciation,
depletion and amortization expense and amortization of excess cost of equity investments(a)Products Pipelines(b)

$
546.2

$
569.6

$
491.2Natural Gas
Pipelines(c)


760.6


600.2


574.8CO2(d)


759.9


537.0


488.2Terminals(e)


523.8


416.0


408.1Kinder Morgan
Canada(f)


141.2


(293.6
)

76.5Segment earnings before
depreciation,
 depletion and amortization expense and amortization of excess cost of equity
 investments


2,731.7


1,829.2


2,038.8Depreciation, depletion and
amortization
 expense(g)


(702.7
)

(547.0
)

(432.8
)Amortization of excess cost of
equity
 investments


(5.7
)

(5.8
)

(5.7
)General and administrative
expenses(h)


(297.9
)

(278.7
)

(238.4
)Interest and other non-operating
 expenses(i)


(420.6
)

(407.4
)

(357.8
)Net income

$
1,304.8

$
590.3

$
1,004.1(a)
Includes revenues, earnings
 from equity investments, allocable interest income and other, net, less
 operating expenses, allocable income taxes, and other expense (income).
 Operating expenses include natural gas purchases and other costs of sales,
 operations and maintenance expenses, fuel and power expenses, and taxes,
 other than income taxes.(b)
2008 amount includes (i) a
 combined $10.0 million decrease in income from the proposed settlement of
 certain litigation matters related to our Pacific operations East Line
 pipeline and other legal liability adjustments; (ii) a $10.0 million decrease
 in income associated with environmental liability adjustments; (iii) a $3.6
 million decrease in income resulting from unrealized foreign currency losses
 on long-term debt transactions; (iv) a combined $2.7 million decrease in
 income resulting from refined product inventory losses and certain property,
 plant and equipment write-offs; (v) a $0.3 million decrease in income related
 to hurricane clean-up and repair activities; and (vi) a $1.3 million gain
 from the 2007 sale of our North System. 2007 amount includes (i) a $152.8
 million gain from the sale of our North System; (ii) a $136.8 million
 increase in expense associated with rate case and other legal liability
 adjustments; (iii) a $15.9 million increase in expense associated with
 environmental liability adjustments; (iv) a $15.0 million increase in expense
 for a litigation settlement reached with Contra Costa County, California; (v)
 a $3.2 million increase in expense from the settlement of certain litigation
 matters related to our West Coast refined products terminal operations; and
 (vi) a $1.8 million increase in income resulting60

from unrealized foreign
 currency gains on long-term debt transactions. 2006 amount includes a $16.5
 million increase in expense associated with environmental liability
 adjustments, and a $5.7 million increase in income resulting from certain
 transmix contract settlements.(c)
2008 amount includes (i) a
 $13.0 million gain from the sale of our 25% equity ownership interest in
 Thunder Creek Gas Services, LLC; (ii) a combined $5.6 million increase in
 income resulting from unrealized mark to market gains and losses due to the
 discontinuance of hedge accounting at Casper Douglas; (iii) a $0.5 million
 decrease in expense associated with environmental liability adjustments; (iv)
 a $5.0 million increase in expense related to hurricane clean-up and repair
 activities, and (v) a $0.3 million increase in expense associated with legal
 liability adjustments. 2007 amount includes an expense of $1.0 million,
 reflecting our portion of a loss from the early extinguishment of debt by Red
 Cedar Gathering Company, and a $0.4 million decrease in expense associated
 with environmental liability adjustments. 2006 amount includes a $1.5 million
 increase in expense associated with environmental liability adjustments, a
 $15.1 million gain from the combined sale of our Douglas natural gas
 gathering system and Painter Unit fractionation facility, and a $6.3 million
 reduction in expense due to the release of a reserve related to a natural gas
 purchase/sales contract.(d)
2008 amount includes a $0.3 million increase in expense associated with
environmental liability
 adjustments. 2007 amount includes a $0.2 million increase in expense
 associated with environmental liability adjustments. 2006 amount includes a
 $1.8 million loss on derivative contracts used to hedge forecasted crude oil
 sales.(e)
2008 amount includes (i) a
 $7.2 million decrease in income related to fire damage and repair activities;
 (ii) a $5.7 million decrease in income related to hurricane clean-up and
 repair activities; (iii) a combined $2.8 million increase in expense from the
 settlement of certain litigation matters related to our Elizabeth River bulk
 terminal and our Staten Island liquids terminal, and other legal liability adjustments;
 and (iv) a $0.6 million decrease in expense associated with environmental
 liability adjustments. 2007 amount includes (i) a $25.0 million increase in
 expense from the settlement of certain litigation matters related to our Cora
 coal terminal; (ii) a $2.0 million increase in expense associated with
 environmental liability adjustments; (iii) a $1.2 million increase in expense
 associated with legal liability adjustments; and (iv) an increase in income
 of $1.8 million from property casualty gains associated with the 2005
 hurricane season. 2006 amount includes an $11.3 million increase in income
 from the net effect of a property casualty insurance gain and incremental
 repair and clean-up expenses (both associated with the 2005 hurricane
 season).(f)
2008 amount includes a $19.3 million decrease in expense associated with
favorable changes in
 Canadian income tax rates, and an $18.9 increase in expense from the amounts
 previously reported in our 2008 fourth quarter earnings release issued on
 January 21, 2009, due to certain non-cash regulatory accounting adjustments.
 2007 amount includes losses of $349.2 million for
 periods prior to our acquisition date of April 30, 2007 (including a $377.1
 million goodwill impairment expense associated with a non-cash reduction in
 the carrying value of Trans Mountains goodwill), and a $1.3 million
 decrease in income from an oil loss allowance. 2006 amount represents earnings for a period prior to our acquisition
 date of April 30, 2007.(g)
2008 amount includes a $6.9
 million increase in expense from the amounts previously reported in our 2008
 fourth quarter earnings release issued on January 21, 2009, due to certain
 non-cash regulatory accounting adjustments.  2007 and 2006 amounts
 include Trans Mountain expenses of $6.3 million and $19.0 million,
 respectively, for periods prior to our acquisition date of April 30, 2007.(h)
Includes unallocated litigation and environmental expenses.
 2008 amount includes (i) a $5.6
 million increase in non-cash compensation expense, allocated to us from
 Knight (we do not have any obligation, nor do we expect to pay any amounts
 related to this expense); (ii) a $0.9 million increase in expense for certain
 Express pipeline system acquisition costs; (iii) a $0.4 million expense
 resulting from the write-off of certain acquisition costs pursuant to a newly
 adopted accounting principle; (iv) a $0.1 million increase in expense
 related to hurricane clean-up and repair activities; and (v) a $2.0 million decrease in expense
 due to the adjustment of certain insurance related liabilities. 2007
 amount includes (i) a $26.2 million increase in expense, allocated to us from
 Knight, associated with closing the going-private transaction (we do not
 have any obligation, nor do we expect to pay any amounts related to this
 expense);
 (ii) a $5.5 million expense for Trans Mountain general and administrative
 expenses for periods prior to our acquisition date of April 30, 2007; (iii) a $2.1
 million expense due to the adjustment of certain insurance related
 liabilities; (iv) a $1.7 million increase in expense associated with the 2005
 hurricane season; (v) a $1.5 million expense for certain Trans Mountain
 acquisition costs; and (vi) a $0.8 million expense related to the
 cancellation of certain commercial insurance policies. 2006 amount
 includes (i) an $18.8 million expense for Trans Mountain general and administrative
 expenses for periods prior to our acquisition date of April 30, 2007; (ii) a $2.4
 million increase in expense related to the cancellation of certain commercial
 insurance policies; and (iii) a $0.4 million decrease in expense related to the allocation of general
 and administrative expenses on hurricane related capital expenditures for the
 replacement and repair of assets (capitalization of overhead expense).(i)
Includes unallocated interest income and income
 tax expense, interest and debt expense, and minority
 interest expense. 2008 amount
 includes (i) a $7.1 million decrease in interest expense from the amounts
 previously reported in our 2008 fourth quarter earnings release issued on
 January 21, 2009, due to certain non-cash Trans Mountain regulatory accounting
 adjustments; (ii) a $2.0 million increase in imputed interest expense related
 to our January 1, 2007 Cochin Pipeline acquisition; and (iii) a $0.2 million
 increase in interest expense related to the proposed settlement of certain
 litigation matters related to our Pacific operations East Line pipeline. 2007 amount
 includes a $2.4 million increase in imputed interest expense related to our
 January 1, 2007 Cochin Pipeline acquisition, and a $1.2 million expense for
 Trans Mountain interest expense for periods prior to our acquisition
 date of April 30, 2007. 2006 amount includes a $6.3 million expense for Trans Mountain
 interest expenses. 2008, 2007 and 2006 amounts also include a $0.4 million decrease in
 expense, a $3.9 million decrease in expense, and a $3.5 million increase
 in expense, respectively, related to the minority interest effect from all of
 the 2008, 2007 and 2006 items previously disclosed in these footnotes.61

For the
year 2008, our net income was $1,304.8 million on revenues of $11,740.3
million. This compares with net income of $590.3 million on revenues of
$9,217.7 million in 2007 and net income of $1,004.1 million on revenues of
$9,048.7 million in 2006. Our 2007 net income included an
impairment expense of $377.1 million associated with a non-cash reduction in the
carrying value of Trans Mountains goodwill. Included within the certain items
footnoted in the table above, and discussed above in Intangibles, the
goodwill impairment charge was recognized by Knight in March 2007. Following
our purchase of Trans Mountain from Knight on April 30, 2007, the financial
results of Trans Mountain since January 1, 2006, including the impact of the
goodwill impairment, are reflected in our results. For more information on this
acquisition and the goodwill impairment, see Notes 3 and 8 to our consolidated
financial statements included elsewhere in this report.

Segment
earnings before depreciation, depletion and amortization expenses

Because
our partnership agreement requires us to distribute 100% of our available cash
to our partners on a quarterly basis (available cash as defined in our
partnership agreement generally consists of all our cash receipts, less cash
disbursements and changes in reserves), we consider each periods earnings
before all non-cash depreciation, depletion and amortization expenses,
including amortization of excess cost of equity investments, to be an important
measure of our success in maximizing returns to our partners. We
also use segment earnings before depreciation, depletion and amortization
expenses (defined in the table above and sometimes referred to in this report
as EBDA) internally as a measure of profit and loss used for evaluating segment
performance and for deciding how to allocate resources to our five reportable
business segments.

As
a result of internal growth and expansion
across our business portfolio, as well as incremental contributions from asset
acquisitions, our total segment earnings before depreciation, depletion
and amortization increased $902.5 million (49%) in 2008, when compared to 2007.
The certain items described in the footnotes to the table above (including the
goodwill impairment expense) accounted for $367.5 million of the overall
increase (combining to decrease segment EBDA by $26.5 million in 2008 and to
decrease segment EBDA by $394.0 million in 2007). The remaining $535.0 million (24%) increase in year-to-year
segment earnings before depreciation, depletion and amortization resulted from
incremental earnings from our CO2, Natural Gas Pipelines, Terminals
and Kinder Morgan Canada business segments. Specifically, in 2008, we
benefitted from higher revenues from crude oil and carbon dioxide sales, the
start-up of the Rockies Express-West natural gas pipeline, improved margins
from our Texas intrastate natural gas pipeline group, incremental earnings from
expanded bulk and liquids terminal operations, and a full year impact of Trans
Mountain and its expansions.

The
overall increase in our earnings compared to last year was tempered by such
factors as (i) a continued slowing economy; (ii) the negative impact of higher
energy pricesprimarily in the first three quarters on demand for petroleum
productswhich negatively impacted our deliveries of gasoline, diesel and jet
fuel in 2008; (iii) increases in average construction and fuel costswhich
negatively impacted both our capital expansion programs and our existing
operations when compared to 2007; (iv) a weakening of the Canadian
dollarrelative to the U.S. dollar and primarily since the end of the third
quarter of 2008; and (v) lower crude oil, natural gas liquids and natural gas
 prices in the fourth quarter of 2008.


In
light of the 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
2007, total segment earnings before depreciation, depletion and amortization
decreased $209.6 million (10%) when compared to the previous year, and
combined, the certain items described in the footnotes to the table above
decreased total segment earnings before depreciation, depletion and
amortization by $489.1 million in 2007, relative to 2006 (combining to decrease
total segment EBDA by $394.0 million in 2007 and to increase segment EBDA by
$95.1 million in 2006).

The
remaining $279.5 million (14%) increase in segment earnings before
depreciation, depletion and amortization in 2007 versus 2006 was driven by increased margins on natural gas
transport, storage and processing activities, incremental earnings from
dry-bulk product and petroleum liquids terminal operations, higher crude oil
and natural gas liquids revenues, incremental earnings from completed expansion
projects, and our acquisitions of both the Trans Mountain pipeline system and the
remaining interest in the Cochin pipeline system that we did not already own.

62

Products
Pipelines

Year Ended
 December 31,2008

2007

2006(In
 millions, except operating statistics)Revenues(a)

$
815.9

$
844.4

$
776.3Operating expenses(b)


(291.0
)

(451.8
)

(308.3
)Other income
(expense)(c)


(1.3
)

154.8


Earnings from equity
investments(d)


24.4


32.5


16.3Interest income and Other,
net-income
 (expense)(e)


2.0


9.4


12.1Income tax benefit
(expense)(f)


(3.8
)

(19.7
)

(5.2
)Earnings before depreciation,
depletion and
 amortization expense and amortization of excess cost of equity investments

$
546.2

$
569.6

$
491.2Gasoline (MMBbl)


398.4


435.5


449.8Diesel fuel (MMBbl)


157.9


164.1


158.2Jet fuel (MMBbl)


117.3


125.1


119.5Total refined
product volumes (MMBbl)


673.6


724.7


727.5Natural gas liquids
(MMBbl)


27.3


30.4


34.0Total delivery
volumes (MMBbl)(g)


700.9


755.1


761.5(a)
2008 amount includes a $5.1 million decrease
 in revenues from the proposed settlement of certain litigation matters
 related to our Pacific operations East Line pipeline.(b)
2008, 2007
 and 2006 amounts include increases in expense of $9.2 million, $15.9 million
 and $13.5 million, respectively, associated with environmental liability adjustments. 2008 amount also includes a combined $5.0
 million increase in expense from the proposed settlement of certain
 litigation matters related to our Pacific operations East Line pipeline and
 other legal liability adjustments, a $0.5 million increase in expense
 resulting from refined product inventory losses, and a $0.2 million increase
 in expense related to hurricane clean-up and repair activities. 2007 amount
 also includes a $136.7 million increase in expense associated with rate case
 and other legal liability adjustments, a $15.0 million expense for a
 litigation settlement reached with Contra Costa County, California, and a
 $3.2 million increase in expense from the settlement of certain litigation
 matters related to our West Coast refined products terminal operations.(c)
2008 and 2007 amounts include
 gains of $1.3 million and $152.8 million, respectively, from the 2007 sale of
 our North System. 2008 amount also includes a $2.2 million decrease in income
 resulting from certain property, plant and equipment write-offs.(d)
2008 amount includes an
 expense of $1.3 million associated with our portion of environmental
 liability adjustments on Plantation Pipe Line Company, and an expense of $0.1 million reflecting our portion of
 Plantation Pipe Line Companys expenses related to hurricane clean-up and
 repair activities. 2007 amount includes an expense of $0.1 million
 associated with our portion of legal liability adjustments on Plantation Pipe
 Line Company. 2006 amount includes an expense of $4.9 million associated with
 our portion of environmental liability adjustments on Plantation Pipe Line
 Company.(e)
2008 and
 2007 amounts include a $3.6 million decrease in income and a $1.8 million increase in income,
 respectively, resulting from unrealized foreign currency losses and gains on
 long-term debt transactions. 2006 amount includes a $5.7 million
 increase in income resulting from transmix contract settlements.(f)
2008 amount
 includes a $0.5 million decrease in expense reflecting the tax effect
 (savings) on our proportionate share of environmental expenses incurred by
 Plantation Pipe Line Company and described in footnote (d), and a $0.1
 million decrease in expense reflecting the tax effect (savings) on the
 incremental legal expenses described in footnote (b). 2006 amount includes a
 $1.9 million decrease in expense reflecting the tax effect (savings) on our
 proportionate share of environmental expenses incurred by Plantation Pipe
 Line Company and described in footnote (d).(g)
Includes
 Pacific, Plantation, Calnev, Central Florida, Cochin, and Cypress pipeline
 volumes.Earnings
before depreciation, depletion and amortization expenses decreased by $23.4
million in 2008 compared to 2007 and increased $78.4 million in 2007 compared
to 2006. Combined, the certain items described in the footnotes
to the table above account for $9.0 million of the decrease in 2008 compared to
2007, and a $5.5 million decrease in the results between 2007 and 2006.
Following is information related to the remaining increases and decreases in
the segments (i) earnings before depreciation, depletion and amortization
expenses (EBDA); and (ii) operating revenues in both 2008 and 2007, when
compared to the respective prior year:

63

Year Ended December 31, 2008 versus Year Ended December 31,
2007EBDA
 increase/(decrease)

Revenues
 increase/(decrease)(In
 millions, except percentages)North System

$
(28.1
)

n/a

$
(41.1
)

n/aPacific
 operations


(9.8
)

(4
)%

(0.7
)

0
%Plantation
 Pipeline


(2.4
)

(6
)%

1.8


4
%Southeast
 Terminals


9.4


22
%

13.7


20
%Cochin
 Pipeline System


6.6


15
%

(11.6
)

(15
)%Central
 Florida Pipeline


5.8


16
%

6.0


13
%West Coast
 Terminals


3.9


8
%

7.5


10
%All other
 (including eliminations)


0.2


0
%

1.0


1
%Total Products
Pipelines

$
(14.4
)

(2
)%
$
(23.4
)

(3
)%Year Ended December 31, 2007 versus Year Ended December 31,
2006EBDA
 increase/(decrease)

Revenues
 increase/(decrease)(In
 millions, except percentages)Cochin
 Pipeline System

$
30.0


212
%
$
39.2


110
%West Coast
 Terminals


12.3


34
%

7.5


12
%Plantation
 Pipeline


8.6


27
%

1.0


2
%Transmix
 operations


8.0


36
%

10.6


32
%Pacific
 operations


5.8


2
%

18.4


5
%Calnev
 Pipeline


5.1


11
%

3.4


5
%Southeast
 Terminals


5.0


13
%

(12.9
)

(16
)%North System


4.9


21
%

(2.6
)

(6
)%All other
 (including eliminations)


4.2


11
%

3.5


7
%Total Products
Pipelines

$
83.9


17
%
$
68.1


9
%The
decrease in both segment earnings before depreciation, depletion and
amortization expenses and segment revenues in 2008 versus 2007 attributable to
our North System were due to our October 2007 divestiture of the pipeline
system and our 50% ownership interest in the Heartland Pipeline Company
(collectively referred to in this report as our North System) to ONEOK
Partners, L.P. Following purchase price adjustments, we received approximately
$295.7 million in cash for the sale. We accounted for our North System business
as a discontinued operation pursuant to generally accepted accounting
principles which require that our income statement be formatted to separate the
divested business from our continuing operations; however, as discussed above,
because the sale of our North System does not change the structure of our
internal organization in a manner that causes a change to our reportable
business segments, we have included the North Systems operating results within
our Products Pipelines business segment disclosures for all periods presented
in this discussion and analysis. This decision was based on the way our
management organizes segments internally to make operating decisions and assess
performance.

Our
North System generated $28.1million of earnings before depreciation, depletion
and amortization expenses in 2007 prior to the effective sale date of October
5, 2007. In addition, we recognized a $152.8 million gain on disposal of the
North System in the fourth quarter of 2007. We also recorded incremental gain
adjustments of $1.3 million in 2008. The gains, unlike the earnings before
depreciation, depletion and amortization expenses, are not reflected in the
operating results above. For more information regarding this divestiture, see
Note 3 to our consolidated financial statements included elsewhere in this
report. For information on our reconciliation of segment information with our
consolidated general-purpose financial statements, see Note 15 to our
consolidated financial statements included elsewhere in this report.

The
decrease in earnings before depreciation, depletion and amortization from our
Pacific operations in 2008 compared to 2007 was primarily due to an increase in
system-wide operating and maintenance expenses. The increase primarily reflects
lower product gains in 2008, due both to lower physical gains and to the impact
of unfavorable changes in diesel fuel versus gasoline prices; lower capitalized
overhead credits, due to lower capital

64

spending in
2008; higher labor and payroll expenses due to an increase in headcount; and
incremental expenses associated with litigation and right-of-way liability
adjustments.

Total
revenues earned by our Pacific operations in 2008 were essentially flat
compared to 2007, as higher pipeline delivery revenues were largely offset by
lower fee-based terminal revenues. The year-over-year increase in refined
products delivery revenues resulted from both higher average tariff rates in
2008 and a more favorable delivery mix of higher-rate East Line volumes versus
lower-rate West Line volumes. The increase was offset by decreases of 7% and
5%, respectively, in gasoline and diesel fuel delivery volumes, relative to last
year, as U.S. gasoline and diesel demand has trailed year-earlier levels.

The
decrease in earnings from our equity investment in Plantation was due to lower
overall net income earned by Plantation Pipe Line Company, mainly due to lower
product transportation and pipeline service revenues. For the year 2008,
pipeline throughput volumes dropped 10% compared to the previous year. The 2008
drop in delivery volumes was due to a combination of decreased demand due to
lower product consumption, supply disruptions caused by hurricane related
refinery outages, and a volume shift by customers to competing pipelines.

When
compared to last year, our Products Pipelines business segment benefitted from
higher earnings before depreciation, depletion and amortization expenses from
our Southeast terminal operations, our Cochin and Central Florida pipeline
systems, and our West Coast terminal operations. The improved performances from
our Southeast and West Coast terminal operations were primarily related
to higher margins on liquids inventory sales, increased earnings from
incremental terminal throughput and storage activity at higher rates, and
incremental returns from the completion of a number of capital expansion
projects that modified and upgraded terminal infrastructure, enabling us to
provide additional terminal and ethanol related services to our customers.

We
continue to invest in projects that have now added ethanol storage and blending
capabilities to six separate terminal facilities included in our Southeast
terminal operations, and we are currently in the process of securing commercial
commitments to support the installation of ethanol handling infrastructure at
our remaining Southeast terminals. In addition, in the fourth quarter of 2008,
we completed construction of four new fuel storage tanks with a combined
capacity of 320,000 barrels at two military bases in the state of California.

The
increase in earnings before depreciation, depletion and amortization expenses
from our Cochin Pipeline was driven largely by a year-end 2008 reduction in
income tax expense, related to lower Canadian operating results in 2008 and to
Canadian income tax liability adjustments. The decrease in income tax expense
more than offset a 15% year-over-year drop in operating revenues that was
primarily related to lower pipeline transportation revenues. The decrease in
delivery revenues was due both to a continued decrease in demand for propane in
Eastern Canadian and Midwestern U.S. petrochemical and fuel markets since the
end of 2007 and to Cochins ceasing of ethane transportation in July 2007.

The
increase in earnings from our Central Florida Pipeline was chiefly revenue
related, driven by incremental ethanol terminal revenues that began in April
2008 and by incremental ethanol pipeline transportation revenues that began in
October 2008. The increase in revenues was also related to higher product
delivery revenues, driven by an increase in the average tariff as a result of a
mid-year tariff rate increase on product deliveries.

For
all segment assets combined, revenues for 2008 from refined petroleum products
deliveries increased a slight 0.8%, but total volumes delivered fell 7.1%, when
compared to 2007. Compared to last year, the segments volumes were negatively
impacted by reductions in demand, driven primarily by higher crude oil and
refined product prices and weaker economic conditions, and partly by lost
business associated with hurricanes in the third quarter of 2008. The decrease
in delivery volumes included an 8.5% drop in gasoline volumes, a 3.8% drop in
diesel fuel volumes, and a 6.2% decline in total jet fuel volumes. Excluding
deliveries by Plantation Pipeline, total segment revenues from refined
petroleum products deliveries increased 1.5% in 2008, when compared to last
year, and total refined products delivery volumes decreased 5.9%. Although
Plantation sustained no hurricane damage in 2008, the pipeline system pumped
reduced volumes in the third quarter of 2008 due to hurricane-induced refinery
shut-downs and to extended delays in restarting certain refineries impacted by
the hurricanes.

All
of the assets in our Products Pipelines business segment produced higher
earnings before depreciation, depletion and amortization expenses in 2007 than
in 2006. The overall increase in segment earnings before

65

depreciation,
depletion and amortization in 2007 compared to 2006 was driven largely by
incremental earnings from our Cochin pipeline system. The higher earnings and
revenues from Cochin were largely attributable to our January 1, 2007
acquisition of the remaining approximate 50.2% ownership interest that we did
not already own. Upon closing of the transaction, we became the operator of the
pipeline. For more information on this acquisition, see Note 3 to our
consolidated financial statements included elsewhere in this report.

Other
increases in segment earnings before depreciation, depletion and amortization
expenses in 2007 compared with 2006 included the following:

 an increase from
our West
 Coast terminal operationsdue mainly to higher operating revenues, lower
 operating expenses and incremental gains from asset sales. The increases in
 terminal revenues were driven by higher throughput volumes from our combined
 Carson/Los Angeles Harbor terminal system, and from our Linnton and
 Willbridge terminals located in Portland, Oregon. The increase in volumes at
 our Carson terminal was partly due to completed storage expansion projects
 since the end of 2006. The decrease in operating expenses was largely related
 to higher environmental expenses recognized in 2006, due to adjustments to
 accrued environmental liabilities; an increase from our
 approximate 51% equity investment in Plantation Pipe Line Companydue to
 higher overall net income earned by Plantation, largely resulting from both
 higher pipeline revenues and lower year-to-year operating expenses. The
 increase in revenues was largely due to a higher oil loss allowance
 percentage in 2007, relative to 2006, and the drop in operating expenses was
 due to decreases in both refined products delivery volumes and pipeline
 integrity expenses; an increase from
our petroleum
 pipeline transmix operationsreflecting incremental revenues from our
 Greensboro, North Carolina transmix facility and higher processing revenues
 from our Colton, California facility. We constructed and placed into service
 our Greensboro facility in May 2006, and the increases in earnings and
 revenues from our Colton facility, which processes transmix generated from
 volumes transported to the Southern California and Arizona markets by our
 Pacific operations pipelines, were primarily due to a year-to-year increase
 in average processing contract rates; an increase from
our Pacific
 operationslargely revenue related, attributable to increases in both
 products transportation volumes and average tariff rates. Combined mainline
 delivery and terminal revenues increased 5% in 2007, compared to 2006, due
 largely to higher delivery volumes to Arizona, the completed expansion of our
 East Line pipeline during the summer of 2006, and higher deliveries to
 various West Coast military bases; an increase from
our Calnev
 Pipelinedriven by higher year-over-year revenues, due to increased military
 and commercial tariff rates in 2007, and higher terminal revenues associated
 with ethanol blending at our Las Vegas terminal that more than offset a 2%
 drop in refined products delivery volumes; and an increase from
our Southeast
 terminal operationsdriven by higher overall liquids throughput volumes; and an increase from
our North
 Systemmainly due to lower combined operating expenses, due to its sale in
 the fourth quarter of 2007 (the decline in expense was greater than the
 associated decline in revenue).Combining
all of the segments operations, while revenues from refined petroleum products
deliveries increased 6.2% in 2007, compared to the prior year, total refined
products delivery volumes decreased 0.4%. Gasoline delivery volumes decreased
3.2% (primarily due to Plantation), while diesel and jet fuel volumes were up
3.7% and 4.7%, respectively, in 2007 versus 2006. Excluding Plantation, which
continued to be impacted by a competing pipeline that began service in
mid-2006, total refined products delivery volumes increased by 0.8% in 2007,
when compared to 2006. Volumes on our Pacific operations and our Central
Florida pipelines were up 1% and 2%, respectively, in 2007, and while natural
gas liquids delivery volumes were down in 2007 versus 2006, revenues were up
substantially due to our increased ownership in the Cochin pipeline system.

66

Natural Gas
Pipelines

Year Ended
 December 31,2008

2007

2006(In
 millions, except operating statistics)Revenues

$
8,422.0

$
6,466.5

$
6,577.7Operating expenses(a)


(7,804.0
)

(5,882.9
)

(6,057.8
)Other income
(expense)(b)


2.7


3.2


15.1Earnings from equity
investments(c)


113.4


19.2


40.5Interest income and Other,
net-income
 (expense)(d)


29.2


0.2


0.7Income tax benefit
(expense)


(2.7
)

(6.0
)

(1.4
)Earnings before depreciation,
depletion and
 amortization expense and amortization of excess cost of equity investments

$
760.6

$
600.2

$
574.8Natural gas transport volumes
(Trillion
 Btus)(e)


2,156.3


1,712.6


1,440.9Natural gas sales volumes
(Trillion
 Btus)(f)


866.9


865.5


909.3(a)
2008, 2007
 and 2006 amounts include a $0.5 million decrease in expense, a $0.4 million
 decrease in expense and a $1.5 million increase in expense, respectively,
 associated with environmental liability
 adjustments. 2008 amount also includes a combined $5.6 million increase in income
 resulting from unrealized mark to market gains and losses due to the
 discontinuance of hedge accounting at Casper Douglas, a $5.0 million increase
 in expense related to hurricane clean-up and repair activities, and a $0.3
 million increase in expense associated with legal liability adjustments.
 Beginning in the second quarter of 2008, our Casper and Douglas gas
 processing operations discontinued hedge accounting. 2006 amount also includes a $6.3 million reduction in expense due to the
 release of a reserve related to a natural gas purchase/sales contract.(b)
2006 amount represents a
 $15.1 million gain from the combined sale of our Douglas natural gas
 gathering system and Painter Unit fractionation facility.(c)
2007 amount includes an
 expense of $1.0 million reflecting our portion of a loss from the early
 extinguishment of debt by Red Cedar Gathering Company.(d)
2008 amount includes a
 $13.0 million gain from the sale of our 25% equity ownership interest in
 Thunder Creek Gas Services, LLC.(e)
Includes
 Kinder Morgan Interstate Gas Transmission LLC, Trailblazer Pipeline Company
 LLC, TransColorado Gas Transmission Company LLC, Rockies Express Pipeline
 LLC, and Texas intrastate natural gas pipeline group pipeline volumes.(f)
Represents
 Texas intrastate natural gas pipeline group volumes.Combined,
the certain items described in the footnotes to the table account for $14.4
million of the $160.4 million increase in earnings before depreciation,
depletion and amortization (EBDA) between 2007 and 2008, and a $20.5 million
decrease in EBDA between 2006 and 2007.

Following
is information related to the increases and decreases in the segments (i)
remaining changes in earnings before depreciation, depletion and amortization
expenses (EBDA); and (ii) changes in operating revenues in both 2008 and 2007,
when compared to the respective prior year:

Year Ended December 31, 2008 versus Year Ended December 31,
2007EBDA
 Increase/(decrease)

Revenues
 increase/(decrease)(In
 millions, except percentages)Rockies Express
Pipeline

$
97.0


769
%
$



Texas Intrastate Natural Gas
Pipeline Group


37.7


11
%

1,924.9


32
%Kinder Morgan Louisiana
Pipeline


11.2


n/a





n/aTransColorado Pipeline


11.1


26
%

12.5


24
%Kinder Morgan Interstate Gas
Transmission


5.4


5
%

(1.8
)

(1
)%Casper and Douglas gas
processing


(8.1
)

(38
)%

24.6


24
%Trailblazer Pipeline


(5.6
)

(11
)%

(5.2
)

(9
)%All others


(2.7
)

(8
)%

2.8


1096
%Intrasegment
Eliminations








(2.3
)

(170
)%Total Natural Gas
Pipelines

$
146.0


24
%
$
1,955.5


30
%67

Year Ended December 31, 2007 versus Year Ended December 31,
2006EBDA
 increase/(decrease)

Revenues
 increase/(decrease)(In
 millions, except percentages)Texas Intrastate Natural Gas
Pipeline Group

$
57.0


19
%
$
(142.2
)

(2
)%Casper and Douglas gas
processing


8.6


67
%

5.6


6
%Kinder Morgan Interstate Gas
Transmission


1.2


1
%

17.6


10
%Rockies Express
Pipeline


(12.6
)

n/a


(0.8
)

n/aRed Cedar Gathering
Company


(7.4
)

(20
)%




All others


(0.9
)

(1
)%

8.4


8
%Intrasegment
Eliminations








0.2


11
%Total Natural Gas
Pipelines

$
45.9


8
%
$
(111.2
)

(2
)%In
2008, our Natural Gas Pipelines business segment benefitted from incremental contributions
from our 51% equity ownership interest in Rockies Express Pipeline LLC, the
owner of the Rockies Express Pipeline. We account for our investment in Rockies
Express under the equity method of accounting, and the increase in our equity
earnings reflects higher net income earned in 2008 by Rockies Express,
primarily due to the start-up of service on the Rockies Express-West pipeline
segment in January and May 2008.

The
Rockies Express Pipeline began limited interim service in the first quarter of
2006 on its westernmost segment (the line that extends from Meeker, Colorado to
Wamsutter, Wyoming), and the $12.6 million decrease in earnings before
depreciation, depletion and amortization from Rockies Express in 2007 reflected
lower net income, when compared to 2006, due primarily to incremental
depreciation and interest expense allocable to another segment of the pipeline
that was placed in service in February 2007 and, until the completion of the
Rockies Express-West project, had limited natural gas reservation revenues and
volumes.

The
segment realized increases in earnings before depreciation, depletion and
amortization expenses in both 2008 and 2007 from strong year-over-year
performances from our Texas intrastate natural gas pipeline group, which
includes the operations of the following four natural gas pipeline systems:
Kinder Morgan Tejas (including Kinder Morgan Border Pipeline), Kinder Morgan
Texas Pipeline, Kinder Morgan North Texas Pipeline and our Mier-Monterrey
Mexico Pipeline.

The
higher earnings in both 2008 and 2007, when compared to the respective prior
years, were primarily due to higher sales margins on renewal and incremental
sales contracts, increased transportation revenues from higher volumes and rates,
greater value from natural gas storage activities, and higher natural gas
processing margins. The earnings improvement in both years from higher natural
gas sales margins reflected more favorable market conditions and year-over-year
customer growth. The increases in earnings from transportation and storage
activities in both 2008 and 2007 were partly driven by incremental natural gas
transport and fee-based storage revenues due to a long-term contract with one
of the groups largest customers that became effective April 1, 2007. The
increases in gas processing margins were largely due to more favorable price
changes in natural gas liquids relative to the price of natural gas.

With
regard to natural gas sales activity, our intrastate groups business strategy
involves relying both on long and short-term natural gas sales and purchase
agreements; however, the spot market activity of our Texas intrastate group,
which involves purchasing and selling natural gas under short-term commitments
at a single volume price, gives us greater flexibility to balance supply and
demand in order to react to changing market conditions. Furthermore, our spot
market transactions can often be accomplished under contract terms that are
less complex than traditional long-term arrangements and allow us to take
advantage of the large concentration of buyers and sellers (as pipeline
interconnections) located close to a large consuming region (the state of
Texas). We use this flexibility with regard to our natural gas sales activities
to help optimize the margins we realize by capturing favorable differences due
to changes in timing, location, prices and volumes. Generally, we attempt to
lock-in an acceptable margin by capturing the difference between our average
gas sales prices and our average gas purchase and cost of fuel prices.

68

Because
our intrastate group buys and sells significant quantities of natural gas, the
variances from period to period in both segment revenues and segment operating
expenses (which include natural gas costs of sales) are partly due to changes
in our intrastate groups average prices and volumes for natural gas purchased
and sold. To the extent possible, we balance the pricing and timing of our
natural gas purchases to our natural gas sales, and these contracts are
frequently settled in terms of an index price for both purchases and sales. In
order to minimize commodity price risk, we attempt to balance sales with
purchases at the index price on the date of settlement.

Following
is information on other year-to-year increases and decreases in segment
earnings before depreciation, depletion and amortization expenses in 2008
compared to 2007:

incremental earnings from
our Kinder
 Morgan Louisiana Pipelinereflecting other non-operating income realized in
 2008 pursuant to FERC regulations governing allowances for capital funds that
 are used for pipeline construction costs (an equity cost of capital
 allowance). The equity cost of capital allowance provides for a reasonable
 return on construction costs that are funded by equity contributions, similar
 to the allowance for capital costs funded by borrowings;an increase in earnings
from our
 TransColorado Pipelinereflecting natural gas transportation contract
 improvements, pipeline expansions completed since the end of 2007, and an increase
 in natural gas production in the Piceance and San Juan basins of New Mexico
 and Colorado.an increase in earnings
from our Kinder
 Morgan Interstate Gas Transmission systemdriven by lower power expenses, due
 to decreased electricity use and lower negotiated rates in 2008, a higher
 gross margin due to both higher operational natural gas sales margins and
 additional transportation revenues, and lower tax expenses payable to the
 state of Texas. (KMIGTs operational gas sales are primarily made possible by
 collection of fuel in kind pursuant to its currently effective gas
 transportation tariff);a decrease in earnings
from our Casper
 Douglas gas processing operationsprimarily attributable to higher natural
 gas purchase costs, due to increases in both prices and volumes, relative to
 2007. The higher cost of sales expense more than offset a year-to-year
 revenue increase resulting from both higher average prices on natural gas
 liquids sales and higher sales of excess natural gas; anda decrease in earnings
from our
 Trailblazer Pipelinemainly due to a 9% drop in revenues in 2008, relative to
 2007, due mainly to lower revenues from both the sales of excess natural gas
 and backhaul natural gas transportation services.And
following is information on other year-to-year increases and decreases in
segment earnings before depreciation, depletion and amortization expenses in
2007 compared to 2006:

an increase in earnings
from our Casper
 Douglas operationsdriven by an overall 6% increase in operating revenues,
 primarily attributable to higher natural gas liquids sales revenues due to
 increases in both prices and volume;a decrease in earnings
from our 49%
 equity investment in the Red Cedar Gathering Companymainly due to lower
 prices on incremental sales of excess fuel gas and to lower natural gas
 gathering revenues.69

CO2

Year Ended December 31,2008

2007

2006(In millions, except operating statistics)Revenues(a)

$
1,133.0

$
824.1

$
736.5Operating expenses(b)


(391.8
)

(304.2
)

(268.1
)Other income (expense)








Earnings from equity
investments


20.7


19.2


19.2Other, net-income
(expense)


1.9





0.8Income tax benefit
(expense)


(3.9
)

(2.1
)

(0.2
)Earnings before depreciation,
depletion and amortization expense and
 amortization of excess cost of equity investments

$
759.9

$
537.0

$
488.2Carbon dioxide delivery volumes
(Bcf)(c)


732.1


637.3


669.2SACROC oil production
(gross)(MBbl/d)(d)


28.0


27.6


30.8SACROC oil production
(net)(MBbl/d)(e)


23.3


23.0


25.7Yates oil production
(gross)(MBbl/d)(d)


27.6


27.0


26.1Yates oil production
(net)(MBbl/d)(e)


12.3


12.0


11.6Natural gas liquids sales
volumes (net)(MBbl/d)(e)


8.4


9.6


8.9Realized weighted average oil
price per Bbl(f)(g)

$
49.42

$
36.05

$
31.42Realized weighted average
natural gas liquids price per Bbl(g)(h)

$
63.00

$
52.91

$
43.90(a)
2006 amount includes a $1.8
 million loss (from a decrease in revenues) on derivative contracts used to
 hedge forecasted crude oil sales.(b)
2008 and 2007 amounts
 include increases in expense associated with environmental liability
 adjustments of $0.3 million and $0.2 million, respectively.(c)
Includes Cortez, Central
 Basin, Canyon Reef Carriers, Centerline and Pecos pipeline volumes.(d)
Represents 100% of the
 production from the field. We own an approximately 97% working interest in
 the SACROC unit and an approximately 50% working interest in the Yates unit.(e)
Net to Kinder Morgan, after
 royalties and outside working interests.(f)
Includes all Kinder Morgan
 crude oil production properties.(g)
Hedge gains/losses for
 crude oil and natural gas liquids are included with crude oil.(h)
Includes production
 attributable to leasehold ownership and production attributable to our
 ownership in processing plants and third party processing agreements.Combined,
the certain items described in the footnotes to the table above account for a
$0.1 million decrease in earnings before depreciation, depletion and
amortization expenses (EBDA) between 2007 and 2008, and $1.6 million of the
$48.8 million increase in EBDA between 2006 and 2007.  The items also account for
a $1.8 million increase in revenues between
2006 and 2007.  For each of the segments two primary businesses, following is information related to
the remaining changes in (i) earnings before depreciation, depletion and amortization expenses; and (ii)
operating revenues in both 2008 and 2007, when compared to the respective prior year:

Year Ended December 31, 2008 versus Year Ended December 31,
 2007EBDA
 increase/(decrease)

Revenues
 increase/(decrease)(In millions, except percentages)Sales and Transportation
Activities

$
123.5


70
%
$
147.3


79
%Oil and Gas Producing
Activities


99.5


28
%

198.5


29
%Intrasegment
Eliminations








(36.9
)

(77
)%Total CO2

$
223.0


42
%
$
308.9


37
%70

Year Ended December 31, 2007 versus Year Ended December 31,
 2006EBDA
 increase/(decrease)

Revenues
 increase/(decrease)(In millions, except percentages)Sales and Transportation
 Activities

$
(9.3
)

(5
)%
$
(8.8
)

(4
)%Oil and Gas Producing
 Activities


56.5


19
%

81.6


14
%Intrasegment Eliminations








13.0


21
%Total
CO2

$
47.2


10
%
$
85.8


12
%The
segments overall $223.0 million (42%) increase in earnings before
depreciation, depletion and amortization in 2008, when compared to 2007, was
driven almost evenly by higher earnings from its carbon dioxide sales and
transportation activities and its oil and gas producing activities. The
earnings increase was largely revenue related, driven by increased crude oil,
carbon dioxide, and natural gas liquids sales revenues, due primarily to
increases in average crude oil (which also impacts the price of carbon dioxide)
and natural gas plant product prices during the first three quarters of 2008.

Generally,
earnings for the segments oil and gas producing activities, which include the
operations associated with its ownership interests in oil-producing fields and
natural gas processing plants, are closely aligned with our realized price
levels for crude oil and natural gas liquids products. Revenues from crude oil sales
and natural gas plant products sales increased $186.2 million (40%) and $7.0
million (4%), respectively, in 2008 compared to 2007, driven by increases of
37% and 19%, respectively, in the realized weighted average price per barrel.

Crude
oil sales volumes increased 2% in 2008, when compared to last year, but natural
gas liquids sales volumes dropped 13% in 2008, due primarily to the effects
from Hurricane Ike, and in part to operational issues on a third party owned
pipeline, which resulted in pro-rationing (production allocation). Hurricane
Ike, which made landfall at Galveston, Texas, on September 13, 2008,
temporarily shut-down third-party fractionation facilities, which caused a
decline in liquids production volumes in and around the Permian Basin area
through the end of November.

Because
prices of crude oil and natural gas liquids are subject to external factors
over which we have no control, and because future price changes may be volatile, our CO2 segment
is exposed to commodity price risk related to the price volatility of crude oil
and natural gas liquids. To some extent, we are able to mitigate this risk
through a long-term hedging strategy that is intended to generate more stable
realized prices by using derivative contracts as hedges to the exposure of
fluctuating expected future cash flows produced by changes in commodity sales
prices. Nonetheless, decreases in the prices of crude oil and natural gas
liquids will have a negative impact on the results of our CO2 business segment. All of our hedge gains and losses for crude
oil and natural gas liquids are included in our realized average price for oil.
Had we not used energy derivative contracts to transfer commodity price risk,
our crude oil sales prices would have averaged $97.70 per barrel in 2008,
$69.63 per barrel in 2007 and $63.27 per barrel in 2006. For more information
on our hedging activities, see Note 14 to our consolidated financial statements
included elsewhere in this report.

The
year-over-year increase in earnings before depreciation, depletion and
amortization from the segments sales and transportation activities in 2008 was
driven by a $87.9 million (137%) increase in carbon dioxide sales revenues and
a $16.1 million (23%) increase in carbon dioxide and crude oil pipeline
transportation revenues. The increase in carbon dioxide sales revenues was
driven by a 75% increase in average sales prices and a 21% increase in average
sales volumes, when compared to 2007. The increase in total pipeline transportation
revenues was chiefly due to a 15% increase in carbon dioxide delivery volumes
in 2008, relative to last year.

The
increase in average carbon dioxide sales prices reflect continued customer
demand for carbon dioxide for use in oil recovery projects throughout the
Permian Basin area and, in addition, a portion of our carbon dioxide contracts
are tied to crude oil prices, which as discussed above, have increased since
the end of 2007. We do not recognize profits on carbon dioxide sales to
ourselves. The increases in carbon dioxide sales and delivery volumes were
largely due to the January 17, 2008 start-up of the Doe Canyon carbon dioxide
source field located in Dolores County, Colorado. We hold an approximately 87%
working interest in Doe Canyon. Since July 2006, we have invested approximately
$90 million to develop this source field. In addition, investments were also
made to drill

71

additional
carbon dioxide wells at the McElmo Dome unit, increase transportation capacity
on the Cortez Pipeline, and extend the Cortez Pipeline to the new Doe Canyon
Deep unit.

The
overall $47.2 million (10%) increase in segment earnings before depreciation,
depletion and amortization expenses in 2007 versus 2006 was driven by higher
earnings from the segments oil and gas producing activities. The increase was
largely due to higher oil production at the Yates oil field unit, higher
realized average oil prices in 2007 relative to 2006, and higher earnings from
natural gas liquids sales, largely due to increased recoveries at the Snyder,
Texas gas plant and to an increase in our realized weighted average price per
barrel.

The
year-to-year decrease in earnings before depreciation, depletion and
amortization from the segments sales and transportation activities in 2007 was
primarily due to a decrease in carbon dioxide sales revenues, resulting mainly
from lower average prices for carbon dioxide, and partly from a 3% drop in
carbon dioxide sales volumes. The segments average price received for all
carbon dioxide sales decreased 9% in 2007, when compared to 2006. The decrease
was mainly attributable to the expiration of a significant high-priced sales
contract in December 2006.

The
$85.8 million (12%) increase in segment revenues in 2007, when compared
to 2006, was mainly due to higher revenues from the segments oil and gas
producing activities natural gas liquids and crude oil sales. Combined, plant
product and crude oil sales revenues increased $77.9 million (14%) in 2007
compared to 2006.

The
increase in revenues from the sales of natural gas liquids and crude oil was
driven by favorable sales price variancesour realized weighted average price
per barrel for liquids products increased 21% in 2007, relative to 2006, and
our average crude oil realization increased 15% in 2007 compared to the prior
year. Plant product liquids volumes also increased 8%, but total crude oil
sales volumes decreased 6% in 2007 compared to 2006, largely due to a 10%
decline in gross production at the SACROC field unit. The decline in crude oil
production at SACROC was mainly attributable to lower observed recoveries from
certain project areas and partly attributable to an intentional slow down in
development pace, given this reduction in recoveries.

For
more information on our ownership interests in the net quantities of proved oil
and gas reserves and our measures of discounted future net cash flows from oil
and gas reserves, please see Note 20 to our consolidated financial statements
included elsewhere in this report.

Terminals

Year Ended December 31,2008

2007

2006(In millions, except operating statistics)Revenues

$
1,173.6

$
963.7

$
864.8Operating expenses(a)


(631.8
)

(536.4
)

(461.9
)Other income
(expense)(b)


(2.7
)

6.3


15.2Earnings from equity
investments


2.7


0.6


0.2Other, net-income
(expense)


1.7


1.0


2.1Income tax benefit
(expense)(c)


(19.7
)

(19.2
)

(12.3
)Earnings before depreciation,
depletion and amortization expense and
 amortization of excess cost of equity investments

$
523.8

$
416.0

$
408.1Bulk transload tonnage
(MMtons)(d)


99.1


96.2


95.1Liquids leaseable capacity
(MMBbl)


54.2


47.5


43.5Liquids utilization %


97.5
%

95.9
%

96.3
%(a)
2008 and 2007 amounts
 include a $0.6 million decrease in expense and a $2.0 million increase in
 expense, respectively, associated with environmental liability adjustments.
 2008 amount also includes a $5.3 million increase in expense related to
 hurricane clean-up and repair activities; a combined $2.8 million increase in
 expense from the settlement of certain litigation matters related to our
 Elizabeth River bulk terminal and our Staten Island liquids terminal, and
 other legal liability adjustments; and a $1.9 million increase in expense
 related to fire damage and repair activities. 2007 amount also includes a
 $25.0 million increase in expense from the settlement of certain litigation
 matters related to our Cora coal terminal, and a $1.2 million increase in
 expense associated with legal liability adjustments. 2006 amount includes a
 $2.8 million increase in expense related to hurricane clean-up and repair
 activities.72

(b)
2008 amount includes a
 decrease in income of $5.3 million from property casualty losses related to
 fire damage, and a decrease in income of $0.8 million from property casualty
 losses related to hurricane damage. 2007 and 2006 amounts include increases
 in income of $1.8 million and $15.2 million, respectively, from property
 casualty gains associated with the 2005 hurricane season.(c)
2008 amount includes a
 decrease in expense (reflecting tax savings) of $0.4 million related to
 hurricane clean-up and repair expenses and casualty losses. 2006 amount
 includes a $1.1 million increase in expense associated with casualty gains
 and hurricane expenses.(d)
Volumes for acquired
 terminals are included for all periods.Combined,
the certain items described in the footnotes to the table above account for
$11.3 million of the $107.8 increase in earnings before depreciation, depletion
and amortization between 2007 and 2008, and a $37.7 million decrease in
earnings before depreciation, depletion and amortization between 2006 and 2007.
The segments remaining $96.5 million (22%) increase in earnings before
depreciation, depletion and amortization expenses in 2008 compared to 2007, and
its remaining $45.6 million (11%) increase in 2007 compared to 2006, were
driven by a combination of internal asset expansions and strategic business
acquisitions completed since the end of 2006.

We
have made and continue to seek terminal acquisitions in order to gain access to
new markets, to complement and/or enlarge our existing terminal operations, and
to benefit from the economies of scale resulting from increases in terminal
storage, handling and throughput capacity. Beginning with our acquisition of
the Vancouver Wharves bulk marine terminal on May 30, 2007 and including, among
others, the terminal assets we acquired from Marine Terminals, Inc. effective
September 1, 2007, we have invested approximately $179.0 million in cash to
acquire both terminal assets and equity interests in terminal operations, and
combined, these acquired operations accounted for incremental earnings before
depreciation, depletion and amortization of $30.4 million, revenues of $86.6
million, equity earnings of $1.7 million, and operating expenses of $57.9
million in 2008.

In
2007, we also benefitted significantly from the incremental contributions
attributable to the bulk and liquids terminal businesses we acquired during
2007 and 2006. Combined, these acquired operations accounted for incremental
amounts of earnings before depreciation, depletion and amortization of $31.2
million, revenues of $83.9 million, operating expenses of $53.2 million and
equity earnings of $0.5 million, respectively, in 2007. All of the incremental
2008 and 2007 amounts listed above represent the earnings, revenues and
expenses from acquired terminals operations during the additional months of
ownership in 2008 and 2007, respectively, and do not include increases or
decreases during the same months we owned the assets in the respective prior
year. For more information on our acquisitions, see Note 3 to our consolidated
financial statements included elsewhere in this report.

For
all other terminal operations (those owned during identical periods in both
pairs of comparable years), earnings before depreciation, depletion and
amortization expenses increased $66.1 million (15%) in 2008, and $14.4 million
(4%) in 2007, when compared to the respective prior years. The increases in
earnings represent net changes in terminal results at various locations, and
the $66.1 million year-over-year increase in 2008 compared to 2007 for terminal
operations owned during identical periods in both years included the following:

a $27.8 million (25%)
increase from our
 Gulf Coast terminal facilities, primarily our two large liquids terminal
 facilities located along the Houston Ship Channel in Pasadena and Galena
 Park, Texas. The increase was due mainly to higher liquids throughput volumes
 and increased liquids storage capacity as a result of expansions completed
 since the end of 2007;a $20.3 million (50%)
increase from our
 Mid-Atlantic terminals, primarily our Pier IX bulk terminal located in
 Newport News, Virginia, due to higher period-over-period coal transfer
 volumes, and our Fairless Hills, Pennsylvania bulk terminal, largely due to
 incremental earnings from a new import fertilizer facility that began
 operations in the second quarter of 2008. The increases in coal throughput at
 Pier IX were largely due to an almost $70 million capital improvement
 project, completed in the first quarter of 2008, that involved the
 construction of a new ship dock and the installation of additional terminal
 equipment. The import fertilizer facility at Fairless Hills cost
 approximately $11.2 million to build, and included the construction of two
 storage domes, conveying equipment, and outbound loading facilities for both
 rail and truck;a $10.5 million (16%)
increase from our
 Northeast terminals, largely due to higher earnings from our New York Harbor
 liquids terminals, which include our Perth Amboy, New Jersey terminal; our
 Carteret, New73

Jersey terminal; and our Kinder Morgan Staten Island
terminal. The
 year-over-year increase in earnings from these terminals was driven by a
 combined 21% increase in liquids throughput volumes (resulting both from
 incremental business driven by strong demand for imported fuel and from tank
 expansions completed since the end of 2007), higher transfer and storage rates,
 and incremental revenues from ancillary terminal services; anda $7.0 million (30%)
increase from our
 West region terminals, mainly from our Vancouver Wharves bulk marine terminal
 and from our Kinder Morgan North 40 terminal, a crude oil tank farm located
 in Edmonton, Alberta, Canada. We announced the construction of the North 40
 terminal in June 2006, and we completed construction and began terminal
 operations in the second quarter of 2008. The increase from Vancouver Wharves
 was due largely to higher terminal revenues from liquids throughput and
 handling services.The
$14.4 million (4%) increase in earnings before depreciation, depletion and
amortization in 2007 compared to 2006 from terminal operations owned during
identical periods in both years was largely due to the following:

a $9.7 million (10%)
increase from our
 two liquids terminal facilities located in Pasadena and Galena Park, Texas.
 The two terminals benefitted from both completed expansions that added new
 liquids tank and truck loading rack capacity since the end of 2006 and
 incremental business from ethanol and biodiesel storage and transfer
 activity. For the entire terminals segment combined, our expansion projects
 and acquisitions completed since the end of 2006 increased our liquids
 terminals leaseable capacity by 9% in 2007, more than offsetting a less than
 1% drop in our overall utilization percentage;a $3.7 million (23%)
increase from the
 combined operations of our Argo and Chicago, Illinois liquids terminals, due
 to increased ethanol throughput and incremental liquids storage and handling
 business;a $1.8 million (4%)
increase from our
 Texas Petcoke terminals, due largely to higher petroleum coke throughput
 volumes in 2007 at our Port of Houston facility;a $1.2 million (15%)
increase from our
 Pier IX bulk terminal, chiefly due to a 19% year-to-year increase in coal
 transfer volumes and higher rail incentives; anda $2.0 million (6%)
decrease from our
 Lower River (Louisiana) terminals, primarily due to both lower revenues from
 our 66 2/3% interest in the International Marine Terminals partnership
 facility, a multi-product bulk terminal located in Sulphur Springs,
 Louisiana, and to higher income tax expense accruals. The decrease in
 revenues from IMT was mainly due to lower tonnage volumes and lower ship
 dockage revenues in 2007, and the increase in income tax expense was largely
 due to higher taxable income attributable to Kinder Morgan Bulk Terminals,
 Inc., our tax-paying subsidiary that owns many of our Louisiana bulk terminal
 businesses which handle non-qualifying products.Kinder Morgan Canada

Year Ended December 31,2008

2007

2006(e)(In millions, except operating statistics)Revenues

$
196.7

$
160.8

$
137.8Operating expenses


(67.9
)

(65.9
)

(53.3
)Other income (expense)(a)





(377.1
)

0.9Earnings from equity
 investments


(0.4
)




Interest income and Other,
 net-income (expense)(b)


(6.2
)

8.0


1.0Income tax benefit
 (expense)(c)


19.0


(19.4
)

(9.9
)Earnings (loss) before depreciation,
depletion and amortization expense and
 amortization of excess cost of equity investments(d)

$
141.2

$
(293.6
)
$
76.5Transport volumes (MMBbl)


86.7


94.4


83.7(a)
2007 amount represents a
 goodwill impairment expense recorded by Knight in the first quarter of 2007.(b)
2008 amount includes a
 $19.3 million decrease in expense associated with favorable changes in
 Canadian income tax rates, and a $12.3 decrease in other non-operating income
 from the amounts previously reported in our 2008 fourth quarter earnings
 release issued on January 21, 2009, due to certain non-cash Trans Mountain
 regulatory accounting adjustments.(c)
2008 amount includes a
 $6.6 million increase in expense from the amounts previously reported in our
 2008 fourth quarter earnings release issued on January 21, 2009, due to
 certain non-cash Trans Mountain regulatory accounting adjustments.(d)
2007 amount includes losses
 of $349.2 million for periods prior to our acquisition date of April 30,
 2007, and a $1.3 million decrease in income from an oil loss allowance.(e)
2006 amounts relate to periods
 prior to our acquisition date of April 30, 2007. See discussion below.74

After
taking into effect the certain items described in footnote to the table
above, the remaining increases in earnings before depreciation, depletion and
amortization totaled $83.9 million (147%) in 2008 versus 2007, and $56.9
million in 2007 versus 2006. The 2007 increase related entirely to our
acquisition of Trans Mountain effective April 30, 2007, and the 2008 increase
consisted of (i) higher earnings of $38.1 million (67%) from the Trans Mountain
pipeline assets we owned in the same periods in both years (May through
December); and (ii) incremental earnings of $45.8 million from periods we owned
assets in 2008 only (Trans Mountain for the period January through April, and
Express and Jet Fuel for the period September through December).

The
$38.1 million increase in earnings from assets owned during the same periods in
both 2008 and 2007 was driven primarily by higher operating revenues, due largely
to the completion of the Trans Mountain Pipeline Anchor Loop expansion project
discussed elsewhere in this report.

The
Anchor Loop project boosted pipeline capacity from 260,000 to 300,000 barrels
per day and resulted in higher period-to-period average toll rates. The higher
tariffs became effective in June 2008, and more than offset an 8% decline in
mainline throughput volumes, which resulted primarily from lower demand for
water-borne exports out of Vancouver, British Columbia.

Other

Year Ended December 31,

Earnings
 increase/(decrease)2008

2007(In millions-income (expense), except percentages)General and administrative
expenses(a)

$
(297.9
)
$
(278.7
)
$
(19.2
)

(7
)%Unallocable interest expense,
net of interest income(b)


(397.6
)

(395.8
)

(1.8
)

Unallocable income tax benefit
(expense)


(9.3
)

(4.6
)

(4.7
)

(102
)%Minority interest(c)


(13.7
)

(7.0
)

(6.7
)

(96
)%Total interest and other
non-operating expenses

$
(420.6
)
$
(407.4
)
$
(13.2
)

(3
)%Year Ended December 31,

Earnings
 increase/(decrease)2007

2006(In millions-income (expense), except percentages)General and administrative
expenses(a)

$
(278.7
)
$
(238.4
)
$
(40.3
)

(17
)%Unallocable interest expense,
net of interest income(b)


(395.8
)

(342.4
)

(53.4
)

(16
)%Unallocable income tax benefit
(expense)


(4.6
)




(4.6
)

Minority interest(c)


(7.0
)

(15.4
)

8.4


55
%Total interest and other
non-operating expenses

$
(407.4
)
$
(357.8
)
$
(49.6
)

(14
)%(a)
Includes such items as
 salaries and employee-related expenses, payroll taxes, insurance, office
 supplies and rentals, unallocated litigation and environmental expenses, and
 shared corporate services. 2008 amount includes (i) a $5.6 million increase
 in non-cash compensation expense, allocated to us from Knight (we do not have
 any obligation, nor do we expect to pay any amounts related to this expense);
 (ii) a $0.9 million increase in expense for certain Express pipeline system
 acquisition costs; (iii) a $0.4 million expense resulting from the write-off
 of certain acquisition costs pursuant to a newly adopted accounting
 principle; (iv) a $0.1 million increase in expense related to hurricane
 clean-up and repair activities; and (v) a $2.0 million decrease in expense
 due to the adjustment of certain insurance related liabilities. 2007 amount
 includes (i) a $26.2 million increase in expense, allocated to us from
 Knight, associated with closing the going-private transaction (we do not have
 any obligation, nor do we expect to pay any amounts related to this expense);
 (ii) a $5.5 million expense related to Trans Mountain expenses for periods
 prior to our acquisition date of April 30, 2007; (iii) a $2.1 million expense
 due to the75

adjustment of certain
 insurance related liabilities; (iv) a $1.7 million increase in expense
 associated with the 2005 hurricane season; (v) a $1.5 million expense for
 certain Trans Mountain acquisition costs; and (vi) a $0.8 million expense
 related to the cancellation of certain commercial insurance policies. 2006
 amount includes (i) an $18.8 million expense related to Trans Mountain
 expenses; (ii) a $2.4 million increase in expense related to the cancellation
 of certain commercial insurance policies; and (iii) a $0.4 million decrease
 in expense related to the allocation of general and administrative expenses
 on hurricane related capital expenditures for the replacement and repair of
 assets (capitalization of overhead expense).(b)
2008 amount includes (i) a
 $7.1 million decrease in interest expense from the amounts previously reported
 in our 2008 fourth quarter earnings release  issued on January 21, 2009, due to
 certain non-cash Trans Mountain regulatory accounting adjustments; (ii) a $2.0
 million increase in imputed interest expense related to our January 1, 2007
 Cochin Pipeline acquisition; and (iii) a $0.2 million increase in interest
 expense related to the proposed settlement of certain litigation matters
 related to our Pacific operations East Line pipeline. 2007 amount
 includes a $2.4 million increase in expense related to imputed interest on our
 Cochin Pipeline acquisition, and a $1.2 million expense for Trans Mountain
 expenses for periods prior to our acquisition date of April 30, 2007. 2006
 amount includes Trans Mountain expenses of $6.3 million.(c)
2008, 2007 and 2006 amounts
 include a $0.4 million decreases in expense, a $3.9 million decrease in
 expense, and a $3.5 million increase in expense, respectively, related to the
 minority interest effect from all of the 2008, 2007 and 2006 items previously
 disclosed in the footnotes to the tables included in Results of
 Operations.Items
not attributable to any segment include general and administrative expenses,
unallocable interest income and income tax expense, interest expense and minority
interest. Overall, our total general and administrative expenses increased
$19.2 million (7%) in 2008 compared to 2007, and $40.3 million (17%) in 2007
compared to 2006. However, the certain items described in footnote (a) to the
tables above resulted in a combined $32.8 million decrease in expense in 2008
compared to 2007, and a combined $17.0 million increase in expense in 2007
compared to 2006.

The
remaining $52.0 million (22%) and $23.3 million (11%) increases in general and
administrative expenses in 2008 and 2007 were largely due to (i) higher
compensation-related expensescomprising salary and benefit expenses, payroll
taxes and other employee and contractor related expenses; and (ii) higher
shared corporate services expensesincluding legal services, corporate
secretary, tax, human resources, information technology and other shared
services. These increases in administrative expenses were associated with our
larger year-over-year asset base and included incremental expenses and higher corporate
overhead associated with the assets and operations we have acquired since the
end of 2005, including the Trans Mountain, Express (one-third interest) and Jet
Fuel pipeline systems we acquired from Knight, and the acquired bulk and
liquids terminal operations that are described above in Terminals. Acquiring
assets and supporting internal growth initiatives result in increased spending
levels and expenses; however, we continue to manage aggressively our
infrastructure expenses in order to operate our assets in the most efficient
manner possible.

Unallocable
interest expense, net of interest income, increased $1.8 million (less than 1%)
in 2008 compared to 2007, and $53.4 million (16%) in 2007 compared to 2006. The
certain items described in footnote (b) to the tables above decreased interest
expense by $8.5 million in 2008 and decreased interest expense by $2.7 million
in 2007, when compared to the respective prior year periods.

The
remaining $10.3 million (3%) increase in expense in 2008 compared to 2007 was
driven by a 22% increase in average borrowings (excluding the value of interest
rate swap agreements), partially offset by a 15% drop in our weighted average
interest rate. The decrease in our weighted average borrowing rate in 2008 reflects
a general decrease in variable interest rates since the end of last yearthe
weighted average interest rate on all of our borrowings was approximately 5.44%
during 2008 and 6.40% during 2007. The remaining $56.1 million (17%) increase
in interest expense in 2007 compared to 2006 was due to both higher average
debt levels and higher effective interest rates. In 2007, average borrowings
increased 17% and the weighted average interest rate on all of our borrowings
increased from 6.2% in 2006 to 6.4% in 2007.

The
year-over-year increases in our average borrowings was largely due to the
capital spending (for asset expansion and improvement projects, including
additional pipeline construction costs) and the external business acquisitions
we have made since the end of 2005. Generally, we initially fund both our
discretionary capital spending (including payments for pipeline project
construction costs) and our acquisition outlays from borrowings under our
commercial paper program or our long-term revolving bank credit facility. From
time to time, we issue senior notes and equity in order to refinance our
commercial paper borrowings. For more information on our capital expansion and
acquisition expenditures, see Liquidity and Capital ResourcesInvesting
Activities.

76

As
of December 31, 2008, approximately 34% of our $8,563.6 million consolidated
debt balance (excluding the value of interest rate swap agreements) was subject
to variable interest rateseither as short-term or long-term variable rate debt
obligations or as fixed-rate debt converted to variable rates through the use
of interest rate swaps. As of December 31, 2007, approximately 42% of our
$7,066.1 million consolidated debt balance was subject to variable interest
rates.

The
incremental unallocable income tax expense, in both 2008 and 2007, relates to
higher year-to-year corporate income tax accruals for the Texas margin tax, an
entity-level tax initiated January 1, 2007 and imposed on the amount of our
total revenue that is apportioned to the state of Texas. Minority interest,
which represents the deduction in our consolidated net income attributable to
all outstanding ownership interests in our operating limited partnerships and
their consolidated subsidiaries that are not held by us, increased in 2008 and
decreased in 2007, when compared to the respective prior year. Both the
increase, in 2008, and the drop, in 2007, was due to overall lower partnership
income in 2007, relative to both 2008 and 2006.

Liquidity and Capital Resources

General

As
of December 31, 2008, we believe our balance sheet and liquidity positions
remained strong. Cash on hand was $62.5 million at the close of the year, and
on December 19, 2008, we demonstrated our continued access to the term debt
market by issuing $500 million in senior notes that mature on February 1, 2019.
Also in December 2008, we took advantage of the general decrease in variable
interest rates since the start of the year by terminating two of our existing
fixed-to-variable interest rate swap agreements, and we received combined
proceeds of $194.3 million from the early termination of these swap agreements
(we terminated a third swap agreement in January 2009 and received additional
proceeds of $144.4 million). Similarly, we demonstrated continued access to the
equity market by raising $176.6 million in cash from the public offering of
3,900,000 additional common units on December 22, 2008.

In
addition, our diverse set of energy assets generated $2,235.9 million in cash
from operations in 2008, and based on long-term contracted customer commitments
and current cost estimates, we expect to realize incremental returns from
completed capital expansion projects that are currently in process. We also
had, at December 31, 2008, $1.47 billion of borrowing capacity available under
our $1.85 billion bank credit facility (discussed below in Short-term
Liquidity) and, at Knights third quarter board meeting on October 15, 2008,
Knights board indicated its willingness to contribute up to $750 million of
equity to us over the subsequent 18 months, if necessary, in order to support
our capital raising efforts.

Our
primary cash requirements, in addition to normal operating expenses, are debt
service, sustaining capital expenditures (defined as capital expenditures which
do not increase the capacity of an asset), expansion capital expenditures and
quarterly distributions to our common unitholders, Class B unitholder and
general partner. In addition to utilizing cash generated from operations, we
could meet our cash requirements for expansion capital expenditures through
borrowings under our credit facility, issuing long-term notes or additional
common units or the proceeds from purchases of additional i-units by KMR with
the proceeds from issuances of additional KMR shares.

In
general, we expect to fund:

cash distributions and
sustaining capital
 expenditures with existing cash and cash flows from operating activities;expansion capital
expenditures and
 working capital deficits with retained cash (resulting from including i-units
 in the determination of cash distributions per unit but paying quarterly
 distributions on i-units in additional i-units rather than cash), additional
 borrowings, the issuance of additional common units or the proceeds from
 purchases of additional i-units by KMR;interest payments with
cash flows from
 operating activities; anddebt principal payments
with additional
 borrowings, as such debt principal payments become due, or by the issuance of
 additional common units or the proceeds from purchases of additional i-units
 by KMR.77

Credit Ratings
and Capital Market
Liquidity

As
part of our financial strategy, we try to maintain an investment-grade credit
rating, which involves, among other things, the issuance of additional limited
partner units in connection with our acquisitions and internal growth
activities in order to maintain acceptable financial ratios. As a publicly
traded limited partnership, our common units are attractive primarily to
individual investors, although such investors represent a small segment of the
total equity capital market. We believe that some institutional investors
prefer shares of KMR over our common units due to tax and other regulatory
considerations, and we are able to access this segment of the capital market
through KMRs purchases of i-units issued by us with the proceeds from the sale
of KMR shares to institutional investors.

On
May 30, 2006, Standard & Poors Rating Services and Moodys Investors
Service each placed our long-term credit ratings on credit watch pending the
resolution of KMIs going-private transaction. On January 5, 2007, in anticipation
of the going-private transaction closing, S&P downgraded us one level to
BBB and removed our rating from credit watch with negative implications. As
previously noted by Moodys in its credit opinion dated November 15, 2006, it
downgraded our credit rating from Baa1 to Baa2 on May 30, 2007, following the
closing of the going-private transaction. Additionally, our rating was
downgraded by Fitch Ratings from BBB+ to BBB on April 11, 2007. Currently, our
long-term corporate debt credit rating is BBB, Baa2 and BBB, respectively, at
S&P, Moodys and Fitch.

On
September 15, 2008, Lehman Brothers Holdings Inc. filed for bankruptcy
protection under the provisions of Chapter 11 of the U.S. Bankruptcy Code. One
Lehman entity was a lending institution that provided a portion of our, Rockies
Express, and Mid Continent Express respective credit facilities. Since Lehman
Brothers declared bankruptcy, its affiliate, which is a party to the
aforementioned credit facilities, has not met its obligations to lend under
those agreements. As such, the commitments have been effectively reduced by $63
million, $41 million, and $100 million, respectively, to $1.79 billion, $1.96
billion, and $1.30 billion. The commitments of the other banks remain unchanged,
and the facilities are not defaulted.

On
October 13, 2008, S&P revised its outlook on our long-term credit rating to
negative from stable (but affirmed our long-term credit rating at BBB), due to
our previously announced expected delay and cost increases associated with the
completion of the Rockies Express Pipeline project. At the same time, S&P
lowered our short-term credit rating to A-3 from A-2. As a result, we no longer
have access to the commercial paper market. However, we believe that our $1.8
billion credit facility is adequate to meet our short term liquidity needs.

Additionally,
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. These financial problems may arise from the current financial
crises, changes in commodity prices or otherwise. We have and are working to
implement, to the extent allowable under applicable contracts, tariffs and
regulations, prepayments and other security requirements, such as letters of
credit, to enhance our credit position relating to amounts owed from these
customers. We cannot provide assurance that one or more of our current or
future 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; however, we believe we have provided adequate allowance for
such customers.

Short-term
Liquidity

We
employ a centralized cash management program that essentially concentrates the
cash assets of our operating partnerships and their subsidiaries in joint
accounts for the purpose of providing financial flexibility and lowering the
cost of borrowing. Our centralized cash management program provides that funds
in excess of the daily needs of our operating partnerships and their
subsidiaries are concentrated, consolidated, or otherwise made available for
use by other entities within our consolidated group. We place no restrictions
on the ability to move cash between entities, payment of inter-company balances
or the ability to upstream dividends to parent companies other than
restrictions that may be contained in agreements governing the indebtedness of
those entities. However, our cash and the cash of our subsidiaries is not
concentrated into accounts of Knight or any company not in our consolidated

78

group of
companies, and Knight has no rights with respect to our cash except as
permitted pursuant to our partnership agreement.

Furthermore,
certain of our operating subsidiaries are subject to FERC enacted reporting
requirements for oil and natural gas pipeline companies that participate in
cash management programs. FERC-regulated entities subject to these rules must,
among other things, place their cash management agreements in writing, maintain
current copies of the documents authorizing and supporting their cash
management agreements, and file documentation establishing the cash management
program with the FERC.

Our
outstanding short-term debt as of December 31, 2008 was $288.7 million,
primarily consisting of a $250 million principal amount of 6.3% senior notes
that matured and was paid on February 1, 2009. As of December 31, 2007, our
outstanding short-term debt was $610.2 million.

Our
principal sources of short-term liquidity are:

our $1.85 billion
five-year senior
 unsecured revolving bank credit facility that matures August 18, 2010; andour cash from operations
(discussed
 following in Operating Activities).Borrowings
under our five-year credit facility can be used for general partnership
purposes and as a backup for a commercial paper program. The facility can be amended
to allow for borrowings up to $2.1 billion. As of both December 31, 2008 and
2007, we had no borrowings under our five-year credit facility. We provide for
liquidity by maintaining excess borrowing capacity under our five year
revolving credit facility. After reduction for (i) our letters of credit; (ii)
commercial paper and/or borrowings under our revolving credit facility outstanding (none at December 31, 2008); and (iii) lending
commitments made by a Lehman Brothers related bank, the remaining available
borrowing capacity under our bank credit facility was $1,473.7 million as of
December 31, 2008.

As
a result of the revision to our short-term credit rating and the current
commercial paper market conditions, we are unable to access commercial paper
borrowings and as of December 31, 2008, there were no borrowings under our
commercial paper program. However, we expect that our financing and liquidity
needs will continue to be met through borrowings made under our long-term bank
credit facility, and we do not anticipate that fluctuations in the availability
of the commercial paper market will affect our liquidity because of the
flexibility provided by our credit facility. As of December 31, 2007, we had
$589.1 million of commercial paper outstanding.

Currently,
we believe our liquidity to be adequate, and we continue to monitor the status
of the capital markets and regularly evaluate the effect that changes in
capital market conditions may have on our announced business strategy to grow
our portfolio of businesses. We expect that part of our short-term financing
and liquidity needs will continue to be met through our long-term bank credit
facility. For more information on our credit facility, see Note 9 to our
consolidated financial statements included elsewhere in this report.

Long-term
Financing

In
addition to our principal sources of short-term liquidity listed above, we
could meet our cash requirements (other than distributions to our common
unitholders, Class B unitholders and general partner) through issuing long-term
notes or additional common units, or by utilizing the proceeds from purchases
of additional i-units by KMR with the proceeds from issuances of KMR shares.

On
September 19, 2008, we filed a registration statement with the Securities and Exchange
Commission under the Securities Act of 1933 on Form S-3. This registration
statement, commonly referred to as a shelf registration statement, will allow
us to sell up to $5 billion of additional common units or debt securities. The
shelf registration statement is intended to provide us with flexibility to
raise funds from the offering of our securities in one or more offerings, in
amounts, and at prices to be set forth in subsequent filings made with the SEC
at the time of each separate offering. This registration statement on Form S-3
was declared effective by the SEC on December 15, 2008.

79

Pursuant
to this shelf registration statement, on January 16, 2009, we entered into an
Equity Distribution Agreement with UBS Securities LLC. According to the
provisions of this Agreement, we may offer and sell from time to time common
units having an aggregate offering value of up to $300 million through UBS, as
sales agent. Sales of the units, if any, will be made by means of ordinary
brokers transactions on the New York Stock Exchange at market prices, in block
transactions or as otherwise agreed between us and UBS. Under the terms of this
Agreement, we also may sell common units to UBS as principal of its own account
at a price agreed upon at the time of the sale. Any sale of common units to UBS
as principal would be pursuant to the terms of a separate terms agreement
between us and UBS.

We
believe this Equity Distribution Agreement provides us further flexibility to
raise funds from the offering of our securities because it provides us the
right, but not the obligation, to draw down on the facility in the future, at
prices we deem appropriate. We retain at all times complete control over the
amount and the timing of each draw down, and we will designate the maximum
number of common units to be sold through UBS, on a daily basis or otherwise as
we and UBS agree. UBS will then use its reasonable efforts to sell, as our
sales agent and on our behalf, all of the designated common units. We may
instruct UBS not to sell common units if the sales cannot be effected at or
above the price designated by us in any such instruction. Either we or UBS may
suspend the offering of common units pursuant to the Agreement by notifying the
other party. As of February 20, 2009,
we have issued 612,083 of our common units pursuant to this Agreement. We received
net proceeds of approximately $29.9 million for the issuance of these common
units.

Our
offerings would be subject to market conditions and our capital needs, and unless we specify otherwise in a
prospectus supplement, we intend to use the net proceeds from the sale of
offered securities for general partnership purposes. This may include, among
other things, additions to working capital, repayment or refinancing of
existing indebtedness or other partnership obligations, financing of capital
expenditures and acquisitions, investment in existing and future projects, and
repurchases and redemptions of securities. Pending any specific application, we
may initially invest funds in short-term marketable securities or apply them to
the reduction of other indebtedness.

We
are subject, however, to changes in the equity and debt markets for our limited
partner units and long-term notes, and there can be no assurance we will be
able or willing to access the public or private markets for our limited partner
units and/or long-term notes in the future. If we were unable or unwilling to
issue additional limited partner units, we would be required to either restrict
potential future acquisitions or pursue other debt financing alternatives, some
of which could involve higher costs or negatively affect our credit ratings.
Furthermore, our ability to access the public and private debt markets is affected
by our credit ratings. See Credit Ratings and Capital Market Liquidity above
for a discussion of our credit ratings.

Equity
Issuances

For
information on our 2007 and 2008 equity issuances, see Note 11 Partners
CapitalEquity Issuances to our consolidated financial statements included
elsewhere in this report.

Debt
Issuances

From
time to time we issue long-term debt securities. All of our long-term debt
securities issued to date, other than those issued under our long-term
revolving credit facility or those issued by our subsidiaries and operating
partnerships, generally have the same terms except for interest rates, maturity
dates and prepayment premiums. All of our outstanding debt securities are
unsecured obligations that rank equally with all of our other senior debt
obligations; however, a modest amount of secured debt has been incurred by some
of our operating partnerships and subsidiaries. Our fixed rate notes provide
that we may redeem the notes at any time at a price equal to 100% of the
principal amount of the notes plus accrued interest to the redemption date plus
a make-whole premium.

As
of December 31, 2008 and 2007, the total liability balance due on the various
series of our senior notes was $8,381.5 million and $6,288.8 million,
respectively, and the total liability balance due on the various borrowings of
our operating partnerships and subsidiaries was $182.1 million and $188.2
million, respectively. For additional information regarding our
debt securities, see Note 9 to our consolidated financial statements included
elsewhere in

80

this report;
for specific information with regard to the 2007 and 2008 changes in the
various series of our senior notes, including debt issuances, see Note 9
DebtLong-Term DebtSenior Notes.

Capital
Structure

We
attempt to maintain a relatively conservative overall capital structure,
financing our expansion capital expenditures and acquisitions with
approximately 50% equity and 50% debt. In the short-term, we fund these
expenditures from borrowings under our credit facility until the amount
borrowed is of a sufficient size to cost effectively do either a debt or equity
offering, or both.

With
respect to our debt financed expenditures, we target a debt mixture of
approximately 50% fixed and 50% variable. We achieve our variable rate exposure
primarily by issuing long-term fixed rate debt and then swapping the fixed rate
interest payments for variable rate payments. Our interest rate mix is
currently weighted more heavily towards fixed interest rates due to a decision
to terminate a portion of our interest rate swap agreements at attractive
prices in December 2008 and January 2009 as discussed under Interest Rate
Risk below.

Our
equity offerings consist of the issuance of additional common units or the
issuance of additional i-units to KMR (which KMR purchases with the proceeds
from the sale of additional KMR shares to institutional investors).

Capital
Expenditures

Our
sustaining capital expenditures for the year 2008 were $180.6 million
(including approximately $0.1 million for our proportionate share of Rockies
Express sustaining capital expenditures), and our forecasted expenditures for
2009 for sustaining capital expenditures are approximately $202.4 million
(including $0.4 million for our proportionate share of Rockies Express).
Generally, we fund our sustaining capital expenditures with our cash flows from
operations.

All
of our capital expenditures, with the exception of sustaining capital
expenditures, are discretionary. The discretionary capital expenditures
reflected in our consolidated financial statements for the year 2008 were
$2,352.5 million, and we forecasted $1,188.2 million for discretionary
capital expenditures in our 2009 budget and capital expenditure plan. In
addition to these amounts, we contributed an aggregate amount of $333.5 million
for both the Rockies Express and Midcontinent Express natural gas pipeline projects
in 2008, and we expect to contribute approximately $1.5 billion in the
aggregate for both projects in 2009.

Capital
Requirements for Recent Transactions

During
2008, our cash outlays for the acquisition of assets and investments totaled$40.2
million. For more information on our capital requirements during 2008 in regard
to our acquisition expenditures, see Note 3 to our consolidated
financial statements included elsewhere in this report. For more information on our recent debt related transactions, see
Note 9 to our consolidated financial statements included elsewhere in this
report.

Off
Balance Sheet Arrangements

We have
invested in entities that are not consolidated in our financial statements. As
of December 31, 2008, our obligations with respect to these investments, as
well as our obligations with respect to a letter of credit, are summarized
below (dollars in millions):

81

Entity

InvestmentType

OurOwnershipInterest

RemainingInterest(s)Ownership

TotalEntityAssets(i)

TotalEntityDebt

OurContingentShare
 ofEntity
 Debt(j)Cortez Pipeline
Company

General Partner

50
%

(a)

$
95.7

$
169.6


$
84.8
(b)West2East Pipeline
LLC(c)

Limited
 Liability

51
%

ConocoPhillips and Sempra Energy

$
4,741.4

$
3,458.9
(d)

$
1,102.1
(e)Midcontinent Express Pipeline
LLC(f)

Limited
 Liability

50
%

Energy Transfer Partners, L.P.

$
981.1

$
837.5


$
418.8
(g)Nassau County, Florida Ocean Highway And Port
Authority
 (h)

N/A

N/A


Nassau County, Florida Ocean Highway and Port Authority


N/A


N/A


$
10.2(a)
The remaining general partner interests are owned by ExxonMobil
 Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil
 Corporation and Cortez Vickers Pipeline Company, an indirect subsidiary of
 M.E. Zuckerman Energy Investors Incorporated.(b)
We
 are severally liable for our percentage ownership share (50%) of the Cortez
 Pipeline Company debt. As of December 31, 2008, Shell Oil Company shares our several
 guaranty obligations jointly and severally for $53.6 million of Cortezs debt
 balance; however, we are obligated to indemnify Shell for the liabilities it
 incurs in connection with such guaranty. Accordingly, as of December 31, 2008
 we have a letter of credit in the amount of $26.8 million issued by JP Morgan
 Chase, in order to secure our indemnification obligations to Shell for 50% of
 the Cortez debt balance of $53.6 million.Further, pursuant to a Throughput and Deficiency Agreement, the
 partners of Cortez Pipeline Company are required to contribute capital to
 Cortez in the event of a cash deficiency. The agreement contractually
 supports the financings of Cortez Capital Corporation, a wholly-owned
 subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez
 Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated
 deficiencies and cash deficiencies relating to the repayment of principal and
 interest on the debt of Cortez Capital Corporation. The partners respective
 parent or other companies further severally guarantee the obligations of the
 Cortez Pipeline owners under this agreement.(c)
West2East Pipeline LLC is a limited liability company and is the sole
 owner of Rockies Express Pipeline LLC. As of December 31, 2008, the remaining
 limited liability member interests in West2East Pipeline LLC are owned by
 ConocoPhillips (24%) and Sempra Energy (25%). We owned a 66 2/3% ownership
 interest in West2East Pipeline LLC from October 21, 2005 until June 30, 2006,
 and we included its results in our consolidated financial statements until
 June 30, 2006. On June 30, 2006, our ownership interest was reduced to 51%,
 West2East Pipeline LLC was deconsolidated, and we subsequently accounted for
 our investment under the equity method of accounting. Upon completion of the
 pipeline, our ownership percentage is expected to be reduced to 50%.(d)
Amount includes an
 aggregate of $1.3 billion in principal amount of fixed rate senior notes
 issued by Rockies Express Pipeline LLC in a private offering in June 2008.
 All payments of principal and interest in respect of these senior notes are
 the sole obligation of Rockies Express. Noteholders have no recourse against
 us or the other member owners of West2East Pipeline LLC for any failure by
 Rockies Express to perform or comply with its obligations pursuant to the
 notes or the indenture.(e)
In addition, there is a
 letter of credit outstanding to support the construction of the Rockies
 Express Pipeline. As of December 31,
 2008, this letter of credit, issued by JPMorgan Chase, had a face amount of $31.4 million.
 Our contingent responsibility with regard to this outstanding letter of
 credit was $16.0 million (51% of total face amount).(f)
Midcontinent
 Express Pipeline LLC is a limited liability company and the owner of the
 Midcontinent Express Pipeline. In January 2008, in conjunction with the signing of additional binding
 pipeline transportation commitments, Midcontinent Express Pipeline LLC and
 MarkWest Pioneer, L.L.C. (a subsidiary of MarkWest Energy Partners, L.P.)
 entered into an option agreement which provides MarkWest 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, we and Energy Transfer Partners, L.P. will each own 45% of
 Midcontinent Express Pipeline LLC, while MarkWest will own the remaining 10%.82

(g)
In addition, there is a
 letter of credit outstanding to support the construction of the Midcontinent
 Express Pipeline. As of December 31,
 2008, this letter of credit, issued by the Royal Bank of Scotland plc, had a face amount of $33.3 million.
 Our contingent responsibility with regard to this outstanding letter of
 credit was $16.7 million (50% of total face amount).(h)
Arose from our Vopak terminal acquisition in July 2001. Nassau
 County, Florida Ocean Highway and Port Authority is a political subdivision
 of the state of Florida. During 1990, Ocean Highway and Port Authority issued
 its Adjustable Demand Revenue Bonds in the aggregate principal amount of
 $38.5 million for the purpose of constructing certain port improvements
 located in Fernandino Beach, Nassau County, Florida. A letter of credit was
 issued as security for the Adjustable Demand Revenue Bonds and was guaranteed
 by the parent company of Nassau Terminals LLC, the operator of the port
 facilities. In July 2002, we acquired Nassau Terminals LLC and became
 guarantor under the letter of credit agreement. In December 2002, we issued a
 $28 million letter of credit under our credit facilities and the former
 letter of credit guarantee was terminated. As of December 31, 2008, the face amount of
 this letter of credit outstanding under our credit facility was $10.2
 million. Principal payments on the bonds are made on the first of December
 each year and reductions are made to the letter of credit.(i)
Principally property, plant and equipment.(j)
Represents the portion of the entitys debt that we may be
 responsible for if the entity cannot satisfy the obligation.For
additional information with regard to our contingent debt obligations, Note 9
DebtContingent Debt to our consolidated financial statements included
elsewhere in this report.

We account
for our investments in Cortez Pipeline Company, West2East Pipeline LLC and
Midcontinent Express Pipeline LLC under the equity method of accounting. For
the year ended December 31, 2008, our share of earnings, based on our ownership
percentage and before amortization of excess investment cost, if any, was $20.8
million from Cortez Pipeline Company, $84.9 million from West2East Pipeline
LLC, and
$0.5 million from Midcontinent Express Pipeline LLC. Additional information
regarding the nature and business purpose of these investments is included in
Notes 7 and 9 to our consolidated financial statements included elsewhere in
this report.

Summary
of Certain Contractual Obligations

Amount of Commitment Expiration per PeriodTotal

1 YearOr Less

2-3 Years

4-5 Years

After 5Years(In millions)Contractual
Obligations:Commercial paper
outstanding

$


$


$


$


$
Other debt borrowings-principal
 payments


8,582.1


288.7


992.7


1,975.5


5,325.2Interest payments(a)


7,735.7


542.9


1,020.9


848.5


5,323.4Lease obligations(b)


149.0


31.3


50.1


32.1


35.5Pension and post-retirement
 welfare plans(c)


70.5


5.1


10.7


12.2


42.5Other obligations(d)


15.1


8.3


6.8





Total

$
16,552.4

$
876.3

$
2,081.2

$
2,868.3

$
10,726.6Other commercial
commitments:Standby letters of
credit(e)

$
343.8

$
273.3

$
25.7

$
26.8

$
18.0Capital
expenditures(f)

$
581.0

$
581.0

$


$


$
(a)
Interest
 payment obligations exclude adjustments for interest rate swap agreements.(b)
Represents
 commitments for capital leases, including interest, and operating leases.(c)
Represents
 expected benefit payments from pension and post-retirement welfare plans as
 of December 31, 2008.(d)
Consist of
 payments due under carbon dioxide take-or-pay contracts and, for the 1 Year
 or Less column only, our purchase and sale agreement with LPC Packaging (a
 California corporation) for the acquisition of certain bulk terminal assets.(e)
The $343.8
 million in letters of credit outstanding as of December 31 2008 consisted of
 the following: (i)
 a $100 million letter of credit that supports certain proceedings with the
 California Public Utilities Commission involving refined products83

tariff charges on the
 intrastate common carrier operations of our Pacific operations pipelines in
 the state of California; (ii) a $55.9 million letter of credit
 supporting our pipeline and terminal operations in Canada; (iii) a combined
 $40.0 million in two letters of credit supporting our hedging of energy
 commodity price risks; (iv) our $30.3 million guarantee under letters of
 credit totaling $45.5 million supporting our International Marine Terminals
 Partnership Plaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds;
 (v) a $26.8 million letter of credit supporting our indemnification
 obligations on the Series D note borrowings of Cortez Capital Corporation;
 (vi) a $25.4 million letter of credit supporting our Kinder Morgan Liquids
 Terminals LLC New Jersey Economic Development Revenue Bonds; (vii) a $18.0
 million letter of credit supporting our Kinder Morgan Operating L.P. B
 tax-exempt bonds; (viii) a $10.2 million letter of credit supporting Nassau
 County, Florida Ocean Highway and Port Authority tax-exempt bonds; (ix) a
 $5.4 million letter of credit supporting our Arrow Terminals, L.P. Illinois
 Development Revenue Bonds; and (x) a combined $16.6 million in seven letters
 of credit supporting environmental and other obligations of us and our
 subsidiaries.(f)
Represents
 commitments for the purchase of plant, property and equipment as of December
 31, 2008.Operating
Activities

Net cash
provided by operating activities was $2,235.9 million in 2008, versus $1,741.8
million in 2007. The overall year-to-year increase of $494.1
million (28%) in cash flow from operations consisted of:

 a $422.2 million increase in
cash from overall higher
 partnership incomeafter adding back, among other things, gains and losses on
 property sales and casualties and certain non-cash expense items, including
 the $377.1 million goodwill impairment charge recognized in the first quarter
 of 2007, and non-cash legal expenses associated with certain adjustments made
 to our reserves related to the legal fees, transportation rate cases and
 other litigation liabilities of our pipeline and terminal
 operationsincluding the $140.0 million expense associated with an increase
 to our litigation reserves in the fourth quarter of 2007. The higher
 partnership income reflects an increase in cash earnings from our five
 reportable business segments in 2008, as discussed above in Results of
 Operations; a $179.3 million increase in
cash from settlements related to
 the early termination of interest rate swap agreements. In December 2008, we
 terminated two existing fixed-to-variable interest rate swap agreements
 having a combined notional principal amount of $700 million and we received
 combined proceeds of $194.3 million; in March 2007, we terminated a
 fixed-to-variable interest rate swap agreement having a notional principal
 amount of $100 million and we received a termination payment of $15.0
 million; a $54.3 million increase
related to higher distributions
 received from equity investmentschiefly due to $82.9 million of initial
 distributions received in 2008 from our investment in West2East Pipeline LLC,
 the sole owner of Rockies Express Pipeline LLC. Currently, we own a 51%
 equity interest in West2East Pipeline LLC, and when construction of the
 Rockies Express Pipeline is completed, our ownership interest will be reduced
 to 50% and the capital accounts of West2East Pipeline LLC will be trued-up to
 reflect our 50% economic interest in the project.The overall
 increase in period-to-period distributions from equity investments includes a
 $28.9 million decrease in distributions received from the Red Cedar Gathering
 Company. In the first quarter of 2007, Red Cedar distributed to us $32.6
 million following a refinancing of its long-term debt obligations. Red Cedar
 used the proceeds received from the March 2007 sale of unsecured senior notes
 to refund and retire the outstanding balance on its then-existing senior
 notes, and to make a distribution to its two owners; a $107.7 million decrease in
cash inflows related to
 period-to-period changes in both non-current assets and liabilities and other
 non-cash expenses. The decrease in cash was driven by, among other things,
 lower transportation and dock prepayments received from Trans Mountain
 pipeline system customers in 2008, lower increases in environmental liability
 reserves in 2008, and lower non-cash general and administrative expenses in
 2008, due to higher expenses in 2007 related to the activities required to complete
 KMIs going-private transaction.With regard to the going-private
 transaction expenses, for accounting purposes, Knight is
 required to allocate to us a portion of these transaction-related amounts and
 we are required
 to recognize the amounts as expense on our income statements; however, we
 were not responsible for paying these buyout expenses, and84

accordingly,
 we recognize the unpaid amount as both a contribution to Partners Capital and an
 increase to Minority interest on our balance sheet; a $30.2 million decrease in
cash attributable to reparation
 and/or refund payments made in 2008 to certain shippers on our Pacific
 operations pipelines. The settlement payments were made pursuant to both
 FERC orders and certain litigation settlement agreementsprimarily related to
 a FERC ruling in February 2008 that resolved certain challenges by
 complainants with regard to delivery tariffs and gathering enhancement fees
 at our Pacific operations Watson Station, located in Carson, California; and a $23.8 million decrease in
cash inflows relative to net
 changes in working capital items.Investing
Activities

Net cash
used in investing activities was $2,825.4 million for the year ended December
31, 2008, compared to $2,428.5 million in the prior year. The $396.9 million
(16%) overall increase in funds utilized in investing activities was primarily
attributable to the following:

 a $841.4 million increase in
cash used from higher capital
 expenditureslargely due to increased investment undertaken to construct our
 Kinder Morgan Louisiana Pipeline, add infrastructure to our carbon dioxide
 producing and delivery operations, and expand our Trans Mountain crude oil
 and refined petroleum products pipeline system.Since the
 end of 2007, rising construction costs, additional regulatory requirements,
 and certain weather delays have continued to create a challenging business
 environment and accordingly, the amount of capital expenditures we made on
 our major projects during 2008 increased from the projection we made at the
 beginning of 2008. Most of this increase has been on our major natural gas
 pipeline projectsfor example, market conditions for consumables, labor and
 construction equipment along with certain provisions in the final
 environmental impact statement have resulted in increased construction costs
 for the Rockies Express Pipeline. Our current estimate of total construction
 costs for the entire Rockies Express pipeline project is now approximately
 $6.2 billion (our proportionate share is 51% and this cost estimate is
 consistent with our January 21, 2009 fourth quarter earnings press release).We continue
 to be focused on managing these cost increases in order to complete our
 expansion projects as close to on-time and on-budget as possible, and we
 attempt to identify ancillary opportunities to increase our returns where
 possible. In addition to utilizing cash generated from its operations or
 proceeds from contributions received from its member owners, Rockies Express
 can fund its cash requirements for capital expenditures through borrowings
 under its own credit facility, issuing its own short-term commercial paper
 (when credit market conditions are favorable), or issuing long-term notes.Our
 sustaining capital expenditures totaled $180.6 million in 2008 and $152.6
 million in 2007. The above amounts include our proportionate share of Rockies
 Express sustaining capital expendituresapproximately $0.1 million in 2008
 and none in 2007but do not include the sustaining capital expenditures of
 our Trans Mountain pipeline system for periods prior to our acquisition date
 of April 30, 2007. Generally, we fund our sustaining capital expenditures
 with existing cash or from cash flows from operations. All of our capital
 expenditures, with the exception of sustaining capital expenditures, are
 discretionary, and our discretionary capital expendituresincluding
 expenditures for internal expansion projectstotaled $2,352.5 million for
 2008, versus $1,539.0 million for 2007; a $254.8 million increase in
cash used due to lower net
 proceeds received from the sales of investments, property, plant and
 equipment, and other net assets (net of salvage and removal costs). The
 decrease in cash sales proceeds was driven by the approximately $298.6
 million we received for the fourth quarter 2007 sale of our North System
 operations. In 2008, we received approximately $50.7 million for the sale of
 our 25% equity ownership interest in Thunder Creek Gas Services, LLC (both
 divestitures are discussed in Note 3 to our consolidated financial statements
 included elsewhere in this report);85

 a $109.6 million increase in
cash used from a loan we made in
 December 2008 to a single customer of our Texas Intrastate natural gas
 pipeline group; a $90.6 million increase in
cash used from incremental
 contributions to investments in 2008, largely driven by a $306.0 million
 equity investment paid in February 2008 to West2East Pipeline LLC to
 partially fund its Rockies Express Pipeline construction costs. Total
 contributions to West2East Pipeline increased $101.2 million in 2008, when
 compared to 2007, and in 2008 we also purchased a combined $13.2 million in
 principal amount of tax-exempt development revenue bonds and contributed $9.0
 million to Fayetteville Express Pipeline LLC, our 50% owned equity investee
 that will construct and operate the Fayetteville Express natural gas
 pipeline.Our purchase
 of the revenue bonds was linked to corresponding loan agreements we entered
 into with borrowing authorities in the states of Louisiana and Mississippi.
 Per the loan agreements, we received $13.2 million under the same payment and
 interest terms of the bonds, and we used the cash to partially fund our
 construction of our Kinder Morgan Louisiana Pipeline and our bulk terminal
 facility expansions within the state of Mississippi.The overall
 increase in period-to-period contributions to investments includes a $34.1
 million decrease in contributions paid to Midcontinent Express Pipeline LLC,
 the sole owner of the Midcontinent Express Pipeline. In 2008 and 2007, we
 contributed $27.5 million and $61.6 million, respectively, for our
 proportionate share of Midcontinent Express Pipeline construction costs. a $696.5 million decrease in
cash used for acquisitions,
 including a decrease of $572.5 million related to our acquisition of Trans
 Mountain from Knight. In 2007, we paid $549.1 million to Knight to acquire
 the net assets of Trans Mountain, and in April 2008, we received a cash
 contribution of $23.4 million from Knight as a result of certain true-up
 provisions in our acquisition agreement. For more information on our
 acquisition of Trans Mountain from Knight, see Note 3 to our consolidated
 financial statements included elsewhere in this report. The remaining $124
 million decrease in cash used was primarily related to higher expenditures
 for terminal assets in 2007 compared to 2008; a $141.2 million decrease in
cash used due to lower
 period-to-period payments for margin and restricted deposits in 2008 compared
 to 2007, associated largely with our utilization of derivative contracts to
 hedge (offset) against the volatility of energy commodity price risks; and an $89.1 million decrease in
cash used related to a return of
 capital received from Midcontinent Express Pipeline LLC in the first quarter
 of 2008. In February 2008, Midcontinent entered into and then made borrowings
 under a new $1.4 billion three-year, unsecured revolving credit facility due
 February 28, 2011. Midcontinent then made distributions (in excess of
 cumulative earnings) to its two member owners to reimburse them for prior
 contributions made to fund its pipeline construction costs. a $27.3 million increase in
cash used due to changes in
 natural gas stored underground and natural gas linefill, property casualty
 indemnifications, and other items.Financing ActivitiesNet cash
 provided by financing activities amounted to $601.3 million in 2008; while in
 the prior year, our financing activities provided net cash of $735.7 million.
 The $134.4 million (18%) overall decrease in cash inflows
 provided by financing activities was primarily due to: a $334.4 million decrease in
cash from higher partnership
 distributions in 2008, when compared to distributions paid in 2007.
 Distributions to all partners, consisting of our common and Class B
 unitholders, our general partner and our minority interests, totaled $1,488.7
 million in 2008, compared to $1,154.3 million last year.86

The increase
 in partnership distributions reflects higher year-over-year distributable
 cash, which represents the amount of cash we generate that is available to
 pay our unitholders. The increase in distributable cash was in turn driven by
 the increase in total segment earnings before depreciation and amortization
 expenses (discussed above in Results of Operations). More information on
 our cash distributions is provided below in Partnership Distributions; a $79.9 million decrease in
cash inflows from partnership
 equity issuances. The decrease relates to the combined $560.9 million we
 received, after commissions and underwriting expenses, from three separate
 offerings of additional common units in 2008, versus the combined $640.8
 million we received last year from our May 2007 issuance of additional i­-units
 to KMR and our December 2007 public offering of additional common units. Both
 our 2008 and 2007 equity issuances are discussed more fully in Note 11 to our
 consolidated financial statements included elsewhere in this report; a $225.3 million increase in
cash from overall debt financing
 activitieswhich include our issuances and payments of debt and our debt
 issuance costs. The period-to-period increase in cash from overall financing
 activities was primarily due to (i) a $295.7 million increase in cash inflows
 from net issuances and payments of senior notes; (ii) a $13.2 million
 increase in cash from funds we originally invested in long-term tax-exempt
 development revenue bonds (described above in Investing Activities); and
 (iii) an $80.0 million decrease in cash inflows from lower overall net
 commercial paper borrowings.The increase
 in cash from changes in senior notes outstanding reflects the combined
 $2,080.2 million we received from three separate public offerings of senior
 notes in 2008 (discussed in Note 9 to our consolidated financial statements
 included elsewhere in this report), versus the $1,784.5 million increase in
 cash inflows from the issuances and payments of senior notes during 2007 (see
 Note 9 to our consolidated financial statements included elsewhere in this
 report for more information on our issuances and payments of senior notes).
 We used the proceeds from each of our 2007 debt offerings and from our first
 two 2008 offerings to reduce the borrowings under our commercial paper
 program. We used the proceeds from our third and final 2008 debt offering (in
 December) to reduce the borrowings under our revolving bank credit facility;
 and a $51.0 million increase in
cash inflows from net changes in
 cash book overdraftsresulting from timing differences on checks issued but
 not yet endorsed. a $3.6 million increase in
cash from repayment from (loans
 to) related party, contributions from minority interest, and other.Partnership
Distributions

Our
partnership agreement requires that we distribute 100% of Available Cash, as
defined in our partnership agreement, to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available Cash consists generally of all of our cash receipts,
including cash received by our operating partnerships and net reductions in
reserves, less cash disbursements and net additions to reserves and amounts
payable to the former general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.

Our
general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, sustaining capital expenditures, rate refunds
and distributions for the next four quarters. These reserves are not restricted
by magnitude, but only by type of future cash requirements with which they can
be associated. When KMR determines our quarterly distributions, it considers
current and expected reserve needs along with current and expected cash flows
to identify the appropriate sustainable distribution level. For 2008, 2007 and 2006, we distributed
approximately 100%, 100% and 103%, respectively, of the total of cash receipts
less cash disbursements (calculations assume that KMR unitholders received cash
instead of additional i-units). The difference between these numbers and 100%
of distributable cash flow reflects net changes in reserves.

Our
general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives distributions
in additional i-units. We do not distribute cash to i-unit owners

87

but instead
retain the cash for use in our business. However, the cash equivalent of
distributions of i-units is treated as if it had actually been distributed for
purposes of determining the distributions to our general partner. Each time we
make a distribution, the number of i-units owned by KMR and the percentage of
our total units owned by KMR increase automatically under the provisions of our
partnership agreement.

Available
cash is initially distributed 98% to our limited partners and 2% to our general
partner. These distribution percentages are modified to provide for incentive
distributions to be paid to our general partner in the event that quarterly
distributions to unitholders exceed certain specified targets.

Available
cash for each quarter is distributed:

 first, 98% to the owners of
all classes of units pro rata and
 2% to our general partner until the owners of all classes of units have received
 a total of $0.15125 per unit in cash or equivalent i-units for such quarter; second, 85% of any available
cash then remaining to the
 owners of all classes of units pro rata and 15% to our general partner until
 the owners of all classes of units have received a total of $0.17875 per unit
 in cash or equivalent i-units for such quarter; third, 75% of any available
cash then remaining to the owners
 of all classes of units pro rata and 25% to our general partner until the
 owners of all classes of units have received a total of $0.23375 per unit in
 cash or equivalent i-units for such quarter; and fourth, 50% of any available
cash then remaining to the
 owners of all classes of units pro rata, to owners of common units and Class
 B units in cash and to owners of i-units in the equivalent number of i-units,
 and 50% to our general partner.Incentive
distributions are generally defined as all cash distributions paid to our
general partner that are in excess of 2% of the aggregate value of cash and
i-units being distributed. Our general
partners incentive distribution that we declared for 2008 and 2007 was $800.8
million and $611.9 million, respectively, while the incentive distribution paid
to our general partner during 2008 and 2007 was $754.6 million and $559.6
million, respectively. The difference between declared and paid distributions
is because our distributions for the fourth quarter of each year are declared
and paid in the first quarter of the following year.

On February
13, 2009, we paid a quarterly distribution of $1.05 per unit for the fourth
quarter of 2008. This distribution was 14% greater than the $0.92 distribution
per unit we paid for the fourth quarter of 2007. We paid this distribution in
cash to our common unitholders and to our Class B unitholders. KMR, our sole
i-unitholder, received additional i-units based on the $1.05 cash distribution
per common unit. We believe that future operating results will
continue to support similar levels of quarterly cash and i-unit distributions;
however, no assurance can be given that future distributions will continue at
such levels.

Litigation and
Environmental

As
of December 31, 2008, we have recorded a total reserve for environmental
claims, without discounting and without regard to anticipated insurance
recoveries, in the amount of $78.9 million. In addition, we have recorded a
receivable of $20.7 million for expected cost recoveries that have been deemed
probable. As of December 31, 2007, our environmental reserve totaled $92.0
million and our estimated receivable for environmental cost recoveries totaled
$37.8 million, respectively.

Our
environmental reserve is primarily established to address and clean up soil and
ground water impacts from former releases to the environment at facilities we
have acquired or accidental spills or releases at facilities that we own.
Reserves for each project are generally established by reviewing existing
documents, conducting interviews and performing site inspections to determine
the overall size and impact to the environment. Reviews are made on a quarterly
basis to determine the status of the cleanup and the costs associated with the
effort. In assessing environmental risks in conjunction with proposed
acquisitions, we review records relating to environmental issues, conduct site
inspections, interview employees, and, if appropriate, collect soil and
groundwater samples.

88

Additionally,
as of December 31, 2008 and 2007, we have recorded a total reserve for legal
fees, transportation rate cases and other litigation liabilities in the amount
of $234.8 million and $247.9 million, respectively. This reserve is primarily
related to various claims from lawsuits arising from our West Coast Products
Pipelines operations, and the contingent amount is based on both the
circumstances of probability and reasonability of dollar estimates. We
regularly assess the likelihood of adverse outcomes resulting from these claims
in order to determine the adequacy of our liability provision.

Though
no assurance can be given, we believe we have established adequate
environmental and legal reserves such that the resolution of pending
environmental matters and litigation will not have a material adverse impact on
our business, cash flows, financial position or results of operations. However,
changing circumstances could cause these matters to have a material adverse
impact.

Pursuant
to our continuing commitment to operational excellence and our focus on safe,
reliable operations, we have implemented, and intend to implement in the
future, enhancements to certain of our operational practices in order to
strengthen our environmental and asset integrity performance. These
enhancements have resulted and may result in higher operating costs and
sustaining capital expenditures; however, we believe these enhancements will
provide us the greater long term benefits of improved environmental and asset
integrity performance.

Please
refer to Notes 16 and 17 of our consolidated financial statements included
elsewhere in this report for additional information regarding pending
litigation and environmental matters, respectively.

Regulation

The
Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform
integrity tests on natural gas transmission pipelines that exist in high
population density areas that are designated as High Consequence Areas.
Pipeline companies are required to perform the integrity tests within ten years
of December 17, 2002, the date of enactment, and must perform subsequent
integrity tests on a seven year cycle. At least 50% of the highest risk
segments must be tested within five years of the enactment date. The risk
ratings are based on numerous factors, including the population density in the
geographic regions served by a particular pipeline, as well as the age and
condition of the pipeline and its protective coating. Testing may consist of
hydrostatic testing, internal electronic testing, or direct assessment of the
piping. A similar integrity management rule for refined petroleum
products pipelines became effective May 29, 2001. All baseline assessments for
products pipelines were required to be completed by March 31, 2008 and we met
that deadline. We have included all incremental
expenditures estimated to occur during 2009 associated with the Pipeline Safety
Improvement Act of 2002 and the integrity management of our products pipelines
in our 2009 budget and capital expenditure plan.

Please
refer to Note 17 to our consolidated financial statements included elsewhere in
this report for additional information regarding regulatory matters.

Fair Value
Measurements

We
utilize energy commodity derivative contracts for the purpose of mitigating our
risk resulting from fluctuations in the market price of natural gas, natural
gas liquids and crude oil, and utilize interest rate swap agreements to
mitigate our risk from fluctuations in interest rates. Pursuant to current accounting
provisions, we record our derivative contracts at their estimated fair values
as of each reporting date. For more information on our risk management
activities, see Note 10 to our consolidated financial statements included
elsewhere in this report.

SFAS
No. 157, Fair Value Measurements establishes a hierarchal disclosure
framework associated with the level of pricing observability utilized in
measuring fair value. The hierarchy of valuation techniques is based upon
whether the inputs to those valuation techniques reflect assumptions other
market participants would use based upon market data obtained from independent
sources (observable inputs) or reflect a companys own assumptions of market
participant valuation (unobservable inputs). This framework defines three
levels of inputs to the fair value measurement process, and requires that each
fair value measurement be assigned to a level corresponding to the lowest level
input that is significant to the fair value measurement in its entirety. In
accordance with SFAS No. 157, the lowest level of fair value hierarchy
based on these two types of inputs is designated as Level 3, and is based on
prices or valuations that require inputs that are both significant to the fair
value measurement and unobservable.

89

As
of December 31, 2008, the fair value of our derivative contracts classified as
Level 3 under the established fair value hierarchy consisted primarily of West
Texas Intermediate crude oil options (costless collars) and West Texas Sour
crude oil hedges. Costless collars are designed to establish floor and ceiling
prices on anticipated future oil production from the assets we own in the
SACROC oil field unit. While the use of these derivative contracts limits the
downside risk of adverse price movements, they may also limit future revenues
from favorable price movements. In addition to these oil-commodity derivatives,
our Level 3 derivative contracts included natural gas basis swaps and natural
gas options. Basis swaps are used in connection with another derivative
contract to reduce hedge ineffectiveness by reducing a basis difference between
a hedged exposure and a derivative contract. Natural gas options are used to
offset the exposure related to certain physical contracts.

The
following table summarizes the total fair value asset and liability
measurements of our Level 3 energy commodity derivative contracts in accordance
with SFAS No. 157.

Significant Unobservable Inputs (Level 3)Assets

LiabilitiesDecember 31,2008

December 31,2007

Change

December 31,2008

December 31,2007

ChangeWTI options

$
34.3

$


$
34.3

$
(2.2
)
$


$
(2.2
)WTS oil swaps


17.1





17.1


(0.2
)

(94.5
)

94.3Natural gas basis
swaps


3.3


2.8


0.5


(5.2
)

(4.7
)

(0.5
)Natural gas options











(2.7
)




(2.7
)Other


0.5


1.0


(0.5
)

(0.8
)

(4.9
)

4.1Total

$
55.2

$
3.8

$
51.4

$
(11.1
)
$
(104.1
)
$
93.0The
largest changes in the fair value of our Level 3 assets and liabilities between
December 31, 2008 and December 31, 2007 were related to West Texas Intermediate
options and West Texas Sour hedges. We entered into the majority of our WTI
option contracts during 2008, which accounts for the changes. The changes in
value from our WTS swap contracts were largely due to favorable crude oil price
changes since the end of 2007. There were no transfers into or out of Level 3
during the period.

The
valuation techniques used for the above Level 3 input derivative contracts are
as follows:

 Option contractsvalued
using internal model. Internal models
 incorporate the use of options pricing and estimates of the present value of
 cash flows based upon underlying contractual terms. The models reflect
 managements estimates, taking into account observable market prices,
 estimated market prices in the absence of quoted market prices, the risk-free
 market discount rate, volatility factors, estimated correlations of commodity
 prices and contractual volumes; WTS oil swapsprices
obtained from a broker using their
 proprietary model for similar assets and liabilities, quotes are non-binding;
 and Natural gas basis
swapsvalues obtained through a pricing
 service, derived by combining raw inputs from the New York Mercantile
 Exchange (referred to in this report as NYMEX) with proprietary quantitative
 models and processes. Although the prices are originating from a liquid
 market (NYMEX), we believe the incremental effort to further validate these
 prices would take undue effort and would not materially alter the
 assumptions. As a result, we have classified the valuation of these
 derivatives as Level 3.For
our energy commodity derivative contracts, the most observable inputs available
are used to determine the fair value of each contract. In the absence of a
quoted price for an identical contract in an active market, we use broker
quotes for identical or similar contracts, or internally prepared valuation
models as primary inputs to determine fair value. No adjustments were made to quotes or prices obtained from brokers and
pricing services, and our valuation methods have not changed during the
quarter ended December 31, 2008.

When
appropriate, valuations are adjusted for various factors including credit
considerations. Such adjustments are generally based on available market
evidence, including but not limited to our credit default swap quotes as of

90

December 31,
2008. Collateral agreements with our counterparties serve to reduce our credit
exposure and are considered in the adjustment. We adjust the fair value
measurements of our energy commodity derivative contracts for credit risk in
accordance with SFAS No. 157, and as of December 31, 2008, our consolidated
Accumulated other comprehensive loss balance included a gain of $2.2 million
related to discounting the value of our energy commodity derivative net assets
for the effect of credit risk.

With
the exception of our Casper and Douglas hedges and the ineffective portion of
our derivative contracts, our energy commodity derivative contracts are
accounted for as cash flow hedges. In accordance with SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities (after amendment by SFAS No. 137, SFAS No. 138 and SFAS No.
149; collectively, SFAS No. 133), gains and losses associated with cash
flow hedges are reported in Accumulated other comprehensive loss in our
accompanying consolidated balance sheets.

Recent
Accounting Pronouncements

Please
refer to Note 18 to our consolidated financial statements included elsewhere in
this report for information concerning recent accounting pronouncements.

Information
Regarding Forward-Looking Statements

This
filing includes forward-looking statements. These forward-looking statements
are identified as any statement that does not relate strictly to historical or
current facts. They use words such as anticipate, believe, intend,
plan, projection, forecast, strategy, position, continue,
estimate, expect, may, or the negative of those terms or other variations
of them or comparable terminology. In particular, statements, express or
implied, concerning future actions, conditions or events, future operating
results or the ability to generate sales, income or cash flow or to make
distributions are forward-looking statements. Forward-looking statements are
not guarantees of performance. They involve risks, uncertainties and
assumptions. Future actions, conditions or events and future results of
operations may differ materially from those expressed in these forward-looking
statements. Many of the factors that will determine these results are beyond
our ability to control or predict. Specific factors which could cause actual
results to differ from those in the forward-looking statements include:

 price trends and overall
demand for natural gas liquids,
 refined petroleum products, oil, carbon dioxide, natural gas, electricity,
 coal and other bulk materials and chemicals in North America; economic activity, weather,
alternative energy sources,
 conservation and technological advances that may affect price trends and
 demand; changes in our tariff rates
implemented by the Federal Energy
 Regulatory Commission or the California Public Utilities Commission; our ability to acquire new
businesses and assets and
 integrate those operations into our existing operations, as well as our
 ability to expand our facilities; difficulties or delays
experienced by railroads, barges,
 trucks, ships or pipelines in delivering products to or from our terminals or
 pipelines; our ability to successfully
identify and close acquisitions
 and make cost-saving changes in operations; shut-downs or cutbacks at
major refineries, petrochemical or
 chemical plants, ports, utilities, military bases or other businesses that
 use our services or provide services or products to us; crude oil and natural gas
production from exploration and
 production areas that we serve, such as the Permian Basin area of West Texas,
 the U.S. Rocky Mountains and the Alberta oil sands; changes in laws or
regulations, third-party relations and
 approvals, and decisions of courts, regulators and governmental bodies that
 may adversely affect our business or our ability to compete;91

 changes in accounting
pronouncements that impact the
 measurement of our results of operations, the timing of when such
 measurements are to be made and recorded, and the disclosures surrounding
 these activities; our ability to offer and sell
equity securities and debt
 securities or obtain debt financing in sufficient amounts to implement that
 portion of our business plan that contemplates growth through acquisitions of
 operating businesses and assets and expansions of our facilities; our indebtedness, which could
make us vulnerable to general
 adverse economic and industry conditions, limit our ability to borrow
 additional funds, and/or place us at competitive disadvantages compared to
 our competitors that have less debt or have other adverse consequences; interruptions of electric
power supply to our facilities due
 to natural disasters, power shortages, strikes, riots, terrorism, war or
 other causes; our ability to obtain
insurance coverage without significant
 levels of self-retention of risk; acts of nature, sabotage,
terrorism or other similar acts
 causing damage greater than our insurance coverage limits; capital and credit markets
conditions, inflation and interest
 rates; the political and economic
stability of the oil producing
 nations of the world; national, international,
regional and local economic,
 competitive and regulatory conditions and developments; our ability to achieve cost
savings and revenue growth; foreign exchange
fluctuations; the timing and extent of
changes in commodity prices for oil,
 natural gas, electricity and certain agricultural products; the extent of our success in
discovering, developing and
 producing oil and gas reserves, including the risks inherent in exploration
 and development drilling, well completion and other development activities; engineering and mechanical or
technological difficulties that
 we may experience with operational equipment, in well completions and
 workovers, and in drilling new wells; the uncertainty inherent in
estimating future oil and natural
 gas production or reserves; the ability to complete
expansion projects on time and on
 budget; the timing and success of our
business development efforts;
 and unfavorable results of
litigation and the fruition of
 contingencies referred to in Note 16 to our consolidated financial statements
 included elsewhere in this report.The
foregoing list should not be construed to be exhaustive. We believe the
forward-looking statements in this report are reasonable. However, there
is no assurance that any of the actions, events or results of the
forward-looking statements will occur, or if any of them do, what impact they
will have on our results of operations or financial condition. Because of these
uncertainties, you should not put undue reliance on any forward-looking
statements.

See
Item 1A Risk Factors for a more detailed description of these and other
factors that may affect the forward-looking statements. When considering
forward-looking statements, one should keep in mind the risk factors described
in Risk Factors above. The risk factors could cause our actual results to
differ materially from those
contained in any forward-looking statement. We disclaim any obligation, other
than as required by applicable

92

law, to update the above list or to announce
publicly the result of any revisions to any of the forward-looking statements
to reflect future events or developments.

Item
7A. Quantitative
and Qualitative Disclosures About Market Risk.

Generally,
our market risk sensitive instruments and positions have been determined to be
other than trading. Our exposure to market risk as discussed below includes
forward-looking statements and represents an estimate of possible changes in
fair value or future earnings that would occur assuming hypothetical future
movements in interest rates or commodity prices. Our views on market risk are
not necessarily indicative of actual results that may occur and do not
represent the maximum possible gains and losses that may occur, since actual
gains and losses will differ from those estimated based on actual fluctuations
in commodity prices or interest rates and the timing of transactions.

Energy
Commodity Market Risk

We are
exposed to commodity market risk and other external risks, such as
weather-related risk, in the ordinary course of business. However, we take
steps to hedge, or limit our exposure to, these risks in order to maintain a
more stable and predictable earnings stream. Stated another way,
we execute a hedging strategy that seeks to protect us financially against
adverse price movements and serves to minimize potential losses. Our strategy involves the use of certain energy
commodity derivative contracts to reduce and minimize the risks associated with
unfavorable changes in the market price of natural gas, natural gas liquids and
crude oil. The derivative contracts we use include energy products traded on
the New York Mercantile Exchange and over-the-counter markets, including, but
not limited to, futures and options contracts, fixed price swaps and basis
swaps.

Fundamentally,
our hedging strategy involves taking a simultaneous position in the futures
market that is equal and opposite to our position, or anticipated position, in
the cash market (or physical product) in order to minimize the risk of financial
loss from an adverse price change. For example, as sellers of crude oil and
natural gas, we often enter into fixed price
swaps and/or futures contracts to guarantee or lock-in the sale price of our
oil or the margin from the sale and purchase of our natural gas at the time of
market delivery, thereby directly offsetting any change in prices, either
positive or negative. A hedge is successful when gains or losses in the
cash market are neutralized by losses or gains in the futures transaction.

Our
policies require that we only enter into derivative contracts with carefully
selected major financial institutions or similar counterparties based upon
their credit ratings and other factors, and we maintain strict dollar and term
limits that correspond to our counterparties credit ratings. While we enter
into derivative transactions only with investment grade counterparties and
actively monitor their credit ratings, it is nevertheless possible that losses
will result from counterparty credit risk in the future. The credit ratings of
the primary parties from whom we transact in energy commodity derivative
contracts (based on contract market values) are as follows (credit ratings
per Standard & Poors Rating Services):

Credit RatingCitigroup
AJ. Aron & Company / Goldman Sachs
AMorgan Stanley
AAs
discussed above, our principal use of energy commodity derivative contracts is
to mitigate the market price risk associated with anticipated transactions for
the purchase and sale of natural gas, natural gas liquids and crude oil. Using
derivative contracts for this purpose helps provide us increased certainty with
regard to our operating cash flows and helps us undertake further capital
improvement projects, attain budget results and meet distribution targets to
our partners. SFAS No. 133 categorizes such use of energy commodity derivative
contracts as cash flow hedges, because the derivative contract is used to hedge
the anticipated future cash flow of a transaction that is expected to occur but
whose value is uncertain. Cash flow hedges are defined as hedges made with the
intention of decreasing  the  variability  in cash flows  related to future  transactions,  as opposed to the value of an asset, liability  or firm
commitment, and SFAS No. 133 prescribes special hedge accounting treatment for such derivatives.

93

In
accounting for cash flow hedges, gains and losses on the derivative contracts
are reported in other comprehensive income, outside Net Income reported in
our consolidated statements of income, but only to the extent that the gains
and losses from the change in value of the derivative contracts can later
offset the loss or gain from the change in value of the hedged future cash
flows during the period in which the hedged cash flows affect net income. That
is, for cash flow hedges, all effective components of the derivative contracts
gains and losses are recorded in other comprehensive income (loss), pending
occurrence of the expected transaction. Other comprehensive
income (loss) consists of those financial items that are included in Accumulated
other comprehensive loss in our accompanying consolidated balance sheets but
not included in our net income. Thus,
in highly effective cash flow hedges, where there is no ineffectiveness, other
comprehensive income changes by exactly as much as the derivative contracts and
there is no impact on earnings until the expected transaction occurs.

All
remaining gains and losses on the derivative contracts (the ineffective
portion) are included in current net income. The ineffective portion of the gain
or loss on the derivative contracts is the difference between the gain or loss
from the change in value of the derivative contract and the effective portion
of that gain or loss. In addition, when the hedged forecasted
transaction does take place and affects earnings, the effective part of the
hedge is also recognized in the income statement, and the earlier recognized
effective amounts are removed from Accumulated other comprehensive loss. If
the forecasted transaction results in an asset or liability, amounts in
Accumulated other comprehensive loss should be reclassified into earnings
when the asset or liability affects earnings through cost of sales,
depreciation, interest expense, etc.

The
accumulated components of other comprehensive income are reported separately as
accumulated other comprehensive income or loss in the stockholders equity
section of the balance sheet. For us, the amounts included in
Accumulated other comprehensive loss in our accompanying consolidated balance
sheets primarily include (i) the effective portion of the gains and losses on
cash flow hedging items; and (ii) foreign currency translation adjustments. The
gains and losses on hedging items primarily relate to the derivative contracts
associated with our hedging of anticipated future cash flows from the sales and
purchases of natural gas, natural gas liquids and crude oil. The translation
adjustments are a cumulative total, resulting from translating all of our
foreign denominated assets and liabilities at current exchange rates, while
equity is translated by using historical or weighted-average exchange rates.

The
total Accumulated other comprehensive loss included within the Partners Capital section of our accompanying
balance sheets as of December 31, 2008 and December 31, 2007, included
amounts associated with energy commodity price risk management activities of
$63.2 million and $1,377.2 million, respectively. The total Accumulated other comprehensive loss as of December 31, 2008
also included a
cumulative translation debit (unrealized loss) balance of $217.3 million. The
total Accumulated other comprehensive loss as of December 31, 2007 included a cumulative translation credit
(unrealized gain) balance of $112.5 million

In future
periods, as the hedged cash flows from our actual purchases and sales of energy
commodities affect our net income, the related gains and losses included in our
accumulated other comprehensive loss as a result of our hedging are transferred
to the income statement as well, effectively offsetting the changes in cash
flows stemming from the hedged risk.

We measure
the risk of price changes in the natural gas, natural gas liquids and crude oil
markets utilizing a value-at-risk model. Value-at-risk is a statistical measure
indicating the minimum expected loss in a portfolio over a given holding period,
within a certain level of statistical confidence.  We utilize a
closed form model to evaluate risk on a daily basis. The value-at-risk computations
utilize a confidence level of 97.7% for the resultant price movement and a
holding period of one day is chosen for the calculation. The confidence level
used means that there is a 97.7% probability that the mark-to-market losses for
a single day will not exceed the value-at-risk number presented. Derivative
contracts evaluated by the model include commodity futures and options
contracts, fixed price swaps, basis swaps and over-the-counter options.

For
each of the years ended December 31, 2008 and 2007, our value-at-risk reached a
high of $1.8 million and $1.6 million, respectively, and a low of $0.7 million
and $0.7 million, respectively. Value-at-risk as of December 31, 2008 was $0.7
million, and averaged $1.5 million for 2008. Value-at-risk as of December 31,
2007 was $1.6 million, and averaged $1.2 million for 2007.

94

Our
calculated value-at-risk exposure represents an estimate of the reasonably
possible net losses that would be recognized on our portfolio of derivative
contracts assuming hypothetical movements in future market rates, and is not
necessarily indicative of actual results that may occur. It does not represent
the maximum possible loss or any expected loss that may occur, since actual
future gains and losses will differ from those estimated. Actual gains and
losses may differ from estimates due to actual fluctuations in market rates,
operating exposures and the timing thereof, as well as changes in our portfolio
of derivatives during the year. In addition, as discussed above, we enter into
these derivative contracts solely for the purpose of mitigating the risks that
accompany certain of our business activities and, therefore, the change in the
market value of our portfolio of derivative contracts, with the exception of a
minor amount of hedging inefficiency, is offset by changes in the value of the
underlying physical transactions. For more information on our risk management
activities, see Note 14 to our consolidated financial statements included
elsewhere in this report.

Interest Rate Risk

In
order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments
and positions is the potential change arising from increases or decreases in
interest rates as discussed below.

For fixed
rate debt, changes in interest rates generally affect the fair value of the
debt instrument, but not our earnings or cash flows. Conversely, for variable
rate debt, changes in interest rates generally do not impact the fair value of
the debt instrument, but may affect our future earnings and cash flows. We do
not have an obligation to prepay fixed rate debt prior to maturity and, as a
result, interest rate risk and changes in fair value should not have a
significant impact on our fixed rate debt until we would be required to
refinance such debt.

As of
December 31, 2008 and 2007, the carrying values of our fixed rate debt were
approximately $8,469.5 million and $6,382.9 million, respectively. These
amounts compare to, as of December 31, 2008 and 2007, fair values of $7,536.4
million and $6,518.7 million, respectively. Fair values were determined using
quoted market prices, where applicable, or future cash flow discounted at
market rates for similar types of borrowing arrangements. A hypothetical 10%
change (approximately 54 basis points) in the average interest rates applicable
to such debt for 2008 and 2007, would result in changes of approximately $284.2
million and $259.9 million, respectively, in the fair values of these
instruments.

The
carrying value and fair value of our variable rate debt, including associated
accrued interest and excluding the value of interest rate swap agreements
(discussed below), was $94.5 million as of December 31, 2008 and $684.5 million
as of December 31, 2007. A hypothetical 10% change in the weighted average
interest rate on all of our borrowings, when applied to our outstanding balance
of variable rate debt as of December 31, 2008 and 2007, including adjustments
for notional swap amounts, would result in changes of approximately $15.8
million and $19.1 million, respectively, in our 2008 and 2007 annual pre-tax
earnings.


We
adjusted the fair value measurement of our long-term debt as of December 31, 2008 in accordance with
SFAS No. 157, and the estimated fair value of our debt as of December 31, 2008 includes a decrease of
$261.1 million related to discounting the fair value measurement for the effect of credit risk.



As of
December 31, 2008 and 2007, we were a party to interest rate swap agreements
with notional principal amounts of $2.8 billion and $2.3 billion, respectively.
An interest rate swap agreement is a contractual agreement entered into between
two counterparties under which each agrees to make periodic interest payments
to the other for an agreed period of time based upon a predetermined amount of
principal, which is called the notional principal amount. Normally at each
payment or settlement date, the party who owes more pays the net amount; so at
any given settlement date only one party actually makes a payment. The
principal amount is notional because there is no need to exchange actual
amounts of principal.

We entered
into our interest rate swap agreements for the purpose of transforming a
portion of the underlying cash flows related to our long-term fixed rate debt
securities into variable rate debt in order to achieve our desired mix of fixed
and variable rate debt. Since the fair value of our fixed rate debt varies with
changes in the market rate of interest, we enter into swap agreements to
receive a fixed and pay a variable rate of interest. Such swap agreements
result in future cash flows that vary with the market rate of interest, and
therefore hedge against changes in the fair value of our fixed rate debt due to
market rate changes.

95

As of both
December 31, 2008 and 2007, all of our interest rate swap agreements
represented fixed-for-variable rate swaps, where we agreed to pay our
counterparties a variable rate of interest on a notional principal amount,
comprised of principal amounts from various series of our long-term fixed rate
senior notes. In exchange, our counterparties agreed to pay us a fixed rate of
interest, thereby allowing us to transform our fixed rate liabilities into
variable rate obligations without the incurrence of additional loan origination
or conversion costs.

We monitor
our mix of fixed rate and variable rate debt obligations in light of changing
market conditions and from time to time may alter that mix by, for example,
refinancing balances outstanding under our variable rate debt with fixed rate
debt (or vice versa) or by entering into interest rate swap agreements or other
interest rate hedging agreements. In general, we attempt to
maintain an overall target mix of approximately 50% fixed rate debt and 50%
variable rate debt.

As of
December 31, 2008, our cash and investment portfolio included approximately
$13.2 million in fixed-income debt securities. Because our investment in debt
securities was made and will be maintained in the future to directly offset the
interest rate risk on a like amount of long-term debt, a hypothetical 10%
increase in interest rates would not have a material effect on the fair market
value of our portfolio; and because we have the ability to liquidate this
portfolio, we do not expect our operating results or cash flows to be
materially affected to any significant degree by the effect of a sudden change
in market interest rates on our investment portfolio.

See Note 9
to our consolidated financial statements included elsewhere in this report for
additional information related to our debt instruments; for more information on
our interest rate swap agreements, see Note 14.

Item 8. Financial Statements and Supplementary
Data.

The
information required in this Item 8 is included in this report as set forth in
the Index to Financial Statements on page 124.

Item 9. Changes in and Disagreements with Accountants on
Accounting
and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Conclusion
Regarding the Effectiveness of Disclosure Controls and Procedures

As of
December 31, 2008, our management, including our Chief Executive Officer and
Chief Financial Officer, has evaluated the effectiveness of the design and
operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
under the Securities Exchange Act of 1934. There are inherent limitations to
the effectiveness of any system of disclosure controls and procedures,
including the possibility of human error and the circumvention or overriding of
the controls and procedures. Accordingly, even effective disclosure controls
and procedures can only provide reasonable assurance of achieving their control
objectives. Based upon and as of the date of the evaluation, our Chief
Executive Officer and our Chief Financial Officer concluded that the design and
operation of our disclosure controls and procedures were effective to provide
reasonable assurance that information required to be disclosed in the reports
we file and submit under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported as and when required, and is accumulated and
communicated to our management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate, to allow timely decisions regarding required
disclosure.

96

Managements
Report on Internal Control Over Financial Reporting

Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f). Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate. Under the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of
the effectiveness of our internal control over financial reporting based on the
framework in Internal Control  Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on our
evaluation under the framework in Internal Control  Integrated Framework,
our management concluded that our internal control over financial reporting was
effective as of December 31, 2008.

The
effectiveness of our internal control over financial reporting as of December
31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent
registered public accounting firm, as stated in their report which appears
herein.

Certain
businesses we acquired during 2008 were excluded from the scope of our
managements assessment of the effectiveness of our internal control over
financial reporting as of December 31, 2008. The excluded businesses consisted
of the following:

  the bulk terminal
assets we
 acquired from Chemserve, Inc., effective August 15, 2008; and  the refined
petroleum
 products storage terminal we acquired from ConocoPhillips, effective December
 10, 2008.These
businesses, in the aggregate, constituted 0.01% of our total operating revenues for
2008 and 0.23%
of our total assets as of December 31, 2008.

Changes
in Internal Control Over Financial Reporting

There has
been no change in our internal control over financial reporting during the
fourth quarter of 2008 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

97

PART III

Item 10. Directors,
Executive Officers and Corporate Governance

Directors and Executive Officers of our General Partner and its
Delegate

Set forth
below is certain information concerning the directors and executive officers of
our general partner and KMR, the delegate of our general partner. All directors
of our general partner are elected annually by, and may be removed by, Kinder
Morgan (Delaware), Inc. as its sole shareholder, and all directors of KMR are
elected annually by, and may be removed by, our general partner as the sole
holder of KMRs voting shares. Kinder Morgan (Delaware), Inc. is a wholly owned
subsidiary of Knight. All officers of our general partner and all officers of
KMR serve at the discretion of the board of directors of our general partner.

Name

Age

Position with our General Partner and KMRRichard D. Kinder

64

Director, Chairman and Chief Executive OfficerC. Park Shaper

40

Director and PresidentSteven J. Kean

47

Executive Vice President, Chief Operating Officer and President,
 Natural Gas PipelinesGary L. Hultquist

65

DirectorC. Berdon Lawrence

66

DirectorPerry M. Waughtal

73

DirectorKimberly A. Dang

39

Vice President and Chief Financial OfficerJeffrey R. Armstrong

40

Vice President (President, Terminals)Thomas A. Bannigan

55

Vice President (President, Products Pipelines)Richard T. Bradley

53

Vice President (President, CO2)David D. Kinder

34

Vice President, Corporate Development and TreasurerJoseph Listengart

40

Vice President, General Counsel and SecretaryJames E. Street

52

Vice President, Human Resources and AdministrationRichard
D. Kinder is
Director, Chairman and Chief Executive Officer of KMR, Kinder Morgan G.P., Inc.
and Knight. Mr. Kinder has served as Director, Chairman and Chief Executive
Officer of KMR since its formation in February 2001. He was elected Director,
Chairman and Chief Executive Officer of Knight in October 1999. He was elected
Director, Chairman and Chief Executive Officer of Kinder Morgan G.P., Inc. in
February 1997. Mr. Kinder was elected President of KMR, Kinder Morgan G.P.,
Inc. and Knight in July 2004 and served as President until May 2005. He has
also served as Chief Manager, and as a member of the Board of Managers, of
Knight Holdco LLC since May 2007. Mr. Kinder is the uncle of David Kinder, Vice
President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc.
and Knight.

C.
Park Shaper is
Director and President of KMR, Kinder Morgan G.P., Inc. and Knight. Mr. Shaper
was elected President of KMR, Kinder Morgan G.P., Inc. and Knight in May 2005.
He served as Executive Vice President of KMR, Kinder Morgan G.P., Inc. and
Knight from July 2004 until May 2005. Mr. Shaper was elected Director of KMR
and Kinder Morgan G.P., Inc. in January 2003 and of Knight in May of 2007. He
was elected Vice President, Treasurer and Chief Financial Officer of KMR upon
its formation in February 2001, and served as its Treasurer until January 2004,
and its Chief Financial Officer until May 2005. He was elected Vice President,
Treasurer and Chief Financial Officer of Knight in January 2000, and served as
its Treasurer until January 2004, and its Chief Financial Officer until May 2005.
Mr. Shaper was elected Vice President, Treasurer and Chief Financial Officer of
Kinder Morgan G.P., Inc. in January 2000, and served as its Treasurer until
January 2004 and its Chief Financial Officer until May 2005. He has also served
as President, and as a member of the Board of Managers, of Knight Holdco LLC
since May 2007. He received a Masters of Business Administration degree from
the J.L. Kellogg Graduate School of Management at Northwestern University. Mr.
Shaper also has a Bachelor of Science degree in Industrial Engineering and a
Bachelor of Arts degree in Quantitative Economics from Stanford University. Mr.
Shaper is also a trust manager of Weingarten Realty Investors.

Steven
J. Kean is
Executive Vice President and Chief Operating Officer of KMR, Kinder Morgan
G.P., Inc. and Knight. He is also President, Natural Gas Pipelines of KMR and
Kinder Morgan G.P., Inc. Mr. Kean was elected Executive Vice President and
Chief Operating Officer of KMR, Kinder Morgan G.P., Inc. and Knight in January
2006. He was named President, Natural Gas Pipelines of KMR and Kinder Morgan
G.P., Inc. in July 2008. He served

98

as Executive Vice President, Operations of KMR, Kinder Morgan G.P.,
Inc. and Knight from May 2005 to January 2006. He served as President, Texas
Intrastate Pipeline Group from June 2002 until May 2005. He served as Vice
President of Strategic Planning for the Kinder Morgan Gas Pipeline Group from
January 2002 until June 2002. He has also served as Chief Operating Officer,
and as a member of the Board of Managers, of Knight Holdco LLC since May 2007.
Mr. Kean received his Juris Doctor from the University of Iowa in May 1985 and
received a Bachelor of Arts degree from Iowa State University in May 1982.

Gary
L. Hultquist is a
Director of KMR and Kinder Morgan G.P., Inc. Mr. Hultquist was elected Director
of KMR upon its formation in February 2001. He was elected Director of Kinder
Morgan G.P., Inc. in October 1999. Since 1995, Mr. Hultquist has been the
Managing Director of Hultquist Capital, LLC, a San Francisco-based strategic
and merger advisory firm.

C.
Berdon Lawrence is
a Director of KMR and Kinder Morgan G.P., Inc. Mr. Lawrence was elected
Director of KMR and Kinder Morgan G.P., Inc. in January 2009. Since October
1999, Mr. Lawrence has served Kirby Corporation as Chairman of the Board.
Prior to that, he served for 30 years as President of Hollywood Marine, an
inland tank barge company of which he was the founder. Mr. Lawrence holds an
M.B.A. degree and a B.B.A. degree in business administration
from Tulane University.

Perry
M. Waughtal is a
Director of KMR and Kinder Morgan G.P., Inc. Mr. Waughtal was elected Director
of KMR upon its formation in February 2001. Mr. Waughtal was elected Director
of Kinder Morgan G.P., Inc. in April 2000. Since 1994, Mr. Waughtal has been
the Chairman of Songy Partners Limited, an Atlanta, Georgia based real estate
investment company.

Kimberly
A. Dang is Vice
President and Chief Financial Officer of KMR, Kinder Morgan G.P., Inc. and
Knight. Mrs. Dang was elected Chief Financial Officer of KMR, Kinder Morgan
G.P., Inc. and Knight in May 2005. She served as Treasurer of KMR, Kinder
Morgan G.P., Inc. and Knight from January 2004 to May 2005. She was elected Vice
President, Investor Relations of KMR,
Kinder Morgan G.P., Inc. and Knight in July 2002 and served in that role until
January 2009. From November 2001 to
July 2002, she served as Director, Investor Relations of KMR, Kinder Morgan
G.P., and Knight. She has also served as
Chief Financial Officer of Knight Holdco LLC since May 2007. Mrs. Dang received
a Masters in Business Administration degree from the J.L. Kellogg Graduate
School of Management at Northwestern University and a Bachelor of Business
Administration degree in accounting from Texas A&M University.

Jeffrey
R. Armstrong is
Vice President (President, Terminals) of KMR and Kinder Morgan G.P., Inc. Mr.
Armstrong became Vice President (President, Terminals) in July 2003. He
served as President, Kinder Morgan Liquids Terminals LLC from March 1, 2001,
when the company was formed via the acquisition of GATX Terminals, through July
2003. From 1994 to 2001, Mr. Armstrong worked for GATX Terminals, where he was
General Manager of their East Coast operations. He received his Bachelors
degree from the United States Merchant Marine Academy and an MBA from the
University of Notre Dame.

Thomas
A. Bannigan is
Vice President (President, Products Pipelines) of KMR and Kinder Morgan G.P.,
Inc. and President and Chief Executive Officer of Plantation Pipe Line Company.
Mr. Bannigan was elected Vice President (President, Products Pipelines) of KMR
upon its formation in February 2001. He was elected Vice President (President,
Products Pipelines) of Kinder Morgan G.P., Inc. in October 1999. Mr. Bannigan
has served as President and Chief Executive Officer of Plantation Pipe Line
Company since May 1998. Mr. Bannigan received his Juris Doctor, cum laude, from
Loyola University in 1980 and received a Bachelors degree from the State
University of New York in Buffalo.

Richard
T. Bradley is Vice
President (President, CO2) of KMR and of Kinder Morgan G.P., Inc.
and President of Kinder Morgan CO2 Company, L.P. Mr. Bradley was
elected Vice President (President, CO2) of KMR upon its formation in
February 2001 and Vice President (President, CO2) of Kinder Morgan
G.P., Inc. in April 2000. Mr. Bradley has been President of Kinder Morgan CO2
Company, L.P. (formerly known as Shell CO2 Company, Ltd.) since
March 1998. Mr. Bradley received a Bachelor of Science in Petroleum Engineering
from the University of Missouri at Rolla.

David
D. Kinder is Vice
President, Corporate Development and Treasurer of KMR, Kinder Morgan G.P., Inc.
and Knight. Mr. Kinder was elected Treasurer of KMR, Kinder Morgan G.P., Inc.
and Knight in May 2005. He

99

was elected Vice President, Corporate Development of KMR, Kinder Morgan
G.P., Inc. and Knight in October 2002. He served as manager of
corporate development for Knight and Kinder Morgan G.P., Inc. from January 2000
to October 2002. He has also served as
Treasurer of Knight Holdco LLC since May 2007. Mr. Kinder graduated cum laude
with a Bachelors degree in Finance from Texas Christian University in 1996. Mr.
Kinder is the nephew of Richard D. Kinder.

Joseph
Listengart is Vice
President, General Counsel and Secretary of KMR, Kinder Morgan G.P., Inc. and
Knight. Mr. Listengart was elected Vice President, General Counsel and
Secretary of KMR upon its formation in February 2001. He was elected Vice
President and General Counsel of Kinder Morgan G.P., Inc. and Vice President,
General Counsel and Secretary of Knight in October 1999. Mr. Listengart was
elected Secretary of Kinder Morgan G.P., Inc. in November 1998 and has been an
employee of Kinder Morgan G.P., Inc. since March 1998. He has also served as
General Counsel and Secretary of Knight Holdco LLC since May 2007. Mr.
Listengart received his Masters in Business Administration from Boston
University in January 1995, his Juris Doctor, magna cum laude, from Boston
University in May 1994, and his Bachelor of Arts degree in Economics from
Stanford University in June 1990.

James
E. Street is Vice
President, Human Resources and Administration of KMR, Kinder Morgan G.P., Inc.
and Knight. Mr. Street was elected Vice President, Human Resources and
Administration of KMR upon its formation in February 2001. He was elected Vice
President, Human Resources and Administration of Kinder Morgan G.P., Inc. and
Knight in August 1999. Mr. Street received a Masters of Business Administration
degree from the University of Nebraska at Omaha and a Bachelor of Science
degree from the University of Nebraska at Kearney.

Corporate Governance

We
have a separately designated standing audit committee established in accordance
with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 comprised of
Messrs. Hultquist, Lawrence and Waughtal. Mr. Waughtal is the chairman of the
audit committee and has been determined by the board to be an audit committee
financial expert. The board has determined that all of the members of the
audit committee are independent as described under the relevant standards.

We
have not, nor has our general partner nor KMR, made, within the preceding three
years, contributions to any tax-exempt organization in which any of our or
KMRs independent directors serves as an executive officer that in any single
fiscal year exceeded the greater of $1.0 million or 2% of such tax-exempt
organizations consolidated gross revenues.

On
April 8, 2008, our chief executive officer certified to the New York Stock
Exchange, as required by Section 303A.12(a) of the New York Stock Exchange
Listed Company Manual, that as of April 8, 2008, he was not aware of any
violation by us of the New York Stock Exchanges Corporate Governance listing
standards. We have also filed as an exhibit to this report the Sarbanes-Oxley
Act Section 302 certifications regarding the quality of our public disclosure.

We
make available free of charge within the Investors information section of our
Internet website, at www.kindermorgan.com, and in print to any unitholder who
requests, the governance guidelines, the charters of the audit committee,
compensation committee and nominating and governance committee, and our code of
business conduct and ethics (which applies to senior financial and accounting
officers and the chief executive officer, among others). Requests for copies
may be directed to Investor Relations, Kinder Morgan Energy Partners, L.P., 500
Dallas Street, Suite 1000, Houston, Texas 77002, or telephone (713) 369-9490.
We intend to disclose any amendments to our code of business conduct and ethics
that would otherwise be disclosed on Form 8-K and any waiver from a provision
of that code granted to our executive officers or directors that would
otherwise be disclosed on Form 8-K on our Internet website within four business
days following such amendment or waiver. The information contained on or
connected to our Internet website is not incorporated by reference into this
Form 10-K and should not be considered part of this or any other report that we
file with or furnish to the SEC.

Interested
parties may contact our lead director, the chairpersons of any of the boards
committees, the independent directors as a group or the full board by mail to
Kinder Morgan Management, LLC, 500 Dallas Street,

100

Suite 1000,
Houston, Texas 77002, Attention: General Counsel, or by e-mail within the
Contact Us section of our Internet website, at www.kindermorgan.com. Any
communication should specify the intended recipient.

Section 16(a) Beneficial Ownership Reporting Compliance

Section
16 of the Securities Exchange Act of 1934 requires our directors and officers,
and persons who own more than 10% of a registered class of our equity
securities, to file initial reports of ownership and reports of changes in
ownership with the Securities and Exchange Commission. Such persons are
required by SEC regulation to furnish us with copies of all Section 16(a) forms
they file.

Based
solely on our review of the copies of such forms furnished to us and written
representations from our executive officers and directors, we believe that all
Section 16(a) filing requirements were met during 2008.

Item 11. Executive
Compensation.

As is
commonly the case for publicly traded limited partnerships, we have no
officers. Under our limited partnership agreement, Kinder Morgan G.P., Inc., as
our general partner, is to direct, control and manage all of our activities.
Pursuant to a delegation of control agreement, Kinder Morgan G.P., Inc. has
delegated to KMR the management and control of our business and affairs to the
maximum extent permitted by our partnership agreement and Delaware law, subject
to our general partners right to approve certain actions by KMR. The executive
officers and directors of Kinder Morgan G.P., Inc. serve in the same capacities
for KMR. Certain of those executive officers also serve as executive officers
of Knight, formerly KMI, and of Knight Holdco LLC, Knights privately owned
parent company. Except as indicated otherwise, all information in this report
with respect to compensation of executive officers describes the total
compensation received by those persons in all capacities for
services rendered to us, our subsidiaries and our affiliates, including Knight
and Knight Holdco LLC. In this Item 11,
we, our or us refers to Kinder Morgan Energy Partners, L.P. and, where
appropriate, Kinder Morgan G.P., Inc., KMR and Knight.

Compensation
Discussion and Analysis

Program
Objectives

We
are a publicly traded master limited partnership, and our businesses consist of
a diversified portfolio of energy transportation, storage and production
assets. We seek to attract and retain executives who will help us achieve our
primary business strategy objective of growing the value of our portfolio of
businesses for the benefit of our unitholders. To help accomplish this goal, we have designed an executive compensation
program that rewards individuals with competitive compensation that
consists of a mix of cash, benefit plans and long-term compensation, with a
majority of executive compensation tied to the at risk portions of the annual
cash bonus.

The
key objectives of our executive compensation program are to attract, motivate
and retain executives who will advance our overall business strategies and
objectives to create and return value to our unitholders. We believe that an
effective executive compensation program should link total compensation to
financial performance and to the attainment of short- and long-term strategic,
operational, and financial objectives. We also believe it should provide
competitive total compensation opportunities at a reasonable cost. In designing
our executive compensation program, we have recognized that our executives have
a much greater portion of their overall compensation at-risk than do our other
employees; consequently, we have tried to establish the at-risk portions of our
executive total compensation at levels that recognize their much increased
level of responsibility and their ability to influence business results.

Currently,
our executive compensation program is principally comprised of the following
two elements: (i) base cash salary; and (ii) possible annual cash bonus
(reflected in the Summary Compensation Table below as Non-Equity Incentive Plan
Compensation). Until October 2008, we paid our executive officers
a base salary not to exceed $200,000, which we believe is below annual base
salaries for comparable positions in the marketplace, based upon independent
salary surveys in which we participate. The cap for our executive officers
base salaries was raised to an annual amount not to exceed $300,000. We believe
the base salaries paid to our executive officers

101

continue to be
below the industry average for similarly positioned executives. While not
awarded by us, KMRs compensation committee was aware of the units awarded by
Knight Holdco LLC (as discussed more fully below) and took these awards
into account as components of the total compensation received by our executive
officers.

In
addition, we believe that the compensation of our Chief Executive Officer,
Chief Financial Officer and the executives named below, collectively referred
to in this Item 11 as our named executive officers, should be directly and
materially tied to the financial performance of Knight and us, and should be
aligned with the interests of our unitholders. Therefore, the majority of our
named executive officers compensation is allocated to the at risk portion of
our compensation programthe annual cash bonus. Accordingly, for 2008, our
executive compensation was weighted toward the cash bonus, payable on the basis
of achieving (i) an earnings before interest, taxes, depreciation, depletion
and amortization (referred to as EBITDA) less capital spending target by
Knight; and (ii) a cash distribution per common unit target by us.

We
periodically compare our executive compensation components with market
information. The purpose of this comparison is to ensure that our total
compensation package operates effectively, remains both reasonable and
competitive with the energy industry, and is generally comparable to the
compensation offered by companies of similar size and scope as us. We also keep abreast of current trends,
developments, and emerging issues in executive compensation, and if
appropriate, will obtain advice and assistance from outside legal, compensation
or other advisors.

We
have endeavored to design our executive compensation program and practices with
appropriate consideration of all tax, accounting, legal and regulatory
requirements. Section 162(m) of the
Internal Revenue Code limits the deductibility of certain compensation for our
executive officers to $1,000,000 of compensation per year; however, if
specified conditions are met, certain compensation may be excluded from
consideration of the $1,000,000 limit. Since the bonuses paid to our executive
officers are paid under Knights Annual Incentive Plan as a result of reaching
designated financial targets established by Mr. Richard D. Kinder and KMRs
compensation committees, we expect that all compensation paid to our executives
would qualify for deductibility under federal income tax rules. Though we are
advised that we and private companies, such as Knight, are not subject to
section 162(m), we and Knight have chosen to generally operate as if this code
section does apply to us and Knight as a measure of appropriate governance.

Prior to
2006, long-term equity awards comprised a third element of our executive
compensation program. These awards primarily consisted of grants of restricted
KMI stock and grants of non-qualified options to acquire shares of KMI common
stock, both pursuant to the provisions of KMIs Amended and
Restated 1999 Stock Plan, referred to in this report as the KMI stock plan.
Prior to 2003, we used both KMI stock options and restricted KMI stock as the
principal components of long-term executive compensation, and beginning in 2003, we used grants of restricted stock
exclusively as the principal component of long-term executive compensation. For
each of the years ended December 31, 2007 and 2008, no restricted stock or
options to purchase shares of KMI, units of us or shares of KMR were granted to
any of our named executive officers.

As
a result of the May 2007 going-private transaction, Knight became a wholly
owned subsidiary of Knight Holdco LLC, and in connection with the going-private
transaction, Knight Holdco LLC awarded members of Knights management Class A-1
and Class B units of Knight Holdco LLC. While not awarded by us, KMRs
compensation committee was aware of the units awarded by Knight Holdco LLC and
took these awards into account as components of the total compensation received
by our executive officers in 2007. In accordance with SFAS No. 123R, Knight
Holdco LLC is required to recognize compensation expense in connection with the
Class A-1 and Class B units over the expected life of such units. As a
subsidiary of Knight Holdco LLC, we are, under accounting rules, allocated a
portion of this compensation expense, although none of us or any of our
subsidiaries have any obligation, nor do we expect, to pay any amounts in
respect of such units. The Class A-1 and Class B units awarded to members of
our management may be viewed as a replacement of restricted stock as a
component of long-term executive compensation. For more information concerning
the Knight Holdco LLC units, see Elements of CompensationOther
CompensationKnight Holdco LLC Units below.

102

Behaviors
Designed to Reward

Our
executive compensation program is designed to reward individuals for advancing
our business strategies and the interests of our stakeholders, and we prohibit
engaging in any detrimental activities, such as performing services for a
competitor, disclosing confidential information or violating appropriate
business conduct standards. Each executive is held accountable to uphold and
comply with company guidelines, which require the individual to maintain a discrimination-free
workplace, to comply with orders of regulatory bodies, and to maintain high
standards of operating safety and environmental protection.

Unlike
many companies, we have no executive perquisites, supplemental executive
retirement, non-qualified supplemental defined benefit/contribution, deferred
compensation or split dollar life insurance programs. Additionally, we do not
have employment agreements other than Knight with its Chairman and Chief Executive Officer, Richard D. Kinder,
 special severance agreements or change of control
agreements for our executives. Our executives are eligible for the same
severance policy as our workforce, which caps severance payments to an amount
equal to six months of salary. We have no executive company cars or executive
car allowances nor do we pay for financial planning services. Additionally, we
do not own any corporate aircraft and we do not pay for executives to fly first
class. We believe that we
are currently below competitive levels for comparable companies in this area of
our overall compensation package; however, we have no current plans to change
our policy of not offering such executive benefits, perquisite programs or
special executive severance arrangements.

At his
request, Mr. Richard D. Kinder, our Chairman and Chief Executive Officer,
receives $1 of base salary per year and no other compensation from Knight.
Additionally, Mr. Kinder has requested that he receive no annual bonus,
unit grants, or other compensation from us. Mr. Kinder does not have any
deferred compensation, supplemental retirement or any other special benefit,
compensation or perquisite arrangement with us. Each year, Mr. Kinder
reimburses us for his portion of health care premiums and parking expenses. Mr.
Kinder was awarded Class B units by and in Knight Holdco LLC in connection with
KMIs going-private transaction, and while we are, under accounting rules,
allocated compensation expense attributable to such Class B units, we have no
obligation, nor do we expect, to pay any amounts in connection with the Class B
units.

Elements of
Compensation

As
outlined above, our executive compensation program currently is principally
composed of two elements: (i) a base cash salary; and (ii) a possible
annual cash bonus. Mr. Richard D. Kinder and our compensation committee review
and approve annually the financial goals and objectives of both Knight and us
that are relevant to the compensation of our named executive officers.

Information
is solicited from relevant members of senior management regarding the
performance of our named executive officers and determinations and
recommendations are made at the regularly scheduled first quarter board
and compensation committee meetings. If any of Knights executive officers is also an executive officer of
our general partner or KMR, the compensation determination or recommendation
(i) may be with respect to the aggregate compensation to be received by
such officer from Knight, KMR, and our general partner that is to be allocated
among them, or alternatively (ii) may be with respect to the compensation
to be received by such executive officers from Knight, KMR or our general
partner, as the case may be, in which case such compensation will be allocated
among Knight, on the one hand, and KMR and our general partner, on the other.

Base
Salary

Base
salary is paid in cash. Until October 2008, all of our named executive
officers, with the exception of our Chairman and Chief Executive Officer who
receives $1 of base salary per year as described above, were paid a base salary
of $200,000 per year. The cap for our executive officers base salaries was
raised to an annual amount not to exceed $300,000. Generally, we believe that
our executive officers base salaries are below base salaries for executives in
similar positions and with similar responsibilities at companies of comparable
size and scope, based upon independent salary surveys in which we participate.

103

Possible Annual
Cash Bonus (Non-Equity Cash
Incentive)

Our
possible annual cash bonuses are provided for under Knights Annual Incentive
Plan, which became effective January 18, 2005. The overall purpose of the
Knight Annual Incentive Plan is to increase our executive officers and our
employees personal stake in the continued success of Knight and us by
providing to them additional incentives through the possible payment of annual
cash bonuses. Under the plan, annual cash bonuses are budgeted for at the
beginning of each year and may be paid to our executive officers and other
employees depending on whether Knight and its subsidiaries (including us) meet
certain performance objectives. Assuming the performance objectives are met,
the budgeted pool of bonus dollars is further assessed and potentially
decreased or increased based on Knight and its subsidiaries (including us)
overall performance in a variety of areas, including safety and environmental
goals and regulatory compliance.

Once
the aggregate pool of bonus dollars is determined, further assessment is done
at the business segment level. Each business segments financial performance as
well as its safety and environmental goals and regulatory compliance are
assessed and factored, positively or negatively, into the amount of bonus
dollars allocated to that business segment. The business units safety and
environmental goals and regulatory compliance are assessed against its
performance in these areas in previous years and industry benchmarks. These
assessments as well as individual performance factor into bonus awards at the
business segment level.

Knight
and its subsidiaries (including us) overall performance, including whether it
has met the performance objectives as well as how, on an overall basis, it has
performed with respect to a variety of areas such as safety and environmental
goals and regulatory compliance, negatively or positively, impacts the bonuses
of our named executive officers. Also, with respect to our named executive
officers, individual performance impacts their bonuses. Our named executive
officers have different areas of responsibility that require different skill
sets. Consequently, many of the skills and aspects of performance taken into
account in determining the bonus awards for the respective named executive
officers differ based on their areas of responsibility. However, some skills,
such as working within a budget, are applicable for all of the executive
officers. While no formula is used in assessing individual performance, the
process of assessing the performance of each of the named executive officers is
consistent, with each such officer being assessed relative to the officers
performance of his or her job in preceding years as well as with respect to
specific matters assigned to the officer over the course of the year.
Individual performance, as described above, as well as safety and environmental
goals and regulatory compliance were taken into account with respect to the
2008 awards.

All
of Knights employees and the employees of its subsidiaries, including KMGP
Services Company, Inc., are eligible to participate in the plan, except
employees who are included in a unit of employees covered by a collective
bargaining agreement unless such agreement expressly provides for eligibility
under the plan. However, only eligible employees who are selected by
KMRs compensation committee will actually
participate in the plan and receive bonuses.

The
plan consists of two components: the executive plan component and the
non-executive plan component. Our Chairman and Chief Executive Officer and all
employees who report directly to the Chairman are eligible for the executive
plan component; however, as stated elsewhere in this Compensation Discussion
and Analysis, Mr. Richard D. Kinder, our Chairman and Chief Executive
Officer, has elected to not participate under the plan. As of December 31,
2008, excluding Mr. Richard D. Kinder, ten of our current officers were
eligible to participate in the executive plan component. All other U.S.
eligible employees were eligible for the non-executive plan component.

Following
recommendations and determinations, KMRs
compensation committee establish which of our employees will be eligible to
participate under the executive plan component of the plan. At or before the
start of each calendar year (or later, to the extent allowed under Internal
Revenue Code regulations), performance objectives for that year are identified.
The performance objectives are based on one or more of the criteria set forth
in the plan. A bonus opportunity is established for each executive officer,
which is the bonus the executive officer could earn if the performance
objectives are fully satisfied. A minimum acceptable level of achievement of
each performance objective may be set, below which no bonus is payable with
respect to that objective. Additional levels may be set above the minimum
(which may also be above the targeted performance objective), with a formula to
determine the percentage of the bonus opportunity to be earned at each level of

104

achievement
above the minimum. Performance at a level above the targeted performance
objective may entitle the executive officer to earn a bonus in excess of 100%
of the bonus opportunity. However, the maximum payout to any individual under
the plan for any year is $2.0 million, and KMRs compensation committee
has the discretion to reduce the bonus amounts payable by us in any performance
period.

Performance
objectives may be based on one or more of the following criteria:


 Knights EBITDA
less capital
 spending, or the EBITDA less capital spending of one of its subsidiaries or
 business units; Knights net income
or the net
 income of one of its subsidiaries or business units; Knights revenues
or the revenues
 of one of its subsidiaries or business units; Knights unit
revenues minus unit
 variable costs or the unit revenues minus unit variable costs of one of its
 subsidiaries or business units; Knights return on
capital, return
 on equity, return on assets, or return on invested capital, or the return on
 capital, return on equity, return on assets, or return on invested capital of
 one of its subsidiaries or business units; Knights free
 cash flow, cash flow return on assets
 or cash flows from operating activities, or the cash flow return on assets or
 cash flows from operating activities of one of its subsidiaries or business
 units; Knights capital
expenditures or
 the capital expenditures of one of its subsidiaries or business units; Knights operations
and maintenance
 expense or general and administrative expense, or the operations and
 maintenance expense or general and administrative expense of one of its
 subsidiaries or business units; Knights
debt-equity ratios and key
 profitability ratios, or the debt-equity ratios and key profitability ratios
 of one of its subsidiaries or business units; or KMPs
distribution per unit.Two
financial performance objectives were set for 2008 under both the executive
plan component and the non-executive plan component. The 2008 financial
performance objectives were $4.02 in cash distributions per common unit by us,
and $1,056 million of EBITDA less capital spending by Knight. Our targets
were the same as our previously disclosed 2008 budget expectations. At the end
of 2008 the extent to which the financial performance objectives had been
attained and the extent to which the bonus opportunity had been earned under
the formula previously established by KMRs compensation committee was
determined.

The
2008 bonuses for our executive officers were overwhelmingly based on whether
the established financial performance objectives were met. Other factors, such
as individual over performance or under performance, were considered. With
respect to using these other factors in assessing performance, KMRs
compensation committee did not find it practicable to, and did not, use a
score card, or quantify or assign relative weight to the specific criteria
considered. The amount of a downward or upward adjustment, subject to the
maximum bonus opportunity that was established at the beginning of the year,
was not subject to a formula. Specific aspects of an individuals performance
were not identified in advance. Rather, the adjustment was based on KMRs
compensation committees judgment, giving consideration to the totality of the
record presented, including the individuals performance, and the magnitude of
any positive or negative factors.

The
table below sets forth the bonus opportunities that could be payable by Knight
and us to our executive officers if the performance objectives established for
2008 are 100% achieved. The amount of the portion of the bonus actually paid by
us to any executive officer under the plan may be reduced from the amount of
any bonus opportunity open to such executive officer. Because payments under
the plan for our executive officers are determined by comparing actual
performance to the performance objectives established each year for eligible executive
officers chosen to participate for that year, it is not possible to accurately
predict any amounts that will actually be paid under the executive plan portion
of the plan over the life of the plan. The

105

compensation committee set bonus opportunities under the plan for 2008 for the
executive officers at dollar amounts in excess of that which were expected to
actually be paid under the plan. The actual payout amounts under the Non-Equity
Incentive Plan Awards made in 2008 are set forth in the Summary Compensation
Table in the column entitled Non-Equity Incentive Plan Compensation.

Knight Annual Incentive PlanBonus Opportunities for 2008Name and Principal Position

Dollar ValueRichard D. Kinder, Chairman and
 Chief Executive Officer

$

(1)Kimberly A. Dang, Vice
 President and Chief Financial Officer


1,000,000
(2)Steven J. Kean, Executive Vice
 President and Chief Operating Officer


1,500,000
(3)Joseph Listengart, Vice
 President, General Counsel and Secretary


1,000,000
(2)C. Park Shaper, Director and
 President


1,500,000
(3)(1)
Declined to participate.(2)
Under the plan, for 2008,
 if neither of the targets was met, no bonus opportunities would have been
 provided; if one of the targets was met, $500,000 in bonus opportunities
 would have been available; if both of the targets had been exceeded by 10%,
 $1,500,000 in bonus opportunities would have been available. The KMR
 compensation committee may, in its sole discretion, reduce the award payable
 by us to any participant for any reason.(3)
Under the plan, for 2008,
 if neither of the targets was met, no bonus opportunities would have been
 provided; if one of the targets was met, $750,000 in bonus opportunities
 would have been available; if both of the targets had been exceeded by 10%,
 $2,000,000 in bonus opportunities would have been available. The KMR
 compensation committee may, in its sole discretion, reduce the award payable by
 us to any participant for any reason.Knight
may amend the plan from time to time without shareholder approval except as
required to satisfy the Internal Revenue Code or any applicable securities
exchange rules. Awards may be granted under the plan for calendar year 2009,
unless the plan is terminated earlier by Knight. However, the plan will remain
in effect until payment has been completed with respect to all awards granted
under the plan prior to its termination.

Other
Compensation

Knight
Inc. Savings Plan.
The Knight Inc. Savings Plan is a defined contribution 401(k) plan. The plan
permits all full-time employees of Knight and KMGP Services Company, Inc.,
including the named executive officers, to contribute between 1% and 50% of
base compensation, on a pre-tax basis, into participant accounts. In addition
to a contribution equal to 4% of base compensation per year for most
plan participants, our general partner may make special discretionary
contributions. Certain employees contributions are based on collective
bargaining agreements. The mandatory contributions are made each pay period on
behalf of each eligible employee. Participants may direct the investment of
both their contributions and employer contributions into a variety of
investments at the employees discretion. Plan assets are held and distributed
pursuant to a trust agreement.

Employer
contributions for employees vest on the second anniversary of the date of hire.
For employees of our Terminals business segment hired after October 1, 2005, a
tiered employer contribution schedule applies and all employer contributions
vest on the third anniversary of the date of hire. This tiered schedule
provides for employer contributions of 1% for service less than one year, 2%
for service between one and two years, 3% for service between two and five
years, and 4% for service of five years or more.

In July
2008, Mr. Richard D. Kinder and KMRs compensation committee approved a special
contribution through July 2009 of an additional 1% of base pay into the Savings
Plan for each eligible employee. Each eligible employee will receive an
additional 1% company contribution based on eligible base pay each pay period
beginning with the first pay period of August 2008 and continuing through the
last pay period of July 2009. The additional 1%

106

contribution does not change or otherwise impact the annual 4%
contribution that eligible employees currently receive. It may be converted to
any other Savings Plan investment fund at any time and it will vest according
to the same vesting schedule described in the preceding paragraph. Since this
additional 1% company contribution is discretionary, Mr. Kinders and the KMR
compensation committees approvals will be required annually for each
additional contribution. During the first quarter of 2009, excluding our
portion of the 1% additional contribution described above, we will not make any
additional discretionary contributions to individual accounts for 2008.

Additionally,
in 2006, an option to make after-tax Roth contributions (Roth 401(k) option)
to a separate participant account was added to the Savings Plan as an
additional benefit to all participants. Unlike traditional 401(k) plans, where
participant contributions are made with pre-tax dollars, earnings grow
tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k)
contributions are made with after-tax dollars, earnings are tax-free, and the
withdrawals are tax-free if they occur after both (i) the fifth year of
participation in the Roth 401(k) option, and (ii) attainment of age 59 1/2,
death or disability. The employer contribution will still be considered taxable
income at the time of withdrawal.

Knight
Inc. Cash Balance Retirement Plan. Employees of KMGP Services Company, Inc. and
Knight, including our named executive officers, are also eligible to
participate in a Cash Balance Retirement Plan. Certain employees continue to
accrue benefits through a career-pay formula, grandfathered according to age
and years of service on December 31, 2000, or collective bargaining
arrangements. All other employees accrue benefits through a personal retirement
account in the Cash Balance Retirement Plan. Under the plan, we make
contributions on behalf of participating employees equal to 3% of eligible
compensation every pay period. Interest is credited to the personal retirement
accounts at the 30-year U.S. Treasury bond rate, or an approved substitute, in
effect each year. Employees become fully vested in the plan after five years,
and they may take a lump sum distribution upon termination of employment or
retirement.

The
following table sets forth the estimated actuarial present value of each named
executive officers accumulated pension benefit as of December 31, 2008, under
the provisions of the Cash Balance Retirement Plan. With respect to our named
executive officers, the benefits were computed using the same assumptions used
for financial statement purposes, assuming current remuneration levels without
any salary projection, and assuming participation until normal retirement at
age sixty-five. These benefits are subject to federal and state income taxes,
where applicable, but are not subject to deduction for social security or other
offset amounts.

Pension BenefitsName

Plan Name

Current 
 Credited Yrs
 of Service

Present Value of
 Accumulated
 Benefit(1)

Contributions
 During 2008Richard D. Kinder

Cash Balance


8

$


$
Kimberly A. Dang

Cash Balance


7


39,693


8,285Steven J. Kean

Cash Balance


7


50,479


8,755Joseph Listengart

Cash Balance


8


60,267


9,188C. Park Shaper

Cash Balance


8


60,267


9,188(1)
The
 present values in the Pension Benefits table are based on certain
 assumptions, including a 6.25% discount rate, 5.0% cash balance interest
 crediting rate, and a lump sum calculated using the IRS 2009 Mortality
 Tables. We assumed benefits would commence at normal retirement age, which is
 65. No death or turnover was assumed prior to retirement date.Other
Potential Post-Employment Benefits. On October 7, 1999, Mr. Richard D. Kinder
entered into an employment agreement with Knight pursuant to which he agreed to
serve as its Chairman and Chief Executive Officer. His employment agreement
provides for a term of three years and one year extensions on each anniversary
of October 7th. Mr. Kinder, at his initiative, accepted an annual salary of $1
to demonstrate his belief in our and Knights long term viability. Mr. Kinder
continues to accept an annual salary of $1, and he receives no other
compensation from us. Mr. Kinder was awarded Class B units by and in Knight
Holdco LLC in connection with Knights going-private transaction, and while we,
as a subsidiary of Knight Holdco LLC, are allocated compensation expense
attributable to such Class B units, we have no obligation, nor do we expect, to
pay any amounts in connection with the Class B units.

107

Knight
believes that Mr. Kinders employment agreement contains provisions that are
beneficial to Knight and its subsidiaries and accordingly, Mr. Kinders
employment agreement is extended annually at the request of Knight and KMRs
Board of Directors. For example, with limited exceptions, Mr. Kinder is
prevented from competing in any manner with Knight or any of its subsidiaries,
while he is employed by Knight and for 12 months following the termination
of his employment with Knight. The agreement contains provisions that address
termination with and without cause, termination as a result of change in duties
or disability, and death. At his current compensation level, the maximum amount
that would be paid to Mr. Kinder or his estate in the event of his termination
is three times $750,000, or $2.25 million. This payment would be made if Mr.
Kinder were terminated by Knight without cause or if Mr. Kinder terminated his
employment with Knight as a result of a change in duties (as defined in the
employment agreement). There are no employment agreements or change-in-control
arrangements with any of our other executive officers.

Knight
Holdco LLC Units.In connection with the going-private
transaction, some of our directors and executive officers received Class A-1
and Class B units of Knight Holdco LLC, Knights parent company. None of our
independent directors, Messrs. Hultquist, Lawrence and Waughtal, received
Knight Holdco LLC units. Generally, Knight Holdco LLC has three classes of
unitsClass A units, Class A-1 units, and Class B units.

The
Class B units were awarded by Knight Holdco LLC to members of Knights
management in consideration of their services to or for the benefit of Knight
Holdco LLC. The Class B units represent interests in the profits of Knight
Holdco LLC following the return of capital for the holders of Class A
units and the achievement of predetermined performance targets over time. The
Class B units will performance vest in increments of 5% of profits
distributions up to a maximum of 20% of all profits distributions that would
otherwise be payable with respect to the Class A units and Class A-1
units, based on the achievement of predetermined performance targets. The
Class B units are subject to time based vesting, and with respect to any
holder thereof, will vest 33 1/3% on each of the third, fourth and
fifth year anniversary of the issuance of such Class B units to such
holder. The amended and restated limited liability company agreement of Knight
Holdco LLC also includes provisions with respect to forfeiture of Class B
units upon termination for cause, Knight Holdco LLCs call rights upon
termination and other related provisions relating to an employees tenure. The
allocation of the Class B units among Knights management was determined
prior to closing by Mr. Richard D. Kinder, and approved by other,
non-management investors in Knight Holdco LLC.

The
Class A-1 units were awarded by Knight Holdco LLC to members of
Knights management (other than Mr. Richard D. Kinder) who reinvested their
equity interests in Knight Holdco LLC in connection with the going-private
transaction in consideration of their services to or for the benefit of Knight
Holdco LLC. Class A-1 units entitle a holder thereof to receive
distributions from Knight Holdco LLC in an amount equal to distributions paid
on Class A units (other than distributions on the Class A units that
represent a return of the capital contributed in respect of such Class A
units), but only after the Class A units have received aggregate distributions
in an amount equal to the amount of capital contributed in respect of the
Class A units.

Summary Compensation Table

The
following table shows compensation paid or otherwise awarded to
(i) our principal executive officer; (ii) our principal financial officer; and
(iii) our three most highly compensated executive officers (other than our
principal executive officer and principal financial officer) serving at fiscal
year end 2008 (collectively referred to as the named executive officers) for
services rendered to us, our subsidiaries or our affiliates, including Knight
and Knight Holdco LLC (collectively referred to as the Knight affiliated
entities), during fiscal years 2008, 2007 and 2006. The amounts in the columns
below, except the column entitled Unit Awards by Knight Holdco LLC, represent
the total compensation paid or awarded to the named executive officers by all
the Knight affiliated entities, and as a result the amounts are in excess of
the compensation expense allocated to and recognized by us for services
rendered to us. The amounts in the column entitled Unit Awards by Knight
Holdco LLC consist of accounting expense calculated in accordance with SFAS
No. 123R and allocated to us for the Knight Holdco LLC Class A-1 and Class B
units awarded by Knight Holdco LLC to the named executive officers. As a subsidiary of Knight Holdco LLC, we are
allocated a portion of the compensation expense recognized by Knight Holdco LLC
with respect to such units, although none of us or any of our subsidiaries have
any obligation, nor do we expect, to pay any amounts in respect of such units
and none of the named executive officers has received any payments in respect
of such units.

108

(1)

(2)

(3)

(4)

(5)

(6)Name and
 Principal Position

Year

Salary

Bonus

Stock
 Awards
 by KMI

Option
 Awards
 by KMI

Non-Equity
 Incentive
 Plan
 Compensation

Change
 in Pension
 Value

All Other
 Compensation

Unit Awards
 by Knight
 Holdco
 LLC

TotalRichard D. Kinder

2008

$
1

$


$


$


$


$


$


$
1,741,834

$
1,741,835Director, Chairman and Chief

2007


1




















1,016,000


1,016,001Executive
Officer

2006


1























1Kimberly A. Dang

2008


223,077











440,000


8,285


11,863


126,523


809,748Chief Vice President and

2007


200,000





338,095





400,000


7,294


32,253


73,800


1,051,442Financial
Officer

2006


200,000





139,296


37,023


270,000


6,968


46,253





699,540Steven J. Kean

2008


223,077











1,150,000


8,755


13,007


505,822


1,900,661Executive Vice
President And

2007


200,000





4,397,080





1,100,000


7,767


147,130


295,010


6,146,987Chief Operating
Officer

2006


200,000





1,591,192


147,943





7,422


284,919





2,231,476Joseph Listengart

2008


223,077











900,000


9,188


11,629


316,923


1,460,817Vice President,
General

2007


200,000





847,350





1,000,000


8,194


102,253


184,872


2,342,669Counsel and Secretary

2006


200,000





721,817








7,835


224,753





1,154,405C. Park Shaper

2008


223,077











1,200,000


9,188


12,769


799,236


2,244,270Director and President

2007


200,000





1,950,300





1,200,000


8,194


155,953


466,110


3,980,5572006


200,000





1,134,283


24,952





7,835


348,542





1,715,612(1)
Consists of expense calculated
in accordance
 with SFAS No. 123R attributable to restricted KMI stock awarded in 2003, 2004
 and 2005 according to the provisions of the KMI Stock Plan. No restricted
 stock was awarded in 2008, 2007 or 2006. For grants of restricted stock, we take the
 value of the award at time of grant and accrue the expense over the vesting
 period according to SFAS No. 123R. For grants made July 16, 2003KMI closing
 price was $53.80, twenty-five percent of
 the shares in each grant vest on the third anniversary after the date of
 grant and the remaining seventy-five percent of the shares in each grant vest
 on the fifth anniversary after the date of grant. For grants made July
 20, 2004KMI closing price was $60.79, fifty
 percent of the shares vest on the third anniversary after the date of grant
 and the remaining fifty percent of the shares vest on the fifth anniversary
 after the date of grant. For grants made July 20, 2005KMI closing
 price was $89.48, twenty-five percent of
 the shares in each grant vest on the third anniversary after the date of
 grant and the remaining seventy-five percent of the shares in each grant vest
 on the fifth anniversary after the date of grant. As a result of the KMI
 going-private transaction, all outstanding restricted shares vested in 2007
 and therefore all remaining compensation expense with respect to restricted
 stock was recognized in 2007 in accordance with SFAS No. 123R. However,
 Knight bore all of the costs associated with this acceleration.(2)
Consists of expense calculated
in accordance
 with SFAS No. 123R attributable to options to purchase KMI shares awarded in
 2002 and 2003 according to the provisions of the KMI Stock Plan. No options
 were granted in 2008, 2007 or 2006. For options granted in 2002volatility of
 0.3912 using a 6 year term, 4.01% five year risk free interest rate return,
 and a 0.71% expected annual dividend rate. For options granted in
 2003volatility of 0.3853 using a 6.25 year term, 3.37% treasury strip quote
 at time of grant, and a 2.973% expected annual dividend rate. As a result of
 the KMI going-private transaction, all outstanding options vested in 2007 and
 therefore all remaining compensation expense with respect to options was
 recognized in 2007 in accordance with SFAS No. 123R. As a condition to their
 being permitted to participate in the KMI going-private transaction, Messrs.
 Kean and Shaper agreed to the cancellation of 10,467 and 22,031 options,
 respectively. These cancelled options had weighted average exercise prices of
 $39.12 and $24.75 per share, respectively. However, Knight bore all of the
 costs associated with this acceleration.(3)
Represents amounts paid
according to the
 provisions of the Knight Annual Incentive Plan. Amounts were earned in the
 fiscal year indicated but were paid in the next fiscal year. Messrs. Kean,
 Listengart and Shaper refused to accept a bonus for 2006. The compensation
 committee agreed that this was not a reflection of performance on these
 individuals.(4)
Represents the 2008, 2007 and
2006, as
 applicable, change in the actuarial present value of accumulated defined
 pension benefit (including unvested benefits) according to the provisions of
 Knights Cash Balance Retirement Plan.(5)
Amounts
 include value of contributions to the Knight Savings Plan (a 401(k) plan),
 value of group-term life insurance exceeding $50,000, taxable parking subsidy
 and, for 2006 and 2007 only, dividends paid on unvested restricted stock
 awards. Amounts in 2006 and 2007 include $10,000 and in 2008 include $11,154
 representing the value of contributions to the Knight Savings Plan. Amounts
 representing the value of dividends paid on unvested restricted stock awards
 are as follows: for 2007Mrs. Dang $21,875; Mr. Kean $136,500; Mr. Listengart
 $91,875; and Mr. Shaper $144,375; for 2006Mrs. Dang $35,875; Mr. Kean
 $273,000; Mr. Listengart $214,375; and Mr. Shaper $336,875.109

(6)
Such
 amounts represent the amount of the non-cash compensation expense calculated
 in accordance with SFAS No. 123R attributable to the Class A-1 and Class B
 units of Knight Holdco LLC and allocated to us for financial reporting
 purposes but does not include any such expense allocated to Knight or any of
 its other subsidiaries. None of the named executive officers has received any
 payments in connection with such units, and none of us or our subsidiaries are
 obligated, nor do we expect, to pay any amounts in respect of such units. See
 Elements of CompensationOther
 CompensationKnight Holdco LLC Units above for further discussion
 of these units.Grants of Plan-Based Awards

The
following supplemental compensation table shows compensation
details on the value of all non-guaranteed and non-discretionary incentive
awards granted during 2008 to our named executive officers. The table includes
awards made during or for 2008. The information in the table under the caption
Estimated Future Payments Under Non-Equity Incentive Plan Awards represents
the threshold, target and maximum amounts payable under the Knight Annual
Incentive Plan for performance in 2008. Amounts actually paid under that plan
for 2008 are set forth in the Summary Compensation Table under the caption
Non-Equity Incentive Plan Compensation. There will not be any additional
payouts under the Annual Incentive Plan for 2008.

Estimated Future Payouts Under
 Non-Equity Incentive Plan Awards(1)Name

Threshold

Target

MaximumRichard
 D. Kinder

$


$


$
Kimberly
 A. Dang


500,000


1,000,000


1,500,000Steven
 J. Kean


750,000


1,500,000


2,000,000Joseph
 Listengart


500,000


1,000,000


1,500,000C.
 Park Shaper


750,000


1,500,000


2,000,000(1)
See
 Elements of CompensationPossible Annual Cash Bonus (Non-Equity Cash Incentive)
 above for further discussion of these awards.Outstanding Equity Awards at Fiscal Year-End

The only
unvested equity awards outstanding at the end of fiscal 2008 were the Class B
units of Knight Holdco LLC awarded in 2007 by Knight Holdco LLC
to the named executive officers. As a
subsidiary of Knight Holdco LLC, we are allocated a portion of the compensation
expense recognized by Knight Holdco LLC with respect to such units, although
none of us or any of our subsidiaries have any obligation, nor do we expect, to
pay any amounts in respect of such units.

Stock awardsName

Type of units

Number of units that
 have not vested

Market value of units of
 stock that have not
 vested(1)Richard
 D. Kinder

Class
 B units

791,405,452


N/AKimberly
 A. Dang

Class
 B units

49,462,841


N/ASteven
 J. Kean

Class
 B units

158,281,090


N/AJoseph
 Listengart

Class
 B units

79,140,545


N/AC.
 Park Shaper

Class
 B units

217,636,499


N/A(1)
Because the Class B units are
equity interests
 of Knight Holdco LLC, a private limited liability company, the market value
 of such interests is not readily determinable. None of the named executive
 officers has received any payments in connection with such units, and none of
 us or our subsidiaries are obligated, nor do we expect, to pay any amounts in
 respect of such units. See Item 13. Certain Relationships and Related
 Transactions, and Director IndependenceRelated TransactionsKMI
 Going-Private Transaction for further discussion of these units.110

Director
Compensation

Compensation
Committee Interlocks and Insider Participation. The compensation committee of KMR functions as
our compensation committee. KMRs compensation committee is comprised of Mr.
Gary L. Hultquist, Mr. C. Berdon Lawrence (since January 21, 2009), and Mr.
Perry M. Waughtal (and Mr. Edward O. Gaylord serving until his death on
September 28, 2008). KMRs compensation committee makes compensation decisions
regarding the executive officers of our general partner and its delegate, KMR.
Mr. Richard D. Kinder, Mr. James E. Street, and Messrs. Shaper and Kean, who
are executive officers of KMR, participate in the deliberations of the KMR
compensation committee concerning executive officer compensation. None of the
members of KMRs compensation committee is or has been one of our officers or
employees, and none of our executive officers served during 2008 on a board of
directors of another entity which has employed any of the members of KMRs
compensation committee.

Directors
Fees. Beginning in
2005, awards under our Common Unit Compensation Plan for Non-Employee Directors
(described following) have served as compensation for each of KMRs three
non-employee directors. In addition, directors are reimbursed for reasonable
expenses in connection with board meetings. Directors of KMR who are also
employees of Knight (Messrs. Richard D. Kinder and C. Park Shaper) do not
receive compensation in their capacity as directors.

Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors.On January 18,
2005, KMRs compensation committee established the Kinder Morgan Energy
Partners, L.P. Common Unit Compensation Plan for Non-Employee Directors. The
plan is administered by KMRs compensation committee and KMRs board has sole
discretion to terminate the plan at any time. The primary purpose of this plan
is to promote our interests and the interests of our unitholders by aligning
the compensation of the non-employee members of the board of directors of KMR
with unitholders interests. Further, since KMRs success is dependent on its
operation and management of our business and our resulting performance, the
plan is expected to align the compensation of the non-employee members of the
board with the interests of KMRs shareholders.

The plan
recognizes that the compensation to be paid to each non-employee director is
fixed by the KMR board, generally annually, and that the compensation is
payable in cash. Pursuant to the plan, in lieu of receiving cash compensation,
each non-employee director may elect to receive common units. Each election
will be generally at or around the first board meeting in January of each
calendar year and will be effective for the entire calendar year. The election
for 2007 was made effective January 17, 2007; the election for 2008 was made
effective January 16, 2008; and the election for 2009 was made effective
January 21, 2009 for Messrs. Hultquist and Waughtal, and effective January 28,
2009 for Mr. Lawrence. A non-employee director may make a new election each
calendar year. The total number of common units authorized under this
compensation plan is 100,000.

Each annual
election will be evidenced by an agreement, the Common Unit Compensation
Agreement, between us and each non-employee
director, and this agreement will contain the terms and conditions of each
award. Pursuant to this agreement, all common units issued under this plan are
subject to forfeiture restrictions that expire six months from the date of
issuance. Until the forfeiture restrictions lapse, common units issued under
the plan may not be sold, assigned, transferred, exchanged, or pledged by a
non-employee director. In the event the directors service as a director of KMR
is terminated prior to the lapse of the forfeiture restriction either for
cause, or voluntary resignation, each director will, for no consideration,
forfeit to us all common units to the extent then subject to the forfeiture
restrictions. Common units with respect to which forfeiture restrictions have
lapsed will cease to be subject to any forfeiture restrictions, and we will
provide each director a certificate representing the units as to which the
forfeiture restrictions have lapsed. In addition, each non-employee director
will have the right to receive distributions with respect to the common units
awarded to him under the plan, to vote such common units and to enjoy all other
unitholder rights, including during the period prior to the lapse of the forfeiture
restrictions.

The
number of common units to be issued to a non-employee director electing to
receive the cash compensation in the form of common units will equal the amount
of such cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the
day the cash compensation is awarded (such
price, the fair market value), rounded down to the nearest 50 common
units. The common units will be issuable as specified in the Common Unit
Compensation Agreement. A non-employee director electing to receive the cash
compensation in the form of common units will receive cash equal to the
difference between (i) the cash compensation awarded to

111

such
non-employee director and (ii) the number of common units to be issued to such
non-employee director multiplied by the fair market value of a common unit. This cash payment will be
payable in four equal installments generally around March 31, June 30,
September 30 and December 31 of the calendar year in which such cash
compensation is awarded.

On January
16, 2008, each of KMRs three non-employee directors was awarded cash
compensation of $160,000 for board service during 2008; however, during a plan
audit it was determined that each director was inadvertently paid an additional
dividend in 2007. As a result, each directors cash compensation for service
during 2008 was adjusted downward to reflect this error. The correction results
in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr.
Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal.
Effective January 16, 2008, two of the three non-employee directors elected to
receive certain amounts of that compensation in the form of our common units
and each was issued common units pursuant to the plan and its agreements (based
on the $55.81 closing market price of our common units on January 16, 2008, as
reported on the New York Stock Exchange). Mr. Gaylord elected to receive
compensation of $84,831.20 in the form of our common units and was issued 1,520
common units; and Mr. Waughtal elected to receive compensation of $157,272.58
in the form of our common units and was issued 2,818 common units. All
remaining compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal; and
$158,380.00 to Mr. Hultquist) was paid in cash to each of the non-employee
directors as described above, and no other compensation was paid to the
non-employee directors during 2008.

On January
21, 2009, each of KMRs three non-employee directors (with Mr. Lawrence
replacing Mr. Gaylord) was awarded cash compensation of $160,000 for board
service during 2009. Effective January 21, 2009, Mr. Hultquist and Mr. Waughtal
elected to receive the full amount of their compensation in the form of cash
only. Effective January 28, 2009, Mr. Lawrence elected to receive compensation
of $159,136.00 in the form of our common units and was issued 3,200 common
units. His remaining compensation ($864.00) will be paid in cash as described
above. No other compensation will be paid to the non-employee directors during
2009.

Directors
Unit Appreciation Rights Plan.On April 1, 2003, KMRs compensation committee established our Directors
Unit Appreciation Rights Plan. Pursuant to this plan, each of KMRs three
non-employee directors was eligible to receive common unit appreciation rights.
Upon the exercise of unit appreciation rights, we will pay, within thirty days
of the exercise date, the participant an amount of cash equal to the excess, if
any, of the aggregate fair market value of the unit appreciation rights
exercised as of the exercise date over the aggregate award price of the rights
exercised. The fair market value of one unit appreciation right as of the
exercise date will be equal to the closing price of one common unit on the New
York Stock Exchange on that date. The award price of one unit appreciation
right will be equal to the closing price of one common unit on the New York
Stock Exchange on the date of grant. Proceeds, if any, from the exercise of a
unit appreciation right granted under the plan will be payable only in cash
(that is, no exercise will result in the issuance of additional common units)
and will be evidenced by a unit appreciation rights agreement.

All unit appreciation
rights granted vest on the six-month anniversary of the date of grant. If a
unit appreciation right is not exercised in the ten year period following the
date of grant, the unit appreciation right will expire and not be exercisable
after the end of such period. In addition, if a participant ceases to serve on
the board for any reason prior to the vesting date of a unit appreciation
right, such unit appreciation right will immediately expire on the date of
cessation of service and may not be exercised.

On April 1,
2003, the date of adoption of the plan, each of KMRs then three non-employee
directors was granted 7,500 unit appreciation rights. In addition, 10,000 unit
appreciation rights were granted to each of KMRs then three non-employee
directors on January 21, 2004, at the first meeting of the board in 2004.
During the first board meeting of 2005, the plan was terminated and replaced by
the Kinder Morgan Energy Partners, L.P. Common Unit Compensation Plan for
Non-Employee Directors; however, all unexercised awards made under the plan
remain outstanding. No unit appreciation rights were exercised during 2006. In
2007, Mr. Hultquist exercised 7,500 unit appreciation rights and received a
cash amount of $116,250. In 2008, Mr. Hultquist exercised his remaining 10,000
unit appreciation rights and received a cash amount of $123,100. As of December
31, 2008, 35,000 unit appreciation rights had been granted, vested and remained
outstanding.

112

The
following table discloses the compensation earned by each of KMRs three
non-employee directors for board service during fiscal year 2008. In addition, directors are reimbursed for
reasonable expenses in connection with board meetings. Directors of KMR who are
also employees of Knight do not receive compensation in their capacity as
directors.

Name

Fees Earned or
 Paid in Cash

Common Unit
 Awards(1)

All Other
 Compensation(2)

TotalEdward O. Gaylord

$
73,565

$
84,831

$
2,858

$
161,254Gary L. Hultquist


158,380








158,380Perry M. Waughtal


54


157,273


5,298


162,625(1)
Represents the value of cash
compensation
 received in the form of our common units according to the provisions of our
 Common Unit Compensation Plan for Non-Employee Directors. Value computed as
 the number of common units elected to be received in lieu of cash times the
 closing price on date of election. For Mr. Gaylord, 1,520 units elected on
 January 16, 2008 times the closing price of $55.81, and for Mr. Waughtal,
 2,818 units elected times the closing price of $55.81.(2)
For each, represents (i) the
unrealized value of
 common unit appreciation rights earned according to the provisions of our
 Directors Unit Appreciation Rights Plan for Non-Employee Directors, determined according to the provisions of
 SFAS No. 123Rfor each common unit appreciation right, equal to the increase
 in value of a corresponding common unit from December 31, 2007 to December
 31, 2008; and (ii) distributions paid on
 unvested common units awarded according to the provisions of our Common Unit
 Compensation Plan for Non-Employee Directors.For
 Mr. Gaylord and Mr. Waughtal, represents $2,858 and $5,298, respectively, for
 distributions paid on unvested common units awarded according to the
 provisions of our Common Unit Compensation Plan for Non-Employee Directors. For
 each, during 2008, no unrealized value of common unit appreciation rights was
 earned due to the decrease in common unit closing price from December 31,
 2007 to December 31, 2008 (equal to $53.99 at December 31, 2007 and $45.75 at
 December 31, 2008). As described above, in 2008, Mr. Hultquist exercised his
 remaining 10,000 unit appreciation rights and received a cash amount of
 $123,100.Compensation
Committee Report

Throughout
fiscal 2008, the compensation
committee of KMRs board of directors was comprised of two directors (Mr. Gary
L. Hultquist and Mr. Perry M. Waughtal), and up to the time of his death on
September 28, 2008, a third director (Mr. Edward O. Gaylord), each of whom the
KMR board of directors has determined meets (or met) the criteria for
independence under KMRs governance guidelines and the New York Stock Exchange
rules.

The KMR compensation committee has discussed and reviewed the above
Compensation Discussion and Analysis for fiscal year 2008 with management.
Based on this review and discussion, the KMR compensation committee recommended
to its board of directors, that this Compensation Discussion and Analysis be
included in this annual report on Form 10-K for the fiscal year 2008.

KMR Compensation Committee:Gary L. Hultquist
Perry M. Waughtal

Item 12. Security Ownership of Certain Beneficial Owners
and
Management and Related Stockholder Matters.

The
following tables set forth information as of January 31, 2009, regarding (i)
the beneficial ownership of (a) our common and Class B units, (b) KMR shares
and (c) Knight Holdco LLC units by all directors of our general partner and
KMR, its delegate, by each of the named executive officers identified in Item
11 Executive Compensation and by all directors and executive officers as a
group; and (ii) the beneficial ownership of our common and Class B units and
KMR shares by all persons known by our general partner to own beneficially at
least 5% of such units or shares. Unless otherwise noted, the address of each
person below is c/o Kinder Morgan Energy Partners, L.P., 500 Dallas Street,
Suite 1000, Houston, Texas 77002.

113

Amount and Nature of Beneficial Ownership(1)

Common Units

Class B Units

Kinder Morgan
 Management SharesNumber
 of Units(2)

Percent
 of Class

Number
 of Units(3)

Percent
 of Class

Number of
 Shares(4)

Percent
 of ClassRichard D. Kinder(5)


315,979


*








111,782


*C. Park Shaper


4,000


*








25,618


*Gary L. Hultquist


7,500


*











C. Berdon Lawrence(6)


3,200


*











Perry M. Waughtal


46,918


*








49,726


*Steven J. Kean

















Joseph Listengart


4,198


*











Kimberly A. Dang


121


*








473


*Directors and Executive Officers
as a group(13
 persons)(7)


395,195


*








209,873


*Knight Inc.(8)


16,370,428


8.94
%

5,313,400


100.00
%

11,128,825


14.27
%Kayne Anderson Capital
Advisors, L.P. and Richard
 A. Kayne(9)














6,210,408


7.96
%Janus Capital
 Management LLC(10)














5,855,967


7.55
%*
Less than 1%.(1)
Except
 as noted otherwise, each beneficial owner has sole voting power and sole
 investment power over the units and shares listed. On January 18, 2005, KMRs board of
 directors initiated a rule requiring each director to own a minimum of 10,000
 common units, KMR shares, or a combination thereof by the end of the fifth
 calendar year following the later to occur of (i) January 18, 2005 or (ii) the
 election date of the director to KMR's board.(2)
As of
 January 31, 2009, we had 183,169,827 common units issued and outstanding.(3)
As of
 January 31, 2009, we had 5,313,400 Class B units issued and outstanding.(4)
Represent
 the limited liability company shares of KMR. As of January 31, 2009, there
 were 77,997,906 issued and outstanding KMR shares, including two voting
 shares owned by our general partner. In all cases, our i-units will be voted
 in proportion to the affirmative and negative votes, abstentions and
 non-votes of owners of KMR shares. Through the provisions in our partnership
 agreement and KMRs limited liability company agreement, the number of
 outstanding KMR shares, including voting shares owned by our general partner,
 and the number of our i-units will at all times be equal.(5)
Includes
 7,879 common units owned by Mr. Kinders spouse. Mr. Kinder disclaims any and
 all beneficial or pecuniary interest in these units.(6)
Includes
 3,200 restricted common units.(7)
Includes
 3,200 restricted common units. Also includes 719 KMR shares purchased by one
 of our executives for his children. The executive disclaims any beneficial
 ownership in such KMR shares.(8)
Includes
 common units owned by Knight Inc. and its consolidated subsidiaries,
 including 1,724,000 common units owned by Kinder Morgan G.P., Inc.(9)
As
 reported on the Schedule 13G/A filed February 13, 2009 by Kayne Anderson
 Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors,
 L.P. reported that in regard to KMR shares, it had sole voting power over 0
 shares, shared voting power over 6,207,400 shares, sole disposition power over
 0 shares and shared disposition power over 6,207,400 shares. Mr. Kayne
 reports that in regard to KMR shares, he had sole voting power over 3,008
 shares, shared voting power over 6,207,400 shares, sole disposition power
 over 3,008 shares and shared disposition power over 6,207,400 shares. Kayne
 Anderson Capital Advisors, L.P.s and Richard A. Kaynes address is 1800
 Avenue of the Stars, Second Floor, Los Angeles, California 90067.(10)
As
reported on the Schedule 13G/A filed February 17, 2009 by Janus Capital Mangement LLC.  Janus Capital
Management reported that in regard to KMR shares, it has sole voting power over 5,844,967 shares, shared
voting power over 11,000 shares, sole disposition power over 5,844,967 and shared disposition power over
11,000 shares.  Janus Capital Management LLCs address is 151 Detroit Street, Denver, Colorado, 80206.114

Amount and Nature of Beneficial Ownership(1)

Knight
 Holdco
 LLC Class A
 Units

% of
 Class A
 Units(2)

Knight
 Holdco LLC
 Class A-1
 Units

% of
 Class A-1
 Units(3)

Knight
 Holdco
 LLC Class B
 Units

% of
 Class B
 Units(4)Richard D. Kinder(5)


2,424,000,000


30.6
%







791,405,452


40.0
%C. Park Shaper(6)


13,598,785


*


7,799,775


28.3
%

217,636,499


11.0
%Gary L. Hultquist

















C. Berdon Lawrence

















Perry M. Waughtal

















Steven J. Kean


6,684,149


*


3,833,788


13.9
%

158,281,090


8.0
%Joseph Listengart


6,059,449


*


3,475,483


12.6
%

79,140,545


4.0
%Kimberly A. Dang(7)


750,032


*


430,191


1.6
%

49,462,841


2.5
%Directors and Executive Officers
as a group (13 persons)


2,460,763,539


31.1
%

21,086,247


76.5
%

1,626,338,205


82.2
%*
Less than 1%.(1)
Except
 as noted otherwise, each beneficial owner has sole voting power and sole
 investment power over the units listed.(2)
As of
 January 31, 2009, Knight Holdco LLC had 7,914,367,913 Class A Units issued
 and outstanding.(3)
As of
 January 31, 2009, Knight Holdco LLC had 27,225,694 Class A-1 Units issued and
 outstanding and 345,042 phantom Class A-1 Units issued and outstanding. The
 phantom Class A-1 Units were issued to Canadian management employees.(4)
As of
 January 31, 2009, Knight Holdco LLC had 1,927,566,908 Class B Units issued
 and outstanding and 50,946,724 phantom Class B Units issued and outstanding.
 The phantom Class B Units were issued to Canadian management employees.(5)
Includes 522,372 Class A
 units owned by Mr. Kinders wife. Mr. Kinder disclaims any and all beneficial
 or pecuniary interest in the Class A units held by his wife. Also includes 263,801,817 Class B Units that
 Mr. Kinder transferred to a limited partnership. Mr. Kinder may be deemed to
 be the beneficial owner of these transferred Class B Units, because Mr.
 Kinder controls the voting and disposition power of these Class B Units, but
 he disclaims ninety-nine percent of any beneficial and pecuniary interest in
 them.(6)
Includes
 217,636,499 Class B Units that Mr. Shaper transferred to a limited
 partnership. Mr. Shaper may be deemed to be the beneficial owner of these
 transferred Class B Units, because Mr. Shaper controls the voting and
 disposition power of these Class B Units, but he disclaims approximately
 twenty-two percent of any beneficial and pecuniary interest in them.(7)
Includes
 49,462,841 Class B Units that Ms. Dang transferred to a limited partnership.
 Ms. Dang may be deemed to be the beneficial owner of these transferred Class
 B Units, because Ms. Dang has voting and disposition power of these Class B
 Units, but she disclaims ten percent of any beneficial and pecuniary interest
 in them.Equity
Compensation Plan Information

The
following table sets forth information regarding our equity compensation plans as
of December 31, 2008. Specifically, the table provides information regarding
our Common Unit Compensation Plan for Non-Employee Directors, described in Item
11 Executive CompensationDirector CompensationKinder Morgan Energy Partners,
L.P. Common Unit Compensation Plan for Non-Employee Directors, and Note 13 of
the notes to our consolidated financial statements included elsewhere in this report.

Plan category

Number of securities
 remaining available for
 future issuance under equity
 compensation plansEquity compensation plans
 Approved by security holders

Equity compensation plans not
 approved by security holders

77,882Total

77,882115

Item 13. Certain Relationships and Related Transactions,
and
Director Independence.

Related
Transactions

Transactions
with Kirby Corporation

The
recently elected director of the boards of our general partner and KMR, Mr. C.
Berdon Lawrence, is Chairman of the Board of Kirby Corporation. In addition,
Mr. Lawrences son was a vice president of a subsidiary of Kirby Corporation
during part of 2008. In 2008, Kirby Corporation received payments from our
subsidiaries totaling $430,835 and made payments to our subsidiaries totaling
$144,300 for services in the ordinary course of Kirby Corporations and our
Terminals segments businesses.

Other

Our policy
is that (i) employees must obtain authorization from the appropriate business
unit president of the relevant company or head of corporate function, and (ii)
directors, business unit presidents, executive officers and heads of corporate
functions must obtain authorization from the non-interested members of the
audit committee of the applicable board of directors, for any business
relationship or proposed business transaction in which they or an immediate
family member has a direct or indirect interest, or from which they or an
immediate family member may derive a personal benefit (a related party
transaction). The maximum dollar amount of related party transactions that may
be approved as described above in this paragraph in any calendar year is $1.0
million. Any related party transactions that would bring the total value of such
transactions to greater than $1.0 million must be referred to the audit
committee of the appropriate board of directors for approval or to determine
the procedure for approval.

For
information regarding other related transactions, see Note 12 of
the notes to our consolidated financial statements included elsewhere in this
report.

Director
Independence

Our
limited partnership agreement provides for us to have a general partner rather
than a board of directors. Pursuant to a
delegation of control agreement, our general partner delegated to KMR, to the
fullest extent permitted under Delaware law and our partnership agreement, all
of its power and authority to manage and control our business and affairs,
except that KMR cannot take certain specified actions without the approval of
our general partner. Through the operation of that agreement and our
partnership agreement, KMR manages and controls our business and affairs, and
the board of directors of KMR performs the functions of and acts as our board
of directors. Similarly, the standing committees of KMRs board of directors
function as standing committees of our board. KMRs board of directors is comprised of the same persons who comprise
our general partners board of directors. References in this report to
the board mean KMRs board, acting as our board of directors, and references to
committees mean KMRs committees, acting as committees of our board of
directors.

The
board has adopted governance guidelines for the board and charters for the
audit committee, nominating and governance committee and compensation
committee. The governance guidelines and the rules of the New York Stock
Exchange require that a majority of the directors be independent, as described
in those guidelines, the committee charters and rules, respectively. Copies of
the guidelines and committee charters are available on our internet website at
www.kindermorgan.com. To assist in making determinations of independence, the
board has determined that the following categories of relationships are not
material relationships that would cause the affected director not to be
independent:

 if the director was an
employee, or
 had an immediate family member who was an executive officer, of KMR or us or
 any of its or our affiliates, but the employment relationship ended more than
 three years prior to the date of determination (or, in the case of employment
 of a director as an interim chairman, interim chief executive officer or
 interim executive officer, such employment relationship ended by the date of
 determination); if during any twelve
month period
 within the three years prior to the determination the director received no
 more than, and has no immediate family member that received more than,
 $100,000 in direct compensation116

from us or our affiliates, other than
(i) director and committee
 fees and pension or other forms of deferred compensation for prior service
 (provided such compensation is not contingent in any way on continued
 service); (ii) compensation received by a director for former service as
 an interim chairman, interim chief executive officer or interim executive
 officer; and (iii) compensation received by an immediate family member
 for service as an employee (other than an executive officer); if the director is at
the date of
 determination a current employee, or has an immediate family member that is
 at the date of determination a current executive officer, of another company
 that has made payments to, or received payments from, us and our affiliates
 for property or services in an amount which, in each of the three fiscal
 years prior to the date of determination, was less than the greater of $1.0
 million or 2% of such other companys annual consolidated gross revenues.
 Contributions to tax-exempt organizations are not considered payments for
 purposes of this determination; if the director is also
a director,
 but is not an employee or executive officer, of our general partner or
 another affiliate or affiliates of KMR or us, so long as such director is
 otherwise independent; and if the director
beneficially owns
 less than 10% of each class of voting securities of us, our general partner,
 or KMR.The
board has affirmatively determined that Messrs. Hultquist, Lawrence and
Waughtal, who constitute a majority of the directors, are independent as
described in our governance guidelines and the New York Stock Exchange rules.
Each of them meets the standards above and has no other relationship with us.
In conjunction with all regular quarterly and certain special board meetings,
these three non-management directors also meet in executive session without
members of management. In January 2009, Mr. Hultquist was elected for a one
year term to serve as lead director to develop the agendas for and preside at
these executive sessions of independent directors.

The
governance guidelines and our audit committee charter, as well as the rules of
the New York Stock Exchange and the Securities and Exchange Commission, require
that members of the audit committee satisfy independence requirements in
addition to those above. The board has determined that all of the members of
the audit committee are independent as described under the relevant standards.

Item 14. Principal Accounting Fees and Services

The
following sets forth fees billed for the audit and other services provided by
PricewaterhouseCoopers LLP for the fiscal years ended December 31, 2008 and
2007 (in dollars):

Year Ended December 31,2008

2007Audit fees(1)

$
2,409,571

$
2,070,205Tax fees(2)


2,144,808


2,563,793Total

$
4,554,379

$
4,633,998(1)
Includes
 fees for integrated audit of annual financial statements and internal control
 over financial reporting, reviews of the related quarterly financial
 statements, and reviews of documents filed with the Securities and Exchange
 Commission.(2)
For 2008 and 2007, amounts include fees of $1,679,358
 and $2,352,533, respectively, billed for professional services rendered for
 tax processing and preparation of Forms K-1 for our unitholders. Amounts also
 include fees of $465,450 and $211,260, respectively, billed for professional
 services rendered for tax return review services and for general state, local
 and foreign tax compliance and consulting services.All
services rendered by PricewaterhouseCoopers LLP are permissible under
applicable laws and regulations, and were pre-approved by the audit committee of KMR and our general partner.
Pursuant to the charter of the audit
committee of KMR, the delegate of our general partner, the committees primary
purposes include the following: (i) to select, appoint, engage, oversee,
retain, evaluate and terminate our external auditors; (ii) to pre-approve all
audit and non-audit services, including tax services, to be provided, consistent
with all applicable laws, to us by our external auditors; and (iii) to
establish the fees and other compensation to be paid to our external auditors. The
audit

117

committee has
reviewed the external auditors fees for audit and non audit services for
fiscal year 2008. The audit committee has also considered whether such non
audit services are compatible with maintaining the external auditors
independence and has concluded that they are compatible at this time.

Furthermore,
the audit committee will review the external auditors proposed audit scope and
approach as well as the performance of the external auditors. It also has
direct responsibility for and sole authority to resolve any disagreements
between our management and our external auditors regarding financial reporting,
will regularly review with the external auditors any problems or difficulties
the auditors encountered in the course of their audit work, and will, at least
annually, use its reasonable efforts to obtain and review a report from the
external auditors addressing the following (among other items): (i) the
auditors internal quality-control procedures; (ii) any material issues raised
by the most recent internal quality-control review, or peer review, of the
external auditors; (iii) the independence of the external auditors; and (iv)
the aggregate fees billed by our external auditors for each of the previous two
fiscal years.

118

PART IV

Item 15. Exhibits and
Financial Statement Schedules

(a)(1) and
(2) Financial
Statements and Financial Statement Schedules

See Index
to Financial Statements set forth on page 124.

(a)(3)
Exhibits

*3.1 
Third Amended
 and Restated Agreement of Limited Partnership of Kinder Morgan Energy
 Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan Energy Partners, L.P.
 Form 10-Q (File No. 1-11234) for the quarter ended June 30, 2001, filed on
 August 9, 2001).*3.2 
Amendment
 No. 1 dated November 19, 2004 to Third Amended and Restated Agreement of
 Limited Partnership of Kinder Morgan Energy Partners, L.P. (filed as Exhibit
 99.1 to Kinder Morgan Energy Partners, L.P. Form 8-K, filed November 22,
 2004).*3.3 
Amendment
 No. 2 to Third Amended and Restated Agreement of Limited Partnership of
 Kinder Morgan Energy Partners, L.P. (filed as Exhibit 99.1 to Kinder Morgan
 Energy Partners, L.P. Form 8-K, filed May 5, 2005).*3.4 
Amendment
 No. 3 to Third Amended and Restated Agreement of Limited Partnership of
 Kinder Morgan Energy Partners, L.P. (filed as Exhibit 3.1 to Kinder Morgan
 Energy Partners, L.P. Form 8-K, filed April 21, 2008).*4.1 
Specimen
 Certificate evidencing Common Units representing Limited Partner Interests
 (filed as Exhibit 4.1 to Amendment No. 1 to Kinder Morgan Energy Partners,
 L.P. Registration Statement on Form S-4, File No. 333-44519, filed on
 February 4, 1998).*4.2 
Indenture
 dated as of January 29, 1999 among Kinder Morgan Energy Partners, L.P., the
 guarantors listed on the signature page thereto and U.S. Trust Company of
 Texas, N.A., as trustee, relating to Senior Debt Securities (filed as Exhibit
 4.1 to the Partnerships Current Report on Form 8-K filed February 16, 1999,
 File No. 1-11234 (the February 16, 1999 Form 8-K)).*4.3 
First
 Supplemental Indenture dated as of January 29, 1999 among Kinder Morgan
 Energy Partners, L.P., the subsidiary guarantors listed on the signature page
 thereto and U.S. Trust Company of Texas, N.A., as trustee, relating to
 $250,000,000 of 6.30% Senior Notes due February 1, 2009 (filed as Exhibit 4.2
 to the February 16, 1999 Form 8-K (File No. 1-11234)).*4.4 
Second
 Supplemental Indenture dated as of September 30, 1999 among Kinder Morgan
 Energy Partners, L.P. and U.S. Trust Company of Texas, N.A., as trustee,
 relating to release of subsidiary guarantors under the $250,000,000 of 6.30%
 Senior Notes due February 1, 2009 (filed as Exhibit 4.4 to the Partnerships
 Form 10-Q (File No. 1-11234) for the quarter ended September 30, 1999.*4.5 
Indenture
 dated November 8, 2000 between Kinder Morgan Energy Partners, L.P. and First
 Union National Bank, as Trustee (filed as Exhibit 4.8 to Kinder Morgan Energy
 Partners, L.P. Form 10-K for 2001 (File No. 1-11234)).*4.6 
Form of
 7.50% Notes due November 1, 2010 (contained in the Indenture filed as Exhibit
 4.8 to the Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234)
 for 2001).*4.7 
Indenture
 dated January 2, 2001 between Kinder Morgan Energy Partners and First Union
 National Bank, as trustee, relating to Senior Debt Securities (including form
 of Senior Debt Securities) (filed as Exhibit 4.11 to Kinder Morgan Energy
 Partners, L.P. Form 10-K (File No. 1-11234) for 2000).*4.8 
Indenture
 dated January 2, 2001 between Kinder Morgan Energy Partners and First Union
 National Bank, as trustee, relating to Subordinated Debt Securities
 (including form of Subordinated Debt Securities) (filed as Exhibit 4.12 to
 Kinder Morgan Energy Partners, L.P. Form 10-K (File No. 1-11234) for 2000).*4.9 
Certificate
 of Vice President and Chief Financial Officer of Kinder Morgan Energy
 Partners, L.P. establishing the terms of the 6.75% Notes due March 15, 2011
 and the 7.40% Notes due March 15, 2031 (filed as Exhibit 4.1 to Kinder Morgan
 Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on March 14, 2001).*4.10 
Specimen of
 6.75% Notes due March 15, 2011 in book-entry form (filed as Exhibit 4.2 to
 Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on
 March 14, 2001).119

*4.11 
Specimen of
 7.40% Notes due March 15, 2031 in book-entry form (filed as Exhibit 4.3 to
 Kinder Morgan Energy Partners, L.P. Form 8-K (File No. 1-11234), filed on
 March 14, 2001).*4.12 
Certificate
 of Vice President and Chief Financial Officer of Kinder Morgan Energy
 Partners, L.P. establishing the terms of the 7.125% Notes due March 15, 2012
 and the 7.750% Notes due March 15, 2032 (filed as Exhibit 4.1 to Kinder
 Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the quarter
 ended March 31, 2002, filed on May 10, 2002).*4.13 
Specimen of
 7.125% Notes due March 15, 2012 in book-entry form (filed as Exhibit 4.2 to
 Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the
 quarter ended March 31, 2002, filed on May 10, 2002).*4.14 
Specimen of
 7.750% Notes due March 15, 2032 in book-entry form (filed as Exhibit 4.3 to
 Kinder Morgan Energy Partners, L.P. Form 10-Q (File No. 1-11234) for the
 quarter ended March 31, 2002, filed on May 10, 2002).*4.15 
Indenture
 dated August 19, 2002 between Kinder Morgan Energy Partners, L.P. and
 Wachovia Bank, National Association, as Trustee (filed as Exhibit 4.1 to the
 Kinder Morgan Energy Partners, L.P. Registration Statement on Form S-4 (File
 No. 333-100346) filed on October 4, 2002 (the October 4, 2002 Form S-4)).*4.16 
First
 Supplemental Indenture to Indenture dated August 19, 2002, dated August 23,
 2002 between Kinder Morgan Energy Partners, L.P. and Wachovia Bank, National
 Association, as Trustee (filed as Exhibit 4.2 to the October 4, 2002 Form
 S-4).*4.17 
Form of
 7.30% Note (contained in the Indenture filed as Exhibit 4.1 to the October 4,
 2002 Form S-4).*4.18 
Senior
 Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P.
 and Wachovia Bank, National Association (filed as Exhibit 4.2 to the Kinder
 Morgan Energy Partners, L.P. Registration Statement on Form S-3 (File No.
 333-102961) filed on February 4, 2003 (the February 4, 2003 Form S-3)).*4.19 
Form of
 Senior Note of Kinder Morgan Energy Partners, L.P. (included in the Form of
 Senior Indenture filed as Exhibit 4.2 to the February 4, 2003 Form S-3).*4.20 
Subordinated
 Indenture dated January 31, 2003 between Kinder Morgan Energy Partners, L.P.
 and Wachovia Bank, National Association (filed as Exhibit 4.4 to the February
 4, 2003 Form S-3).*4.21 
Form of
 Subordinated Note of Kinder Morgan Energy Partners, L.P. (included in the
 Form of Subordinated Indenture filed as Exhibit 4.4 to the February 4, 2003
 Form S-3).*4.22 
Certificate
 of Vice President, Treasurer and Chief Financial Officer and Vice President,
 General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder
 Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.
 establishing the terms of the 5.00% Notes due December 15, 2013 (filed as
 Exhibit 4.25 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2003 filed March
 5, 2004).*4.23 
Certificate
 of Executive Vice President and Chief Financial Officer and Vice President,
 General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder
 Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.
 establishing the terms of the 5.125% Notes due November 15, 2014 (filed as
 Exhibit 4.27 to Kinder Morgan Energy Partners, L.P. Form 10-K for 2004 filed
 March 4, 2005).*4.24 
Certificate
 of Vice President, Treasurer and Chief Financial Officer and Vice President,
 General Counsel and Secretary of Kinder Morgan Management, LLC and Kinder
 Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners, L.P.
 establishing the terms of the 5.80% Notes due March 15, 2035 (filed as
 Exhibit 4.1 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the quarter
 ended March 31, 2005, filed on May 6, 2005).*4.25 
Certificate
 of Vice President and Chief Financial Officer of Kinder Morgan Management,
 LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners,
 L.P. establishing the terms of the 6.00% Senior Notes due 2017 and 6.50%
 Senior Notes due 2037 (filed as Exhibit 4.28 to Kinder Morgan Energy
 Partners, L.P. Form 10-K for 2006 filed March 1, 2007).*4.26 
Certificate of the Vice President and
 Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan
 Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan Energy Partners,
 L.P., establishing the terms of the 6.95% Senior Notes due 2038 (filed
 as Exhibit 4.2 to Kinder Morgan Energy Partners, L.P. Form 10-Q for the
 quarter ended June 30, 2007 filed August 8, 2007).*4.27 
Certificate of the Vice President and
 Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan
 Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
 Energy Partners, L.P., establishing the terms of the 5.85% Senior Notes due
 2012 (filed as Exhibit 4.2 to Kinder Morgan Energy Partners,
 L.P. Form 10-Q for the quarter ended September 30, 2007 filed November 9,
 2007).120

*4.28 
Certificate of the Vice President and
 Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan
 Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
 Energy Partners, L.P., establishing the terms of the 5.95% Senior Notes due
 2018 (filed as Exhibit 4.28 to Kinder Morgan Energy Partners,
 L.P. Form 10-K for 2007 filed February 26, 2008).4.29 
Certificate of the Vice President and
 Treasurer and the Vice President and Chief Financial Officer of Kinder Morgan
 Management, LLC and Kinder Morgan G.P., Inc., on behalf of Kinder Morgan
 Energy Partners, L.P., establishing the terms of the 9.00% Senior Notes due
 2019.4.30 
Certain
 instruments with respect to long-term debt of Kinder Morgan Energy Partners,
 L.P. and its consolidated subsidiaries which relate to debt that does not
 exceed 10% of the total assets of Kinder Morgan Energy Partners, L.P. and its
 consolidated subsidiaries are omitted pursuant to Item 601(b) (4) (iii) (A)
 of Regulation S-K, 17 C.F.R. sec.229.601. Kinder Morgan Energy Partners, L.P.
 hereby agrees to furnish supplementally to the Securities and Exchange
 Commission a copy of each such instrument upon request.*10.1 
Delegation
 of Control Agreement among Kinder Morgan Management, LLC, Kinder Morgan G.P.,
 Inc. and Kinder Morgan Energy Partners, L.P. and its operating partnerships
 (filed as Exhibit 10.1 to the Kinder Morgan Energy Partners, L.P. Form 10-Q
 for the quarter ended June 30, 2001).*10.2 
Amendment No. 1 to Delegation of Control
 Agreement, dated as of July 20, 2007, among Kinder Morgan G.P., Inc., Kinder
 Morgan Management, LLC, Kinder Morgan Energy Partners, L.P. and its operating
 partnerships (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.s
 Current Report on Form 8-K on July 20, 2007).*10.3 
Kinder
 Morgan Energy Partners, L.P. Directors Unit Appreciation Rights Plan (filed
 as Exhibit 10.6 to the Kinder Morgan Energy Partners, L.P. Form 10-K for 2003
 filed March 5, 2004).*10.4 
Amendment
 No. 1 to Kinder Morgan Energy Partners, L.P. Directors Unit Appreciation
 Rights Plan (filed as Exhibit 10.7 to the Kinder Morgan Energy Partners, L.P.
 Form 10-K for 2003 filed March 5, 2004).*10.5 
Kinder
 Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
 Directors (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P. Form
 8-K filed January 21, 2005).*10.6 
Form of
 Common Unit Compensation Agreement entered into with Non-Employee Directors
 (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P. Form 8-K filed
 January 21, 2005).*10.7 
Five-Year
 Credit Agreement dated as of August 5, 2005 among Kinder Morgan Energy
 Partners, L.P., the lenders party thereto and Wachovia Bank, National
 Association as Administrative Agent (filed as Exhibit 10.1 to Kinder Morgan
 Energy Partners, L.P.s Current Report on Form 8-K, filed on August 11,
 2005).*10.8 
First
 Amendment, dated October 28, 2005, to Five-Year Credit Agreement dated as of
 August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party
 thereto and Wachovia Bank, National Association as Administrative Agent
 (filed as Exhibit 10.1 to Kinder Morgan Energy Partners, L.P.s Form 10-Q for
 the quarter ended September 30, 2006).*10.9 
Second
 Amendment, dated April 13, 2006, to Five-Year Credit Agreement dated as of
 August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party
 thereto and Wachovia Bank, National Association as Administrative Agent
 (filed as Exhibit 10.2 to Kinder Morgan Energy Partners, L.P.s Form 10-Q for
 the quarter ended September 30, 2006).*10.10 
Third
 Amendment, dated October 6, 2006, to Five-Year Credit Agreement dated as of
 August 5, 2005 among Kinder Morgan Energy Partners, L.P., the lenders party
 thereto and Wachovia Bank, National Association as Administrative Agent
 (filed as Exhibit 10.3 to Kinder Morgan Energy Partners, L.P.s Form 10-Q for
 the quarter ended September 30, 2006).*10.11 
Retention
 and Relocation Agreement, dated as of March 5, 2007, between Kinder Morgan,
 Inc. and Scott E. Parker (filed as Exhibit 10.2 to Kinder Morgan, Inc.'s
 Quarterly Report on Form 10-Q for the quarter ended March 31, 2007).*10.12 
First
 Amendment to Retention and Relocation Agreement, dated as of July 16, 2008,
 between Knight Inc. and Scott E. Parker (filed as Exhibit 10.1 to Kinder
 Morgan Energy Partners, L.P. Form 8-K, filed July 25, 2008).11.1 
Statement
 re: computation of per share earnings.12.1 
Statement
 re: computation of ratio of earnings to fixed charges.121

*18.1 
Letter re:
 change in accounting principle (filed as exhibit 18 to Kinder Morgan Energy
 Partners, L.P. Form 10-Q, filed August 7, 2008).21.1 
List of
 Subsidiaries.23.1 
Consent of
 PricewaterhouseCoopers LLP.23.2 
Consent of
 Netherland, Sewell and Associates, Inc.31.1 
Certification
 by CEO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act
 of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
 2002.31.2 
Certification
 by CFO pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act
 of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
 2002.32.1 
Certification
 by CEO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
 of the Sarbanes-Oxley Act of 2002.32.2 
Certification
 by CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
 of the Sarbanes-Oxley Act of 2002.*
Asterisk indicates exhibits
 incorporated by reference as indicated; all other exhibits are filed
 herewith, except as noted otherwise.122

INDEX TO FINANCIAL STATEMENTS

Page
 NumberKINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIESReport
 of Independent Registered Public Accounting Firm
124Consolidated
 Statements of Income for the years ended December 31, 2008, 2007 and 2006
126Consolidated
 Statements of Comprehensive Income for the years ended December 31, 2008,
 2007 and 2006
127Consolidated
 Balance Sheets as of December 31, 2008 and 2007
128Consolidated
 Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006
129Consolidated
 Statements of Partners Capital for the years ended December 31, 2008, 2007
 and 2006
130Notes
 to Consolidated Financial Statements
131123

Report of Independent
Registered Public Accounting Firm

To the
Partners of 
Kinder Morgan Energy Partners, L.P.

In our opinion, the accompanying consolidated balance sheets and
the
related statements of income and comprehensive income, of partners capital and
of cash flows present fairly, in all material respects, the financial position
of Kinder Morgan Energy Partners, L.P. (the Partnership) and its subsidiaries
at December 31, 2008 and 2007, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2008 in
conformity with accounting principles generally accepted in the United States
of America. Also in our opinion, the Partnership maintained, in all material
respects, effective internal control over financial reporting as of December
31, 2008, based on criteria established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Partnerships management
is responsible for these financial statements, for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in
Managements Report on Internal Control over Financial Reporting appearing in
item 9A. Our responsibility is to express opinions on these financial
statements and on the Partnerships internal control over financial reporting
based on our integrated audits. We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting
was maintained in all material respects. Our audits of the financial statements
included examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. Our audit of internal control over financial
reporting included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audits also included performing such
other procedures as we considered necessary in the circumstances. We believe
that our audits provide a reasonable basis for our opinions.

A companys internal control over financial reporting is a
process
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A companys internal
control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition,
use, or disposition of the companys assets that could have a material effect
on the financial statements.

Because of its inherent limitations, internal control over
financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

As described
in Managements Report on Internal Control Over Financial Reporting, management
has excluded:


The bulk terminal
 assets acquired from Chemserve, Inc., effective August 15, 2008; and
The refined
 petroleum products storage terminal acquired from ConocoPhillips, effective
 December 10, 2008,124

(the Acquired Businesses) from its assessment of
internal control
over financial reporting as of December 31, 2008 because these businesses were
each acquired by the Partnership in purchase business combinations during 2008.
We have also excluded the Acquired Businesses from our audit of internal
control over financial reporting. These Acquired Businesses are wholly-owned
subsidiaries whose total assets and total revenues, in the aggregate, represent
0.23% and 0.01%, respectively, of the related consolidated financial statement
amounts as of and for the year ended December 31, 2008.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
February 23, 2009

125

KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED STATEMENTS OF
INCOME

Year Ended December 31,2008

2007

2006(In millions except per unit amounts)RevenuesNatural gas
sales

$
7,705.2

$
5,834.7

$
6,039.9Services


2,770.3


2,449.2


2,177.6Product sales
and other


1,264.8


933.8


831.211,740.3


9,217.7


9,048.7Costs, Expenses
and OtherGas purchases
and other costs of sales


7,716.1


5,809.8


5,990.9Operations and
maintenance


1,010.2


1,024.6


777.0Fuel and
power


272.6


237.5


223.7Depreciation,
depletion and amortization


702.7


540.0


423.9General and
administrative


297.9


278.7


238.4Taxes, other
than income taxes


186.7


153.8


134.4Goodwill
impairment expense





377.1


Other expense
(income)


2.6


(11.5
)

(31.2
)10,188.8


8,410.0


7,757.1Operating
Income


1,551.5


807.7


1,291.6Other Income
(Expense)Earnings from
equity investments


160.8


69.7


74.0Amortization of
excess cost of equity investments


(5.7
)

(5.8
)

(5.6
)Interest,
net


(388.2
)

(391.4
)

(337.8
)Other,
net


19.2


14.2


12.0Minority
Interest


(13.7
)

(7.0
)

(15.4
)Income from
Continuing Operations Before Income Taxes


1,323.9


487.4


1,018.8Income
Taxes


(20.4
)

(71.0
)

(29.0
)Income from
Continuing Operations


1,303.5


416.4


989.8Discontinued
Operations:Income from
operations of North System





21.1


14.3Gain on
disposal of North System


1.3


152.8


Income (loss)
from Discontinued Operations


1.3


173.9


14.3Net
Income

$
1,304.8

$
590.3

$
1,004.1Calculation of
Limited Partners interest in Net Income (loss):Income from
Continuing Operations

$
1,303.5

$
416.4

$
989.8Less: General
Partners interest


(805.8
)

(609.9
)

(513.2
)Limited
Partners interest


497.7


(193.5
)

476.6Add: Limited
Partners interest in Discontinued Operations


1.3


172.2


14.2Limited
Partners interest in Net Income (loss)

$
499.0

$
(21.3
)
$
490.8Basic Limited
Partners Net Income (loss) per Unit:Income (loss)
from Continuing Operations

$
1.94

$
(0.82
)
$
2.12Income from
Discontinued Operations





0.73


0.07Net Income
(loss)

$
1.94

$
(0.09
)
$
2.19Weighted
average number of units outstanding


257.2


236.9


224.6Diluted Limited
Partners Net Income (loss) per Unit:Income (loss)
from Continuing Operations

$
1.94

$
(0.82
)
$
2.12Income from
Discontinued Operations





0.73


0.06Net Income
(loss)

$
1.94

$
(0.09
)
$
2.18Weighted
average number of units outstanding


257.2


236.9


224.9Per unit cash
distribution declared

$
4.02

$
3.48

$
3.26The accompanying notes are an integral part
of these consolidated financial statements.

126

KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME

Year Ended December 31,2008

2007

2006(In millions)Net Income

$
1,304.8

$
590.3

$
1,004.1Change in fair value of
derivatives used for hedging purposes


651.4


(974.2
)

(187.5
)Reclassification of change in
fair value of derivatives to net
 income


663.7


433.2


428.1Foreign currency translation
adjustments


(329.8
)

132.5


(19.6
)Minimum pension liability
adjustments, other post-retirement benefit
 plan transition obligations, pension and other post-retirement benefit plan
 actuarial gains/losses, and reclassification of pension and other
 post-retirement benefit plan actuarial gains/losses, prior service
 costs/credits and transition obligations to net income, net of tax


3.6


(3.5
)

(1.8
)Total other
comprehensive income (loss)


988.9


(412.0
)

219.2Comprehensive Income

$
2,293.7

$
178.3

$
1,223.3The accompanying notes are an integral part
of these consolidated financial statements.

127

KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31,2008

2007(Dollars in millions)ASSETSCurrent AssetsCash and cash
equivalents

$
62.5

$
58.9Restricted deposits





67.9Accounts, notes and interest
receivable, netTrade


978.9


960.2Related parties


9.0


3.6InventoriesProducts


16.2


19.5Materials and supplies


28.0


18.3Gas imbalancesTrade


14.1


21.2Related parties





5.7Other current assets


135.7


54.41,244.4


1,209.7Property, Plant and Equipment,
net


13,241.4


11,591.3Investments


954.3


655.4Notes receivableTrade





0.1Related parties


178.1


87.9Goodwill


1,058.9


1,077.8Other intangibles, net


205.8


238.6Deferred charges and other
assets


1,002.9


317.0Total Assets

$
17,885.8

$
15,177.8LIABILITIES
 AND PARTNERS CAPITALCurrent LiabilitiesAccounts payableCash book overdrafts

$
42.8

$
19.0Trade


831.0


926.7Related parties


24.6


22.6Current portion of long-term
debt


288.7


610.2Accrued interest


172.3


131.2Accrued taxes


51.9


73.8Deferred revenues


41.1


22.8Gas imbalancesTrade


10.2


23.7Related parties


2.2


Accrued other current
liabilities


317.3


728.31,782.1


2,558.3Long-Term Liabilities and
Deferred CreditsLong-term debtOutstanding


8,274.9


6,455.9Value of interest rate
swaps


951.3


152.29,226.2


6,608.1Deferred revenues


12.9


14.2Deferred income taxes


178.0


202.4Asset retirement
obligations


74.0


50.8Other long-term liabilities and
deferred credits


496.3


1,254.19,987.4


8,129.6Commitments and Contingencies
(Notes 13 and 16)Minority Interest


70.7


54.2Partners CapitalCommon Units (182,969,427 and
170,220,396 units issued and outstanding
 as of December 31, 2008 and 2007, respectively)


3,458.9


3,048.4Class B Units (5,313,400 and
5,313,400 units issued and outstanding as
 of December 31, 2008 and 2007, respectively)


94.0


102.0i-Units (77,997,906 and
72,432,482 units issued and outstanding as of
 December 31, 2008 and 2007, respectively)


2,577.1


2,400.8General Partner


203.3


161.1Accumulated other comprehensive
loss


(287.7
)

(1,276.6
)6,045.6


4,435.7Total Liabilities and
Partners Capital

$
17,885.8

$
15,177.8The accompanying notes are an integral part
of these consolidated financial statements.

128

KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED STATEMENTS OF
CASH FLOWS

Year Ended December 31,2008

2007

2006(In millions)Cash Flows From Operating
ActivitiesNet
income

$
1,304.8

$
590.3

$
1,004.1Adjustments to
reconcile net income to net cash provided by operating
 activities:Depreciation,
depletion and amortization


702.7


547.0


432.8Amortization of
excess cost of equity investments


5.7


5.8


5.7Impairment of
goodwill





377.1


Income from the
allowance for equity funds used during construction


(10.6
)




Income from the
sale of property, plant and equipment and investments


(11.7
)

(162.5
)

(15.2
)Income from
property casualty indemnifications





(1.8
)

(15.2
)Earnings from
equity investments


(160.8
)

(71.5
)

(76.2
)Distributions
from equity investments


158.4


104.1


67.9Proceeds from
termination of interest rate swap agreements


194.3


15.0


Changes in
components of working capital:Accounts
receivable


105.4


92.6


15.8Other current
assets


(9.1
)

3.9


13.8Inventories


(7.3
)

(6.9
)

0.9Accounts
payable


(100.6
)

(79.7
)

(48.8
)Accrued
interest


41.1


47.3


8.0Accrued
liabilities


57.4


(9.5
)

(10.6
)Accrued
taxes


(22.3
)

40.7


14.2Rate
reparations, refunds and other litigation reserve adjustments


(13.7
)

140.0


(19.1
)Other,
net


2.2


109.9


(14.2
)Net Cash Provided by Operating
Activities


2,235.9


1,741.8


1,363.9Cash Flows From Investing
ActivitiesAcquisitions of
assets and equity investments


(40.2
)

(164.2
)

(387.2
)Repayment
(Payment) for Trans Mountain Pipeline


23.4


(549.1
)

Loans to
customers


(109.6
)




Additions to
property, plant and equip. for expansion and maintenance
 projects


(2,533.0
)

(1,691.6
)

(1,182.1
)Sale of
property, plant and equipment, and other net assets net of
 removal costs


47.8


302.6


70.8Property
casualty indemnifications





8.0


13.1Net proceeds
from (Investments in) margin deposits


71.0


(70.2
)

2.3Contributions
to investments


(366.7
)

(276.1
)

(2.5
)Distributions
from equity investments


89.1





Natural gas
stored underground and natural gas liquids line-fill


(7.2
)

12.3


(12.9
)Other





(0.2
)

(3.4
)Net Cash Used in Investing
Activities


(2,825.4
)

(2,428.5
)

(1,501.9
)Cash Flows From Financing
ActivitiesIssuance of
debt


9,028.6


7,686.1


4,632.5Payment of
debt


(7,525.0
)

(6,409.3
)

(3,698.7
)Repayments from
(Loans to) related party


1.8


4.4


1.1Debt issue
costs


(12.7
)

(13.8
)

(2.0
)Increase
(Decrease) in cash book overdrafts


23.8


(27.2
)

15.8Proceeds from
issuance of common units


560.9


342.9


248.4Proceeds from
issuance of i-units





297.9


Contributions
from minority interest


9.3


8.9


109.8Distributions
to partners:Common
units


(684.5
)

(552.6
)

(512.1
)Class B
units


(20.7
)

(18.0
)

(17.2
)General
Partner


(764.7
)

(567.7
)

(523.2
)Minority
interest


(18.8
)

(16.0
)

(119.0
)Other,
net


3.3


0.1


(3.0
)Net Cash Provided by Financing
Activities


601.3


735.7


132.4Effect of exchange rate changes
on cash and cash equivalents


(8.2
)

3.2


0.2Increase (Decrease) in Cash and
Cash Equivalents


3.6


52.2


(5.4
)Cash and Cash Equivalents,
beginning of year


58.9


6.7


12.1Cash and Cash Equivalents, end
of year

$
62.5

$
58.9

$
6.7Noncash Investing and Financing
Activities:Contribution of
net assets to partnership investments

$


$


$
17.0Assets acquired
by the issuance of units





15.0


1.6Related party
assets acquired by the issuance of units


116.0





Assets acquired
by the assumption or incurrence of liabilities


4.8


19.7


6.1Assets acquired
by the transfer of Trans Mountain








1,199.5Liabilities
assumed by the transfer of Trans Mountain








282.5Related party
asset settlements with Knight





276.2


Related party
liability settlements with Knight





556.6


Supplemental disclosures of cash
flow information:Cash paid
during the year for interest (net of capitalized interest)


373.3


336.0


329.2Cash paid
during the year for income taxes


35.7


6.2


25.6The accompanying notes are an integral part
of these consolidated financial statements.

129

KINDER MORGAN ENERGY PARTNERS, L.P. AND
SUBSIDIARIES

CONSOLIDATED STATEMENTS OF
PARTNERS CAPITAL

2008

2007

2006Units

Amount

Units

Amount

Units

Amount(Dollars in millions)Common Units:Beginning Balance


170,220,396

$
3,048.4


162,816,303

$
3,414.9


157,005,326

$
2,680.4Net income (loss)





343.4





(20.4
)




347.8Units issued as consideration
pursuant to common unit compensation plan
for non-employee directors


4,338


0.3


7,280


0.4


5,250


0.3Units issued as consideration in
the acquisition of assets


2,014,693


116.0


266,813


15.0


34,627


1.6Units issued for cash


10,730,000


560.3


7,130,000


342.5


5,771,100


248.2Trans Mountain Pipeline
acquisition





16.4





(166.8
)




648.7Express/Jet Fuel Pipelines
acquisition





52.7











Knight Inc. going-private
transaction exp.





5.9





15.4





Distributions





(684.5
)




(552.6
)




(512.1
)Ending Balance


182,969,427


3,458.9


170,220,396


3,048.4


162,816,303


3,414.9Class B Units:Beginning Balance


5,313,400


102.0


5,313,400


126.1


5,313,400


109.6Net income (loss)





10.4





(0.6
)




11.6Trans Mountain Pipeline
acquisition





0.5





(6.0
)




22.1Express/Jet Fuel Pipelines
acquisition





1.6











Knight Inc. going-private
transaction exp.





0.2





0.5





Distributions





(20.7
)




(18.0
)




(17.2
)Ending Balance


5,313,400


94.0


5,313,400


102.0


5,313,400


126.1i-Units:Beginning Balance


72,432,482


2,400.8


62,301,676


2,154.2


57,918,373


1,783.6Net income (loss)





145.2





(0.3
)




131.4Units issued for cash








5,700,000


297.6





Trans Mountain Pipeline
acquisition





6.0





(57.4
)




239.2Express/Jet Fuel Pipelines
acquisition





22.6











Knight Inc. going-private
transaction exp.





2.5





6.7





Distributions


5,565,424





4,430,806





4,383,303


Ending Balance


77,997,906


2,577.1


72,432,482


2,400.8


62,301,676


2,154.2General Partner:Beginning Balance





161.1





119.2





119.9Net income





805.8





611.6





513.3Trans Mountain Pipeline
acquisition





0.2





(2.2
)




9.2Express/Jet Fuel Pipelines
acquisition





0.8











Knight Inc. going-private
transaction exp.





0.1





0.2





Distributions





(764.7
)




(567.7
)




(523.2
)Ending Balance





203.3





161.1





119.2Accum. other comprehensive
income (loss):Beginning Balance





(1,276.6
)




(866.1
)




(1,079.7
)Change in fair value of
derivatives used for hedging purposes





651.4





(974.2
)




(187.5
)Reclassification of change in
fair value of derivatives to net income





663.7





433.2





428.1Foreign currency translation
adjustments





(329.8
)




132.5





(19.6
)Pension and other
post-retirement benefit liability changes





3.6





(3.5
)




(1.8
)Adj. to initially apply SFAS No.
158-pension and other post-retirement
 benefit acctg. changes











1.5





(5.6
)Ending Balance





(287.7
)




(1,276.6
)




(866.1
)Total Partners
Capital


266,280,733

$
6,045.6


247,966,278

$
4,435.7


230,431,379

$
4,948.3The accompanying notes are an integral part of these consolidated
financial statements.

130

KINDER MORGAN
ENERGY PARTNERS, L.P. AND SUBSIDIARIES

NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
1.
OrganizationGeneral

Kinder
Morgan Energy Partners, L.P. is a Delaware limited partnership formed in August
1992. Unless the context requires otherwise, references to we,
us, our or the Partnership are intended to mean Kinder Morgan Energy
Partners, L.P. and its consolidated subsidiaries.

We own and
manage a diversified portfolio of energy transportation and storage assets and
presently conduct our business through five reportable business segments. These
segments and the activities performed to provide services to our customers and
create value for our unitholders are as follows:


Products Pipelines -
transporting,
 storing and processing refined petroleum products;
Natural Gas Pipelines -
 transporting, storing, buying, selling, gathering, treating and processing
 natural gas;
CO2 
transporting
 oil, producing, transporting and selling carbon dioxide, commonly called CO2,
 for use in, and selling crude oil, natural gas and natural gas liquids
 produced from, enhanced oil recovery operations;
Terminals - transloading,
 storing and delivering a wide variety of bulk, petroleum, petrochemical and
 other liquid products at terminal facilities located across North America;
 and
Kinder Morgan Canada 
transporting
 crude oil and refined petroleum products from Edmonton, Alberta, Canada to
 marketing terminals and refineries in British Columbia and the state of
 Washington, and owning an interest in an integrated oil transportation
 network that connects Canadian and United States producers to refineries in
 the U.S. Rocky Mountain and Midwest regions.We focus on
providing fee-based services to customers, generally avoiding near-term
commodity price risks and taking advantage of the tax benefits of a limited
partnership structure. We trade on the New York Stock Exchange under the symbol
KMP, and we conduct our operations through the following five limited
partnerships: (i) Kinder Morgan Operating L.P. A (OLP-A); (ii) Kinder Morgan
Operating L.P. B (OLP-B); (iii) Kinder Morgan Operating L.P. C (OLP-C);
(iv) Kinder Morgan Operating L.P. D (OLP-D); and (v) Kinder Morgan CO2
Company (KMCO2).

Combined,
the five limited partnerships are referred to as our operating partnerships,
and we are the 98.9899% limited partner and our general partner is the 1.0101%
general partner in each. Both we and our operating partnerships are governed by
Amended and Restated Agreements of Limited Partnership, as amended and certain
other agreements that are collectively referred to in this report as the
partnership agreements.

Knight Inc. and Kinder Morgan G.P., Inc.

On
August 28, 2006, Kinder Morgan, Inc., a Kansas corporation referred to as
KMI in this report, entered into an agreement and plan of merger whereby
generally each share of KMI common stock would be converted into the right to
receive $107.50 in cash without interest. KMI in turn would merge with a wholly
owned subsidiary of Knight Holdco LLC, a privately owned company in which
Richard D. Kinder, Chairman and Chief Executive Officer of KMI, would be a
major investor. On May 30, 2007, the merger closed, with KMI continuing as the
surviving legal entity and subsequently renamed Knight Inc., referred to as
Knight in this report. Additional investors in Knight Holdco LLC include the
following: other senior members of Knight management, most of whom are also
senior officers of Kinder Morgan G.P., Inc. (our general partner) and of Kinder
Morgan Management, LLC (our general partners delegate); KMI co-founder William
V. Morgan; KMI board members Fayez Sarofim and Michael C. Morgan; and
affiliates of (i) Goldman Sachs Capital Partners; (ii) the Highstar Funds;

131

(iii) The Carlyle Group; and (iv) Riverstone Holdings LLC. This
transaction is referred to in this report as the going-private transaction.

Knight
is privately owned and indirectly owns all of the common stock of our general
partner. On July 27, 2007, our general partner issued and sold 100,000 shares
of Series A fixed-to-floating rate term cumulative preferred stock due 2057.
The consent of holders of a majority of these preferred shares is required with
respect to a commencement of or a filing of a voluntary bankruptcy proceeding
with respect to us, or two of our subsidiaries: SFPP, L.P. and Calnev Pipe Line
LLC. As of December 31, 2008, Knight and
its consolidated subsidiaries owned, through its general and limited partner
interests, an approximate 14.1% interest in us.

Kinder Morgan Management, LLC

Kinder
Morgan Management, LLC, a Delaware limited liability company, was formed on
February 14, 2001. Its shares represent limited liability company interests and
are traded on the New York Stock Exchange under the symbol KMR. Kinder Morgan
Management, LLC is referred to as KMR in this report. Our general partner
owns all of KMRs voting securities and, pursuant to a delegation of control agreement,
our general partner delegated to KMR, to the fullest extent permitted under
Delaware law and our partnership agreement, all of its power and authority to
manage and control our business and affairs, except that KMR cannot take
certain specified actions without the approval of our general partner.

Under the
delegation of control agreement, KMR manages and controls our business and
affairs and the business and affairs of our operating limited partnerships and
their subsidiaries. Furthermore, in accordance with its limited liability
company agreement, KMRs activities are limited to being a limited partner in,
and managing and controlling the business and affairs of us, our operating
limited partnerships and their subsidiaries. As of December 31, 2008, KMR owned
approximately 29.3% of our outstanding limited partner units (which are in the
form of i-units that are issued only to KMR).

2.
Summary of
Significant Accounting PoliciesBasis
of Presentation

Our
consolidated financial statements were prepared in accordance with accounting
principles generally accepted in the United States and include our accounts and
those of our operating partnerships and their majority-owned and controlled
subsidiaries. Our accounting records are maintained in United
States dollars, and all references to dollars are United States dollars, except
where stated otherwise. Canadian dollars are designated as C$. All significant intercompany items have been
eliminated in consolidation, and certain amounts from prior years have been
reclassified to conform to the current presentation. Our accompanying
consolidated financial statements reflect amounts on a historical cost basis,
and, accordingly, do not reflect any purchase accounting adjustments related to
the May 30, 2007 going-private transaction of KMI, now known as Knight.

In
addition, certain amounts included in or affecting our financial statements and
related disclosures must be estimated, requiring us to make certain assumptions
with respect to values or conditions which cannot be known with certainty at
the time our financial statements are prepared. These estimates and assumptions
affect the amounts we report for assets and liabilities, our revenues and
expenses during the reporting period, and our disclosure of contingent assets
and liabilities at the date of our financial statements. 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.

Prior
to the third quarter of 2008, we reported five business segments: Products
Pipelines; Natural Gas Pipelines; CO2; Terminals; and Trans
Mountain. As discussed in Note 3 below, we acquired (i) a one-third interest in
the Express pipeline system; and (ii) the Jet Fuel pipeline system from Knight
on August 28, 2008, and following the acquisition of these businesses, the
operations of our Trans Mountain, Express and Jet Fuel pipeline systems have

132

been combined
to represent the Kinder Morgan Canada segment. For more information on our
reportable business segments, see Note 15.

We believe
that certain accounting policies are of more significance in our financial
statement preparation process than others, and set out below are the principal
accounting policies we apply in the preparation of our consolidated financial
statements.

Cash
Equivalents

We define
cash equivalents as all highly liquid short-term investments with original
maturities of three months or less.

Accounts
Receivables

Our policy for
determining an appropriate allowance for doubtful accounts varies according to
the type of business being conducted and the customers being served. Generally,
we make periodic reviews and evaluations of the appropriateness of the
allowance for doubtful accounts based on a historical analysis of uncollected
amounts, and we record adjustments as necessary for changed circumstances and
customer-specific information. When specific receivables are determined to be
uncollectible, the reserve and receivable are relieved. The following table
shows the balance in the allowance for doubtful accounts and activity for the
years ended December 31, 2008, 2007 and 2006 (in millions):

Valuation and
 Qualifying AccountsAllowance for Doubtful Accounts

Balance at
 beginning of
 Period

Additions
 charged to costs
 and expenses

Additions
 charged to other
 accounts(1)

Deductions(2)

Balance at
 end of
 periodYear ended December 31, 2008

$
7.0

$
0.6

$


$
(1.5)

$
6.1Year ended December 31, 2007

$
6.8

$
0.4

$


$
(0.2)

$
7.0Year ended December 31, 2006

$
6.5

$
0.3

$
0.3

$
(0.3)

$
6.8(1)
Amount for 2006 represents the allowance recognized when we acquired
 Devco USA L.L.C. ($0.2) and Transload Services, LLC ($0.1).(2)
Deductions represent the write-off of receivables and currency
 translation adjustments.In
addition, the balances of Accrued other current liabilities in our accompanying
consolidated balance sheets include amounts related to customer prepayments of
approximately $10.8 million as of December 31, 2008 and $6.5 million as of
December 31, 2007.

Inventories

Our
inventories of products consist of natural gas liquids, refined petroleum
products, natural gas, carbon dioxide and coal. We report these assets at the
lower of weighted-average cost or market. We report materials and supplies at
the lower of cost or market. In December of 2008, we recognized a
lower of cost or market adjustment of $12.9 million in our CO2 business
segment. Additionally, as of December 31,
2008 and 2007, we owed certain customers a total of $1.0 million and $8.3
million, respectively, for the value of natural gas inventory stored in our
underground storage facilities, and we reported these amounts within Accounts
PayableTrade in our accompanying consolidated balance sheets.

Property, Plant and Equipment

Capitalization, Depreciation and Depletion
and Disposals

We report
property, plant and equipment at its acquisition cost. We expense costs for
maintenance and repairs in the period incurred. The cost of property, plant and
equipment sold or retired and the related depreciation are removed from our
balance sheet in the period of sale or disposition. For our pipeline system
assets, we generally

133

charge the original cost of property sold or retired to accumulated
depreciation and amortization, net of salvage and cost of removal. We do not
include retirement gain or loss in income except in the case of significant
retirements or sales. Gains and losses on minor system sales,
excluding land, are recorded to the appropriate accumulated depreciation
reserve. Gains and losses for operating systems sales and land sales are booked
to income or expense accounts in accordance with regulatory accounting
guidelines.

We compute
depreciation using the straight-line method based on estimated economic lives.
Generally, we apply composite depreciation rates to functional groups of
property having similar economic characteristics. The rates range from 1.6% to
12.5%, excluding certain short-lived assets such as vehicles. Depreciation
estimates are based on various factors, including age (in the case of acquired
assets), manufacturing specifications, technological advances and historical
data concerning useful lives of similar assets. Uncertainties that impact these
estimates included changes in laws and regulations relating to restoration and
abandonment requirements, economic conditions, and supply and demand in the
area. When assets are put into service, we make estimates with respect to
useful lives (and salvage values where appropriate) that we believe are
reasonable. However, subsequent events could cause us to change our estimates,
thus impacting the future calculation of depreciation and amortization expense.
Historically, adjustments to useful lives have not had a material impact on our
aggregate depreciation levels from year to year.

Our
oil and gas producing activities are
accounted for under the successful efforts method of accounting. Under this
method costs that are incurred to acquire leasehold and subsequent development
costs are capitalized. Costs that are associated with the drilling of
successful exploration wells are capitalized if proved reserves are found.
Costs associated with the drilling of exploratory wells that do not find proved
reserves, geological and geophysical costs, and costs of certain non-producing
leasehold costs are expensed as incurred. The capitalized costs of our
producing oil and gas properties are depreciated and depleted by the
units-of-production method. Other miscellaneous property, plant and equipment
are depreciated over the estimated useful lives of the asset.

A
gain on the sale of property, plant and equipment used in our oil and gas
producing activities or in our bulk and liquids terminal activities is
calculated as the difference between the cost of the asset disposed of, net of
depreciation, and the sales proceeds received. A gain on an asset disposal is
recognized in income in the period that the sale is closed. A loss on the sale
of property, plant and equipment is calculated as the difference between the
cost of the asset disposed of, net of depreciation, and the sales proceeds
received or the maket value if the asset is being held for sale. A loss is
recognized when the asset is sold or when the net cost of an asset held for
sale is greater than the market value of the asset.

In
addition, we engage in enhanced recovery techniques in which carbon dioxide is
injected into certain producing oil reservoirs. In some cases, the acquisition
cost of the carbon dioxide associated with enhanced recovery is capitalized as part of our
development costs when it is injected. The
acquisition cost associated with pressure maintenance operations for reservoir
management is expensed when it is injected. When carbon dioxide is
recovered in conjunction with oil production, it is extracted and re-injected,
and all of the associated costs are expensed as incurred. Proved developed
reserves are used in computing units of production rates for drilling and
development costs, and total proved reserves are used for depletion of
leasehold costs. The units-of-production rate is determined by field.

As
discussed in Inventories above, we maintain natural gas in underground
storage as part of our inventory. This component of our inventory represents
the portion of gas stored in an underground storage facility generally known as
working gas, and represents an estimate of the portion of gas in these
facilities available for routine injection and withdrawal to meet demand. In
addition to this working gas, underground gas storage reservoirs contain
injected gas which is not routinely cycled but, instead, serves the function of
maintaining the necessary pressure to allow efficient operation of the
facility. This gas, generally known as cushion gas, is divided into the
categories of recoverable cushion gas and unrecoverable cushion gas, based
on an engineering analysis of whether the gas can be economically removed from
the storage facility at any point during its life. The portion of the cushion
gas that is determined to be unrecoverable is considered to be a permanent part
of the facility itself (thus, part of our Property, Plant and Equipment, net
balance in our accompanying consolidated balance sheets), and this
unrecoverable portion is depreciated over the facilitys estimated useful life.
The portion of the cushion gas that is determined to be recoverable is also
considered a component of the facility but is not depreciated because it is
expected to ultimately be recovered and sold.

134

Impairments

We evaluate
the impairment of our long-lived assets in accordance with Statement of
Financial Accounting Standards No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. SFAS No. 144 requires that long-lived assets
that are to be disposed of by sale be measured at the lower of book value or
fair value less the cost to sell. We review for the impairment of long-lived
assets whenever events or changes in circumstances indicate that our carrying
amount of an asset may not be recoverable. We would recognize an impairment
loss when estimated future cash flows expected to result from our use of the
asset and its eventual disposition is less than its carrying amount. In
December 2008, we completed an impairment test of the long-lived assets
included within our CO2 business segment and determined that the
assets were not impaired as of December 31, 2008.

We evaluate
our oil and gas producing properties for impairment of value on a
field-by-field basis or, in certain instances, by logical grouping of assets if
there is significant shared infrastructure, using undiscounted future cash
flows based on total proved and risk-adjusted probable and possible reserves.
Due to the decline in crude oil and natural gas prices during the course of
2008, on December 31, 2008, we conducted an impairment test on our oil and gas
producing properties in our CO2 business segment and determined that no impairment was necessary. For
the purpose of impairment testing, we use the forward curve prices as observed
at the test date. The forward curve cash flows may differ from the amounts
presented in Note 20 due to differences between the forward curve and spot
prices. Oil and gas producing properties deemed to be impaired are written down
to their fair value, as determined by discounted future cash flows based on
total proved and risk-adjusted probable and possible reserves or, if available,
comparable market values. Unproved oil and gas properties that are individually
significant are periodically assessed for impairment of value, and a loss is
recognized at the time of impairment.

Equity Method
of Accounting

We account
for investments greater than 20% in affiliates, which we do not control, by the
equity method of accounting. Under this method, an investment is carried at our
acquisition cost, plus our equity in undistributed earnings or losses since
acquisition, and less distributions received.

Excess
of Cost Over Fair Value

We
account for our business acquisitions and intangible assets in accordance with
the provisions of SFAS No. 141, Business Combinations, and SFAS No. 142,
Goodwill and Other Intangible Assets. Accounting
standards require that goodwill not be amortized, but instead should be tested,
at least on an annual basis, for impairment. Pursuant to this SFAS No. 142,
goodwill and other intangible assets with indefinite useful lives cannot be
amortized until their useful life becomes determinable. Instead, such assets
must be tested for impairment annually or on an interim basis if events
or circumstances indicate that the fair value of the asset has decreased below
its carrying value.

Pursuant
to our adoption of SFAS No. 142, Goodwill and Other Intangible Assets on January
1, 2002, we selected a goodwill impairment measurement date of January 1 of
each year, and we have determined that our goodwill was not impaired as of
January 1, 2008. In the second quarter of 2008, we changed the date of our
annual goodwill impairment test date to May 31 of each year. The change was
made following our managements decision to match our impairment testing date
to the impairment testing date of Knightfollowing the completion of its
going-private transaction on May 30, 2007, Knight established as its goodwill
impairment measurement date May 31 of each year. This change to the date of our
annual goodwill impairment test constitutes a change in the method of applying
an accounting principle, as discussed in paragraph 4 of SFAS No. 154, Accounting
Changes and Error Corrections. We believe that this change in accounting
principle is preferable because our test would then be performed at the same
time as Knight, which indirectly owns all the common stock of our general
partner.

SFAS
No. 154 requires an entity to report a change in accounting principle through
retrospective application of the new accounting principle to all periods,
unless it is impracticable to do so. However, our change to a new testing date,
when applied to prior periods, does not yield different financial statement
results. Furthermore, there were no impairment charges resulting from the May
31, 2008 impairment testing, and no event indicating an impairment has occurred
subsequent to that date. However, our consolidated income statement for the
year ended December 31,

135

2007 included
a goodwill impairment expense of $377.1 million, due to the inclusion of
Knights first quarter 2007 impairment of goodwill that resulted from a
determination of the fair values of Trans Mountain pipeline assets prior to our
acquisition of these assets on April 30, 2007. For more information on this
acquisition and this impairment expense, see Notes 3 and 8, respectively.

Our total
unamortized excess cost over fair value of net assets in consolidated
affiliates was $1,058.9 million as of December 31, 2008 and $1,077.8 million as
of December 31, 2007. Such amounts are reported as Goodwill on our
accompanying consolidated balance sheets. Our total unamortized excess cost over
underlying fair value of net assets accounted for under the equity method was$138.2
million as of both December 31, 2008 and December 31, 2007. Pursuant to SFAS
No. 142, this amount, referred to as equity method goodwill, should continue to
be recognized in accordance with Accounting Principles Board Opinion No. 18,
The Equity Method of Accounting for Investments in Common Stock. Accordingly,
we included this amount within Investments on our accompanying consolidated
balance sheets.

In almost
all cases, the price we paid to acquire our share of the net assets of our
equity investees differed from the underlying book value of such net assets.
This differential consists of two pieces. First, an amount related to the
difference between the investees recognized net assets at book value and at
current fair values (representing the appreciated value in plant and other net
assets), and secondly, to any premium in excess of fair value (representing
equity method goodwill as described above) we paid to acquire the investment.
The first differential, representing the excess of the fair market value of our
investees plant and other net assets over its underlying book value at the
date of acquisition totaled $169.0 million and $174.7 million as of December
31, 2008 and 2007, respectively, and similar to our treatment of equity method
goodwill, we included these amounts within Investments on our accompanying
consolidated balance sheets. As of December 31, 2008, this excess investment
cost is being amortized over a weighted average life of approximately 29.9
years.

In addition
to our annual impairment test of goodwill, we periodically reevaluate the
amount at which we carry the excess of cost over fair value of net assets
accounted for under the equity method, as well as the amortization period for
such assets, to determine whether current events or circumstances warrant
adjustments to our carrying value and/or revised estimates of useful lives in
accordance with APB Opinion No. 18. The impairment test under APB
No. 18 considers whether the fair value of the equity investment as a whole,
not the underlying net assets, has declined and whether that decline is other
than temporary. As of December 31, 2008, we
believed no such impairment had occurred and no reduction in estimated useful
lives was warranted. For more information on our investments, see Note 7.

Revenue
Recognition Policies

We
recognize revenues as services are rendered or goods are delivered and, if
applicable, title has passed. We generally sell natural gas under
long-term agreements, with periodic price adjustments. In some cases, we sell
natural gas under short-term agreements at prevailing market prices. In all
cases, we recognize natural gas sales revenues when the natural gas is sold to
a purchaser at a fixed or determinable price, delivery has occurred and title
has transferred, and collectibility of the revenue is reasonably assured. The
natural gas we market is primarily purchased gas produced by third parties, and
we market this gas to power generators, local distribution companies,
industrial end-users and national marketing companies. We recognize gas
gathering and marketing revenues in the month of delivery based on customer
nominations and generally, our natural gas marketing revenues are recorded
gross, not net of cost of gas sold.

We provide
various types of natural gas storage and transportation services to customers.
The natural gas remains the property of these customers at all times. In many
cases (generally described as firm service), the customer pays a two-part
rate that includes (i) a fixed fee reserving the right to transport or store
natural gas in our facilities; and (ii) a per-unit rate for volumes actually
transported or injected into/withdrawn from storage. The fixed-fee component of
the overall rate is recognized as revenue in the period the service is
provided. The per-unit charge is recognized as revenue when the volumes are
delivered to the customers agreed upon delivery point, or when the volumes are
injected into/withdrawn from our storage facilities. In other cases (generally
described as interruptible service), there is no fixed fee associated with
the services because the customer accepts the possibility that service may be
interrupted at our discretion in order to serve customers who have purchased
firm service. In the case of interruptible service, revenue is recognized in
the same manner utilized for the per-unit rate

136

for volumes actually transported under firm service agreements. In addition to
our firm and interruptible
transportation services, we also provide natural gas park and loan service to
assist customers in managing short-term gas surpluses or deficits. Revenues are
recognized based on the terms negotiated under these contracts.

We
provide crude oil transportation services and refined petroleum products
transportation and storage services to customers. Revenues are recorded when
products are delivered and services have been provided, and adjusted according
to terms prescribed by the toll settlements with shippers and approved by
regulatory authorities.

We
recognize bulk terminal transfer service revenues based on volumes loaded and
unloaded. We recognize liquids terminal tank rental revenue ratably over the
contract period. We recognize liquids terminal throughput revenue based on
volumes received and volumes delivered. Liquids terminal minimum take-or-pay
revenue is recognized at the end of the contract year or contract term depending
on the terms of the contract. We recognize transmix processing revenues based
on volumes processed or sold, and if applicable, when title has passed. We
recognize energy-related product sales revenues based on delivered quantities
of product.

Revenues
from the sale of oil, natural gas liquids and natural gas production are
recorded using the entitlement method. Under the entitlement method, revenue is
recorded when title passes based on our net interest. We record our entitled
share of revenues based on entitled volumes and contracted sales prices. Since
there is a ready market for oil and gas production, we sell the majority of our
products soon after production at various locations, at which time title and
risk of loss pass to the buyer. As a result, we maintain a minimum amount of
product inventory in storage.

Allowance For
Funds Used During Construction

Included
in the cost of our qualifying property, plant and equipment is an allowance for
funds used during construction or upgrade, often referred to as AFUDC. AFUDC on
debt represents the estimated cost of capital, from borrowed funds, during the
construction period. Total AFUDC on debt resulting from the capitalization of
interest expense in 2008, 2007 and 2006 was $48.6 million, $31.4 million and
$20.3 million, respectively. Similarly,
AFUDC on equity represents an estimate of the cost of capital funded by equity
contributions, and in the twelve months ended December 31, 2008, 2007
and 2006, we also capitalized approximately $10.6 million, $6.1 million and
$2.2 million, respectively, of equity AFUDC.

Unit-Based
Compensation

We account
for common unit options granted under our common unit option plan according
to the provisions of SFAS No. 123R (revised 2004), Share-Based Payment, which
became effective for us January 1, 2006. However, we have not granted common
unit options or made any other share-based payment awards since May 2000, and
as of December 31, 2005, all outstanding options to purchase our common units
were fully vested. Therefore, the adoption of this Statement did not have an
effect on the accounting for these common unit options in our consolidated
financial statements, as we had reached the end of the requisite service period
for any compensation cost resulting from share-based payments made under our
common unit option plan.

Environmental
Matters

We expense
or capitalize, as appropriate, environmental expenditures that relate to
current operations. We expense expenditures that relate to an existing
condition caused by past operations, which do not contribute to current or
future revenue generation. We do not discount environmental liabilities to a
net present value, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, our recording of these accruals coincides with our
completion of a feasibility study or our commitment to a formal plan of action.
We recognize receivables for anticipated associated insurance recoveries when
such recoveries are deemed to be probable.

We
routinely conduct reviews of potential environmental issues and claims that
could impact our assets or operations. These reviews assist us in identifying
environmental issues and estimating the costs and timing of remediation
efforts. We also routinely adjust our environmental liabilities to reflect
changes in previous estimates. In making environmental liability estimations,
we consider the material effect of environmental compliance, pending

137

legal actions against us, and potential third-party liability claims.
Often, as the remediation evaluation and effort progresses, additional
information is obtained, requiring revisions to estimated costs. These
revisions are reflected in our income in the period in which they are
reasonably determinable. For more information on our environmental disclosures,
see Note 16.

Legal

We are
subject to litigation and regulatory proceedings as the result of our business
operations and transactions. We utilize both internal and external counsel in
evaluating our potential exposure to adverse outcomes from orders, judgments or
settlements. 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, and we accrue for
such amounts. To the extent that actual outcomes differ from our estimates, or
additional facts and circumstances cause us to revise our estimates, our
earnings will be affected. In general, we expense legal costs as
incurred and all recorded legal liabilities are revised as better information
becomes available. For more information on
our legal disclosures, see Note 16.

Pensions and
Other Post-retirement Benefits

We account
for pension and other post-retirement benefit plans according to
the provisions of SFAS No. 158,
Employers Accounting for Defined Benefit Pension and Other Postretirement
Plans, an amendment of FASB Statement Nos. 87, 88, 106 and 132(R). This
Statement requires us to fully recognize the overfunded or underfunded status
of our consolidating subsidiaries pension and post-retirement benefit plans as
either assets or liabilities on our balance sheet. For more information on our pension and post-retirement benefit
disclosures, see Note 10.

Gas
Imbalances

We value
gas imbalances due to or due from interconnecting pipelines at the lower of
cost or market. Gas imbalances represent the difference between customer
nominations and actual gas receipts from, and gas deliveries to, our
interconnecting pipelines and shippers under various operational balancing and
shipper imbalance agreements. Natural gas imbalances are either settled in cash
or made up in-kind subject to the pipelines various tariff provisions.

Minority
Interest

Minority
interest, sometimes referred to as noncontrolling interest, represents the
outstanding ownership interests in our five operating limited partnerships and
their consolidated subsidiaries that are not owned by us. In our consolidated
income statements, the minority interest in the income (or loss) of a
consolidated subsidiary is shown as a deduction from (or an addition to) our
consolidated net income. In our consolidated balance sheets, minority interest
represents the noncontrolling ownership interest in our consolidated net assets
and is presented separately between liabilities and Partners Capital.

As of
December 31, 2008, our minority interest consisted of the following:

 the 1.0101% general
 partner interest in each of our five operating partnerships; the 0.5% special
 limited partner interest in SFPP, L.P.; the 50% interest in
 Globalplex Partners, a Louisiana joint venture owned 50% and controlled by
 Kinder Morgan Bulk Terminals, Inc.; the 33 1/3% interest in
 International Marine Terminals Partnership, a Louisiana partnership owned 66
 2/3% and controlled by Kinder Morgan Operating L.P. C; the approximate 31%
 interest in the Pecos Carbon Dioxide Company, a Texas general partnership
 owned approximately 69% and controlled by Kinder Morgan CO2
 Company, L.P. and its consolidated subsidiaries;138

 the 1% interest in
 River Terminals Properties, L.P., a Tennessee partnership owned 99% and
 controlled by Kinder Morgan River Terminals LLC; and the 35% interest in
Guilford
 County Terminal Company, LLC, a limited liability company owned 65% and
 controlled by Kinder Morgan Southeast Terminals LLC.Income
Taxes

We are not
a taxable entity for federal income tax purposes. As such, we do not directly pay
federal income tax. Our taxable income or loss, which may vary substantially
from the net income or net loss we report in our consolidated statement of
income, is includable in the federal income tax returns of each partner. The
aggregate difference in the basis of our net assets for financial and tax
reporting purposes cannot be readily determined as we do not have access to
information about each partners tax attributes in us.

Some of our
corporate subsidiaries and corporations in which we have an equity investment
do pay U.S. federal, state, and foreign income taxes. Deferred income tax
assets and liabilities for certain operations conducted through corporations
are recognized for temporary differences between the assets and liabilities for
financial reporting and tax purposes. Changes in tax legislation are included
in the relevant computations in the period in which such changes are effective.
Deferred tax assets are reduced by a valuation allowance for the amount of any
tax benefit not expected to be realized.

Foreign
Currency Transactions and Translation

We
account for foreign currency transactions and the foreign currency translation
of our consolidating foreign subsidiaries in accordance with the provisions of
SFAS No. 52, Foreign Currency Translation. Foreign currency transactions are
those transactions whose terms are denominated in a currency other than the
currency of the primary economic environment in which our foreign subsidiary
operates, also referred to as its functional currency. Transaction gains or
losses result from a change in exchange rates between (i) the functional
currency, for example the Canadian dollar for a Canadian subsidiary; and (ii)
the currency in which a foreign currency transaction is denominated, for
example the U.S. dollar for a Canadian subsidiary.

We
translate the assets and liabilities of each of our consolidating foreign
subsidiaries to U.S. dollars at year-end exchange rates. Income and expense
items are translated at weighted-average rates of exchange prevailing during
the year and stockholders equity accounts are translated by using historical
exchange rates. Translation adjustments result from translating all assets and
liabilities at current year-end rates, while stockholders equity is translated
by using historical and weighted-average rates. The cumulative translation
adjustments balance is reported as a component of accumulated other
comprehensive income/(loss) within Partners Capital on our accompanying
consolidated balance sheet.

Comprehensive
Income

Statement
of Financial Accounting Standards No. 130, Accounting for Comprehensive
Income, requires that enterprises report a total for comprehensive income. The
difference between our net income and our comprehensive income resulted from
(i) unrealized gains or losses on derivatives utilized for hedging our exposure
to fluctuating expected future cash flows produced by both energy commodity
price risk and interest rate risk; (ii) foreign currency translation
adjustments; and (iii) unrealized gains or losses related to changes in pension
and other post-retirement benefit plan liabilities. For more information on our
risk management activities, see Note 14.

Cumulative
revenues, expenses, gains and losses that under generally accepted accounting
principals are included within our comprehensive income but excluded from our
earnings are reported as accumulated other comprehensive
income/(loss) within Partners Capital in our consolidated balance sheets. The following table summarizes changes in the
amount of our Accumulated other comprehensive loss in our accompanying
consolidated balance sheets for each of the
two years ended December 31, 2007 and 2008 (in millions):

139

Net unrealized
 gains/(losses)
 on cash flow
 hedge derivatives

Foreign
 currency
 translation
 adjustments

Pension and
 other
 post-retirement
 liability adjs.

Total
 Accumulated other
 comprehensive
 income/(loss)December 31, 2006

$
(838.7
)
$
(20.0
)
$
(7.4
)
$
(866.1
)Change for period


(541.0
)

132.5


(2.0
)

(410.5
)December 31, 2007


(1,379.7
)

112.5


(9.4
)

(1,276.6
)Change for period


1,315.1


(329.8
)

3.6


988.9December 31, 2008

$
(64.6
)
$
(217.3
)
$
(5.8
)
$
(287.7
)Net
Income Per Unit

We
compute Basic Limited Partners Net Income per Unit by dividing our limited
partners interest in net income by the weighted average number of units
outstanding during the period. Diluted Limited Partners Net Income per Unit
reflects the maximum potential dilution that could occur if units whose
issuance depends on the market price of the units at a future date were
considered outstanding, or if, by application of the treasury stock method,
options to issue units were exercised, both of which would result in the
issuance of additional units that would then share in our net income. See Note
18 for further information regarding recent accounting pronouncements relating
to earnings per unit.

Asset
Retirement Obligations

We
account for asset retirement obligations pursuant to SFAS No. 143, Accounting
for Asset Retirement Obligations. For more information on our asset retirement
obligations, see Note 4.

Risk
Management Activities

We utilize
energy commodity derivative contracts for the purpose of mitigating our risk
resulting from fluctuations in the market price of natural gas, natural gas
liquids and crude oil. In addition, we enter into interest rate swap agreements
for the purpose of hedging the interest rate risk associated with our debt
obligations.

Our
derivative contracts are accounted for under SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS No. 137,
Accounting for Derivative Instruments and Hedging Activities  Deferral of the
Effective Date of FASB Statement No.133 and No. 138, Accounting for Certain
Derivative Instruments and Certain Hedging Activities. SFAS No. 133 established
accounting and reporting standards requiring that every derivative contract
(including certain derivative contracts embedded in other contracts) be
recorded in the balance sheet as either an asset or liability measured at its
fair value. If the derivative transaction qualifies for and is designated as a
normal purchase and sale, it is exempted from the fair value accounting
requirements of SFAS No. 133 and is accounted for using traditional accrual
accounting.

Furthermore,
SFAS No. 133 requires that changes in the derivative contracts fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. If a derivative contract meets those criteria, SFAS No. 133 allows a
derivative contracts gains and losses to offset related results on the hedged
item in the income statement, and requires that a company formally designate a
derivative contract as a hedge and document and assess the effectiveness of
derivative contracts associated with transactions that receive hedge
accounting.

Our
derivative contracts that hedge our commodity price risks involve our normal
business activities, which include the sale of natural gas, natural gas liquids
and crude oil, and these derivative contracts have been designated as cash flow
hedges as defined by SFAS No. 133. SFAS No. 133 designates derivative contracts
that hedge exposure to variable cash flows of forecasted transactions as cash
flow hedges and the effective portion of the derivative contracts gain or loss
is initially reported as a component of other comprehensive income (outside
earnings) and subsequently reclassified into earnings when the forecasted
transaction affects earnings. The ineffective portion of the gain or loss is
reported in earnings immediately. See Note
14 for more information on our risk management activities and disclosures.

140

Accounting
for Regulatory Activities

Our
regulated utility operations are accounted for in accordance with the
provisions of SFAS No. 71, Accounting for the Effects of Certain Types of
Regulation, which prescribes the circumstances in which the application of
generally accepted accounting principles is affected by the economic effects of
regulation. Regulatory assets and liabilities represent probable future
revenues or expenses associated with certain charges and credits that will be
recovered from or refunded to customers through the ratemaking process.

The amount
of regulatory assets and liabilities reflected within Deferred charges and
other assets and Other long-term liabilities and deferred credits,
respectively, in our accompanying consolidated balance sheets as of December
31, 2008 and December 31, 2007 are not material to our consolidated balance
sheets.

3.
Acquisitions, Joint Ventures and Divestitures

Acquisitions
from Unrelated Entities

During
2008, 2007 and 2006, we completed the following acquisitions, and except for
our acquisitions from Knight (discussed below in Acquisitions from Knight),
these acquisitions were accounted for as business combinations according to the
provisions of Statement of Financial Accounting Standards No. 141, Business
Combinations. SFAS No. 141 requires business combinations involving unrelated
entities to be accounted for using the purchase method of accounting, which
establishes a new basis of accounting for the purchased assets and
liabilitiesthe acquirer records all the acquired assets and assumed
liabilities at their estimated fair market values (not the acquired entitys
book values) as of the acquisition date.

The
preliminary allocation of these assets (and any liabilities assumed) were
adjusted to reflect the final determined amounts, and although the time that is
required to identify and measure the fair value of the assets acquired and the
liabilities assumed in a business combination will vary with circumstances,
generally our allocation period ends when we no longer are waiting for
information that is known to be available or obtainable. The results of
operations from these acquisitions accounted for as business combinations are
included in our consolidated financial statements from the acquisition date.

Allocation
 of Purchase Price(in
 millions)Ref.

Date

Acquisition

Purchase
 Price

Current
 Assets

Property
 Plant &
 Equipment

Deferred
 Charges
 & Other

Goodwill(1)

2/06

Entrega Gas Pipeline
LLC

$
244.6

$


$
244.6

$


$
(2)

4/06

Oil and Gas Properties


63.6


0.1


63.5





(3)

4/06

Terminal Assets


61.9


0.5


43.6





17.8(4)

11/06

Transload Services,
LLC


16.6


1.6


6.6





8.4(5)

12/06

Devco USA L.L.C.


7.3


0.8





6.5


(6)

12/06

Roanoke, Virginia Products
Terminal


6.4





6.4





(7)

1/07

Interest in Cochin
Pipeline


47.8





47.8





(8)

5/07

Vancouver Wharves Marine
Terminal


59.5


6.1


53.4





(9)

9/07

Marine Terminals, Inc.
Assets


102.1


0.2


60.8


22.5


18.6(10)

8/08

Wilmington, North Carolina
Liquids Terminal


12.7





5.9





6.8(11)

12/08

Phoenix, Arizona Products
Terminal


27.5





27.5





(1)
Entrega Gas Pipeline LLC

Effective
February 23, 2006, Rockies Express Pipeline LLC acquired Entrega Gas Pipeline
LLC from EnCana Corporation for $244.6 million in cash. West2East Pipeline LLC
is a limited liability company and is the sole owner of Rockies Express
Pipeline LLC. We contributed 66 2/3% of the consideration for this purchase,
which corresponded to our percentage ownership of West2East Pipeline LLC at
that time. At the time of acquisition, Sempra  Energy  held  the  remaining  33  1/3%  ownership  interest  and  contributed  this  same  proportional  amount  of  the  total
consideration.

141

On
the acquisition date, Entrega Gas Pipeline LLC owned the Entrega Pipeline, an
interstate natural gas pipeline of over 300
miles in length. The acquired assets are included in our Natural Gas Pipelines
business segment.

In
April 2006, Rockies Express Pipeline LLC merged with and into Entrega Gas
Pipeline LLC, and the surviving entity was renamed Rockies Express Pipeline
LLC. Going forward, the entire pipeline system (including lines currently being
developed by Rockies Express Pipeline LLC) will be known as the Rockies Express
Pipeline. The combined 1,679-mile pipeline system will be one of the largest
natural gas pipelines ever constructed in North America. The project, with an expected cost of $6.3 billion
(including expansion), will have the capability to transport 1.8 billion cubic feet
per day of natural gas, and binding firm commitments have been secured for all
of the pipeline capacity.

On
June 30, 2006, ConocoPhillips exercised its option to acquire a 25% ownership
interest in West2East Pipeline LLC. On that date, a 24% ownership interest was
transferred to ConocoPhillips, and an additional 1% interest will be
transferred once construction of the entire project is completed. Through our
subsidiary Kinder Morgan W2E Pipeline LLC, we will continue to operate the
project but our ownership interest decreased to 51% of the equity in the
project (down from 66 2/3%). Sempras ownership interest in West2East Pipeline
LLC decreased to 25% (down from 33 1/3%). When construction of the entire
project is completed, our ownership interest will be reduced to 50% at which
time the capital accounts of West2East Pipeline LLC will be trued up to reflect
our 50% economics in the project. We do not anticipate any additional changes
in the ownership structure of the Rockies Express Pipeline project.

West2East
Pipeline LLC qualifies as a variable interest entity as defined by Financial
Accounting Standards Board Interpretation No. 46 (Revised December 2003) (FIN
46R), Consolidation of Variable Interest Entities-an interpretation of ARB No.
51, because the total equity at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support
provided by any parties, including equity holders. Furthermore, following
ConocoPhillips acquisition of its ownership interest in West2East Pipeline LLC
on June 30, 2006, we receive 50% of the economics of the Rockies Express
project on an ongoing basis, and thus, effective June 30, 2006, we were no
longer considered the primary beneficiary of this entity as defined by FIN 46R.
Accordingly, on that date, we made the change in accounting for our investment
in West2East Pipeline LLC from full consolidation to the equity method
following the decrease in our ownership percentage.

Under
the equity method, we record the costs of our investment within the
Investments line on our consolidated balance sheet and as changes in the net
assets of West2East Pipeline LLC occur (for example, earnings and dividends),
we recognize our proportional share of that change in the Investment account.
We also record our proportional share of any accumulated other comprehensive
income or loss within the Accumulated other comprehensive loss line on our
consolidated balance sheet.

In
addition, we have guaranteed our proportionate share of West2East Pipeline
LLCs debt borrowings under a $2 billion credit facility entered into by
Rockies Express Pipeline LLC. For more information on our contingent debt, see
Note 9.

(2) April
2006 Oil and Gas Properties

On
April 5, 2006, Kinder Morgan Production Company L.P. purchased various oil and
gas properties from Journey Acquisition  I, L.P. and Journey 2000, L.P. for an
aggregate consideration of approximately $63.6 million, consisting of $60.0
million in cash and $3.6 million in assumed liabilities. The acquisition was
effective March 1, 2006. However, we divested certain acquired properties that
are not considered candidates for carbon dioxide enhanced oil recovery, thus
reducing our total investment. We received proceeds of approximately $27.1
million from the sale of these properties.

The
properties are primarily located in the Permian Basin area of West Texas,
produce approximately 400 barrels of oil equivalent per day, and include some
fields with potential for enhanced oil recovery development near our current
carbon dioxide operations. The acquired operations are included as part of our
CO2 business segment.

142

(3) April
2006 Terminal Assets

In
April 2006, we acquired terminal assets and operations from A&L Trucking,
L.P. and U.S. Development Group in three separate transactions for an aggregate
consideration of approximately $61.9 million, consisting of $61.6 million in
cash and $0.3 million in assumed liabilities.

The
first transaction included the acquisition of equipment and infrastructure on
the Houston Ship Channel that loads and stores steel products. The acquired
assets complement our nearby bulk terminal facility purchased from General
Stevedores, L.P. in July 2005. The second acquisition included the purchase of
a rail terminal at the Port of Houston that handles both bulk and liquids
products. The rail terminal complements our existing Texas petroleum coke
terminal operations and maximizes the value of our existing deepwater terminal
by providing customers with both rail and vessel transportation options for
bulk products. Thirdly, we acquired the entire membership interest of Lomita
Rail Terminal LLC, a limited liability company that owns a high-volume rail
ethanol terminal in Carson, California. The terminal serves approximately 80%
of the Southern California demand for reformulated fuel blend ethanol with
expandable offloading/distribution capacity, and the acquisition expanded our
existing rail transloading operations. All of the acquired assets are included
in our Terminals business segment. A total of $17.8 million of goodwill was
assigned to our Terminals business segment and the entire amount is expected to
be deductible for tax purposes. We believe the purchase price for the assets,
including intangible assets, exceeded the fair value of acquired identifiable
net assets and liabilitiesin the aggregate, these factors represented
goodwill.

(4)
Transload Services, LLC

Effective
November 20, 2006, we acquired all of the membership interests of Transload
Services, LLC from Lanigan Holdings, LLC for an aggregate consideration of
approximately $16.6 million, consisting of $15.8 million in cash and $0.8
million of assumed liabilities. Transload Services, LLC is a leading provider
of innovative, high quality material handling and steel processing services,
operating 14 steel-related terminal facilities located in the Chicago
metropolitan area and various cities in the United States. Its operations
include transloading services, steel fabricating and processing, warehousing
and distribution, and project staging. Specializing in steel processing and
handling, Transload Services can inventory product, schedule shipments and
provide customers cost-effective modes of transportation. The combined
operations include over 92 acres of outside storage and 445,000 square feet of
covered storage that offers customers environmentally controlled warehouses
with indoor rail and truck loading facilities for handling temperature and
humidity sensitive products. The acquired assets are included in our Terminals
business segment, and the acquisition further expanded and diversified our existing
terminals materials services (rail transloading) operations.

A
total of $8.4 million of goodwill was assigned to our Terminals business
segment, and the entire amount is expected to be deductible for tax purposes.
We believe this acquisition resulted in the recognition of goodwill primarily
because it establishes a business presence in several key markets, taking
advantage of the non-residential and highway construction demand for steel that
contributed to our acquisition price exceeding the fair value of acquired
identifiable net assets and liabilitiesin the aggregate, these factors
represented goodwill.

(5) Devco
USA L.L.C.

Effective
December 1, 2006, we acquired all of the membership interests in Devco USA L.L.C.,
an Oklahoma limited liability company, for an aggregate consideration of
approximately $7.3 million, consisting of $4.8 million in cash, $1.6 million in
common units, and $0.9 million of assumed liabilities. The primary asset
acquired was a technology based identifiable intangible asset, a proprietary
process that transforms molten sulfur into premium solid formed pellets that
are environmentally friendly, easy to handle and store, and safe to transport.
The process was developed internally by Devcos engineers and employees. Devco,
a Tulsa, Oklahoma based company, has more than 20 years of sulfur handling
expertise and we believe the acquisition and subsequent application of this
acquired technology complements our existing dry-bulk terminal operations. We
allocated $6.5 million of our total purchase price to the value of this
intangible asset, and we have included the acquisition as part of our Terminals
business segment.

143

(6)
Roanoke, Virginia Products Terminal

Effective
December 15, 2006, we acquired a refined petroleum products terminal located in
Roanoke, Virginia from Motiva Enterprises, LLC for approximately $6.4 million
in cash. The terminal has storage capacity of approximately 180,000 barrels per
day for refined petroleum products like gasoline and diesel fuel. The terminal
is served exclusively by the Plantation Pipeline and Motiva has entered into a
long-term contract to use the terminal. The acquisition complemented the other
refined products terminals we own in the southeast region of the United States,
and the acquired terminal is included as part our Products Pipelines business
segment.

(7)
Interest in Cochin Pipeline

Effective
January 1, 2007, we acquired the remaining approximate 50.2% interest in the
Cochin pipeline system that we did not already own for an aggregate
consideration of approximately $47.8 million, consisting of $5.5 million in
cash and a note payable having a fair value of $42.3 million. As part of the
transaction, the seller also agreed to reimburse us for certain pipeline
integrity management costs over a five-year period in an aggregate amount not
to exceed $50 million. Upon closing, we became the operator of the pipeline.

The
Cochin Pipeline is a multi-product liquids pipeline consisting of approximately
1,900 miles of pipe operating between Fort Saskatchewan, Alberta, and Windsor,
Ontario, Canada. Its operations are included as part of our Products Pipelines
business segment.

(8)
Vancouver Wharves Terminal

On
May 30, 2007, we purchased the Vancouver Wharves bulk marine terminal from
British Columbia Railway Company, a crown corporation owned by the Province of
British Columbia, for an aggregate consideration of $59.5 million, consisting
of $38.8 million in cash and $20.7 million in assumed liabilities. The
acquisition both expanded and complemented our existing terminal operations,
and all of the acquired assets are included in our Terminals business segment.

In
the first half of 2008, we made our final purchase price adjustments to reflect
final fair value of acquired assets and final expected value of assumed
liabilities. Our adjustments increased Property, Plant and Equipment, net by
$2.7 million, reduced working capital balances by $1.6 million, and increased
long-term liabilities by $1.1 million. Based on our estimate of fair market
values, we allocated $53.4 million of our combined purchase price to Property,
Plant and Equipment, net, and $6.1 million to items included within Current
Assets.

(9) Marine
Terminals, Inc. Assets

Effective
September 1, 2007, we acquired certain bulk terminals assets from Marine
Terminals, Inc. for an aggregate consideration of $102.1 million, consisting of
$100.8 million in cash and assumed liabilities of $1.3 million. The acquired
assets and operations are primarily involved in the handling and storage of
steel and alloys. The acquisition both expanded and complemented our existing
ferro alloy terminal operations and will provide customers further access to
our growing national network of marine and rail terminals. All of the acquired
assets are included in our Terminals business segment.

In
the first nine months of 2008, we paid an additional $0.5 million for purchase
price settlements, and we made purchase price adjustments to reflect final fair
value of acquired assets and final expected value of assumed liabilities. Our
2008 adjustments primarily reflected changes in the allocation of the purchase
cost to intangible assets acquired. Based on our estimate of fair market
values, we allocated $60.8 million of our combined purchase price to Property,
Plant and Equipment, net; $21.7 million to Other intangibles, net; $18.6
million to Goodwill; and $1.0 million to Other current assets and Deferred
charges and other assets.

The
allocation to Other intangibles, net included a $20.1 million amount
representing the fair value of a service contract entered into with Nucor
Corporation, a large domestic steel company with significant operations in the
Southeast region of the United States. For valuation purposes, the service
contract was determined to have a useful life of 20 years, and pursuant to the
contracts provisions, the acquired terminal facilities will continue to
provide Nucor with handling, processing, harboring and warehousing services.

144

The
allocation to Goodwill, which is expected to be deductible for tax purposes,
was based on the fact that this acquisition both expanded and complemented our
existing ferro alloy terminal operations and will provide Nucor and other
customers further access to our growing national network of marine and rail
terminals. We believe the acquired value of the assets, including all
contributing intangible assets, exceeded the fair value of acquired
identifiable net assets and liabilitiesin the aggregate, these factors
represented goodwill.

(10)
Wilmington, North Carolina Liquids Terminal

On
August 15, 2008, we purchased certain terminal assets from Chemserve, Inc. for
an aggregate consideration of $12.7 million, consisting of $11.8 million in
cash and $0.9 million in assumed liabilities. The liquids terminal facility is
located in Wilmington, North Carolina and stores petroleum products and
chemicals. The acquisition both expanded and complemented our existing
Mid-Atlantic region terminal operations, and all of the acquired assets are
included in our Terminals business segment. In the fourth quarter of 2008, we
allocated our purchase price to reflect final fair value of acquired assets and
final expected value of assumed liabilities. A total of $6.8 million of
goodwill was assigned to our Terminals business segment and the entire amount
is expected to be deductible for tax purposes. We believe this acquisition
resulted in the recognition of goodwill primarily because of certain
advantageous factors (including the synergies provided by increasing our
liquids storage capacity in the Southeast region of the U.S.) that contributed
to our acquisition price exceeding the fair value of acquired identifiable net
assets and liabilitiesin the aggregate, these factors represented goodwill.

(11)
Phoenix, Arizona Products Terminal

Effective
December 10, 2008, our West Coast Products Pipelines operations acquired a
refined petroleum products terminal located in Phoenix, Arizona from
ConocoPhillips for approximately $27.5 million in cash. The terminal has
storage capacity of approximately 200,000 barrels for gasoline, diesel fuel and
ethanol. The acquisition complemented our existing Phoenix liquids assets, and
the acquired incremental storage will increase our combined storage capacity in
the Phoenix market by approximately 13%. The acquired terminal is included as
part our Products Pipelines business segment.

Pro Forma
Information

Pro forma
consolidated income statement information that gives effect to all of the
acquisitions we have made and all of the joint ventures we have entered into
since January 1, 2007 as if they had occurred as of January 1, 2007 is not
presented because it would not be materially different from the information
presented in our accompanying consolidated statements of income.

Acquisitions
from Knight

According
to the provisions of Emerging Issues Task Force Issue No. 04-5, Determining
Whether a General Partner, or the General Partners as a Group, Controls a
Limited Partnership or Similar Entity When the Limited Partners Have Certain
Rights, effective January 1, 2006, Knight (which indirectly owns all the
common stock of our general partner) was deemed to have control over us and no
longer accounted for its investment in us under the equity method of
accounting. Instead, as of this date, Knight included our accounts, balances
and results of operations in its consolidated financial statements and, as
required by the provisions of SFAS No. 141, we accounted for each of the two
separate acquisitions discussed below as transfers of net assets between
entities under common control.

Trans
Mountain Pipeline System

On
April 30, 2007, we acquired the Trans Mountain pipeline system from Knight for
$549.1 million in cash. The transaction was approved by the independent
directors of both Knight and KMR following the receipt by such directors of
separate fairness opinions from different investment banks. We paid $549
million of the purchase price on April 30, 2007, and we paid the remaining $0.1
million in July 2007.

145

In
April 2008, as a result of finalizing certain true-up provisions in our
acquisition agreement related to Trans Mountain pipeline expansion spending, we
received a cash contribution of $23.4 million from Knight. Pursuant to the
accounting provisions concerning transfers of net assets between entities under
common control, and consistent with our treatment of cash payments made to
Knight for Trans Mountain net assets in 2007, we accounted for this cash
contribution as an adjustment to equityprimarily as an increase in Partners
Capital in our accompanying consolidated balance sheet. We also included this
$23.4 million receipt as a cash inflow item from investing activities in our
accompanying consolidated statement of cash flows.

The
Trans Mountain pipeline system, which transports crude oil and refined products
from Edmonton, Alberta, Canada to marketing terminals and refineries in British
Columbia and the state of Washington, completed a pump station expansion in
April 2007 that increased pipeline throughput capacity to approximately 260,000
barrels per day. An additional expansion that increased pipeline capacity by
25,000 barrels per day was completed and began service on May 1, 2008. We
completed construction on a final 15,000 barrel per day expansion on October
30, 2008, and total pipeline capacity is now approximately 300,000 barrels per
day.

In
addition, because Trans Mountains operations are managed separately, involve
different products and marketing strategies, and produce discrete financial information
that is separately evaluated internally by our management, we identified our
Trans Mountain pipeline system as a separate reportable business segment prior
to the third quarter of 2008. Following the acquisition of our interests in the
Express and Jet Fuel pipeline systems on August 28, 2008, discussed following,
we combined the operations of our Trans Mountain, Express and Jet Fuel pipeline
systems to represent the Kinder Morgan Canada segment.

Express and
Jet Fuel Pipeline Systems

Effective
August 28, 2008, we acquired Knights 33 1/3% ownership interest in the Express
pipeline system. The pipeline system is a batch-mode, common-carrier, crude oil
pipeline system consisting of both the Express Pipeline and the Platte Pipeline
(collectively referred to in this report as the Express pipeline system). We
also acquired Knights full ownership of an approximately 25-mile jet 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). As consideration for these assets, we paid to Knight approximately 2.0
million common units, valued at $116.0 million. The acquisition complemented
our existing Canadian pipeline system (Trans Mountain), and all of the acquired
assets (including an acquired cash balance of $7.4 million) are included in our
Kinder Morgan Canada business segment.

We
now operate the Express pipeline system, and we account for our 33 1/3%
ownership in the system under the equity method of accounting. In addition to
our 33 1/3% equity ownership, our investment in Express includes an investment
in unsecured debenture bonds issued by Express Holdings U.S. L.P., the
partnership that maintains ownership of the U.S. portion of the Express
pipeline system. For more information on this long-term note receivable, see
Note 12.

When
accounting for transfers of net assets between entities under common control,
the purchase cost provisions (as they relate to purchase business combinations
involving unrelated entities) of SFAS No. 141 explicitly do not apply; instead
the method of accounting prescribed by SFAS No. 141 for such net asset
transfers is similar to the pooling-of-interests method of accounting. Under
this method, the carrying amount of net assets recognized in the balance sheets
of each combining entity are carried forward to the balance sheet of the
combined entity, and no other assets or liabilities are recognized as a result
of the combination (that is, no recognition is made for a purchase premium or
discount representing any difference between the consideration paid and the
book value of the net assets acquired).

Therefore,
in each of these two business acquisitions from Knight, we recognized the
assets and liabilities acquired at their carrying amounts (historical cost) in
the accounts of Knight (the transferring entity) at the date of transfer. The
accounting treatment for combinations of entities under common control is
consistent with the concept of poolings as combinations of common shareholder
(or unitholder) interests, as the carrying amount of the assets and liabilities
transferred to us were carried forward to our balance sheet, and all of the
acquired equity accounts were also carried forward intact initially, and
subsequently adjusted due to differences between (i) the consideration we paid
for the acquired net assets; and (ii) the book value (carrying value) of the
acquired net assets.

146

In
addition to requiring that assets and liabilities be carried forward at
historical costs, SFAS No. 141 also prescribes that for transfers of net assets
between entities under common control, all financial statements presented be
combined as of the date of common control, and all financial statements and
financial information presented for prior periods should be restated to furnish
comparative information. However, based upon our managements consideration of
all of the quantitative and qualitative aspects of the transfer of the
interests in the Express and Jet Fuel pipeline system net assets from Knight to
us, we determined that the presentation of combined financial statements which
include the financial information of the Express and Jet Fuel pipeline systems
would not be materially different from financial statements which did not
include such information and accordingly, we elected not to include the
financial information of the Express and Jet Fuel pipeline systems in our
consolidated financial statements for any periods prior to the transfer date of
August 28, 2008.

Our
consolidated financial statements and all other financial information included
in this report therefore, have been prepared assuming that the transfer of
both the 33 1/3% interest in the Express pipeline system net assets and the Jet
Fuel pipeline system net assets from Knight to us had occurred at the date of
transfer (August 28, 2008).

Joint Ventures

Rockies Express
Pipeline
LLC

In
the first quarter of 2008, we made capital contributions of $306.0 million to
West2East Pipeline LLC (the sole owner of Rockies Express Pipeline LLC) to
partially fund its Rockies Express Pipeline construction costs. We included
this cash contribution as an increase to Investments in our accompanying
consolidated balance sheet as of December 31, 2008, and we included it within
Contributions to investments in our accompanying consolidated statement of
cash flows for the year ended December 31, 2008. We own a 51% equity interest
in West2East Pipeline LLC.

On
June 24, 2008, Rockies Express completed a private offering of an aggregate of
$1.3 billion in principal amount of fixed rate senior notes. Rockies Express
received net proceeds of approximately $1.29 billion from this offering, after
deducting the initial purchasers discount and estimated offering expenses, and
virtually all of the net proceeds from the sale of the notes were used to repay
short-term commercial paper borrowings.

All
payments of principal and interest in respect of these senior notes are the
sole obligation of Rockies Express. Noteholders will have no recourse against
us, Sempra Energy or ConocoPhillips (the two other member owners of West2East
Pipeline LLC), or against any of our or their respective officers, directors,
employees, shareholders, members, managers, unitholders or affiliates for any
failure by Rockies Express to perform or comply with its obligations pursuant
to the notes or the indenture.

Midcontinent Express
Pipeline LLC

In
2008, we made capital contributions of $27.5 million to Midcontinent Express
Pipeline LLC to partially fund its Midcontinent Express Pipeline construction
costs. We included this cash contribution as an increase to Investments in
our accompanying consolidated balance sheet as of December 31, 2008, and we
included it within Contributions to investments in our accompanying
consolidated statement of cash flows for the year ended December 31, 2008. We
own a 50% equity interest in Midcontinent Express Pipeline LLC.

We
also received, in the first quarter of 2008, an $89.1 million return of capital
from Midcontinent Express Pipeline LLC. In February 2008, Midcontinent entered
into and then made borrowings under a new $1.4 billion three-year, unsecured
revolving credit facility due February 28, 2011. Midcontinent then made
distributions (in excess of cumulative earnings) to its two member owners to
reimburse them for prior contributions made to fund its pipeline construction
costs, and we reflected this cash receipt separately within the investing
section of our accompanying consolidated statement of cash flows.

147

Fayetteville Express
Pipeline LLC

On
October 1, 2008, we announced that we have entered into a 50/50 joint venture
with Energy Transfer Partners, L.P. to build and develop the Fayetteville
Express Pipeline, a new natural gas pipeline that will provide shippers in the
Arkansas Fayetteville Shale area with takeaway natural gas capacity, added
flexibility, and further access to growing markets.

The
new pipeline will also interconnect with Natural Gas Pipeline Company of
America LLCs pipeline in White County, Arkansas; Texas Gas Transmission LLCs
pipeline in Coahoma County, Mississippi; and ANR Pipeline Companys pipeline in
Quitman County, Mississippi. Natural Gas Pipeline Company of Americas pipeline
is operated and 20% owned by Knight. The Fayetteville Express Pipeline will
have an initial capacity of two billion cubic feet of natural gas per day.
Pending necessary regulatory approvals, the approximately $1.2 billion pipeline
project is expected to be in service by late 2010 or early 2011. Fayetteville
Express Pipeline LLC has secured binding 10-year commitments totaling
approximately 1.85 billion cubic feet per day.

In
the fourth quarter of 2008, we made capital contributions of $9.0 million to
Fayetteville Express Pipeline LLC to fund our proportionate share of certain
pre-construction pipeline costs. We included this cash contribution as an
increase to Investments in our accompanying consolidated balance sheet as of
December 31, 2008, and we included it within Contributions to investments in
our accompanying consolidated statement of cash flows for the year ended
December 31, 2008.

Divestitures

Douglas Gas
Gathering and Painter Gas Fractionation

Effective
April 1, 2006, we sold our Douglas natural gas gathering system and our Painter
Unit fractionation facility to Momentum Energy Group, LLC for approximately
$42.5 million in cash. Our investment in the net assets we sold in this
transaction, including all transaction related accruals, was approximately
$24.5 million, most of which represented property, plant and equipment, and we
recognized approximately $18.0 million of gain on the sale of these net assets.
We used the proceeds from these asset sales to reduce the outstanding balance
on our commercial paper borrowings.

Additionally,
upon the sale of our Douglas gathering system, we reclassified a net loss of
$2.9 million from Accumulated other comprehensive loss into net income on
those derivative contracts that effectively hedged uncertain future cash flows
associated with forecasted Douglas gathering transactions. We included the net
amount of the gain, $15.1 million, within the caption Other expense (income)
in our accompanying consolidated statement of income for the year ended
December 31, 2006. For more information on our accounting for derivative
contracts, see Note 14.

North System
Natural Gas
Liquids Pipeline System  Discontinued Operations

On
July 2, 2007, we announced that we entered into an agreement to sell the North
System natural gas liquids pipeline and our 50% ownership interest in the
Heartland Pipeline Company (collectively referred to in this report as our
North System) to ONEOK Partners, L.P. for approximately $298.6 million in cash.
Our investment in net assets, including all transaction related accruals, was
approximately $145.8 million, most of which represented property, plant and
equipment, and we recognized approximately $152.8 million of gain in the fourth
quarter of 2007 from the sale of these net assets. We reported this gain
separately as Gain on disposal of North System within the discontinued
operations section of our accompanying consolidated statement of income for the
year ended December 31, 2007. Prior to the sale, all of the assets were
included in our Products Pipelines business segment.

In
the first half of 2008, following final account and inventory reconciliations,
we paid a net amount of $2.4 million to ONEOK to fully settle amounts related
to (i) working capital items; (ii) total physical product liquids inventory and
inventory obligations for certain liquids products; and (iii) the allocation of
pre-acquisition investee distributions. Based primarily upon these adjustments,
which were below the amounts reserved, we recognized an additional gain of $1.3
million in 2008, and we reported this gain separately as Adjustment to gain on
disposal of

148

North System within the
discontinued operations section of our accompanying consolidated statement of
income for the year ended December 31, 2008.

In
accordance with SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, we accounted for the North System business as a
discontinued operation whereby the financial results and the gains on disposal
of the North System have been reclassified to discontinued operations in our
accompanying consolidated statements of income.

Summarized
financial information of the North System is as follows (in millions):

Year Ended
 December 31,2008

2007

2006Operating revenues

$


$
41.1

$
43.7Operating expenses





(14.8
)

(22.7
)Depreciation and
 amortization





(7.0
)

(8.9
)Earnings from equity
 investments





1.8


2.2Amortization of excess cost
 of equity investments








(0.1
)Other, net  income (expense)








0.1Income from
operations





21.1


14.3Gain on
disposal


1.3


152.8


Total earnings
from discontinued operations

$
1.3

$
173.9

$
14.3Additionally,
in our accompanying consolidated statement of cash flows, we elected not to
present separately the North Systems operating and investing cash flows as
discontinued operations, and, because
the sale of the North System does not change the structure of our internal
organization in a manner that causes a change to our reportable business
segments pursuant to the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, we have included the North
Systems financial results within our Products Pipelines business segment
disclosures for all periods presented in this report.

Thunder
Creek Gas Services, LLC

Effective
April 1, 2008, we sold our 25% ownership interest in Thunder Creek Gas
Services, LLC, referred to in this report as Thunder Creek, to PVR Midstream
LLC, a subsidiary of Penn Virginia Corporation. Prior to the sale, we accounted
for our investment in Thunder Creek under the equity method of accounting and
included its financial results within our Natural Gas Pipelines business
segment. In the second quarter of 2008, we received cash proceeds, net of
closing costs and settlements, of approximately $50.7 million for our
investment, and we recognized a gain of $13.0 million with respect to this transaction.
We used the proceeds from this sale to reduce the outstanding balance on our
commercial paper borrowings, and we included the amount of the gain within the
caption Other, net in our accompanying consolidated statement of income for
the year ended December 31, 2008.

4.
Asset Retirement Obligations

According
to the provisions of Financial Accounting Standards No. 143, Accounting for
Asset Retirement Obligations, we record liabilities for obligations related to
the retirement and removal of long-lived assets used in our businesses. We
record, as liabilities, the fair value of asset retirement obligations on a
discounted basis when they are incurred, which is typically at the time the
assets are installed or acquired. Amounts recorded for the related assets are
increased by the amount of these obligations. Over time, the liabilities
increase due to the change in their present value, and the initial capitalized
costs will be depreciated over the useful lives of the related assets. The liabilities
are eventually extinguished when the asset is taken out of service.

In
our CO2 business segment, we are required to plug and abandon oil
and gas wells that have been removed from service and to remove our surface
wellhead equipment and compressors. As of December 31, 2008 and December 31,
2007, we have recognized asset retirement obligations in the aggregate amount
of $74.1 million and $49.2 million, respectively, relating to these
requirements at existing sites within our CO2 business segment. The
$24.9 million increase since December 31, 2007 was primarily related to higher
estimated service, material and equipment costs related to our legal
obligations associated with the retirement of tangible long-lived assets.

149

In
our Natural Gas Pipelines business segment, the operating systems are composed
of underground piping, compressor stations and associated facilities, natural
gas storage facilities and certain other facilities and equipment. Currently,
we have no plans to abandon any of these facilities, the majority of which have
been providing utility services for many years. However, if we were to cease
providing utility services in total or in any particular area, we may be
required to remove certain surface facilities and equipment from land belonging
to our customers and others (we would generally have no obligations for removal
or remediation with respect to equipment and facilities, such as compressor
stations, located on land we own). We believe we can reasonably estimate both
the time and costs associated with the retirement of these facilities and as of
December 31, 2008 and December 31, 2007, we have recognized asset retirement
obligations in the aggregate amount of $2.4 million and $3.0 million,
respectively, relating to the businesses within our Natural Gas Pipelines
business segment.

We
have included $2.5 million of our total asset retirement obligations as of
December 31, 2008 with Accrued other current liabilities in our accompanying
consolidated balance sheet. The remaining $74.0 million obligation is reported
separately as a non-current liability. A reconciliation of the beginning and
ending aggregate carrying amount of our asset retirement obligations for each
of the years ended December 31, 2008 and 2007 is as follows (in millions):

Year Ended
 December 31,2008

2007Balance at beginning of
 period

$
52.2

$
50.3Liabilities
incurred/revised


26.2


0.4Liabilities
settled


(5.4
)

(1.1
)Accretion
expense


3.5


2.6Balance at end of period

$
76.5

$
52.2We
have various other obligations throughout our businesses to remove facilities
and equipment on rights-of-way and other leased facilities. We currently
cannot reasonably estimate the fair
value of these obligations because the associated assets have indeterminate
lives. These assets include
pipelines, certain processing plants and distribution facilities, and certain
bulk and liquids terminal facilities. An asset retirement obligation, if any,
will be recognized once sufficient information is available to reasonably
estimate the fair value of the obligation.

5.
Income Taxes

Components
of the income tax provision applicable to continuing operations for federal,
foreign and state taxes are as follows (in millions):



Year Ended December 31,2008

2007

2006Taxes current expense:Federal

$
24.4

$
12.7

$
12.8State


8.5


8.2


2.3Foreign


(4.5)


31.5


11.2Total


28.4


52.4


26.3Taxes deferred expense:Federal


6.0


11.8


1.6State


1.5


6.2


0.2Foreign


(15.5)


0.6


0.9Total


(8.0)


18.6


2.7Total tax provision

$
20.4

$
71.0

$
29.0Effective tax rate


1.5
%

14.6
%

2.8
%The
difference between the statutory federal income tax rate and our effective
income tax rate is summarized as follows:

150

Year Ended December 31,2008

2007

2006Federal income tax rate


35.0
%

35.0
%

35.0
%Increase (decrease) as a result of:Partnership
earnings not
 subject to tax


(35.0
)%

(35.0
)%

(35.0
)%Corporate
subsidiary earnings
 subject to tax


1.6
%

3.0
%

1.0
%Income tax
expense attributable
 to corporate equity earnings


0.6
%

2.3
%

0.5
%Income tax
expense attributable
 to foreign corporate earnings


(1.2)
%

6.6
%

1.1
%State
taxes


0.5
%

2.7
%

0.2
%Effective tax rate


1.5
%

14.6
%

2.8
%Our
deferred tax assets and liabilities as of December 31, 2008 and
2007 result from the following (in
millions):

December 31,2008

2007Deferred tax assets:Book
accruals

$
3.2

$
13.1Net Operating
Loss/Alternative
 minimum tax credits


1.4


1.2Other


1.8


1.7Total deferred tax assets


6.4


16.0Deferred tax liabilities:Property, plant
and equipment


161.3


189.9Other


23.1


28.5Total deferred tax liabilities


184.4


218.4Net deferred tax liabilities

$
178.0

$
202.4Pursuant to
the provisions of FASBs Interpretation No. 48, Accounting for Uncertainty
in Income Taxesan Interpretation of FASB Statement No. 109, which became
effective January 1, 2007, we must recognize the tax benefit from an uncertain
tax position only if it is more likely than not that the tax position will be
sustained on examination by the taxing authorities, based not only on the
technical merits of the tax position based on tax law, but also the past
administrative practices and precedents of the taxing authority. The tax
benefits recognized in the financial statements from such a position are
measured based on the largest benefit that has a greater than 50% likelihood of
being realized upon ultimate resolution.

Our
adoption of FIN No. 48 on January 1, 2007 did not result in a cumulative effect
adjustment to Partners Capital on our consolidated balance sheet. A
reconciliation of our beginning and ending gross unrecognized tax benefits for
each of the years ended December 31, 2008 and 2007 is as follows (in millions):


Year Ended
 December 31,2008

2007Balance at beginning of
 period

$
6.3

$
3.2Additions based
on current year tax positions


0.4


4.7Additions based
on prior year tax positions


9.6


0.1Reductions
based on settlements with taxing authority


(0.1
)

Reductions due
to lapse in statute of limitations


(1.3
)

(1.7
)Balance at end of period

$
14.9

$
6.3As
of December 31, 2007, we had $0.7 million of accrued interest and no accrued
penalties, and our continuing practice is to recognize interest and/or
penalties related to income tax matters in income tax expense. During the year
ended December 31, 2008, we recognized approximately $0.5 million
in interest expense, and during the year ended December 31, 2007, we
recognized interest income of approximately $0.4 million.

151

As
of December 31, 2008 (i) we had $1.2 million of accrued
interest and no accrued penalties; (ii) we believe it is
reasonably possible that our liability for unrecognized tax benefits will
decrease by approximately $0.2 million during the next
twelve months; and (iii) we believe approximately all of the total $14.9 million
of unrecognized tax benefits on our
consolidated balance sheet as of December 31, 2008 would affect our effective
income tax rate in future periods in the event those unrecognized tax benefits
were recognized. In addition, we have U.S. and state tax years open to
examination for the periods 2003 through 2008.

6.
Property, Plant and Equipment

Classes
and Depreciation

As
of December 31, 2008 and 2007, our property, plant and equipment consisted of
the following (in millions):

December 31,2008

2007Natural gas, liquids, crude oil and carbon dioxide pipelines

$
5,752.4

$
5,498.4Natural gas, liquids, carbon dioxide pipeline, and terminals station
 equipment


6,432.1


5,076.2Natural gas, liquids (including linefill), and transmix processing


210.3


168.3Other


1,523.1


1,060.4Accumulated depreciation and depletion


(2,554.0
)

(2,044.0
)11,363.9


9,759.3Land and land right-of-way


549.0


551.5Construction work in process


1,328.5


1,280.5Property, Plant and Equipment, net

$
13,241.4

$
11,591.3Depreciation
and depletion expense charged against property, plant and equipment consisted
of $684.2 million in 2008, $529.3 million in 2007 and $416.6 million in 2006.

Property
Casualties

2005
Hurricanes

On August
29, 2005, Hurricane Katrina made landfall in the United States Gulf Coast causing
widespread damage to residential and commercial property. In addition, on
September 23, 2005, Hurricane Rita struck the Texas-Louisiana Gulf Coast
causing additional damage to insured interests. The primary assets we operate
that were impacted by these storms included several bulk and liquids terminal
facilities located in the states of Louisiana and Mississippi, and certain of
our Gulf Coast liquids terminals facilities, which are located along the
Houston Ship Channel. All of our terminal facilities affected by these storms
were repaired and re-opened, and all of the facilities were covered by property
casualty insurance. Some of the facilities were also covered by business
interruption insurance.

In the
fourth quarter of 2006, we reached settlements with our insurance carriers on
all of our property damage claims related to the 2005 hurricane season and as a
result of these settlements, we recognized a property casualty gain of $15.2
million, excluding all hurricane repair and clean-up expenses. This casualty
gain represented the excess of indemnity proceeds received or recoverable over
the book value of damaged or destroyed assets. We also recognized additional
casualty gains of approximately $1.8 million in the first quarter of 2007, based
upon our final determination of the book value of the fixed assets destroyed or
damaged and indemnities pursuant to flood insurance coverage. These
recognized casualty gains are reported within the captions Other expense
(income) in our accompanying consolidated statements of income for each of the
years ended December 31, 2006 and 2007.

152

In addition
to the $15.2 million casualty gain, 2006 income and expense items related to
hurricane activity included the following (i) a $2.8 million increase
in operating and maintenance expenses from hurricane repair and clean-up
activities, (ii) a $1.1 million increase in income tax expense associated with
overall hurricane income and expense items, (iii) a $0.4 million decrease in
general and administrative expenses from the allocation of overhead expenses to
hurricane related capital projects, and (iv) a $3.1 million increase in
minority interest expense related to the allocation of hurricane income and
expense items to minority interest. Combined, the hurricane income and expense
items, including the casualty gain, resulted in a total increase in net income
of $8.6 million in 2006.

We also
collected, in 2006 and 2007, property insurance indemnities of $13.1 million
and $8.0 million, respectively, and we disclosed these cash receipts separately
as Property casualty indemnifications within investing activities on our
accompanying consolidated statements of cash flows. We also incurred capital
expenditures related to the repair and replacement of damaged assets due to
these 2005 storms. For the year 2006, we spent approximately $12.2 million for
hurricane repair and replacement costs and including accruals, sustaining
capital expenditures for hurricane repair and replacement costs totaled $14.2
million.

2008
Hurricanes and Fires

In
September 2008, two hurricanes struck the Gulf Coast communities of southern
Texas and Louisiana and a third hurricane made U.S. landfall near the South
Carolina-North Carolina border. The three named hurricanesHanna, Gustav, and
Ikecaused wide-spread damage to residential and commercial property but our
primary assets in those areas experienced only relatively minor damage. We
realized a combined $11.1 million decrease in net income due to incremental
expenses associated with the clean-up and asset damage from these storms (but
excluding estimates for lost business and lost revenues). The decrease to net
income primarily consisted of a $10.5 million increase in operating and
maintenance expenses from hurricane repair and clean-up activities included
within the caption Operations and maintenance in our accompanying
consolidated statement of income for 2008.

Additionally,
in the third quarter of 2008, we experienced fire damage at three separate
terminal locations. The largest was an explosion and fire at our Pasadena,
Texas liquids terminal facility on September 23, 2008. The fire primarily
damaged a manifold system used for liquids distribution. We intend to repair
the damaged portions of each separate terminal facility, and we recognized a
combined $7.2 million decrease in net income due to incremental expenses and
asset damage associated with these fires (excluding estimates for lost business
and lost revenues). The decrease to net income primarily consisted of combined
casualty losses totaling $5.3 million and reported within the caption Other
expense (income) in our accompanying consolidated statement of income for
2008.

7.
Investments

Our
long-term investments as of December 31, 2008 consisted of equity investments
totaling $941.1 million and bond investments totaling $13.2 million. Our bond
investments consist of certain tax exempt, fixed-income development revenue
bonds acquired in the fourth quarter of 2008. Because we have both the ability
and the intent to hold these debt securities to maturity, we account for these
investments at historical cost. Our bond investments are further discussed in
Note 9.

Our
significant equity investments as of December 31, 2008 consisted of:

 West2East Pipeline LLC (51%); Plantation Pipe Line Company (51%); Red Cedar Gathering Company (49%); Express pipeline system (33 1/3%); Cortez Pipeline Company (50%); and Midcontinent Express Pipeline LLC (50%).153

We operate
and own a 51% ownership interest in West2East Pipeline LLC, a limited liability
company that is the sole owner of Rockies Express Pipeline LLC. ConocoPhillips
owns a 24% ownership interest in West2East
Pipeline LLC and Sempra Energy holds the remaining 25% interest. As
discussed in Note 3, when construction of the entire Rockies Express Pipeline
project is completed, our ownership interest will be reduced to 50% at which
time the capital accounts of West2East Pipeline LLC will be trued up to reflect
our 50% economics in the project. According to the provisions of current
accounting standards, because we will receive 50% of the economics of the
Rockies Express project on an ongoing basis, we are not considered the primary
beneficiary of West2East Pipeline LLC and thus, we account for our investment
under the equity method of accounting. Prior to June 30, 2006, we owned a 66
2/3% ownership interest in West2East Pipeline LLC and we accounted for our
investment under the full consolidation method. Following the decrease in our
ownership interest to 51% effective June 30, 2006, we deconsolidated this
entity and began to account for our investment under the equity method of
accounting.

Similarly,
we operate and own an approximate 51% ownership interest in Plantation Pipe
Line Company, and an affiliate of ExxonMobil owns the remaining approximate 49%
interest. Each investor has an equal number of directors on Plantations board
of directors, and board approval is required for certain corporate actions that
are considered participating rights. Therefore, we do not control Plantation
Pipe Line Company, and we account for our investment under the equity method.

We acquired
our ownership interest in the Red Cedar Gathering Company from Knight (then
Kinder Morgan, Inc.) on December 31, 1999. We acquired our ownership interest
in the Express pipeline system from Knight effective August 28, 2008. We
acquired a 50% ownership interest in Cortez Pipeline Company from affiliates of
Shell in April 2000. We formed Midcontinent Express Pipeline LLC in May 2006.

In 2007, we
began making cash contributions to Midcontinent Express, the sole owner of the Midcontinent
Express Pipeline, for our share of the
Midcontinent Express Pipeline construction costs; however, as of December 31,
2008, we had no net investment in Midcontinent Express because in 2008, Midcontinent
Express established and made borrowings under its own revolving bank credit
facility in order to fund its pipeline construction costs and to make
distributions to its member owners to fully reimburse them for prior
contributions.

In
January 2008, Midcontinent Express Pipeline LLC and MarkWest Pioneer, L.L.C. (a
subsidiary of MarkWest Energy Partners, L.P.) entered into an option agreement
which provides MarkWest a one-time right to purchase a 10% ownership interest
in Midcontinent Express Pipeline LLC after the pipeline is fully constructed
and fully placed into servicecurrently estimated to be August 1, 2009. If the option
is exercised, we and Energy Transfer Partners, L.P. will each own 45% of
Midcontinent Express Pipeline LLC, while MarkWest will own the remaining 10%.

In addition
to the investments listed above (excluding Express), our significant equity investments
as of December 31, 2007 included our 25% equity interest in Thunder Creek Gas
Services, LLC. We sold our ownership interest in Thunder Creek to PVR Midstream
LLC on April 1, 2008. Both the acquisition of our investment in Express and the
divestiture of our investment in Thunder Creek are discussed in Note 3.

Our total
equity investments consisted of the following (in millions):

December 31,2008

2007West2East Pipeline LLC

$
501.1

$
191.9Plantation Pipe Line Company


196.6


195.4Red Cedar Gathering Company


138.9


135.6Express pipeline system


64.9


Cortez Pipeline Company


13.6


14.2Midcontinent Express Pipeline LLC





63.0Thunder Creek Gas Services, LLC





37.0All others


26.0


18.3Total equity investments

$
941.1

$
655.4Our
earnings (losses) from equity investments were as follows (in millions):

154

Year Ended December 31,2008

2007

2006West2East Pipeline LLC

$
84.9

$
(12.4
)
$
Red Cedar Gathering Company


26.7


28.0


36.3Plantation Pipe Line Company


22.3


29.4


12.8Cortez Pipeline Company


20.8


19.2


19.2Thunder Creek Gas Services, LLC


1.3


2.2


2.4Midcontinent Express Pipeline LLC


0.5


1.4


Express pipeline system


(0.5
)




All others


4.8


1.9


3.3Total

$
160.8

$
69.7

$
74.0Amortization of excess costs

$
(5.7
)
$
(5.8
)
$
(5.6
)Summarized
combined unaudited financial information for our significant equity investments
(listed or described above) is reported below (in millions; amounts represent
100% of investee financial information):

Year Ended December 31,Income Statement

2008

2007

2006Revenues

$
1,015.0

$
473.0

$
441.9Costs and expenses


681.6


355.1


299.5Earnings before extraordinary
 items and Cumulative effect of a change in accounting principle


333.4


117.9


142.4Net income

$
333.4

$
117.9

$
142.4December 31,Balance Sheet

2008

2007Current assets

$
221.7

$
138.3Non-current assets


6,797.5


3,519.5Current liabilities


3,690.1


319.5Non-current liabilities


2,015.3


2,624.1Partners/owners equity


1,313.8


714.28.
IntangiblesGoodwill
and Excess Investment Cost

As
an investor, the price we pay to acquire an ownership interest in an investees
net assets will most likely differ from the underlying interest in the net
assets book value, with book value representing the investees net assets per
its financial statements. This differential
relates to both discrepancies between the investees recognized net assets at
book value and at current fair values and to any premium we pay to acquire the
investment. Under ABP No. 18, any such premium paid by an investor,
which is analogous to goodwill, must be identified.

For
our investments in affiliated entities that are included in our consolidation,
the excess cost over underlying fair value of net assets is referred to as
goodwill and reported separately as Goodwill in our accompanying consolidated
balance sheets. Goodwill is not subject to amortization but must be tested for
impairment at least annually. This test requires us to assign goodwill to an
appropriate reporting unit and to determine if the implied fair value of the
reporting units goodwill is less than its carrying amount.

Pursuant
to our adoption of SFAS No. 142, Goodwill and Other Intangible Assets on
January 1, 2002, we selected a goodwill impairment measurement date of January
1 of each year; and we have determined that our goodwill was not impaired as of
January 1, 2008. In the second quarter of 2008, we changed our impairment
measurement date to May 31 of each year. The change was made following our
managements decision to match our impairment testing date to the impairment
testing date of Knightfollowing the completion of its going-private
transaction on May 30, 2007, Knight established May 31 of each year as its
goodwill impairment measurement date. This change in the date of our annual
goodwill impairment test constitutes a change in the method of applying an
accounting principle, as discussed in paragraph 4 of SFAS No. 154, Accounting
Changes and Error Corrections. We believe that this change in accounting
principle is preferable because our test would then be performed at the same
time as Knight, which indirectly owns all the common stock of our general
partner.

155

SFAS
No. 154 requires an entity to report a change in accounting principle through
retrospective application of the new accounting principle to all periods,
unless it is impracticable to do so. However, our change to a new testing date,
when applied to prior periods, does not yield different financial statement
results. Furthermore, there were no impairment charges resulting from the May
31, 2008 impairment testing, and no event indicating an impairment has occurred
subsequent to that date.


In
conjunction with our goodwill impairment test on May 31, 2008, the fair value of each of our
segments reporting units was determined from the present value of the expected future cash flows from
the applicable reporting unit (inclusive of a terminal value calculated using market multiples between
six and nine times cash flows) discounted at a rate of 9.0%.  In accordance with paragraph 23 of SFAS
No. 142, the value of each reporting unit was determined on a stand-alone basis from the perspective of
a market participant and represented the price that would be received to sell the unit as a whole in an
orderly transaction between market participants at the measurement date.


Changes
in the carrying amount of our goodwill for each of the two years ended December
31, 2007 and 2008 are summarized as follows (in millions):

Products
 Pipelines

Natural Gas
 Pipelines

CO2

Terminals

Kinder
 Morgan
 Canada(a)

TotalBalance as
 of December 31, 2006

$
263.2

$
288.4

$
46.1

$
231.3

$
592.0

$
1,421.0Acquisitions and purchase price
adjs.











(2.2
)




(2.2
)Disposals

















Impairments














(377.1
)

(377.1
)Currency translation
adjustments














36.1


36.1Balance as
 of December 31, 2007

$
263.2

$
288.4

$
46.1

$
229.1

$
251.0

$
1,077.8Acquisitions and purchase price
adjs.











28.5





28.5Disposals

















Impairments

















Currency translation
adjustments














(47.4
)

(47.4
)Balance as
 of December 31, 2008

$
263.2

$
288.4

$
46.1

$
257.6

$
203.6

$
1,058.9(a)
On April 18, 2007, we announced that we would
 acquire the Trans Mountain pipeline system from Knight, and this transaction
 was completed April 30, 2007 (discussed in Note 3). Following the provisions
 of generally accepted accounting principles, the consideration of this
 transaction caused Knight to consider the fair value of the Trans Mountain
 pipeline system, and to determine whether goodwill related to these assets
 was impaired. Based on this determination, Knight recorded a goodwill
 impairment charge of $377.1 million in the first quarter of 2007, and because
 we have included all of the historical results of Trans Mountain as though
 the net assets had been transferred to us on January 1, 2006, this impairment
 expense is now reflected in our consolidated results of operations.For our
investments in entities that are not fully consolidated but instead are
included in our financial statements under the equity method of accounting, the
premium we pay that represents excess cost over underlying fair
value of net assets is referred to as equity method goodwill, and under SFAS
No. 142, this excess cost is not subject to amortization but rather to
impairment testing pursuant to APB No. 18. The impairment test under APB No. 18
considers whether the fair value of the equity investment as a whole, not the
underlying net assets, has declined and whether that decline is other than
temporary. Therefore, we periodically reevaluate the amount at which we carry
the excess of cost over fair value of net assets accounted for under the equity
method, as well as the amortization period for such assets, to determine
whether current events or circumstances warrant adjustments to our carrying
value and/or revised estimates of useful lives in accordance with APB Opinion
No. 18. As of both December 31, 2008 and 2007, we have reported $138.2 million
in equity method goodwill within the caption Investments in our accompanying
consolidated balance sheets.

We
also periodically reevaluate the difference between the fair value of net
assets accounted for under the equity method and our proportionate share of the
underlying book value (that is, the investees net assets per its financial
statements) of the investee at date of acquisition. In almost all instances,
this differential, relating to the discrepancy between our share of the
investees recognized net assets at book values and at current fair values,
represents our share of undervalued depreciable assets, and since those assets
(other than land) are subject to depreciation, we amortize this portion of our
investment cost against our share of investee earnings. We reevaluate this
differential, as well as the amortization period for such undervalued
depreciable assets, to determine whether current events or circumstances
warrant adjustments to our carrying value and/or revised estimates of useful
lives in accordance with APB Opinion No. 18. The caption Investments in our
accompanying consolidated balance sheets includes excess fair value of net
assets over book value costs of $169.0 million as of December 31, 2008 and
$174.7 million as of December 31, 2007.

156

Other
Intangibles

Excluding
goodwill, our other intangible assets 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 our accompanying consolidated balance sheets. Following is
information related to our intangible assets subject to amortization (in
millions):

December
 31,
 2008

December
 31,
 2007Customer relationships, contracts and
agreementsGross carrying amount

$
246.0

$
264.1Accumulated
amortization


(51.1
)

(36.9
)Net carrying amount


194.9


227.2Technology-based assets,
 lease value and otherGross carrying amount


13.3


13.3Accumulated
amortization


(2.4
)

(1.9
)Net carrying amount


10.9


11.4Total Other intangibles,
 net

$
205.8

$
238.6Our
customer relationships, contracts and agreements relate primarily to our
Terminals business segment, and include relationships and contracts for
handling and storage of petroleum, chemical, and dry-bulk materials, including
oil, gasoline and other refined petroleum products, coal, petroleum coke,
fertilizer, steel and ores. The values of these intangible assets were
determined by us (often in conjunction with third party valuation specialists)
by first, estimating the revenues derived from a customer relationship or
contract (offset by the cost and expenses of supporting assets to fulfill the contract), and
secondly, discounting the revenues at a risk adjusted discount rate.

The
decrease in the carrying amount of customer relationships, contracts and
agreements since December 31, 2007 was primarily due to purchase price
adjustments related to the fair value of an intangible customer contract
included in our purchase of certain assets from Marine Terminals, Inc. on
September 1, 2007. For more information on this acquisition, see Note 3
Acquisitions and Joint VenturesAcquisitions from Unrelated EntitiesMarine
Terminals, Inc. Assets.

We
amortize our intangible assets by applying the straight-line method - the
method of amortizing cost to amortization expense such that there is an even
allocation of expense over the life of the intangible. We believe amortizing
our intangibles on a straight-line basis most appropriately recognizes the pattern
of economic benefits realized from these assets, because our experience has
demonstrated that the benefit generally will be realized through the cash flows
under each asset essentially equally throughout its corresponding life. For the
years ended December 31, 2008, 2007 and 2006, the amortization expense on our
intangibles totaled $14.7 million, $14.3 million and $13.7 million,
respectively. These expense amounts primarily consisted of amortization of our
customer relationships, contracts and agreements. Our estimated amortization
expense for these assets for each of the next five fiscal years (2009  2013)
is approximately $13.8 million, $13.6 million, $13.4 million, $13.1 million and
$13.1 million, respectively.

The
life of each intangible asset is based either on the life of the corresponding
customer contract or agreement or, in the case of a customer relationship
intangible (the life of which was determined by an analysis of all available
data on that business relationship), the length of time used in the discounted
cash flow analysis to determine the value of the customer relationship. As of
December 31, 2008, the weighted average amortization period for our intangible
assets was approximately 17.3 years.

157

9.
DebtShort-Term
Debt

Our
outstanding short-term debt as of December 31, 2008 was $288.7 million. The
balance consisted of (i) $250 million in principal amount of 6.30% senior notes
due February 1, 2009; (ii) $23.7 million in principal amount of tax-exempt
bonds that mature on April 1, 2024, but are due on demand pursuant to certain
standby purchase agreement provisions contained in the bond indenture (our
subsidiary Kinder Morgan Operating L.P. B is the obligor on the bonds); (iii)
an $8.5 million portion of a 5.40% long-term note payable (our subsidiaries
Kinder Morgan Operating L.P. A and Kinder Morgan Canada Company are the
obligors on the note); and (iv) a $6.5 million portion of 5.23% senior notes
(our subsidiary, Kinder Morgan Texas Pipeline, L.P., is the obligor on the
notes).

Our
outstanding short-term debt as of December 31, 2007 was $610.2 million,
consisting of (i) $589.1 million of commercial paper borrowings; (ii) a $9.9
million portion of the 5.40% long-term note payable due from our subsidiaries
Kinder Morgan Operating L.P. A and Kinder Morgan Canada Company; (iii) a $6.2
million portion of the 5.23% senior notes due from our subsidiary Kinder Morgan
Texas Pipeline, L.P.; and (iv) a remaining $5.0 million in principal amount of
7.84% senior notes due July 23, 2008 from our subsidiary Central Florida Pipe
Line LLC, the obligor on the notes.

The
weighted average interest rate on all of our borrowings was approximately 5.44%
during 2008 and 6.40% during 2007.

Credit
Facility

Our
$1.85 billion five-year unsecured bank credit facility matures August 18, 2010
and can be amended to allow for borrowings up to $2.1 billion. Borrowings under
our credit facility can be used for general partnership purposes and as a
backup for our commercial paper program. As of both December 31, 2008 and 2007,
there were no borrowings under the credit facility.

As
of December 31, 2008, the amount available for borrowing under our credit
facility was reduced by an aggregate amount of $313.0 million,
consisting of (i) a $100 million letter of credit that supports certain
proceedings with the California Public Utilities Commission involving refined
products tariff charges on the intrastate common carrier operations of our
Pacific operations pipelines in the state of California; (ii) a combined $73.7
million in three letters of credit that support tax-exempt bonds; (iii) a
combined $55.9 million in letters of credit that support our pipeline and
terminal operations in Canada; (iv) a combined $40 million in two letters of
credit that support our hedging of commodity price risks associated with the
sale of natural gas, natural gas liquids and crude oil; (v) a $26.8 million
letter of credit that supports our indemnification obligations on the Series D
note borrowings of Cortez Capital Corporation; and (vi) a combined $16.6
million in other letters of credit supporting other obligations of us and our
subsidiaries.

On
September 15, 2008, Lehman Brothers Holdings Inc. filed for
bankruptcy protection under the provisions of Chapter 11 of the U.S. Bankruptcy
Code. One Lehman entity was a lending institution that provided $63 million of
our credit facility. Since Lehman Brothers declared bankruptcy, its affiliate,
which is a party to our credit facility, has not met its
obligations to lend under those agreements and our credit facility has effectively been reduced by its
commitment. The commitments of the other
banks remain unchanged, and the facility is not defaulted.

Our
five-year credit facility is with a syndicate of financial institutions, and
Wachovia Bank, National Association is the administrative agent. The credit
facility permits us to obtain bids for fixed rate loans from members of the
lending syndicate. Interest on our credit facility accrues at our option at a
floating rate equal to either (i) the administrative agents base rate (but not
less than the Federal Funds Rate, plus 0.5%); or (ii) LIBOR, plus a margin,
which varies depending upon the credit rating of our long-term senior unsecured
debt.

158

Our credit
facility included the following restrictive covenants as of December 31, 2008:


total debt divided by earnings
 before interest, income taxes, depreciation and amortization for the
 preceding four quarters may not exceed: 5.5, in the case of any such
 period ended on the last day of (i) a fiscal quarter in which we make any
 Specified Acquisition, or (ii) the first or second fiscal quarter next
 succeeding such a fiscal quarter; or5.0, in the case of any such period ended on the last day of any
 other fiscal quarter;
certain limitations on entering into mergers, consolidations and
 sales of assets;
limitations on granting liens; and
prohibitions on making any
 distribution to holders of units if an event of default exists or would exist
 upon making such distribution.In addition
to normal repayment covenants, under the terms of our credit facility, the
occurrence at any time of any of the following would constitute an event of default
(i) our failure to make required payments of any item of indebtedness or any
payment in respect of any hedging agreement, provided that the aggregate
outstanding principal amount for all such indebtedness or payment obligations
in respect of all hedging agreements is equal to or exceeds $75 million; (ii)
our general partners failure to make required payments of any item of
indebtedness, provided that the aggregate outstanding principal amount for all
such indebtedness is equal to or exceeds $75 million; (iii) adverse judgments
rendered against us for the payment of money in an aggregate amount in excess
of $75 million, if this same amount remains undischarged for a period of thirty
consecutive days during which execution shall not be effectively stayed; and
(iv) voluntary or involuntary commencements of any proceedings or petitions
seeking our liquidation, reorganization or any other similar relief under any
federal, state or foreign bankruptcy, insolvency, receivership or similar law.

Excluding
the relatively non-restrictive specified negative covenants and events of
defaults, our credit facility does not contain any provisions designed to
protect against a situation where a party to an agreement is unable to find a
basis to terminate that agreement while its counterpartys impending financial
collapse is revealed and perhaps hastened through the default structure of some
other agreement. The credit
facility also does not contain a material adverse change clause coupled
with a lockbox provision; however, the facility does provide that the margin we
will pay with respect to borrowings and the facility fee that we will pay on
the total commitment will vary based on our senior debt investment rating. None
of our debt is subject to payment acceleration as a result of any change to our
credit ratings.

Commercial
Paper Program

On
October 13, 2008, Standard & Poors Rating Services lowered our short-term
credit rating to A-3 from A-2. As a result of this revision and current commercial
paper market conditions, we are currently unable to access commercial paper
borrowings, and as of December 31, 2008, we had no commercial paper borrowings.
However, we expect that our financing and liquidity needs will continue to be
met through borrowings made under our bank credit facility described above.

As
of December 31, 2007, we had $589.1 million of commercial paper outstanding
with a weighted average interest rate of 5.58%. The borrowings under our
commercial paper program were used principally to finance the acquisitions and
capital expansions we made during 2007.

Long-Term
Debt

Our
outstanding long-term debt, excluding the value of interest rate swaps, as of
December 31, 2008 and 2007 was $8,274.9 million and $6,455.9 million,
respectively. The balances consisted of the following (in millions):

159

December 31,2008

2007Kinder Morgan Energy Partners,
L.P.
 borrowings:6.30% senior
notes due February 1, 2009

$
250.0

$
250.07.50% senior
notes due November 1, 2010


250.0


250.06.75% senior
notes due March 15, 2011


700.0


700.07.125% senior
notes due March 15, 2012


450.0


450.05.85% senior
notes due September 15, 2012


500.0


500.05.00% senior
notes due December 15, 2013


500.0


500.05.125% senior
notes due November 15, 2014


500.0


500.06.00% senior
notes due February 1, 2017


600.0


600.05.95% senior
notes due February 15, 2018


975.0


9.00% senior
notes due February 1, 2019


500.0


7.400% senior
notes due March 15, 2031


300.0


300.07.75% senior
notes due March 15, 2032


300.0


300.07.30% senior
notes due August 15, 2033


500.0


500.05.80% senior
notes due March 15, 2035


500.0


500.06.50% senior
notes due February 1, 2037


400.0


400.06.95% senior
notes due January 15, 2038


1,175.0


550.0Commercial
paper borrowings





589.1Bank credit
facility borrowings





Subsidiary borrowings:Central Florida
Pipe Line LLC-7.840% senior notes due July 23, 2008





5.0Arrow Terminals
L.P.-IL Development Revenue Bonds due January 1, 2010


5.3


5.3Kinder Morgan
Louisiana Pipeline LLC-6.0% LA Development Revenue note
 due Jan. 1, 2011


5.0


Kinder Morgan
Operating L.P. A-5.40% BP note, due March 31, 2012


19.4


23.6Kinder Morgan
Canada Company-5.40% BP note, due March 31, 2012


17.2


21.0Kinder Morgan
Texas Pipeline, L.P.-5.23% Senior Notes, due January 2,
 2014


37.0


43.2Kinder Morgan
Liquids Terminals LLC-N.J. Development Revenue Bonds due
 Jan. 15, 2018


25.0


25.0Kinder Morgan
Columbus LLC-5.50% MS Development Revenue note due Sept.
 1, 2022


8.2


Kinder Morgan
Operating L.P. B-Jackson-Union Cos. IL Revenue Bonds
 due April 1, 2024


23.7


23.7International
Marine Terminals-Plaquemines, LA Revenue Bonds due March
 15, 2025


40.0


40.0Other
miscellaneous subsidiary debt


1.3


1.4Unamortized debt discount on
senior notes


(18.5
)

(11.2
)Current portion of long-term
debt


(288.7
)

(610.2
)Total Long-term debt

$
8,274.9

$
6,455.9Senior Notes

During
2007, we completed three separate public offerings of senior notes, and on
August 15, 2007, we repaid $250 million of 5.35% senior notes that matured on
that date. With regard to the three offerings, we received proceeds, net of
underwriting discounts and commissions, as follows (i) $992.8 million from a
January 30, 2007 public offering of a total of $1.0 billion in principal amount
of senior notes, consisting of $600 million of 6.00% notes due February 1,
2017, and $400 million of 6.50% notes due February 1, 2037; (ii) $543.9 million
from a June 21, 2007 public offering of $550 million in principal amount of
6.95% senior notes due January 15, 2038; and (iii) $497.8 million from an
August 28, 2007 public offering of $500 million in principal amount of 5.85%
senior notes due September 15, 2012.

During
2008, we also completed three separate public offerings of senior notes. With
regard to the three offerings, we received proceeds, net of underwriting
discounts and commissions, as follows (i) $894.1 million from a February 12,
2008 public offering of a total of $900 million in principal amount of senior
notes, consisting of $600 million of 5.95% notes due February 15, 2018, and
$300 million of 6.95% notes due January 15, 2038 (these notes constitute a
further issuance of the $550 million aggregate principal amount of 6.95% notes
we issued on June 21, 2007 and form a single series with those notes); (ii)
$687.7 million from a June 6, 2008 public offering of a total of $700 million
in principal amount of senior notes, consisting of $375 million of 5.95% notes
due February 15, 2018 (these notes constitute a further issuance of the $600
million aggregate principal amount of 5.95% notes we issued on February 12,
2008 and form a single series with those notes), and $325 million of 6.95%
notes due January 15, 2038 (these notes constitute a further issuance of the
combined $850 million aggregate principal amount of 6.95% notes we issued on
June 21, 2007 and February 12, 2008, and form a single series with those
notes); and (iii) $498.4

160

million from a
December 19, 2008 public offering of $500 million in principal amount of 9.00%
senior notes due February 1, 2019.

All
of our fixed rate senior notes provide that
we may redeem the notes at any time at a price equal to 100% of the principal
amount of the notes plus accrued interest to the redemption date plus a
make-whole premium. In addition, the $500 million in principal amount of
9.00% senior notes issued in December 2008 may be repurchased at the
noteholders option. Each holder of the notes has the right to require us to
repurchase all or a portion of the notes owned by such holder on February 1,
2012 at a purchase price equal to 100% of the principal amount of the notes
tendered by the holder plus accrued and unpaid interest to, but excluding, the
repurchase date. On and after February 1, 2012, interest will cease to accrue
on the notes tendered for repayment. A holders exercise of the repurchase
option is irrevocable.

We
used the proceeds from each of the three 2007 debt offerings and from the first
two 2008 debt offerings to reduce the borrowings under our commercial paper
program. We used the proceeds from our December 2008 debt offering to reduce
the borrowings under our credit facility.

As
of December 31, 2008 and 2007, our total liability balance due on the various
series of our senior notes was $8,381.5 million and $6,288.8 million,
respectively. For a listing of the various outstanding series of our senior
notes, see the table above included in Long-Term Debt.

Interest
Rate Swaps

Information
on our interest rate swaps is contained in Note 14.

Subsequent
Event

On
February 2, 2009, we paid $250 million to retire the principal amount of our
6.3% senior notes that matured on that date.

Subsidiary
Debt

Our
subsidiaries are obligors on the following debt. The agreements governing these
obligations contain various affirmative and negative covenants and events of
default. We do not believe that these provisions will materially affect
distributions to our partners.

Central Florida
Pipeline LLC Debt

Central
Florida Pipeline LLC was an obligor on an aggregate principal amount of $40
million of senior notes originally issued to a syndicate of eight insurance
companies. The senior notes had a fixed annual interest rate of 7.84% with
repayments in annual installments of $5 million beginning July 23, 2001.
Central Florida Pipeline LLC paid the final $5.0 million outstanding principal
amount on July 23, 2008.

Arrow
Terminals L.P.

Arrow
Terminals L.P. is an obligor on a $5.3 million principal amount of Adjustable
Rate Industrial Development Revenue Bonds issued by the Illinois Development
Finance Authority. The bonds have a maturity date of January 1, 2010, and interest on these bonds is paid and computed
quarterly at the Bond Market Association Municipal Swap Index. The bonds are
collateralized by a first mortgage on assets of Arrows Chicago operations and
a third mortgage on assets of Arrows Pennsylvania operations. As of December
31, 2008, the interest rate was 1.328%. The bonds are also backed by a $5.4
million letter of credit issued by JP Morgan Chase that backs-up the $5.3
million principal amount of the bonds and $0.1 million of interest on the bonds
for up to 45 days computed at 12% per annum on the principal amount thereof.

161

Kinder
Morgan Operating L.P. A Debt

Effective
January 1, 2007, we acquired the remaining approximately 50.2% interest in the
Cochin pipeline system that we did not already own (see Note 3 Acquisitions
and Joint VenturesAcquisitions from Unrelated EntitiesInterest in Cochin
Pipeline). As part of our purchase price, two of our subsidiaries issued a
long-term note payable to the seller having a fair value of $42.3 million. We
valued the debt equal to the present value of amounts to be paid, determined
using an annual interest rate of 5.40%. The principal amount of the note, along
with interest, is due in five annual installments of $10.0 million beginning
March 31, 2008. We paid the first installment on March 31, 2008, and the final
payment is due March 31, 2012. Our subsidiaries Kinder Morgan Operating L.P.
A and Kinder Morgan Canada Company are the obligors on the note, and as of
December 31, 2008, the outstanding balance under the note was $36.6 million.

Kinder
Morgan Texas Pipeline, L.P. Debt

Kinder
Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior
notes with a fixed annual stated interest rate as of August 1, 2005, of 8.85%.
The assumed principal amount, along with interest, is due in monthly
installments of approximately $0.7 million. The final payment is due January 2,
2014. As of December 31, 2008, KMTPs outstanding balance under the senior
notes was $37.0 million.

Additionally,
the unsecured senior notes may be prepaid at any time in amounts of at least
$1.0 million and at a price equal to the higher of par value or the present
value of the remaining scheduled payments of principal and interest on the
portion being prepaid.

Kinder Morgan
Liquids Terminals LLC Debt

Kinder
Morgan Liquids Terminals LLC is the obligor on $25.0 million of Economic
Development Revenue Refunding Bonds issued by the New Jersey Economic
Development Authority. These bonds have a maturity date of January 15, 2018.
Interest on these bonds is computed on the basis of a year of 365 or 366 days,
as applicable, for the actual number of days elapsed during Commercial Paper,
Daily or Weekly Rate Periods and on the basis of a 360-day year consisting of
twelve 30-day months during a Term Rate Period. As of December 31, 2008, the
interest rate was 0.52%. We have an outstanding letter of credit issued by
Citibank in the amount of $25.4 million that backs-up the $25.0 million
principal amount of the bonds and $0.4 million of interest on the bonds for up
to 46 days computed at 12% on a per annum basis on the principal thereof.

Kinder
Morgan Operating L.P. B Debt

As
of December 31, 2008, our subsidiary Kinder Morgan Operating L.P. B was the
obligor of a principal amount of $23.7 million of tax-exempt bonds due April 1,
2024. The bonds were issued by the Jackson-Union Counties Regional Port
District, a political subdivision embracing the territories of Jackson County
and Union County in the state of Illinois. These variable rate demand bonds
bear interest at a weekly floating market rate and are backed-up by a letter of
credit issued by Wachovia.

The
bond indenture also contains certain standby purchase agreement provisions
which allow investors to put (sell) back their bonds at par plus accrued
interest. In the fourth quarter of 2008 certain investors elected to sell back
their bonds and we paid a total principal and interest amount of $5.2 million
according to the letter of credit reimbursement provisions. However, the bonds
were subsequently resold and as of December 31, 2008, we were fully reimbursed
for our prior payments. As of December 31, 2008, the interest rate on these
bonds was 3.04%. Our outstanding letter of credit issued by Wachovia totaled
$18.0 million, which backs-up a principal amount of $17.7 million and
$0.3 million of interest on the bonds for up to 55 days computed at 12% per
annum on the principal amount thereof.

International
Marine Terminals Debt

We
own a 66 2/3% interest in International Marine Terminals partnership. The principal
assets owned by IMT are dock and wharf facilities financed by the Plaquemines
Port, Harbor and Terminal District (Louisiana) $40.0

162

million
Adjustable Rate Annual Tender Port Facilities Revenue Refunding Bonds
(International Marine Terminals Project) Series 1984A and 1984B. As of December
31, 2008, the interest rate on these bonds was 2.20%.

On
March 15, 2005, these bonds were refunded and the maturity date was extended
from March 15, 2006 to March 15, 2025. No other changes were made under the
bond provisions. The bonds are backed by two letters of credit issued by KBC
Bank N.V. On March 19, 2002, an Amended and Restated Letter of Credit
Reimbursement Agreement relating to the letters of credit in the amount of
$45.5 million was entered into by IMT and KBC Bank. In connection with that
agreement, we agreed to guarantee the obligations of IMT in proportion to our
ownership interest. Our obligation is approximately $30.3 million for
principal, plus interest and other fees.

Gulf Opportunity
Zone Bonds

To help
fund our business growth in the states of Mississippi and Louisiana, we
completed the purchase of a combined $13.2 million in principal amount of tax
exempt revenue bonds in two separate transactions in December 2008. The bond
offerings were issued under the Gulf Opportunity Zone Act of 2005 and consisted
of the following: (i) $8.2 million in principal amount of 5.5% Development
Revenue Bonds issued by the Mississippi Business Finance Corporation, a public,
non-profit corporation that coordinates a variety of resources used to assist
business and industry in the state of Mississippi; and (ii) $5.0 million in
principal amount of 6.0% Development Revenue Bonds issued by the Louisiana
Community Development Authority, a political subdivision of the state of
Louisiana.

The
Mississippi revenue bonds mature on September 1, 2022, and both principal and
interest is due in full at maturity. We hold an option to redeem in full (and
settle the note payable to MBFC) the principal amount of bonds held by us
without penalty after one year. The Louisiana revenue bonds have a maturity
date of January 1, 2011 and provide for semi-annual interest payments each July
1 and January 1.

Maturities of
Debt

The scheduled
maturities of our outstanding debt, excluding value of interest rate swaps, as
of December 31, 2008, are summarized as follows (in millions):

Year

Commitment2009

$
288.72010


270.82011


721.22012


1,466.42013


506.5Thereafter


5,310.0Total

$
8,563.6Contingent
Debt

As
prescribed by the provisions of Financial Accounting Standards Board
Interpretation (FIN) No. 45, Guarantors Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of
Others, we disclose certain types of guarantees or indemnifications we have
made. These disclosures cover certain types of guarantees included within debt
agreements, even if the likelihood of requiring our performance under such
guarantee is remote. The following is a description of our contingent debt
agreements as of December 31, 2008.

Cortez Pipeline
Company Debt

Pursuant
to a certain Throughput and Deficiency Agreement, the partners of Cortez
Pipeline Company (Kinder Morgan CO2 Company, L.P.  50% partner; a
subsidiary of Exxon Mobil Corporation  37% partner; and Cortez Vickers
Pipeline Company  13% partner) are required, on a several, proportional
percentage ownership basis, to contribute capital to Cortez Pipeline Company in
the event of a cash deficiency. Furthermore, due to our indirect ownership of
Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we
severally guarantee 50% of the debt of Cortez Capital Corporation, a
wholly-owned subsidiary of Cortez Pipeline Company.

163

As
of December 31, 2008, the debt facilities of Cortez Capital Corporation
consisted of (i) $53.6 million of Series D notes due May 15, 2013; (ii) a $125
million short-term commercial paper program; and (iii) a $125 million five-year
committed revolving credit facility due December 22, 2009 (to support the
above-mentioned $125 million commercial paper program). As of December 31,
2008, Cortez Capital Corporation had outstanding borrowings of $116.0 million
under its five-year credit facility. The average interest rate on the Series D
notes was 7.14%.

In
October 2008, Standard & Poors Rating Services lowered Cortez Capital
Corporations short-term credit rating to A-3 from A-2. As a result of this
revision and current commercial paper market conditions, Cortez is unable to
access commercial paper borrowings; however, it expects that its financing and
liquidity needs will continue to be met through borrowings made under its
long-term bank credit facility.

With
respect to Cortezs Series D notes, Shell Oil Company shares our several
guaranty obligations jointly and severally; however, we are obligated to
indemnify Shell for liabilities it incurs in connection with such guaranty. As
of December 31, 2008, JP Morgan Chase has issued a letter of credit on our
behalf in the amount of $26.8 million to secure our indemnification obligations
to Shell for 50% of the $53.6 million in principal amount of Series D notes outstanding
as of December 31, 2008.

Nassau
County, Florida Ocean Highway and Port Authority Debt

We
have posted a letter of credit as security for borrowings under Adjustable
Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and
Port Authority. The bonds were issued for the purpose of constructing certain
port improvements located in Fernandino Beach, Nassau County, Florida. Our
subsidiary, Nassau Terminals LLC is the operator of the marine port facilities.
The bond indenture is for 30 years and allows the bonds to remain outstanding
until December 1, 2020. Principal
payments on the bonds are made on the first of December each year and
corresponding reductions are made to the letter of credit.

In
October 2008, pursuant to the standby purchase agreement provisions contained
in the bond indenturewhich require the sellers of those guarantees to buy the
debt backcertain investors elected to put (sell) back their bonds at par plus
accrued interest. A total principal and interest amount of $11.8 million was
tendered and drawn against our letter of credit and accordingly, we paid this
amount pursuant to the letter of credit reimbursement provisions. This payment
reduced the face amount of our letter of credit from $22.5 million to $10.7
million. In December 2008, the bonds that were put back were re-sold, and we
were fully reimbursed for our prior letter of credit payments. As of December 31, 2008, this letter of
credit had a face amount of $10.2 million.

Rockies
Express Pipeline LLC Debt

Pursuant
to certain guaranty agreements, all three member owners of West2East Pipeline
LLC (which owns all of the member interests in Rockies Express Pipeline LLC)
have agreed to guarantee, severally in the same proportion as their percentage
ownership of the member interests in West2East Pipeline LLC, borrowings under
Rockies Express (i) $2.0 billion five-year, unsecured revolving credit
facility due April 28, 2011; (ii) $2.0 billion commercial paper program; and
(iii) $600 million in principal amount of floating rate senior notes due August
20, 2009. The three member owners and their respective ownership interests
consist of the following: our subsidiary Kinder Morgan W2E Pipeline LLC  51%,
a subsidiary of Sempra Energy  25%, and a subsidiary of ConocoPhillips  24%.

Borrowings
under the Rockies Express commercial paper program and/or its credit facility
are primarily used to finance the construction of the Rockies Express
interstate natural gas pipeline and to pay related expenses. The credit
facility, which can be amended to allow for borrowings up to $2.5 billion,
supports borrowings under the commercial paper program, and borrowings under
the commercial paper program reduce the borrowings allowed under the credit
facility. The $600 million in principal amount of senior notes were issued on
September 20, 2007. The notes are unsecured and are not redeemable prior to
maturity. Interest on the notes is paid and computed quarterly at an interest rate
of three-month LIBOR (with a floor of 4.25%) plus a spread of 0.85%. Upon
maturity in August 2009, we expect that Rockies Express will repay these senior
notes from equity contributions received from its member owners.

164

Upon
issuance of the notes, Rockies Express entered into two floating-to-fixed
interest rate swap agreements having a combined notional principal amount of
$600 million and maturity dates of August 20, 2009. On September 24, 2008,
Rockies Express terminated one of the aforementioned interest rate swaps that
had Lehman Brothers as the counterparty. The notional principal amount of the
terminated swap agreement was $300 million. The remaining interest rate swap
agreement effectively converts the interest expense associated with $300
million of these senior notes from its stated variable rate to a fixed rate of
5.47%.

In
October 2008, Standard & Poors Rating Services lowered Rockies Express
Pipeline LLCs short-term credit rating to A-3 from A-2. As a result of this revision
and current commercial paper market conditions, Rockies Express is unable to
access commercial paper borrowings, and as of December 31, 2008, there were no
borrowings under its commercial paper program. However, Rockies Express expects
that its financing and liquidity needs will continue to be met through
borrowings made under its long-term bank credit facility and contributions by
its equity investors.

As
of December 31, 2008, in addition to the $600 million in floating rate senior
notes, Rockies Express had outstanding borrowings of $1,561.0 million under its
five-year credit facility. Accordingly, as of December 31, 2008, our contingent
share of Rockies Express debt was $1,102.1 million (51% of total guaranteed
borrowings). In addition, there is a letter of credit outstanding to support
the construction of the Rockies Express Pipeline. As of December 31, 2008, this letter of credit, issued by JPMorgan
Chase, had a face amount of $31.4
million. Our contingent responsibility with regard to this outstanding
letter of credit was $16.0 million (51% of total face amount).

One
of the Lehman entities was a lending bank with an approximately $41 million
commitment to the Rockies Express $2.0 billion credit facility. Since declaring
bankruptcy, Lehman has not met its obligations to lend under the credit
facility and our credit facility has effectively been reduced by its commitment.
The commitments of the other banks remain unchanged and the facility
is not defaulted.

Midcontinent
Express Pipeline LLC Debt

Pursuant
to certain guaranty agreements, each of the two member owners of Midcontinent
Express Pipeline LLC have agreed to guarantee, severally in the same proportion
as their percentage ownership of the member interests in Midcontinent Express
Pipeline LLC, borrowings under Midcontinents $1.4 billion three-year,
unsecured revolving credit facility, entered into on February 29, 2008 and due
February 28, 2011. The facility is with a syndicate of financial institutions
with The Royal Bank of Scotland plc as the administrative agent. Borrowings
under the credit agreement will be used to finance the construction of the
Midcontinent Express Pipeline system and to pay related expenses. One of the
Lehman entities was a lending bank with an approximately $100 million commitment
to the Midcontinent Express $1.4 billion credit facility and our credit facility has effectively been reduced by its commitment.
Since declaring bankruptcy, Lehman has not met its obligations to lend under the credit
facility. The commitments of the other banks remain unchanged and the facility
is not defaulted.

Midcontinent
Express Pipeline LLC is an equity method investee of ours, and the two member
owners and their respective ownership interests consist of the following: our
subsidiary Kinder Morgan Operating L.P. A  50%, and Energy Transfer
Partners, L.P.  50%. As of December 31, 2008, Midcontinent Express Pipeline
LLC had $837.5 million borrowed under its three-year credit facility.
Accordingly, as of December 31, 2008, our contingent share of Midcontinent
Express debt was $418.8 million (50% of total borrowings). Furthermore, the
revolving credit facility can be used for the issuance of letters of credit to
support the construction of the Midcontinent Express Pipeline, and as of
December 31, 2008, a letter of credit having a face amount of $33.3 million was
issued under the credit facility. Accordingly, as of December 31, 2008, our
contingent responsibility with regard to this outstanding letter of credit was
$16.7 million (50% of total face amount).

In
addition, on September 4, 2007, Midcontinent Express Pipeline LLC entered into
a $197 million reimbursement agreement with JPMorgan Chase as the
administrative agent. The agreement included covenants and required payments of
fees that are common in such arrangements, and both we and Energy Transfer
Partners, L.P. agreed to guarantee borrowings under the reimbursement agreement
in the same proportion as the associated percentage ownership of Midcontinent
Express member interests. This reimbursement agreement expired on September 3,
2008.

165

Fair Value of
Financial Instruments

Fair value
as used in SFAS No. 107, Disclosures About Fair Value of Financial
Instruments, represents the amount at which an instrument could be exchanged
in a current transaction between willing parties. The estimated fair value of
our long-term debt, including its current portion and excluding the value of
interest rate swaps, is based upon prevailing interest rates available to us as
of December 31, 2008 and December 31, 2007 and is disclosed below (in
millions).

December 31, 2008

December 31, 2007CarryingValue

EstimatedFair Value

CarryingValue

EstimatedFair ValueTotal Debt

$
8,563.6

$
7,627.3

$
7,066.1

$
7,201.8We
adjusted the fair value measurement of our long-term debt as of December 31,
2008 in accordance with SFAS No. 157, and the estimated fair value of our debt
as of December 31, 2008 (presented in the table above) includes a decrease of
$261.1 million related to discounting the fair value measurement for the effect
of credit risk.

10.     Pensions and Other Post-Retirement Benefits

Pension and
Post-Retirement Benefit Plans

Due
to our acquisition of the Trans Mountain pipeline system (see Note 3), Kinder
Morgan Canada Inc. and Trans Mountain Pipeline Inc. (as general partner of
Trans Mountain Pipeline L.P.) are sponsors of pension plans for eligible Trans
Mountain employees. The plans include registered defined benefit pension plans,
supplemental unfunded arrangements, which provide pension benefits in excess of
statutory limits, and defined contributory plans. We also provide
post-retirement benefits other than pensions for retired employees. Our
combined net periodic benefit costs for these Trans Mountain pension and
post-retirement benefit plans for 2008 and 2007 were approximately $3.5 million
and $3.2 million, respectively, recognized ratably over each year. As of
December 31, 2008, we estimate our overall net periodic pension and
post-retirement benefit costs for these plans for the year 2009 will be
approximately $3.1 million, although this estimate could change if there is a
significant event, such as a plan amendment or a plan curtailment, which would
require a remeasurement of liabilities. We
expect to contribute approximately $7.7 million to these benefit plans in 2009.

Additionally,
in connection with our acquisition of SFPP, L.P. and Kinder Morgan Bulk
Terminals, Inc. in 1998, we acquired certain liabilities for pension and
post-retirement benefits. We provide medical and life insurance benefits to
current employees, their covered dependents and beneficiaries of SFPP and
Kinder Morgan Bulk Terminals. We also provide the same benefits to former
salaried employees of SFPP. Additionally, we will continue to fund these costs
for those employees currently in the plan during their retirement years. SFPPs
post-retirement benefit plan is frozen and no additional participants may join
the plan. The noncontributory defined benefit pension plan covering the former
employees of Kinder Morgan Bulk Terminals is the Knight Inc. Retirement Plan.
The benefits under this plan are based primarily upon years of service and
final average pensionable earnings; however, benefit accruals were frozen as of
December 31, 1998.

Our net
periodic benefit cost for the SFPP post-retirement benefit plan was a credit
of less
than $0.1
million in 2008, a credit of $0.2 million in 2007, and a credit of $0.3 million
in 2006. The credits in all three years resulted in increases to
income, largely due to amortizations of an actuarial gain and a negative prior
service cost. As of December 31, 2008, we estimate our overall net periodic
post-retirement benefit cost for the SFPP
post-retirement benefit plan for the year 2009 will be a credit of
approximately $0.1 million; however, this
estimate could change if a future significant event would require a
remeasurement of liabilities. In addition,
we expect to contribute approximately $0.3 million to this post-retirement
benefit plan in 2009.

On
September 29, 2006, the FASB issued SFAS No. 158, Employers Accounting for
Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB
Statement Nos. 87, 88, 106 and 132(R). One of the provisions of this Statement
requires an employer with publicly traded equity securities to recognize the
overfunded or underfunded status of a defined benefit pension plan or
post-retirement benefit plan (other than a multiemployer

166

plan) as an
asset or liability in its statement of financial position and to provide the
required disclosures as of the end of the fiscal year ending after December 15,
2006. We adopted SFAS No. 158 on December 31, 2006, and pursuant to the
provisions of this Statement, we report
amounts that have not yet been recognized as a component of benefit expense as
part of the net benefit liability on our balance sheet (for example,
unrecognized prior service costs or credits, net (actuarial) gain or loss, and
transition obligation or asset) with a corresponding adjustment to accumulated
other comprehensive income.

As of
December 31, 2008 and 2007, the recorded value of our pension and
post-retirement benefit obligations for these plans was a combined $33.4
million and $37.5 million, respectively. We consider our overall pension and
post-retirement benefit liability exposure to be minimal in relation to the
value of our total consolidated assets and net income.

Multiemployer
Plans

As a result
of acquiring several terminal operations, primarily our acquisition of Kinder
Morgan Bulk Terminals, Inc. effective July 1, 1998, we participate in several
multi-employer pension plans for the benefit of employees who are union
members. We do not administer these plans and contribute to them in accordance
with the provisions of negotiated labor contracts. Other benefits include a
self-insured health and welfare insurance plan and an employee health plan
where employees may contribute for their dependents health care costs. Amounts
charged to expense for these plans were approximately $7.8 million for the year
ended December 31, 2008, $6.7 million for the year ended December 31, 2007, and
$6.3 million for the year ended December 31, 2006.

Kinder Morgan
Savings Plan

The Kinder
Morgan Savings Plan is a defined contribution 401(k) plan. The plan permits all
full-time employees of Knight, Inc. and KMGP Services Company, Inc. to
contribute between 1% and 50% of base compensation, on a pre-tax basis, into
participant accounts. In addition to a contribution equal to 4% of
base compensation per year for most plan participants, our general partner may
make special discretionary contributions. Certain employees contributions are
based on collective bargaining agreements. The contributions are made
each pay period on behalf of each eligible employee. Participants may direct
the investment of their contributions and all employer contributions, including
discretionary contributions, into a variety of investments. Plan assets are
held and distributed pursuant to a trust agreement. The total amount charged to
expense for our Savings Plan was $13.3 million during 2008, $11.7 million
during 2007, and $10.2 million during 2006.

Employer
contributions for employees vest on the second anniversary of the date of hire.
Effective October 1, 2005, for new employees of our Terminals segment, a tiered
employer contribution schedule was implemented. This tiered schedule provides
for employer contributions of 1% for service less than one year, 2% for service
between one and two years, 3% for services between two and five years, and 4%
for service of five years or more. All employer contributions for Terminals
employees hired after October 1, 2005 vest on the third anniversary of the date
of hire.

At its July
2008 meeting, the compensation committee of the KMR board of directors approved
a special contribution of an additional 1% of base pay into the Savings Plan
for each eligible employee. Each eligible employee will receive an additional
1% company contribution based on eligible base pay each pay period beginning
with the first pay period of August 2008 and continuing through the last pay
period of July 2009. The additional 1% contribution does not change or
otherwise impact, the annual 4% contribution that eligible employees currently
receive and it will vest according to the same vesting schedule described in
the preceding paragraph. Since this additional 1% company contribution is
discretionary, compensation committee approval will be required annually for
each additional contribution. During the first quarter of 2009, excluding the
1% additional contribution described above, we will not make any additional
discretionary contributions to individual accounts for 2008.

Additionally,
participants have an option to make after-tax Roth contributions (Roth 401(k)
option) to a separate participant account. Unlike traditional 401(k) plans, where
participant contributions are made with pre-tax dollars, earnings grow
tax-deferred, and the withdrawals are treated as taxable income, Roth 401(k)
contributions are made with after-tax dollars, earnings are tax-free, and the
withdrawals are tax-free if they occur after both (i) the

167

fifth year of participation in the Roth 401(k) option, and (ii)
attainment of age 59 1/2, death or disability. The employer contribution will
still be considered taxable income at the time of withdrawal.

Cash Balance
Retirement Plan

Employees
of KMGP Services Company, Inc. and Knight are also eligible to participate in a
Cash Balance Retirement Plan. Certain employees continue to accrue benefits
through a career-pay formula, grandfathered according to age and years of
service on December 31, 2000, or collective bargaining arrangements. All other
employees accrue benefits through a personal retirement account in the Cash
Balance Retirement Plan. Under the plan, we credit each participating
employees personal retirement account an amount equal to 3% of eligible compensation every pay period. Interest is
credited to the personal retirement accounts at the 30-year U.S. Treasury bond
rate, or an approved substitute, in effect each year. Employees become fully
vested in the plan after three years, and they may take a lump sum distribution
upon termination of employment or retirement.

11.     Partners Capital

Limited
Partner Units

As of
December 31, 2008 and 2007, our partners capital consisted of the following
limited partner units:

December
 31,
 2008

December
 31,
 2007Common units


182,969,427


170,220,396Class B units


5,313,400


5,313,400i-units


77,997,906


72,432,482Total limited
partner units


266,280,733


247,966,278The total
limited partner units represent our limited partners interest and an effective
98% interest in us, exclusive of our general partners incentive distribution
rights. Our general partner has an effective 2% interest in us, excluding its
incentive distribution rights.

As of
December 31, 2008, our common unit total consisted of 166,598,999 units held by
third parties, 14,646,428 units held by Knight and its consolidated affiliates
(excluding our general partner) and 1,724,000 units held by our general
partner. As of December 31, 2007, our common unit total consisted of
155,864,661 units held by third parties, 12,631,735 units held by Knight and
its consolidated affiliates (excluding our general partner) and 1,724,000 units
held by our general partner.

The
Class B units are similar to our common units except that they are not eligible
for trading on the New York Stock Exchange. All of our Class B units were
issued to a wholly-owned subsidiary of Knight in December 2000.

On
both December 31, 2008 and December 31, 2007, all of our i-units were held by
KMR. Our i-units are a separate class of limited partner interests in us and
are not publicly traded. In accordance with its limited liability company
agreement, KMRs activities are restricted to being a limited partner in us,
and to controlling and managing our business and affairs and the business and
affairs of our operating limited partnerships and their subsidiaries. Through the
combined effect of the provisions in our partnership agreement and the
provisions of KMRs limited liability company agreement, the number of
outstanding KMR shares and the number of i-units will at all times be equal.

Under
the terms of our partnership agreement, we agreed that we will not, except in
liquidation, make a distribution on an i-unit other than in additional i-units
or a security that has in all material respects the same rights and privileges
as our i-units. The number of i-units we distribute to KMR is based upon the
amount of cash we distribute to the owners of our common units. When cash is
paid to the holders of our common units, we will issue additional i-units to
KMR. The fraction of an i-unit paid per i-unit owned by KMR will have a value
based on the cash payment on the common unit.

168

The
cash equivalent of distributions of i-units will be treated as if it had
actually been distributed for purposes of determining the distributions to our
general partner. We will not distribute the cash to the holders of our i-units
but will instead retain the cash for use in our business. If additional units
are distributed to the holders of our common units, we will issue an equivalent
amount of i-units to KMR based on the number of i-units it owns. Based on the
preceding, KMR received a distribution of
1,646,891 i-units on November 14, 2008. These additional i-units distributed
were based on the $1.02 per unit distributed to our common unitholders on that
date. During the year ended December 31, 2008, KMR received distributions of
5,565,424 i-units. These additional i-units distributed were based on the $3.89
per unit distributed to our common unitholders during 2008. During 2007, KMR
received distributions of 4,430,806 i-units, based on the $3.39 per unit
distributed to our common unitholders during 2007.

Equity
Issuances

2007
Issuances

On
May 17, 2007, KMR issued 5,700,000 of its shares in a public offering at a
price of $52.26 per share. The net proceeds from the offering were used by KMR
to buy additional i-units from us, and we received net proceeds of $297.9
million for the issuance of these 5,700,000 i-units.

On
December 5, 2007, we issued, in a public offering, 7,130,000 of our common
units, including common units sold pursuant to the underwriters over-allotment
option, at a price of $49.34 per unit, less commissions and underwriting
expenses. We received net proceeds of $342.9 million for the issuance of these
7,130,000 common units.

We
used the proceeds from each of these two issuances to reduce the borrowings
under our commercial paper program. In addition, pursuant to our purchase and
sale agreement with Trans-Global Solutions, Inc., we issued 266,813 common
units in May 2007 to TGS to settle a purchase price liability related to our
acquisition of bulk terminal operations from TGS in April 2005. As agreed
between TGS and us, the units were issued equal to a value of $15.0 million.

2008
Issuances

On
February 12, 2008, we completed an offering of 1,080,000 of our common units at
a price of $55.65 per unit in a privately negotiated transaction. We received
net proceeds of $60.1 million for the issuance of these 1,080,000 common units,
and we used the proceeds to reduce the borrowings under our commercial paper
program.

On
March 3, 2008, we issued, in a public offering, 5,000,000 of our common units
at a price of $57.70 per unit, less commissions and underwriting expenses. At
the time of the offering, we granted the underwriters a 30-day option to
purchase up to an additional 750,000 common units from us on the same terms and
conditions, and pursuant to this option, we issued an additional 750,000 common
units on March 10, 2008 upon exercise of this option. After commissions and
underwriting expenses, we received net proceeds of $324.2 million for the
issuance of these 5,750,000 common units, and we used the proceeds to reduce
the borrowings under our commercial paper program.

In
connection with our August 28, 2008 acquisition of Knights 33 1/3% ownership
interest in the Express pipeline system and Knights full ownership of the Jet
Fuel pipeline system, we issued 2,014,693 of our common units to Knight. The
units were issued August 28, 2008, and as agreed between Knight and us, were
valued at $116.0 million. For more information on this acquisition, see Note 3
Acquisitions and Joint VenturesAcquisitions from KnightExpress and Jet Fuel
Pipeline Systems.

In
addition, on December 22, 2008, we issued, in a public offering, 3,900,000 of
our common units at a price of $46.75 per unit, less commissions and
underwriting expenses. After commissions and underwriting expenses, we received
net proceeds of $176.6 million for the issuance of these common units, and we
used the proceeds to reduce the borrowings under our bank credit facility.

On
December 16, 2008, we furnished to the Securities and Exchange Commission two
Current Reports on Form 8-K and one Current Report on Form 8-K/A (in each case,
containing disclosures under item 7.01 of Form 8-K)

169

containing
certain information with respect to this public offering of our common units.
We also filed a prospectus supplement with respect to this common unit offering
on December 17, 2008. These Current Reports may have constituted prospectuses
not meeting the requirements of the Securities Act due to the legends used in
the Current Reports. Accordingly, under certain circumstances, purchasers of
the common units from us in the offering might have the right to require us to
repurchase the common units they purchased, or if they have sold those common
units, to pay damages. Consequently, we could have a potential liability
arising out of these possible violations of the Securities Act. The magnitude
of any potential liability is presently impossible to quantify, and would
depend upon whether it is demonstrated we violated the Securities Act, the
number of common units that purchasers in the offering sought to require us to
repurchase and the trading price of our common units.

Income
Allocation and Declared Distributions

For
the purposes of maintaining partner capital accounts, our partnership agreement
specifies that items of income and loss shall be allocated among the partners,
other than owners of i-units, in accordance with their percentage interests.
Normal allocations according to percentage interests are made, however, only
after giving effect to any priority income allocations in an amount equal to
the incentive distributions that are allocated 100% to our general partner.
Incentive distributions are generally defined as all cash distributions paid to
our general partner that are in excess of 2% of the aggregate value of cash and
i-units being distributed.

Incentive
distributions allocated to our general partner are determined by the amount
quarterly distributions to unitholders exceed certain specified target levels,
according to the provisions of our partnership agreement. For the years ended
December 31, 2008, 2007 and 2006, we declared distributions of $4.02, $3.48 and
$3.26 per unit, respectively. Under the terms of our partnership agreement, our
total distributions to unitholders for 2008, 2007 and 2006 required incentive
distributions to our general partner in the amount of $800.8 million, $611.9
million and $528.4 million, respectively. The increased incentive distributions
paid for 2008 over 2007, and 2007 over 2006 reflect the increases in amounts
distributed per unit as well as the issuance of additional units. Distributions
for the fourth quarter of each year are declared and paid during the first
quarter of the following year.

Fourth
Quarter 2008 Incentive Distribution

On January
21, 2009, we declared a cash distribution of $1.05 per unit for the quarterly
period ended December 31, 2008. This distribution was paid on February 13,
2009, to unitholders of record as of January 31, 2009. Our common unitholders
and Class B unitholders received cash. KMR, our sole i-unitholder, received a
distribution in the form of additional i-units based on the $1.05 distribution
per common unit. The number of i-units distributed was 1,917,189. For each
outstanding i-unit that KMR held, a fraction of an i-unit (0.024580) was issued.
The fraction was determined by dividing:

$1.05, the cash amount distributed
 per common unitby $42.717, the average of
KMRs
 limited liability shares closing market prices from January 13-27, 2009, the
 ten consecutive trading days preceding the date on which the shares began to
 trade ex-dividend under the rules of the New York Stock Exchange.This
February 13, 2009 distribution included an incentive distribution to our
general partner in the amount of $216.6 million. Since this distribution was
declared after the end of the quarter, no amount is shown in our December 31,
2008 balance sheet as a distribution payable.

Fourth
Quarter 2006 Incentive Distribution Waiver

According
to the provisions of the Knight Annual Incentive Plan, in order for the
executive officers of our general partner and KMR, and for the employees of
KMGP Services Company, Inc. and Knight who operate our business to earn a non-equity cash incentive (bonus) for 2006, both
we and Knight were required to meet pre-established financial performance
targets. The target for us was $3.28 in cash distributions per common
unit for 2006. Because we did not
meet our 2006 budget target, we had no obligation to fund our 2006 bonus plan;
however,

170

at its January
17, 2007 board meeting, the board of directors of KMI (now Knight) determined
that it was in KMIs long-term interest to fund a partial payout of our bonuses
through a reduction in our general partners incentive distribution.

Accordingly,
our general partner, with the approval of the compensation committees and
boards of KMI and KMR, waived $20.1 million of its 2006 incentive distribution
for the fourth quarter of 2006. The waived amount approximated an amount equal
to our actual bonus payout for 2006, which was approximately 75% of our
budgeted full bonus payout for 2006 of $26.5 million. Including the effect of
this waiver, our distributions to unitholders for 2006 resulted in payments of
incentive distributions to our general partner in the amount of $508.3 million.
The waiver of $20.1 million of incentive payment in the fourth quarter of 2006
reduced our general partners equity earnings by $19.9 million.

12.     Related Party Transactions

General and
Administrative Expenses

KMGP
Services Company, Inc., a subsidiary of our general partner, provides employees
and Kinder Morgan Services LLC, a wholly owned subsidiary of KMR, provides
centralized payroll and employee benefits services to (i) us; (ii) our
operating partnerships and subsidiaries; (iii) our general partner; and (iv)
KMR (collectively, the Group). Employees of KMGP Services Company, Inc. are
assigned to work for one or more members of the Group. The direct costs of all
compensation, benefits expenses, employer taxes and other employer expenses for
these employees are allocated and charged by Kinder Morgan Services LLC to the
appropriate members of the Group, and the members of the Group reimburse Kinder
Morgan Services LLC for their allocated shares of these direct costs. There is
no profit or margin charged by Kinder Morgan Services LLC to the members of the
Group. The administrative support necessary to implement these payroll and
benefits services is provided by the human resource department of Knight, and
the related administrative costs are allocated to members of the Group in
accordance with existing expense allocation procedures. The effect of these
arrangements is that each member of the Group bears the direct compensation and
employee benefits costs of its assigned or partially assigned employees, as the
case may be, while also bearing its allocable share of administrative costs.
Pursuant to our limited partnership agreement, we provide reimbursement for our
share of these administrative costs and such reimbursements will be accounted
for as described above. Additionally, we reimburse KMR with respect to costs
incurred or allocated to KMR in accordance with our limited partnership
agreement, the delegation of control agreement among our general partner, KMR,
us and others, and KMRs limited liability company agreement.

The named
executive officers of our general partner and KMR and other employees that
provide management or services to both Knight and the Group are employed by
Knight. Additionally, other Knight employees assist in the operation of certain
of our assets (discussed below in Operations). These employees expenses are
allocated without a profit component between Knight on the one
hand, and the appropriate members of the
Group, on the other hand.


Additionally,
due to certain going-private transaction expenses allocated to us from Knight, we
recognized a total of $5.6 million in non-cash compensation expense in 2008.  For accounting purposes,
Knight is required to allocate to us a portion of these transaction-related amounts and we are required
to recognize the amounts as expense on our income statements; however, we were not responsible for
paying these buyout expenses, and accordingly, we recognize the unpaid amount as both a contribution to
Partners Capital and an increase to Minority interest on our balance sheet.


Furthermore,
in accordance with SFAS No. 123R, Knight Holdco LLC is required to recognize
compensation expense in connection with their Class A-1 and Class B units over
the expected life of such units. As a subsidiary of Knight Holdco LLC, we are
allocated a portion of this compensation expense, although we have no
obligation nor do we expect to pay any of these costs.

Partnership
Interests and Distributions

Kinder Morgan
G.P., Inc.

Kinder
Morgan G.P., Inc. serves as our sole general partner. Pursuant to our
partnership agreement, our general partners interests represent a 1% ownership
interest in us, and a direct 1.0101% ownership interest in each of our five
operating partnerships. Collectively, our general partner owns an effective 2%
interest in our operating partnerships, excluding incentive distributions
rights as follows:

171

 its 1.0101% direct general
partner
 ownership interest (accounted for as minority interest in our consolidated financial
 statements); and its 0.9899% ownership interest
 indirectly owned via its 1% ownership interest in us.In
addition, as of December 31, 2008, our general partner owned 1,724,000 common
units, representing approximately 0.65% of our outstanding limited partner
units.

Our
partnership agreement requires that we distribute 100% of Available Cash, as
defined in our partnership agreement, to our partners within 45 days following
the end of each calendar quarter in accordance with their respective percentage
interests. Available Cash consists generally of all of our cash receipts,
including cash received by our operating partnerships and net reductions in
reserves, less cash disbursements and net additions to reserves and amounts
payable to the former general partner of SFPP, L.P. in respect of its remaining
0.5% interest in SFPP.

Our
general partner is granted discretion by our partnership agreement, which
discretion has been delegated to KMR, subject to the approval of our general
partner in certain cases, to establish, maintain and adjust reserves for future
operating expenses, debt service, maintenance capital expenditures, rate
refunds and distributions for the next four quarters. These reserves are not
restricted by magnitude, but only by type of future cash requirements with
which they can be associated. When KMR determines our quarterly distributions,
it considers current and expected reserve needs along with current and expected
cash flows to identify the appropriate sustainable distribution level.

Our
general partner and owners of our common units and Class B units receive
distributions in cash, while KMR, the sole owner of our i-units, receives
distributions in additional i-units. We do not distribute cash to i-unit owners
but instead retain the cash for use in our business. However, the cash
equivalent of distributions of i-units is treated as if it had actually been
distributed for purposes of determining the distributions to our general
partner. Each time we make a distribution, the number of i-units owned by KMR
and the percentage of our total units owned by KMR increase automatically under
the provisions of our partnership agreement.

Available
cash is initially distributed 98% to our limited partners and 2% to our general
partner. These distribution percentages are modified to provide for incentive
distributions to be paid to our general partner in the event that quarterly
distributions to unitholders exceed certain specified targets.

Available
cash for each quarter is distributed:

 first, 98% to the owners of
all classes of units pro rata and
 2% to our general partner until the owners of all classes of units have
 received a total of $0.15125 per unit in cash or equivalent i-units for such
 quarter; second, 85% of any available
cash then remaining to the
 owners of all classes of units pro rata and 15% to our general partner until
 the owners of all classes of units have received a total of $0.17875 per unit
 in cash or equivalent i-units for such quarter; third, 75% of any available
cash then remaining to the owners
 of all classes of units pro rata and 25% to our general partner until the
 owners of all classes of units have received a total of $0.23375 per unit in
 cash or equivalent i-units for such quarter; and fourth, 50% of any available
cash then remaining to the
 owners of all classes of units pro rata, to owners of common units and Class
 B units in cash and to owners of i-units in the equivalent number of i-units,
 and 50% to our general partner.For
more information on incentive distributions paid to our general partner, see
Note 11 Income Allocation and Declared Distributions.

172

Knight
Inc.

Knight Inc.
remains the sole indirect stockholder of our general partner. Also, as of December
31, 2008, Knight directly owned 10,852,788 common units, indirectly owned
5,313,400 Class B units and 5,517,640 common units through its consolidated
affiliates, including our general partner, and owned 11,128,826 KMR shares,
representing an indirect ownership interest of 11,128,826 i-units. Together,
these units represented approximately 12.3% of our outstanding limited partner
units. Including both its general and limited partner interests in us, at the
2008 distribution level, Knight received approximately 51% of all quarterly
distributions from us, of which approximately 44% was attributable to its
general partner interest and the remaining 7% was attributable to its limited
partner interest. The actual level of distributions Knight will receive in the
future will vary with the level of distributions to our limited partners
determined in accordance with our partnership agreement.

Kinder Morgan
Management, LLC

As of
December 31, 2008, KMR, our general partners delegate, remained the sole owner
of our 77,997,906 i-units.

Asset
Acquisitions and Sales

In March
2008, our subsidiary Kinder Morgan CO2 Company, L.P. sold certain
pipeline meter equipment to Cortez Pipeline Company, its 50% equity investee,
for its current fair value of $5.7 million. The meter equipment is still being
employed in conjunction with our CO2 business segment.

From time
to time in the ordinary course of business, we buy and sell pipeline and
related services from Knight and its subsidiaries. Such transactions are
conducted in accordance with all applicable laws and regulations and on an
arms length basis consistent with our policies governing such transactions. In
conjunction with our acquisition of (i) certain Natural Gas Pipelines assets
and partnership interests from Knight in December 1999 and December 2000; and
(ii) all of the ownership interest in TransColorado Gas Transmission Company
LLC from two wholly-owned subsidiaries of Knight on November 1, 2004, Knight
agreed to indemnify us and our general partner with respect to approximately
$733.5 million of our debt. Knight would be obligated to perform under this
indemnity only if we are unable, and/or our assets were insufficient to satisfy
our obligations.

Operations

Natural Gas
Pipelines and Products Pipelines Business
Segments

On
February 15, 2008, Knight sold an 80% ownership interest in NGPL PipeCo LLC,
which owns Natural Gas Pipeline Company of America LLC and certain affiliates
(collectively referred to in this report as NGPL) to Myria Acquisition Inc. for
approximately $5.9 billion. Myria is comprised of a syndicate of investors led
by Babcock & Brown, an international investment and specialized fund and
asset management group. Knight accounts for its remaining 20% ownership
interest in NGPL under the equity method of accounting and, pursuant to the
provisions of a 15-year operating agreement, continues to operate NGPLs
assets.

Knight (or
its subsidiaries) and NGPL operate and maintain for us the assets comprising
our Natural Gas Pipelines business segment. NGPL operates Trailblazer Pipeline
Company LLCs assets under a long-term contract pursuant to which Trailblazer
Pipeline Company LLC incurs the costs and expenses related to NGPLs operating
and maintaining the assets. Trailblazer Pipeline Company LLC provides the funds
for its own capital expenditures. NGPL does not profit from or suffer loss
related to its operation of Trailblazer Pipeline Company LLCs assets.

The
remaining assets comprising our Natural Gas Pipelines business segment as well
as our Cypress Pipeline (and our North System until its sale in October 2007,
described in Note 3 DivestituresNorth System Natural Gas Liquids Pipeline
System  Discontinued Operations), which is part of our Products Pipelines
business segment, are operated under other agreements between Knight and us.
Pursuant to the applicable underlying agreements, we pay Knight either a fixed
amount or actual costs incurred as reimbursement for the corporate general and
administrative expenses incurred in connection with the operation of these
assets. The combined amounts paid to Knight and NGPL for corporate general and
administrative costs, including amounts related to Trailblazer Pipeline Company

173

LLC, were $45.0 million of actual costs incurred for 2008 (and no fixed
costs), $1.0 million of fixed costs and $48.1 million of actual costs incurred
for 2007, and $1.0 million of fixed costs and $37.9 million of actual costs
incurred for 2006.

We believe
the amounts paid to Knight and NGPL for the services they provided each year
fairly reflect the value of the services performed. However, due to the nature
of the allocations, these reimbursements may not exactly match the actual time
and overhead spent. We believe the fixed amounts that were agreed upon at the
time the contracts were entered into were reasonable estimates of the corporate
general and administrative expenses to be incurred by both Knight and NGPL in
performing such services. We also reimburse both Knight and NGPL for operating
and maintenance costs and capital expenditures incurred with respect to our
assets.

In
addition, we purchase natural gas transportation and storage services from
NGPL. For each of the years 2008, 2007 and 2006, these expenses totaled $8.1
million, $6.8 million and $3.6 million, respectively, and we included these
expense amounts within the caption Gas purchases and other costs of sales in
our accompanying consolidated statements of income.

CO2
Business Segment

Knight or
its subsidiaries also operate and maintain for us the power plant we
constructed at the SACROC oil field unit, located in the Permian Basin area of
West Texas. The power plant provides nearly half of SACROCs current
electricity needs. Kinder Morgan Power Company, a subsidiary of Knight,
operates and maintains the power plant under a five-year contract expiring in
June 2010. Pursuant to the contract, Knight incurs the costs and expenses
related to operating and maintaining the power plant for the production of
electrical energy at the SACROC field. Such costs include supervisory personnel
and qualified operating and maintenance personnel in sufficient numbers to
accomplish the services provided in accordance with good engineering, operating
and maintenance practices. Kinder Morgan Production Company fully reimburses
Knights expenses, including all agreed-upon labor costs.

In
addition, Kinder Morgan Production Company is responsible for processing and
directly paying invoices for fuels utilized by the plant. Other materials,
including but not limited to lubrication oil, hydraulic oils, chemicals,
ammonia and any catalyst are purchased by Knight and invoiced monthly as
provided by the contract, if not paid directly by Kinder Morgan Production
Company. The amounts paid to Knight in 2008, 2007 and 2006 for operating and
maintaining the power plant were $3.1 million, $3.1 million and $2.9 million,
respectively. Furthermore, we believe the amounts paid to Knight for the
services they provide each year fairly reflect the value of the services
performed.

Risk
Management

Certain
of our business activities expose us to risks associated with changes in the
market price of natural gas, natural gas liquids and crude oil. We also have
exposure to interest rate risk as a result of the issuance of our fixed rate
debt obligations. Pursuant to our managements approved risk management policy,
we use derivative contracts to hedge or reduce our exposure to these risks and
protect our profit margins.

Our
commodity-related risk management activities are monitored by our risk
management committee, which is a separately designated standing committee whose job responsibilities involve operations
exposed to commodity market risk and other external risks in the ordinary
course of business. Our risk management committee is charged with the
review and enforcement of our managements risk management policy. The
committee is comprised of 17 executive-level employees of Knight or KMGP Services Company, Inc. whose job
responsibilities involve operations exposed to commodity market risk and other
external risks in the ordinary course of our businesses. The committee is
chaired by our President and is charged with the following three
responsibilities: (i) establish and review risk limits consistent with our risk
tolerance philosophy; (ii) recommend to the audit committee of our general
partners delegate any changes, modifications, or amendments to our risk
management policy; and (iii) address and resolve any other high-level risk
management issues.

In
addition, as discussed in Note 1, as a result of the May 2007 going-private
transaction of Knight, a number of individuals and entities became significant
investors in Knight. By virtue of the size of their ownership interest in

174

Knight, two of
those investors became related parties to us (as that term is defined in
authoritative accounting literature): (i) American International Group, Inc.,
referred to in this report as AIG, and certain of its affiliates; and (ii)
Goldman Sachs Capital Partners and certain of its affiliates.

We
and/or our affiliates enter into transactions with certain AIG affiliates in
the ordinary course of their conducting insurance and insurance-related
activities, although no individual transaction is, and all such transactions
collectively are not, material to our consolidated financial statements. We
also conduct commodity risk management activities in the ordinary course of
implementing our risk management strategies in which the counterparty to
certain of our derivative transactions is an affiliate of Goldman Sachs. In
conjunction with these activities, we are a party (through one of our
subsidiaries engaged in the production of crude oil) to a hedging facility with
J. Aron & Company/Goldman Sachs which requires us to provide certain
periodic information, but does not require the posting of margin. As a result
of changes in the market value of our derivative positions, we have created
both amounts receivable from and payable to Goldman Sachs affiliates.

The
following table summarizes the fair values of our energy commodity derivative
contracts that are (i) associated with commodity price risk management
activities with related parties; and (ii) included on our accompanying
consolidated balance sheets as of December 31, 2008 and December 31, 2007 (in
millions):

December
 31,
 2008

December
 31,
 2007Derivatives-
asset/(liability)Other current assets

$
60.4

$
Deferred charges and other
assets


20.1


Accrued other current
liabilities


(13.2
)

(239.8
)Other long-term liabilities and
deferred credits

$
(24.1
)
$
(386.5
)For
more information on our risk management activities see Note 14.

KM
Insurance, Ltd.

KM
Insurance, Ltd., referred to as KMIL, is a Bermuda insurance company and
wholly-owned subsidiary of Knight. KMIL was formed during the second quarter of
2005 as a Class 2 Bermuda insurance company, the sole business of which is to
issue policies for Knight and us to secure the deductible portion of our
workers compensation, automobile liability, and general liability policies
placed in the commercial insurance market. We accrue for the cost of insurance,
which is included in the related party general and administrative expenses and
which totaled approximately $7.6 million in 2008, $3.6 million in 2007 and $5.8
million in 2006.

Notes
Receivable

Plantation
Pipe Line Company

We
have a seven-year note receivable bearing interest at the rate of 4.72% per
annum from Plantation Pipe Line Company, our 51.17%-owned equity investee. The
outstanding note receivable balance was $88.5 million as of December 31, 2008,
and $89.7 million as of December 31, 2007. Of these amounts, $3.7 million and
$2.4 million were included within Accounts, notes and interest receivable,
netRelated parties, as of December 31, 2008 and December 31, 2007,
respectively, and the remainder was included within Notes
receivableRelated parties at each reporting date.

Express
US Holdings LP

In
conjunction with the acquisition of our 33 1/3% equity ownership interest in
the Express pipeline system (discussed in Note 3 Acquisitions and Joint
VenturesAcquisitions from KnightExpress and Jet Fuel Pipeline Systems) from
Knight on August 28, 2008, we acquired a long-term investment 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. As of
our acquisition date, the value of this unsecured debenture was equal to
Knights carrying value of $107.0 million. The note is denominated in Canadian
dollars, and the principal amount of the note is $113.6 million Canadian
dollars, due in full on January 9, 2023. It bears interest at the rate of 12.0%
per annum and

175

provides for
quarterly payments of interest in Canadian dollars on March 31, June 30,
September 30 and December 31 each year.

As
of December 31, 2008, the outstanding note receivable balance, representing the
translated amount included in our consolidated financial statements in U.S.
dollars, was $93.3 million, and we included this amount within Notes
receivableRelated parties on our accompanying consolidated balance
sheet.

Knight
Inc.

As
of December 31, 2007, an affiliate of Knight owed to us a long-term note with a
principal amount of $0.6 million, and we included this balance within Notes
receivableRelated parties on our consolidated balance sheet as of that
date. The note had no fixed terms of repayment and was denominated in Canadian
dollars. In each of the second and third quarters of 2008, we received payments
of $0.3 million in principal amount under this note, and as of December 31,
2008, there was no outstanding balance due under this note. The above amounts
represent translated amounts in U.S. dollars.

Additionally,
prior to our acquisition of Trans Mountain on April 30, 2007, Knight and
certain of its affiliates advanced cash to Trans Mountain. The advances were
primarily used by Trans Mountain for capital expansion projects. Knight and its
affiliates also funded Trans Mountains cash book overdrafts (outstanding
checks) as of April 30, 2007. Combined, the funding for these items totaled
$67.5 million, and we reported this amount within the caption Changes in
components of working capital: Accounts Receivable in the operating section of
our accompanying consolidated statement of cash flows.

Coyote
Gas Treating, LLC

Coyote
Gas Treating, LLC is a joint venture that was organized in December 1996. It is
referred to as Coyote Gulch in this report. The sole asset owned by Coyote
Gulch is a 250 million cubic feet per day natural gas treating facility located
in La Plata County, Colorado. Prior to the contribution of our ownership
interest in Coyote Gulch to Red Cedar Gathering on September 1, 2006 (described
below), we were the managing partner and owned a 50% equity interest in Coyote
Gulch.

As
of January 1, 2006, we had a $17.0 million note receivable from Coyote Gulch.
The term of the note was month-to-month. In March 2006, the owners of Coyote
Gulch agreed to transfer Coyote Gulchs notes payable to members equity.
Accordingly, we contributed the principal amount of $17.0 million related to
our note receivable to our equity investment in Coyote Gulch.

On
September 1, 2006, we and the Southern Ute Tribe (owners of the remaining 50%
interest in Coyote Gulch) agreed to transfer all of the members equity in
Coyote Gulch to the members equity of Red Cedar Gathering Company, a joint
venture organized in August 1994. Red Cedar owns and operates natural gas
gathering, compression and treating facilities in the Ignacio Blanco Field in
La Plata County, Colorado, and is owned 49% by us and 51% by the Southern Ute
Tribe.

Accordingly,
on September 1, 2006, we and the Southern Ute Tribe contributed the value of
our respective 50% ownership interests in Coyote Gulch to Red Cedar, and as a
result, Coyote Gulch became a wholly owned subsidiary of Red Cedar. The value
of our 50% equity contribution from Coyote Gulch to Red Cedar on September 1,
2006 was $16.7 million, and this amount remains included within Investments
on our consolidated balance sheet as of December 31, 2008 and 2007.

Other

Generally,
KMR makes all decisions relating to the management and control of our business.
Our general partner owns all of KMRs voting securities and is its sole
managing member. Knight, through its wholly owned and controlled subsidiary
Kinder Morgan (Delaware), Inc., owns all the common stock of our general
partner. Certain conflicts of interest could arise as a result of the
relationships among KMR, our general partner, Knight and us. The officers of
Knight have fiduciary duties to manage Knight, including selection and
management of its investments in its subsidiaries and affiliates, in a manner
beneficial to themselves. In general, KMR has a fiduciary

176

duty to manage us in a manner beneficial to our unitholders. The
partnership agreements for us and our operating partnerships contain provisions
that allow KMR to take into account the interests of parties in addition to us
in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders,
as well as provisions that may restrict the remedies available to our
unitholders for actions taken that might, without such limitations, constitute
breaches of fiduciary duty.

The
partnership agreements provide that in the absence of bad faith by KMR, the
resolution of a conflict by KMR will not be a breach of any duties. The duty of
the officers of Knight may, therefore, come into conflict with the duties of
KMR and its directors and officers to our unitholders. The audit committee of
KMRs board of directors will, at the request of KMR, review (and is one of the
means for resolving) conflicts of interest that may arise between Knight or its
subsidiaries, on the one hand, and us, on the other hand.

13.
Leases and
 CommitmentsCapital
Leases

We acquired
certain leases classified as capital leases as part of our acquisition of
Kinder Morgan River Terminals LLC in October 2004. We lease our Memphis,
Tennessee port facility under an agreement accounted for as a capital lease.
The lease is for 24 years and expires in 2017.

Amortization
of assets recorded under capital leases is included with depreciation expense.
The components of property, plant and equipment recorded under capital leases
are as follows (in millions):

December 31,
 2008

December 31,
 2007Leasehold improvements

$
2.2

$
2.2Less: Accumulated amortization


(0.4
)

(0.3
)Total

$
1.8

$
1.9Future
commitments under capital lease obligations as of December 31, 2008 are as
follows (in millions):

Year

Commitment2009

$
0.22010


0.22011


0.22012


0.22013


0.2Thereafter


0.5Subtotal


1.5Less: Amount representing
 interest


(0.5
)Present value of minimum capital lease payments

$
1.0Operating
Leases

Including
probable elections to exercise renewal options, the remaining terms on our
operating leases range from one to 61 years. Future commitments related to
these leases as of December 31, 2008 are as follows (in millions):

Year

Commitment2009

$
31.12010


27.72011


22.12012


17.92013


13.8Thereafter


34.9Total minimum payments

$
147.5177

We have not
reduced our total minimum payments for future minimum sublease rentals
aggregating approximately $1.1 million. Total lease and rental expenses were
$61.7 million for 2008, $49.2 million for 2007 and $54.2 million for 2006.

Directors
Unit Appreciation Rights Plan

On April 1,
2003, KMRs compensation committee established our Directors Unit Appreciation
Rights Plan. Pursuant to this plan, each of KMRs non-employee directors was
eligible to receive common unit appreciation rights. Upon the exercise of unit
appreciation rights, we will pay, within thirty days of the exercise date, the
participant an amount of cash equal to the excess, if any, of the aggregate
fair market value of the unit appreciation rights exercised as of the exercise date
over the aggregate award price of the rights exercised. The fair market value
of one unit appreciation right as of the exercise date will be equal to the
closing price of one common unit on the New York Stock Exchange on that date.
The award price of one unit appreciation right will be equal to the closing
price of one common unit on the New York Stock Exchange on the date of grant.

All unit
appreciation rights granted vest on the six-month anniversary of the date of
grant. If a unit appreciation right is not exercised in the ten year period
following the date of grant, the unit appreciation right will expire and not be
exercisable after the end of such period. In addition, if a participant ceases
to serve on the board for any reason prior to the vesting date of a unit
appreciation right, such unit appreciation right will immediately expire on the
date of cessation of service and may not be exercised.

During the
first board meeting of 2005, the plan was terminated and replaced by the Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors (discussed following).

No unit
appreciation rights were exercised during 2006. During 2007, 7,500 unit
appreciation rights were exercised by one director at an aggregate fair value
of $53.00 per unit. During 2008, 10,000 unit appreciation rights were exercised
by one director at an aggregate fair value of $60.32 per unit. As of December
31, 2008, 35,000 unit appreciation rights had been granted, vested and remained
outstanding.

Kinder
Morgan Energy Partners, L.P. Common Unit Compensation Plan for Non-Employee
Directors

On January
18, 2005, KMRs compensation committee
established the Kinder Morgan Energy Partners, L.P. Common Unit Compensation
Plan. The plan is administered by KMRs compensation committee and KMRs board
has sole discretion to terminate the plan at any time. The primary purpose of
this plan was to promote our interests and the interests of our unitholders by
aligning the compensation of the non-employee members of the board of directors
of KMR with unitholders interests. Further, since KMRs success is dependent
on its operation and management of our business and our resulting performance,
the plan is expected to align the compensation of the non-employee members of
the board with the interests of KMRs shareholders.

The plan
recognizes that the compensation to be paid to each non-employee director is
fixed by the KMR board, generally annually, and that the compensation is
payable in cash. Pursuant to the plan, in lieu of receiving cash compensation,
each non-employee director may elect to receive common units. Each election is
made generally at or around the first board meeting in January of each calendar
year and is effective for the entire calendar year. A non-employee director may
make a new election each calendar year. The total number of common units
authorized under this compensation plan is 100,000.

The
elections under this plan for 2006, 2007, and 2008 were made effective January
17, 2006, January 17, 2007 and January 16, 2008, respectively. The election for
2009 by Messrs. Hultquist and Waughtal were made effective
January 21, 2009, and the election for 2009 by Mr. Lawrence was made effective January
28, 2009. Each annual election is evidenced
by an agreement, the Common Unit Compensation Agreement, between us and each non-employee director, and
this agreement contains the terms and conditions of each award. Pursuant to
this agreement, all common units issued under this plan are subject to
forfeiture restrictions that expire six months from the date of issuance. Until
the forfeiture restrictions lapse, common units issued under the plan may not
be sold, assigned, transferred, exchanged, or pledged by a non-employee
director. In the event the directors service as a director of KMR is
terminated prior to the lapse of the forfeiture restriction either for cause,
or voluntary resignation, each director will, for no consideration, forfeit to
us all common units to the extent then subject to the forfeiture

178

restrictions. Common units with respect to which forfeiture
restrictions have lapsed cease to be subject to any forfeiture restrictions,
and we will provide each director a certificate representing the units as to
which the forfeiture restrictions have lapsed. In addition, each non-employee
director has the right to receive distributions with respect to the common
units awarded to him under the plan, to vote such common units and to enjoy all
other unitholder rights, including during the period prior to the lapse of the
forfeiture restrictions.

The
number of common units to be issued to a non-employee director electing to
receive the cash compensation in the form of common units will equal the amount
of such cash compensation awarded, divided by the closing price of the common units on the New York Stock Exchange on the
day the cash compensation is awarded (such
price, the fair market value), rounded down to the nearest 50 common
units. The common units will be issuable as specified in the Common Unit
Compensation Agreement. A non-employee director electing to receive the cash
compensation in the form of common units will receive cash equal to the
difference between (i) the cash compensation awarded to such non-employee
director and (ii) the number of common units to be issued to such non-employee
director multiplied by the fair market
value of a common unit. This cash payment is payable in four equal installments
generally around March 31, June 30, September 30 and December 31 of the
calendar year in which such cash compensation is awarded.

On January
17, 2006, each of KMRs then three non-employee directors was awarded cash
compensation of $160,000 for board service during 2006. Effective January 17,
2006, each non-employee director elected to receive compensation of $87,780 in
the form of our common units and was issued 1,750 common units pursuant to the
plan and its agreements (based on the $50.16 closing market price of our common
units on January 17, 2006, as reported on the New York Stock Exchange). The
remaining $72,220 cash compensation was paid to each of the non-employee
directors as described above. No other compensation was paid to the
non-employee directors during 2006.

On January
17, 2007, each of KMRs then three non-employee directors was awarded cash
compensation of $160,000 for board service during 2007. Effective January 17,
2007, each non-employee director elected to receive certain amounts of compensation
in the form of our common units and each were issued common units pursuant to
the plan and its agreements (based on the $48.44 closing market price of our
common units on January 17, 2007, as reported on the New York Stock Exchange).
Mr. Gaylord elected to receive compensation of $95,911.20 in the form of our
common units and was issued 1,980 common units; Mr. Waughtal elected to receive
compensation of $159,852.00 in the form of our common units and was issued
3,300 common units; and Mr. Hultquist elected to receive compensation of
$96,880.00 in the form of our common units and was issued 2,000 common units.
All remaining cash compensation ($64,088.80 to Mr. Gaylord; $148.00 to Mr.
Waughtal; and $63,120.00 to Mr. Hultquist) was paid to each of the non-employee
directors as described above, and no other compensation was paid to the
non-employee directors during 2007.

On January
16, 2008, each of KMRs then three non-employee directors was awarded cash
compensation of $160,000 for board service during 2008; however, during a plan
audit it was determined that each director was inadvertently paid an additional
dividend in 2007. As a result, each directors cash compensation for service
during 2008 was adjusted downward to reflect this error. The correction results
in cash compensation awarded for 2008 in the amounts of $158,380.00 for Mr.
Hultquist; $158,396.20 for Mr. Gaylord; and $157,327.00 for Mr. Waughtal.
Effective January 16, 2008, two of the three non-employee directors elected to
receive certain amounts of compensation in the form of our common units and
each was issued common units pursuant to the plan and its agreements (based on
the $55.81 closing market price of our common units on January 16, 2008, as
reported on the New York Stock Exchange). Mr. Gaylord elected to receive
compensation of $84,831.20 in the form of our common units and was issued 1,520
common units; and Mr. Waughtal elected to receive compensation of $157,272.58
in the form of our common units and was issued 2,818 common units. All
remaining cash compensation ($73,565.00 to Mr. Gaylord; $54.42 to Mr. Waughtal;
and $158,380.00 to Mr. Hultquist) was paid to each of the non-employee
directors as described above, and no other compensation was paid to the
non-employee directors during 2008.

On January
21, 2009, each of KMRs three non-employee directors (with Mr. Lawrence
replacing Mr. Gaylord after Mr. Gaylords death) was awarded cash compensation
of $160,000 for board service during 2009. Effective January 21, 2009, Mr.
Hultquist and Mr. Waughtal elected to receive the full amount of their
compensation in the form of cash only. Effective January 28, 2009, Mr. Lawrence
elected to receive compensation of $159,136.00 in the

179

form of our common units and was issued 3,200 common units. His
remaining compensation ($864.00) will be paid in cash as described above. No
other compensation will be paid to the non-employee directors during 2009.

14.
Risk ManagementCertain
of our business activities expose us to risks associated with unfavorable
changes in the market price of natural gas, natural gas liquids and crude oil.
We also have exposure to interest rate risk as a result of the issuance of our
debt obligations. Pursuant to our managements approved risk management policy,
we use derivative contracts to hedge or reduce our exposure to certain of these
risks, and we account for these hedging transactions according to the
provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities and associated amendments, collectively, SFAS No. 133.

Energy
Commodity Price Risk Management

We
are exposed to risks associated with unfavorable changes in the market price of
natural gas, natural gas liquids and crude oil as a result of the forecasted
purchase or sale of these products. Specifically, these risks are associated
with unfavorable price volatility related to (i) pre-existing or anticipated
physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas
purchases; and (iii) natural gas system use and storage.

Given
our portfolio of businesses as of December 31, 2008, our principal use of
energy commodity derivative contracts was to mitigate the risk associated with
unfavorable market movements in the price of energy commodities. The
unfavorable price changes are often caused by shifts in the supply and demand
for these commodities, as well as their locations. Our energy commodity
derivative contracts act as a hedging (offset) mechanism against the volatility
of energy commodity prices by allowing us to transfer this price risk to
counterparties who are able and willing to bear it.

Discontinuance
of Hedge Accounting

Effective
at the beginning of the second quarter of 2008, we determined that the
derivative contracts of our Casper and Douglas natural gas processing
operations that previously had been designated as cash flow hedges for
accounting purposes no longer met the hedge effectiveness assessment as
required by SFAS No. 133. Consequently, we discontinued hedge accounting
treatment for these relationships (primarily crude oil hedges of heavy natural
gas liquids sales) effective as of March 31, 2008. Since the forecasted sales of
natural gas liquids volumes (the hedged item) are still expected to occur, all
of the accumulated losses through March 31, 2008 on the related derivative
contracts remained in accumulated other comprehensive income, and will not be
reclassified into earnings until the physical transactions occurs. Any changes
in the value of these derivative contracts subsequent to March 31, 2008
will no longer be deferred in other comprehensive income, but rather will impact
current period income. As a result, we recognized an increase in income of $5.6
million in 2008 related to the increase in value of derivative contracts
outstanding as of December 31, 2008 for which hedge accounting had been
discontinued.

Hedging
effectiveness and ineffectiveness

Pursuant
to SFAS No. 133, our energy commodity derivative contracts are designated as
cash flow hedges and for cash flow hedges, the portion of the change in the
value of derivative contracts that is effective in offsetting undesired changes
in expected cash flows (the effective portion) is reported as a component of
other comprehensive income (outside current earnings, net income), but only to
the extent that they can later offset the undesired changes in expected cash
flows during the period in which the hedged cash flows affect earnings. To the
contrary, the portion of the change in the value of derivative contracts that
is not effective in offsetting undesired changes in expected cash flows (the
ineffective portion), as well as any component excluded from the computation of
the effectiveness of the derivative contracts, is required to be recognized
currently in earnings. Reflecting the portion of changes in the value of
derivative contracts that were not effective in offsetting underlying changes
in expected cash flows (the ineffective portion of hedges), we recognized a
loss of $2.4 million during 2008, a loss of $0.1 million during 2007 and a loss
of $1.3 million during 2006, respectively. These recognized losses resulting
from hedge ineffectiveness are reported within the captions Natural gas sales,
Gas purchases and other costs of sales, and Product sales and other in our
accompanying consolidated statements of income, and for each of the years ended

180

2008, 2007 and
2006, we did not exclude any component of the derivative contracts gain or
loss from the assessment of hedge effectiveness.

Furthermore,
during the years 2008, 2007 and 2006, we reclassified $663.7 million, $433.2
million and $428.1 million, respectively, of Accumulated other comprehensive
loss into earnings. With the exception of (i) an approximate $0.1 million loss
reclassified in the first quarter of 2007; and (ii) a $2.9 million loss
resulting from the discontinuance of cash flow hedges related to the sale of
our Douglas gathering assets in 2006 (described in Note 3 DivestituresDouglas
Gas Gathering and Painter Gas Fractionation), none of the reclassification of
Accumulated other comprehensive loss into earnings during 2008, 2007 or 2006
resulted from the discontinuance of cash flow hedges due to a determination
that the forecasted transactions would no longer occur by the end of the
originally specified time period or within an additional two-month period of
time thereafter, but rather resulted from the hedged forecasted transactions
actually affecting earnings (for example, when the forecasted sales and
purchases actually occurred). The proceeds or payments resulting from the
settlement of cash flow hedges are reflected in the operating section of our
statement of cash flows as changes to net income and working capital.

Our
consolidated Accumulated other comprehensive loss balance was $287.7 million
as of December 31, 2008 and $1,276.6 million as of December 31, 2007. These
consolidated totals included Accumulated other comprehensive loss amounts
associated with the commodity price risk management activities of $63.2 million
as of December 31, 2008 and $1,377.2 million as of December 31, 2007.
Approximately $20.4 million of the total amount associated with our commodity
price risk management activities as of December 31, 2008 is expected to be
reclassified into earnings during the next twelve months (when the associated
forecasted sales and purchases are also expected to occur).

Fair
Value of Energy Commodity Derivative Contracts

Derivative
contracts that are entered into for the purpose of mitigating commodity price
risk include swaps, futures and options. Additionally, basis swaps may also be
used in connection with another derivative contract to reduce hedge
ineffectiveness by reducing a basis difference between a hedged exposure and a
derivative contract. The fair values of these derivative contracts are included
in our accompanying consolidated balance sheets within Other current assets,
Deferred charges and other assets, Accrued other current liabilities, and
Other long-term liabilities and deferred credits.

The
following table summarizes the fair values of our energy commodity derivative
contracts associated with our commodity price risk management activities and
included on our accompanying consolidated balance sheets as of December 31,
2008 and December 31, 2007 (in millions):

December
 31,
 2008




December
 31,
 2007Derivatives-net
 asset/(liability)Other current assets

$
115.3



$
37.0Deferred charges and other
assets


48.9




4.4Accrued other current
liabilities


(129.5
)



(593.9
)Other long-term liabilities and
deferred credits

$
(92.2
)


$
(836.8
)As
of December 31, 2008, the maximum length of time over which we have hedged our
exposure to the variability in future cash flows associated with energy
commodity price risk is through April 2013. Additional information on the fair
value measurements of our energy commodity derivative contracts is included
below in SFAS No. 157.

Interest
Rate Risk Management

In
order to maintain a cost effective capital structure, it is our policy to
borrow funds using a mix of fixed rate debt and variable rate debt. We use
interest rate swap agreements to manage the interest rate risk associated with
the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related
to our long-term fixed rate debt securities into variable rate cash flows in
order to achieve our desired mix of fixed and variable rate debt.

181

Since the
fair value of fixed rate debt varies inversely with changes in the market rate
of interest, we enter into swap agreements to receive a fixed and pay a
variable rate of interest in order to convert the interest
expense associated with certain of our senior notes from fixed rates to
variable rates, resulting in future cash
flows that vary with the market rate of interest. These swaps, therefore, hedge
against changes in the fair value of our fixed rate debt that result from
market interest rate changes.

As of
December 31, 2007, we were a party to interest rate swap agreements with a
total notional principal amount of $2.3 billion. On February 12,
2008, following our issuance of $600 million of 5.95% senior notes on that
date, we entered into two additional fixed-to-variable interest rate swap
agreements having a combined notional principal amount of $500 million. On June
6, 2008, following our issuance of $700 million in principal amount of senior
notes in two separate series on that date, we entered into two additional
fixed-to-variable interest rate swap agreements having a combined notional
principal amount of $700 million. Then, in December 2008, we took advantage of
the market conditions by terminating two of our existing fixed-to-variable swap
agreements. In separate transactions, we terminated fixed-to-variable interest
rate swap agreements having (i) a notional principal amount of $375 million and
a maturity date of February 15, 2018; and (ii) a notional principal amount of
$325 million and a maturity date of January 15, 2038. We received combined
proceeds of $194.3 million from the early termination of these swap agreements.

Therefore,
as of December 31, 2008, we had a combined notional principal amount of $2.8
billion of fixed-to-variable interest rate swap agreements effectively
converting the interest expense associated with certain series of our senior
notes from fixed rates to variable rates based on an interest rate of LIBOR
plus a spread. All of our swap agreements have termination dates that
correspond to the maturity dates of the related series of senior notes and, as
of December 31, 2008, the maximum length of time over which we have hedged a
portion of our exposure to the variability in the value of this debt due to
interest rate risk is through January 15, 2038.

Hedging
effectiveness and ineffectiveness

Our
interest rate swap contracts have been designated as fair value hedges and meet
the conditions required to assume no ineffectiveness under SFAS No. 133.
Therefore, we have accounted for them using the shortcut method prescribed by
SFAS No. 133 and accordingly, we adjust the carrying value of each swap
contract to its fair value each quarter, with an offsetting entry to adjust the
carrying value of the debt securities whose fair value is being hedged. We
record interest expense equal to the variable rate payments under the swap
contracts.

Fair
Value of Interest Rate Swap Agreements

The
differences between the fair value and the original carrying value associated
with our interest rate swap agreements, that is, the derivative contracts
changes in fair value, are included within Deferred charges and other assets
and Other long-term liabilities and deferred credits in our accompanying
consolidated balance sheets. The offsetting entry to adjust the carrying value
of the debt securities whose fair value was being hedged is included within
Value of interest rate swaps on our accompanying consolidated balance sheets,
which also includes any unamortized portion of proceeds received from the early
termination of interest rate swap agreements.

Our
settlement amounts continue to be accounted for in connection with the original
anticipated interest payments that the swap was established to offset (since
they are still expected to occur as designated), and accordingly, we amortize
this deferred gain or loss (as a reduction or increase to periodic interest
expense) over the remaining term of the original swap periods. To date, all the
swaps we have terminated have resulted in deferred gains. As of December 31,
2008, unamortized premiums received from early swap terminations totaled $204.2
million. In addition to the two swap agreements we terminated in December 2008,
discussed above, in March 2007 we terminated an existing fixed-to-variable
interest rate swap agreement having a notional principal amount of $100 million
and a maturity date of March 15, 2032. We received $15.0 million from the early
termination of this swap agreement, and as of December 31, 2007, this
unamortized premium totaled $14.2 million.

The
following table summarizes the net fair value of our interest rate swap
agreements associated with our interest rate risk management activities and
included on our accompanying consolidated balance sheets as of December 31,
2008 and December 31, 2007 (in millions):

182

December 31,
 2008

December 31,
 2007Derivatives-net
asset/(liability)Deferred charges and other assets


$
747.1



$
138.0Other long-term
liabilities and deferred credits








Net fair value
of interest rate swaps


$
747.1



$
138.0Additional
information on the fair value measurements of our interest rate swap agreements
is included below in SFAS No. 157.

Subsequent
Event

In
January 2009 we terminated an existing fixed-to-variable swap agreement having
a notional principal amount of $300 million and a maturity date of March 15,
2031. We received proceeds of $144.4 million from the early termination of this
swap agreement.

SFAS No.
157

On
September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. In
general, fair value measurements and disclosures are made in accordance with
the provisions of this Statement and, while not requiring material new fair
value measurements, SFAS No. 157 established a single definition of fair value
in generally accepted accounting principles and expanded disclosures about fair
value measurements. The provisions of this Statement apply to other accounting
pronouncements that require or permit fair value measurements; the Financial
Accounting Standards Board having previously concluded in those accounting
pronouncements that fair value is the relevant measurement attribute.

On
February 12, 2008, the FASB issued FASB Staff Position FAS 157-2, Effective
Date of FASB Statement No. 157, referred to as FAS 157-2 in this report. FAS
157-2 delayed the effective date of SFAS No. 157 for all nonfinancial assets
and nonfinancial liabilities, except those that are recognized or disclosed at
fair value in the financial statements on a recurring basis (at least
annually).

Accordingly,
we adopted SFAS No. 157 for financial assets and financial liabilities
effective January 1, 2008. The adoption did not have a material impact on our
balance sheet, statement of income, or statement of cash flows since we already
apply its basic concepts in measuring fair values. We adopted SFAS No. 157 for
non-financial assets and non-financial liabilities effective January 1, 2009.
This includes applying the provisions of SFAS No. 157 to (i) nonfinancial
assets and liabilities initially measured at fair value in business
combinations; (ii) reporting units or nonfinancial assets and liabilities
measured at fair value in conjunction with goodwill impairment testing; (iii)
other nonfinancial assets measured at fair value in conjunction with impairment
assessments; and (iv) asset retirement obligations initially measured at fair
value. The adoption did not have a material impact on our balance sheet, statement
of income, or statement of cash flows since we already apply its basic concepts
in measuring fair values.

On
October 10, 2008, the FASB issued FASB Staff Position FAS 157-3, Determining
the Fair Value of a Financial Asset When the Market for That Asset Is Not
Active, referred to as FAS 157-3 in this report. FAS 157-3 provides
clarification regarding the application of SFAS 157 in inactive markets. The
provisions of FAS 157-3 were effective upon issuance. This Staff Position did
not have any material effect on our consolidated financial statements.

The
degree of judgment utilized in measuring the fair value of financial
instruments generally correlates to the level of pricing observability. Pricing
observability is affected by a number of factors, including the type of
financial instrument, whether the financial instrument is new to the market,
and the characteristics specific to the transaction. Financial instruments with
readily available active quoted prices or for which fair value can be measured
from actively quoted prices generally will have a higher degree of pricing
observability and a lesser degree of judgment utilized in measuring fair value.
Conversely, financial instruments rarely traded or not quoted will generally have
less (or no) pricing observability and a higher degree of judgment utilized in
measuring fair value.

183

SFAS
No. 157 established a hierarchal disclosure framework associated with the level
of pricing observability utilized in measuring fair value. This framework
defined three levels of inputs to the fair value measurement process, and
requires that each fair value measurement be assigned to a level corresponding
to the lowest level input that is significant to the fair value measurement in
its entirety. The three broad levels of inputs defined by the SFAS No. 157
hierarchy are as follows:

 Level 1
Inputsquoted prices
 (unadjusted) in active markets for identical assets or liabilities that the
 reporting entity has the ability to access at the measurement date; Level 2
Inputsinputs other than
 quoted prices included within Level 1 that are observable for the asset or
 liability, either directly or indirectly. If the asset or liability has a
 specified (contractual) term, a Level 2 input must be observable for
 substantially the full term of the asset or liability; and Level 3
Inputsunobservable inputs
 for the asset or liability. These unobservable inputs reflect the entitys
 own assumptions about the assumptions that market participants would use in
 pricing the asset or liability, and are developed based on the best
 information available in the circumstances (which might include the reporting
 entitys own data).Derivative
contracts can be exchange-traded or over-the-counter, referred to in this
report as OTC. Exchange-traded derivative contracts typically fall within
Level 1 of the fair value hierarchy if they are traded in an active
market. We value exchange-traded derivative contracts using quoted market prices
for identical securities.

OTC
derivative contracts are valued using models utilizing a variety of inputs
including contractual terms; commodity, interest rate and foreign currency
curves; and measures of volatility. The selection of a particular model and
particular inputs to value an OTC derivative contract depends upon the
contractual terms of the instrument as well as the availability of pricing
information in the market. We use similar models to value similar instruments.
For OTC derivative contracts that trade in liquid markets, such as generic
forwards and swaps, model inputs can generally be verified and model selection
does not involve significant management judgment. Such contracts are typically
classified within Level 2 of the fair value hierarchy.

Certain
OTC derivative contracts trade in less liquid markets with limited pricing
information, and the determination of fair value for these derivative contracts
is inherently more difficult. Such contracts are classified within Level 3
of the fair value hierarchy. The valuations of these less liquid OTC derivative
contracts are typically impacted by Level 1 and/or Level 2 inputs
that can be observed in the market, as well as unobservable Level 3
inputs. Use of a different valuation model or different valuation input values
could produce a significantly different estimate of fair value. However,
derivative contracts valued using inputs unobservable in active markets are
generally not material to our financial statements.

When
appropriate, valuations are adjusted for various factors including credit
considerations. Such adjustments are generally based on available market
evidence. In the absence of such evidence, managements best estimate is used.
Our fair value measurements of derivative contracts are adjusted for credit
risk in accordance with SFAS No. 157, and as of December 31, 2008, our
consolidated Accumulated other comprehensive loss balance includes a gain of
$2.2 million related to discounting the value of our energy commodity
derivative liabilities for the effect of credit risk. We also adjusted
the fair value measurements of our interest rate swap agreements for credit
risk in accordance with SFAS No. 157, and as of December 31, 2008, our
consolidated Value of interest rate swaps balance included a decrease (loss)
of $10.6 million related to discounting the fair value measurement of our
interest rate swap agreements asset value for the effect of credit risk.

The
following tables summarize the fair value measurements of our (i) energy
commodity derivative contracts; and (ii) interest rate swap agreements as of
December 31, 2008, based on the three levels established by SFAS No. 157, and
does not include cash margin deposits, which are reported as Restricted
deposits in our accompanying consolidated balance sheets (in millions):

184

Asset Fair Value Measurements as of
 December 31, 2008 UsingTotal

Quoted Prices in Active
 Markets for Identical
 Assets (Level 1)

Significant Other
 Observable
 Inputs (Level 2)

Significant
 Unobservable
 Inputs (Level 3)Energy
 commodity derivative contracts(a)

$
164.2


$
0.1



$
108.9



$
55.2Interest
 rate swap agreements


747.1








747.1




Liability Fair Value Measurements as of
 December 31, 2008 UsingTotal

Quoted Prices in Active
 Markets for Identical
 Liabilities (Level 1)

Significant Other
 Observable
 Inputs (Level 2)

Significant
 Unobservable
 Inputs (Level 3)Energy
 commodity derivative contracts(b)

$
(221.7
)

$




$
(210.6
)


$
(11.1
)Interest
 rate swap agreements
















(a)
Level 2
 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas
 hedges that are settled on NYMEX. Level 3 consists primarily of West Texas
 Intermediate options and West Texas Sour hedges.(b)
Level 2
 consists primarily of OTC West Texas Intermediate hedges. Level 3 consists
 primarily of natural gas basis swaps, natural gas options and West Texas Intermediate
 options.The
table below provides a summary of changes in the fair value of our Level 3
energy commodity derivative contracts for the year ended December 31, 2008 (in
millions):

Significant Unobservable Inputs (Level 3)Year Ended
 December 31, 2008Derivatives-net
 asset/(liability)Beginning of Period


$
(100.3
)Realized and unrealized net
losses



69.6Purchases and
settlements



74.8Transfers in (out) of Level
3



End of Period


$
44.1Change in unrealized net losses
relating to
 contracts still held as of December 31, 2008


$
88.8Credit
Risks

We
have counterparty credit risk as a result of our use of energy commodity derivative
contracts. Our counterparties consist primarily of financial institutions,
major energy companies and local distribution companies. This concentration of
counterparties may impact our overall exposure to credit risk, either
positively or negatively in that the counterparties may be similarly affected
by changes in economic, regulatory or other conditions.

We
maintain credit policies with regard to our counterparties that we believe
minimize our overall credit risk. These policies include (i) an evaluation of
potential counterparties financial condition (including credit ratings); (ii)
collateral requirements under certain circumstances; and (iii) the use of
standardized agreements which allow for netting of positive and negative exposure
associated with a single counterparty. Based on our policies, exposure, credit
and other reserves, our management does not anticipate a material adverse
effect on our financial position, results of operations, or cash flows as a
result of counterparty performance.

Our
over-the-counter swaps and options are entered into with counterparties outside
central trading organizations such as a futures, options or stock exchange.
These contracts are with a number of parties, all of which have investment grade
credit ratings. While we enter into derivative transactions principally with
investment grade counterparties and actively monitor their ratings, it is
nevertheless possible that from time to time losses will result from
counterparty credit risk in the future.

185

In
addition, in conjunction with the purchase of exchange-traded derivative
contracts or when the market value of our derivative contracts with specific
counterparties exceeds established limits, we are required to provide collateral
to our counterparties, which may include posting letters of credit or placing
cash in margin accounts. As of December 31, 2008 and December 31, 2007, we had
outstanding letters of credit totaling $40.0 million and $298.0 million,
respectively, in support of our hedging of commodity price risks associated
with the sale of natural gas, natural gas liquids and crude oil. Additionally,
as of December 31, 2008, our counterparties associated with our energy
commodity contract positions and over-the-counter swap agreements had margin
deposits with us totaling $3.1 million, and we reported this amount within
Accrued other liabilities in our accompanying consolidated balance sheet. As
of December 31, 2007, we had cash margin deposits associated with our commodity
contract positions and over-the-counter swap partners totaling $67.9 million,
and we reported this amount as Restricted deposits in our accompanying
consolidated balance sheet.

We
are also exposed to credit related losses in the event of nonperformance by
counterparties to our interest rate swap agreements. As of December 31, 2008,
all of our interest rate swap agreements were with counterparties with
investment grade credit ratings, and
the $747.1 million total value of our interest rate swap derivative assets at
December 31, 2008 (disclosed above) included amounts of $301.8 million and
$249.0 million related to open positions with Citigroup and Merrill Lynch,
respectively.

Other

Certain
of our business activities expose us to foreign currency fluctuations. However,
due to the limited size of this exposure, we do not believe the risks
associated with changes in foreign currency will have a material adverse effect on our business, financial position,
results of operations or cash flows. As a result, we do not significantly hedge
our exposure to fluctuations in foreign currency.

15.
Reportable SegmentsWe
divide our operations into five reportable business segments:


 Products Pipelines;
 Natural Gas Pipelines; CO2;
 Terminals; and
 Kinder Morgan CanadaEach
segment uses the same accounting policies as those described in the summary of
significant accounting policies (see Note 2). We evaluate
performance principally based on each segments earnings before depreciation,
depletion and amortization, which excludes general and administrative expenses,
third-party debt costs and interest expense, unallocable interest income, and
minority interest. Our reportable segments are strategic business units that
offer different products and services. Each segment is managed separately
because each segment involves different products and marketing strategies. We
identified our Trans Mountain pipeline system as a separate reportable business
segment prior to the third quarter of 2008. Following the acquisition of our
interests in the Express and Jet Fuel pipeline systems on August 28, 2008,
discussed in Note 3, we combined the operations of our Trans Mountain, Express
and Jet Fuel pipeline systems to represent the Kinder Morgan Canada segment.

Our
Products Pipelines segment derives its revenues primarily from the
transportation and terminaling of refined petroleum products, including
gasoline, diesel fuel, jet fuel and natural gas liquids. Our Natural Gas
Pipelines segment derives its revenues primarily from the sale, transport,
processing, treating, storage and gathering of natural gas. Our CO2
segment derives its revenues primarily from the production and sale of crude
oil from fields in the Permian Basin of West Texas and from the transportation
and marketing of carbon dioxide used as a flooding medium for recovering crude
oil from mature oil fields. Our Terminals segment derives its revenues
primarily from

186

the
transloading and storing of refined petroleum products and dry and liquid bulk
products, including coal, petroleum coke, cement, alumina, salt and other bulk
chemicals. Our Kinder Morgan Canada business segment derives its revenues
primarily from the transportation of crude oil and refined products.

As
discussed in Note 3, due to the October 2007 sale of our North System, an
approximately 1,600-mile interstate common carrier pipeline system whose
operating results were included as part of our Products Pipelines business
segment, we accounted for the North System business as a discontinued
operation. Consistent with the management approach of identifying and reporting
discrete financial information on operating segments, we have included the North
Systems financial results within our Products Pipelines business segment
disclosures for all periods presented in this report and, as prescribed by SFAS
No. 131, we have reconciled the total of our reportable segments financial
results to our consolidated financial results by separately identifying, in the
following pages where applicable, the North System amounts as discontinued
operations.

Financial
information by segment follows (in millions):

2008

2007

2006RevenuesProducts PipelinesRevenues from external
customers

$
815.9

$
844.4

$
776.3Intersegment revenues








Natural Gas PipelinesRevenues from external
customers


8,422.0


6,466.5


6,577.7Intersegment revenues








CO2Revenues from external
customers


1,133.0


824.1


736.5Intersegment revenues








TerminalsRevenues from external
customers


1,172.7


963.0


864.1Intersegment revenues


0.9


0.7


0.7Kinder Morgan CanadaRevenues from external
customers


196.7


160.8


137.8Intersegment revenues








Total segment revenues


11,741.2


9,259.5


9,093.1Less: Total intersegment
revenues


(0.9
)

(0.7
)

(0.7
)11,740.3


9,258.8


9,092.4Less: Discontinued
operations





(41.1
)

(43.7
)Total consolidated
revenues

$
11,740.3

$
9,217.7

$
9,048.7Operating expenses(a)Products Pipelines

$
291.0

$
451.8

$
308.3Natural Gas Pipelines


7,804.0


5,882.9


6,057.8CO2


391.8


304.2


268.1Terminals


631.8


536.4


461.9Kinder Morgan Canada


67.9


65.9


53.3Total segment operating
expenses


9,186.5


7,241.2


7,149.4Less: Total intersegment
operating expenses


(0.9
)

(0.7
)

(0.7
)9,185.6


7,240.5


7,148.7Less: Discontinued
operations





(14.8
)

(22.7
)Total consolidated operating
expenses

$
9,185.6

$
7,225.7

$
7,126.0Other expense (income)Products Pipelines

$
1.3

$
(154.8
)
$
Natural Gas Pipelines


(2.7
)

(3.2
)

(15.1
)CO2








Terminals


2.7


(6.3
)

(15.2
)Kinder Morgan
Canada(b)





377.1


(0.9
)Total segment Other expense
(income)


1.3


212.8


(31.2
)Less: Discontinued
operations


1.3


152.8


Total consolidated Other expense
(income)

$
2.6

$
365.6

$
(31.2
)187

2008

2007

2006Depreciation, depletion and
amortizationProducts
Pipelines

$
89.4

$
89.2

$
82.9Natural Gas
Pipelines


68.5


64.8


65.4CO2


385.8


282.2


190.9Terminals


122.6


89.3


74.6Kinder Morgan
Canada


36.4


21.5


19.0Total segment
depreciation, depletion and amortiz


702.7


547.0


432.8Less:
Discontinued operations





(7.0
)

(8.9
)Total consol.
depreciation, depletion and amortiz

$
702.7

$
540.0

$
423.9Earnings from equity
investmentsProducts
Pipelines

$
24.4

$
32.5

$
16.3Natural Gas
Pipelines


113.4


19.2


40.5CO2


20.7


19.2


19.2Terminals


2.7


0.6


0.2Kinder Morgan
Canada


(0.4
)




Total segment
earnings from equity investments


160.8


71.5


76.2Less:
Discontinued operations





(1.8
)

(2.2
)Total
consolidated equity earnings

$
160.8

$
69.7

$
74.0Amortization of excess cost of
equity investmentsProducts
Pipelines

$
3.3

$
3.4

$
3.4Natural Gas
Pipelines


0.4


0.4


0.3CO2


2.0


2.0


2.0Terminals








Kinder Morgan
Canada








Total segment
amortization of excess cost of invests


5.7


5.8


5.7Less:
Discontinued operations








(0.1
)Total consol.
amortization of excess cost of invests

$
5.7

$
5.8

$
5.6Interest incomeProducts
Pipelines

$
4.3

$
4.4

$
4.5Natural Gas
Pipelines


1.2





0.1CO2








Terminals








Kinder Morgan
Canada


3.9





Total segment
interest income


9.4


4.4


4.6Unallocated
interest income


0.6


1.3


3.1Total
consolidated interest income

$
10.0

$
5.7

$
7.7Other, net-income
(expense)Products
Pipelines

$
(2.3
)
$
5.0

$
7.6Natural Gas
Pipelines


28.0


0.2


0.6CO2


1.9





0.8Terminals


1.7


1.0


2.1Kinder Morgan
Canada


(10.1
)

8.0


1.0Total segment
other, net-income (expense)


19.2


14.2


12.1Less:
Discontinued operations








(0.1
)Total
consolidated other, net-income (expense)

$
19.2

$
14.2

$
12.0Income tax benefit
(expense)Products
Pipelines

$
(3.8
)
$
(19.7
)
$
(5.2
)Natural Gas
Pipelines


(2.7
)

(6.0
)

(1.4
)CO2


(3.9
)

(2.1
)

(0.2
)Terminals


(19.7
)

(19.2
)

(12.3
)Kinder Morgan
Canada


19.0


(19.4
)

(9.9
)Total segment
income tax benefit (expense)


(11.1
)

(66.4
)

(29.0
)Unallocated
income tax benefit (expense)


(9.3
)

(4.6
)

Total
consolidated income tax benefit (expense)

$
(20.4
)
$
(71.0
)
$
(29.0
)188

2008

2007

2006Segment earnings before
depreciation, depletion, amortization and
 amortization of excess cost of equity investments(c)Products
Pipelines

$
546.2

$
569.6

$
491.2Natural Gas
Pipelines


760.6


600.2


574.8CO2


759.9


537.0


488.2Terminals


523.8


416.0


408.1Kinder Morgan
Canada


141.2


(293.6
)

76.5Total segment
earnings before DD&A


2,731.7


1,829.2


2,038.8Total segment
depreciation, depletion and amortiz


(702.7
)

(547.0
)

(432.8
)Total segment
amortization of excess cost of invests


(5.7
)

(5.8
)

(5.7
)General and
administrative expenses


(297.9
)

(278.7
)

(238.4
)Interest and
other non-operating expenses(d)


(420.6
)

(407.4
)

(357.8
)Total
consolidated net income

$
1,304.8

$
590.3

$
1,004.1Capital
expenditures(e)Products
Pipelines

$
221.7

$
259.4

$
196.0Natural Gas
Pipelines


946.5


264.0


271.6CO2


542.6


382.5


283.0Terminals


454.1


480.0


307.7Kinder Morgan
Canada


368.1


305.7


123.8Total
consolidated capital expenditures

$
2,533.0

$
1,691.6

$
1,182.1Investments at December
31Products
Pipelines

$
202.6

$
202.3

$
211.1Natural Gas
Pipelines


654.0


427.5


197.9CO2


13.6


14.2


16.1Terminals


18.6


10.6


0.5Kinder Morgan
Canada


65.5


0.8


0.7Total
consolidated investments

$
954.3

$
655.4

$
426.3Assets at December 31Products
Pipelines

$
4,183.0

$
4,045.0

$
3,910.5Natural Gas
Pipelines


5,535.9


4,347.3


3,946.6CO2


2,339.9


2,004.5


1,870.8Terminals


3,347.6


3,036.4


2,397.5Kinder Morgan
Canada


1,583.9


1,440.8


1,314.0Total segment
assets


16,990.3


14,874.0


13,439.4Corporate
assets(f)


895.5


303.8


102.8Total
consolidated assets

$
17,885.8

$
15,177.8

$
13,542.2(a)
Includes natural gas
 purchases and other costs of sales, operations and maintenance expenses, fuel
 and power expenses and taxes, other than income taxes.(b)
2007 amount represents an
 expense of $377.1 million attributable to a goodwill impairment charge
 recognized by Knight, as discussed in Notes 3 and 8.(c)
Includes revenues, earnings
 from equity investments, allocable interest income, and other, net, less
 operating expenses, allocable income taxes, and other expense (income).(d)
Includes unallocated
 interest income and income tax expense, interest and debt expense, and
 minority interest expense.(e)
Sustaining capital
 expenditures, including our share of Rockies Express sustaining capital
 expenditures, totaled $180.6 million in 2008, $152.6 million in 2007 and
 $125.5 million in 2006. These listed amounts do not include sustaining
 capital expenditures for the Trans Mountain Pipeline (part of Kinder Morgan
 Canada) for periods prior to our acquisition date of April 30, 2007.
 Sustaining capital expenditures are defined as capital expenditures which do
 not increase the capacity of an asset.(f)
Includes cash and cash
 equivalents; margin and restricted deposits; unallocable interest receivable,
 prepaid assets and deferred charges; and risk management assets related to
 the fair value of interest rate swaps.We
do not attribute interest and debt expense to any of our reportable business
segments. For each of the years ended December 31, 2008, 2007 and 2006, we
reported (in millions) total consolidated interest expense of $398.2 million,
$397.1 million and $345.5 million, respectively.

189

Our total
operating revenues are derived from a wide customer base. For each of the three years
ended December 31, 2008, 2007 and 2006, no revenues from transactions with a
single external customer amounted to 10% or more of our total consolidated
revenues.

Following
is geographic information regarding the revenues and long-lived assets of our
business segments (in millions):

2008

2007

2006Revenues from external customersUnited
States

$
11,452.0

$
8,986.3

$
8,889.9Canada


267.0


211.9


139.3Mexico and
other(a)


21.3


19.5


19.5Total consol.
revenues from
 external customers

$
11,740.3

$
9,217.7

$
9,048.7Long-lived assets at December 31(b)United
States

$
13,563.2

$
11,054.3

$
9,917.2Canada


1,547.6


1,420.0


766.4Mexico and
other(a)


87.8


89.5


91.4Total
consolidated long-lived
 assets

$
15,198.6

$
12,563.8

$
10,775.0(a)
Includes operations in
 Mexico and the Netherlands.(b)
Long-lived assets exclude
 (i) goodwill; (ii) other intangibles, net; and (iii) long-term note
 receivables from related parties.16.
Litigation,
 Environmental and Other Contingencies

Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during 2008.  This note also contains a description of any material legal proceeding initiated during 2008 in which we are involved.



Federal Energy Regulatory Commission Proceedings





        FERC Docket No. OR92-8, et al.Complainants/Protestants: Chevron, Navajo, ARCO, BP WCP, Western Refining, ExxonMobil, Tosco, and Texaco (Ultramar is an intervenor)Defendant: SFPP; FERC Docket No.OR92-8-025Complainants/Protestants:  BP WCP; ExxonMobil; Chevron; ConocoPhillips; and UltramarDefendant: SFPPSubject:  Complaints against East Line and West Line rates and Watson Station Drain-Dry Charge




        FERC Docket No. OR96-2, et al.Complainants/Protestants: All Shippers except Chevron (which is an intervenor)Defendant: SFPPSubject:  Complaints against all SFPP rates




        FERC Docket Nos. OR02-4 and OR03-5Complainant/Protestant: ChevronDefendant: SFPP; FERC Docket No. OR04-3Complainants/Protestants: America West Airlines, Southwest Airlines, Northwest Airlines, and Continental AirlinesDefendant: SFPP; FERC Docket Nos. OR03-5, OR05-4 and OR05-5Complainants/Protestants: BP WCP, ExxonMobil, and ConocoPhillips (other shippers intervened)Defendant: SFPPSubject:  Complaints against all SFPP rates; OR02-4 was dismissed and Chevron appeal pending at U.S. Court of Appeals for D.C. Circuit (D.C. Circuit)




        FERC Docket Nos. OR07-1 & OR07-2Complainant/Protestant: TesoroDefendant: SFPPSubject:  Complaints against North Line and West Line rates; held in abeyance




        FERC Docket Nos. OR07-3 & OR07-6Complainants/Protestants: BP WCP, Chevron, ConocoPhillips; ExxonMobil, Tesoro, and Valero MarketingDefendant: SFPPSubject:  Complaints against 2005 and 2006 indexed rate increases; dismissed by FERC; appeal pending at D.C. Circuit




        FERC Docket No. OR07-4Complainants/Protestants: BP WCP, Chevron, and ExxonMobilDefendants: SFPP, Kinder Morgan G.P., Inc., and Knight Inc.Subject:  Complaints against all SFPP rates; held in abeyance; complaint withdrawn as to SFPPs affiliates




        FERC Docket Nos. OR07-5 and OR07-7 (consolidated) and IS06-296Complainants/Protestants: ExxonMobil and TesoroDefendants: Calnev, Kinder Morgan G.P., Inc., and Knight Inc Subject:  Complaints and protest against Calnev rates; OR07-5 and IS06-296 were settled in 2008




        FERC Docket Nos. OR07-8 and OR07-11 (consolidated)Complainants/Protestants: BP WCP and ExxonMobil Defendant: SFPPSubject:  Complaints against SFPP 2005 index rates; settled in 2008




        FERC Docket No. OR07-9Complainant/Protestant: BP WCPDefendant: SFPPSubject:  Complaint against ultra low sulfur diesel surcharge; dismissed by FERC; BP WCP appeal dismissed by D.C. Circuit




        FERC Docket No. OR07-14Complainants/Protestants: BP WCP and ChevronDefendants: SFPP, Calnev, and several affiliatesSubject:  Complaint against cash management practices; dismissed by FERC




        FERC Docket No. OR07-16Complainant/Protestant: TesoroDefendant: CalnevSubject:  Complaint against Calnev 2005, 2006 and 2007 indexed rate increases; dismissed by FERC; Tesoro appeal dismissed by D.C. Circuit




        FERC Docket Nos. OR07-18, OR07-19 & OR07-22Complainants/Protestants: Airline Complainants, BP WCP, Chevron, ConocoPhillips and Valero MarketingDefendant: CalnevSubject:  Complaints against Calnev rates; complaint amendments pending before FERC




        FERC Docket No. OR07-20Complainant/Protestant: BP WCPDefendant: SFPPSubject:  Complaint against 2007 indexed rate increases; dismissed by FERC; appeal pending at D.C. Circuit




        FERC Docket Nos. OR08-13 & OR08-15Complainants/Protestants: BP WCP and ExxonMobilDefendant: SFPPSubject:  Complaints against all SFPP rates and 2008 indexed rate increases




        FERC Docket No. IS05-230 (North Line rate case)Complainants/Protestants: ShippersDefendant: SFPPSubject:  SFPP filing to increase North Line rates to reflect expansion; initial decision issued; pending at FERC




        FERC Docket No. IS05-327Complainants/Protestants: ShippersDefendant: SFPPSubject:  2005 indexed rate increases; protests dismissed by FERC; appeal dismissed by D.C. Circuit




        FERC Docket Nos. IS06-283, IS06-356, IS08-28 and IS08-302Complainants/Protestants: ShippersDefendant: SFPPSubject:  East Line expansion rate increases; settled


190


        FERC Docket Nos. IS06-356, IS07-229 and IS08-302Complainants/Protestants: ShippersDefendant: SFPPSubject:  2006, 2007 and 2008 indexed rate increases; protests dismissed by FERC; East Line rates resolved by East Line settlement




        FERC Docket No. IS07-137Complainants/Protestants: ShippersDefendant: SFPPSubject:  ULSD surcharge




        FERC Docket No. IS07-234Complainants/Protestants: BP WCP and ExxonMobilDefendant: CalnevSubject:  2007 indexed rate increases; protests dismissed by FERC




        FERC Docket No. IS08-390Complainants/Protestants: BP WCP, ExxonMobil, ConocoPhillips, Valero, Chevron, the AirlinesDefendant: SFPPSubject:  West Line rate increase




        Motions to compel payment of interim damages (various dockets)Complainants/Protestants: ShippersDefendants: SFPP, Kinder Morgan G.P., Inc., and Knight Inc.; Motion for resolution on the merits (various dockets)Complainants/Protestants:  BP WCP and ExxonMobilDefendant:  SFPP and Calnev.




In this note, we refer to SFPP, L.P. as SFPP; Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; Navajo Refining Company, L.P. as Navajo; ARCO Products Company as ARCO; BP West Coast Products, LLC as BP WCP; Texaco Refining and Marketing Inc. as Texaco; Western Refining Company, L.P. as Western Refining; Mobil Oil Corporation as Mobil; ExxonMobil Oil Corporation as ExxonMobil; Tosco Corporation as Tosco; ConocoPhillips Company as ConocoPhillips; Ultramar Diamond Shamrock Corporation/Ultramar Inc. as Ultramar; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; America West Airlines, Inc., Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airline Complainants; and the Federal Energy Regulatory Commission, as FERC.



The tariffs and rates charged by SFPP and CALNEV are subject to numerous ongoing proceedings at the FERC, including the above listed shippers complaints and protests regarding interstate rates on these pipeline systems.   These complaints have been filed over numerous years beginning in 1992 through and including 2008.  In general, these complaints allege the rates and tariffs charged by SFPP and CALNEV are not just and reasonable.  If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach up to two years prior to the filing of their complaint) or refunds of any excess rates paid, and SFPP and CALNEV may be required to reduce their rates going forward.These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.



As to SFPP, the issues involved in these proceedings include, among others: (i) whether certain of our Pacific operations' rates are grandfathered under the Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether substantially changed circumstances have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) whether indexed rate increases are justified; and (iv) the appropriate level of return and income tax allowance we may include in our rates.  The issues involving CALNEV are similar.



In May 2005, the FERC issued a statement of general policy stating it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income.  Whether a pipelines owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis; consequently, the level of income tax allowance to which SFPP will ultimately be entitled is not certain.  In May of 2007, the D.C. Court upheld the FERCs tax allowance policy.



In December 2005, SFPP received a FERC order in OR92-8 and OR96-2 that directed it to submit compliance filings and revised tariffs.  In accordance with the FERCs December 2005 order and its February 2006 order on rehearing, SFPP submitted a compliance filing to the FERC in March 2006, and rate reductions were implemented on May 1, 2006.  In addition, in December 2005, we recorded accruals of $105.0 million for expenses attributable to an increase in our reserves related to our rate case liability.



In December 2007, as a follow-up to a March 2006 SFPP compliance filing to FERC, SFPP received a FERC order that directed us to submit revised compliance filings and revised tariffs.   In conjunction with FERCs December 2007 order, our other FERC and CPUC rate cases, and other unrelated litigation matters, we increased



191

our litigation reserves by $140.0 million in the fourth quarter of 2007.  And, in accordance with FERCs December 2007 order and its February 2008 order on rehearing, SFPP submitted a compliance filing to FERC in February 2008, and further rate reductions were implemented on March 1, 2008.



During 2008, SFPP and CALNEV made combined settlement payments to various shippers totaling approximately $30 million in connection with OR92-8-025, IS6-283 and OR07-5.  In October 2008, SFPP entered into a settlement resolving disputes regarding its East Line rates filed in Docket No. IS08-28 and related dockets.  In January 2009, the FERC approved the settlement.  Upon the finality of FERCs approval, reduced settlement rates are expected to go into effect on May 1, 2009, and SFPP will make refunds and settlement payments shortly thereafter estimated to total approximately $16.0 million.



Based on our review of these FERC proceedings, we estimate that as of December 31, 2008, shippers are seeking approximately $355 million in reparation and refund payments and approximately $30 to $35 million in additional annual rate reductions.  We assume that, with respect to our SFPP litigation reserves, any reparations and accrued interest thereon will be paid no earlier than the second quarter of 2009.


California
Public Utilities Commission Proceedings

On
April 7, 1997, ARCO, Mobil and Texaco filed a complaint against SFPP with the
California Public Utilities Commission, referred to in this note as the CPUC.
The complaint challenges rates charged by SFPP for intrastate transportation of
refined petroleum products through its pipeline system in the state of
California and requests prospective rate adjustments and refunds with respect
to previously untariffed charges for certain pipeline transportation and
related services.

In
October 2002, the CPUC issued a resolution, referred to in this note as the
Power Surcharge Resolution, approving a 2001 request by SFPP to raise its
California rates to reflect increased power costs. The resolution reserves the
right to require refunds, from the date of issuance of the resolution, to the
extent the CPUCs analysis of cost data to be submitted by SFPP demonstrates
that SFPPs California jurisdictional rates are unreasonable in any fashion.

On
December 26, 2006, Tesoro filed a complaint challenging the reasonableness of
SFPPs intrastate rates for the three-year period from December 2003 through
December 2006 and requesting approximately $8 million in reparations. As a
result of previous SFPP rate filings and related protests, the rates that are
the subject of the Tesoro complaint are being collected subject to refund.

SFPP
also has various, pending ratemaking matters before the CPUC that are unrelated
to the above-referenced complaints and the Power Surcharge Resolution. Protests
to these rate increase applications have been filed by various shippers. As a
consequence of the protests, the related rate increases are being collected
subject to refund.

All
of the above matters have been consolidated and assigned to a single
administrative law judge. At the time of this report, it is unknown when a
decision from the CPUC regarding the CPUC complaints and the Power Surcharge
Resolution will be received. No schedule has been established for hearing and
resolution of the consolidated proceedings other than the 1997 CPUC complaint
and the Power Surcharge Resolution. Based on our review of these CPUC proceedings,
we estimate that shippers are seeking approximately $100 million in reparation
and refund payments and approximately $35 million in annual rate reductions.

On
June 6, 2008, as required by CPUC order, SFPP and Calnev Pipe Line Company filed
separate general rate case applications, neither of which request a change in
existing pipeline rates and both of which assert that existing pipeline rates
are reasonable. On September 26, 2008, SFPP filed an amendment to its general
rate case application, requesting CPUC approval of a $5 million rate increase
for intrastate transportation services to become effective November 1, 2008.
Protests to the amended rate increase application have been filed by various
shippers and, as a consequence, the related rate increase is being collected
subject to refund. The CPUC has issued a ruling suspending further activity
with respect to the SFPP and Calnev Pipe Line Company general rate case
applications, pending CPUC resolution of the 1997 CPUC complaint and Power
Surcharge proceedings. Consequently, no action has been taken by the CPUC with
respect to either the SFPP amended general rate case filing or the Calnev
general rate case filing.

Carbon
Dioxide Litigation

Gerald
O. Bailey et al. v. Shell Oil Co. et al/Southern District of Texas Lawsuit

Kinder
Morgan CO2, Kinder Morgan Energy Partners, L.P. and Cortez Pipeline
Company are among the defendants in a proceeding in the federal courts for the
southern district of Texas. Gerald O. Bailey
et al. v. Shell Oil Company et al., (Civil Action Nos. 05-1029 and
05-1829 in the U.S. District Court for the Southern District of
Texasconsolidated by Order dated July 18, 2005). The plaintiffs are asserting
claims for the underpayment of

192

royalties on carbon dioxide produced from the McElmo
Dome Unit. The plaintiffs assert claims for fraud/fraudulent inducement, real
estate fraud, negligent misrepresentation, breach of fiduciary and agency
duties, breach of contract and covenants, violation of the Colorado Unfair
Practices Act, civil theft under Colorado law, conspiracy, unjust enrichment,
and open account. Plaintiffs Gerald O. Bailey, Harry Ptasynski, and W.L. Gray
& Co. have also asserted claims as private relators under the False Claims
Act and for violation of federal and Colorado antitrust laws. The plaintiffs
seek actual damages, treble damages, punitive damages, a constructive trust and
accounting, and declaratory relief. The defendants filed motions for summary
judgment on all claims.

Effective
March 5, 2007, all defendants and plaintiffs Bridwell Oil Company, the Alicia
Bowdle Trust, and the Estate of Margaret Bridwell Bowdle executed a final
settlement agreement which provides for the dismissal of these plaintiffs
claims with prejudice to being refiled. On June 10, 2007, the Houston federal
district court entered an order of partial dismissal by which the claims by and
against the settling plaintiffs were dismissed with prejudice. The claims
asserted by Bailey, Ptasynski, and Gray are not included within the settlement
or the order of partial dismissal. Effective April 8, 2008, the Shell and
Kinder Morgan defendants and plaintiff Gray entered into an indemnification
agreement that provides for the dismissal of Grays claims with prejudice.

On
April 22, 2008, the federal district court granted defendants motions for
summary judgment and ruled that plaintiffs Bailey, Ptasynski, and Gray take
nothing on their claims. The court entered final judgment in favor of defendants
on April 30, 2008. Defendants have filed a motion seeking sanctions against
plaintiff Bailey. The plaintiffs have appealed the final judgment to the United
States Fifth Circuit Court of Appeals. In October 2008, plaintiffs filed their
brief in the Fifth Circuit Court of Appeals. Defendants filed their brief in
the Fifth Circuit in December 2008.

CO2Claims Arbitration

Cortez
Pipeline Company and Kinder Morgan CO2, successor to Shell CO2
Company, Ltd., were among the named defendants in CO2 Committee,
Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005.
The arbitration arose from a dispute over a class action settlement agreement
which became final on July 7, 2003 and disposed of five lawsuits formerly
pending in the U.S. District Court, District of Colorado. The plaintiffs in
such lawsuits primarily included overriding royalty interest owners, royalty
interest owners, and small share working interest owners who alleged
underpayment of royalties and other payments on carbon dioxide produced from
the McElmo Dome Unit.

The
settlement imposed certain future obligations on the defendants in the
underlying litigation. The plaintiff alleged that, in calculating royalty and
other payments, defendants used a transportation expense in excess of what is
allowed by the settlement agreement, thereby causing alleged underpayments of
approximately $12 million. The plaintiff also alleged that Cortez Pipeline
Company should have used certain funds to further reduce its debt, which, in
turn, would have allegedly increased the value of royalty and other payments by
approximately $0.5 million. On August 7, 2006, the arbitration panel issued its
opinion finding that defendants did not breach the settlement agreement. On June
21, 2007, the New Mexico federal district court entered final judgment
confirming the August 7, 2006 arbitration decision.

On
October 2, 2007, the plaintiff initiated a second arbitration (CO2
Committee, Inc. v. Shell CO2 Company, Ltd., aka Kinder Morgan CO2
Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2and
an ExxonMobil entity. The second arbitration asserts claims similar to those
asserted in the first arbitration. On June 3, 2008, the plaintiff filed a
request with the American Arbitration Association seeking administration of the
arbitration. In October 2008, the New Mexico federal district court entered an
order declaring that the panel in the first arbitration should decide whether
the claims in the second arbitration are barred by res judicata. The plaintiff
filed a motion for reconsideration of that order, which was denied by the New
Mexico federal district court in January 2009. Plaintiff has appealed to the
Tenth Circuit Court of Appeals and continues to seek administration of the
second arbitration by the American Arbitration Association.

MMS
Notice of Noncompliance and Civil Penalty

On
December 20, 2006, Kinder Morgan CO2 received a Notice of
Noncompliance and Civil Penalty: Knowing or Willful Submission of False,
Inaccurate, or Misleading InformationKinder Morgan CO2 Company,
L.P., Case

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No. CP07-001 from the U.S. Department of the
Interior, Minerals Management Service, referred to in this note as the MMS.
This Notice, and the MMSs position that Kinder Morgan CO2 has
violated certain reporting obligations, relates to a disagreement between the
MMS and Kinder Morgan CO2 concerning the approved transportation
allowance to be used in valuing McElmo Dome carbon dioxide for purposes of
calculating federal royalties.

The
Notice of Noncompliance and Civil Penalty assesses a civil penalty of
approximately $2.2 million as of December 15, 2006 (based on a penalty of
$500.00 per day for each of 17 alleged violations) for Kinder Morgan CO2s
alleged submission of false, inaccurate, or misleading information relating to
the transportation allowance, and federal royalties for CO2 produced
at McElmo Dome, during the period from June 2005 through October 2006. The MMS
stated that civil penalties will continue to accrue at the same rate until the
alleged violations are corrected.

The
parties have reached a settlement of the Notice of Noncompliance and Civil
Penalty. The settlement agreement is subject to final MMS approval and upon
approval will be funded from existing reserves and indemnity payments by Shell
CO2General LLC and Shell CO2 LLC pursuant to a royalty
claim indemnification agreement.

MMS
Order to Report and Pay

On
March 20, 2007, Kinder Morgan CO2 received an Order to Report and
Pay from the MMS. The MMS contends that Kinder Morgan CO2 has over-reported transportation
allowances and underpaid royalties in the amount of approximately $4.6 million
for the period from January 1, 2005 through December 31, 2006 as a result of
its use of the Cortez Pipeline tariff as the transportation allowance in
calculating federal royalties. The MMS claims that the Cortez Pipeline tariff
is not the proper transportation allowance and that Kinder Morgan CO2
must use its reasonable actual costs calculated in accordance with certain
federal product valuation regulations. The MMS set a due date of April 13, 2007
for Kinder Morgan CO2s payment of the $4.6 million in claimed
additional royalties, with possible late payment charges and civil penalties
for failure to pay the assessed amount.

Kinder
Morgan CO2 has not paid the $4.6 million, and on April 19, 2007, it
submitted a notice of appeal and statement of reasons in response to the Order
to Report and Pay, challenging the Order and appealing it to the Director of
the MMS in accordance with 30 C.F.R. sec. 290.100, et seq.

In
addition to the March 2007 Order to Report and Pay, in April 2007, Kinder
Morgan CO2 received an Audit Issue Letter sent by the Colorado
Department of Revenue on behalf of the U.S. Department of the Interior. In the
letter, the Department of Revenue states that Kinder Morgan CO2 has
over-reported transportation allowances and underpaid royalties (due to the use
of the Cortez Pipeline tariff as the transportation allowance for purposes of
federal royalties) in the amount of $8.5 million for the period from April 2000
through December 2004.

The
MMS and Kinder Morgan CO2have reached a settlement of the March
2007 and August 2007 Orders to Report and Pay. The settlement is subject to
final MMS approval and upon approval will be funded from existing reserves and
indemnity payments from Shell CO2General LLC and Shell CO2 LLC
pursuant to a royalty claim indemnification agreement.

J.
Casper Heimann, Pecos Slope Royalty Trust and Rio Petro LTD, individually and
on behalf of all other private royalty and overriding royalty owners in the
Bravo Dome Carbon Dioxide Unit, New Mexico similarly situated v. Kinder Morgan
CO2 Company, L.P., No. 04-26-CL (8th Judicial District
Court, Union County New Mexico)

This
case involves a purported class action against Kinder Morgan CO2
alleging that it has failed to pay the full royalty and overriding royalty
(royalty interests) on the true and proper settlement value of compressed
carbon dioxide produced from the Bravo Dome Unit during the period beginning
January 1, 2000. The complaint purports to assert claims for violation of the
New Mexico Unfair Practices Act, constructive fraud, breach of contract and of
the covenant of good faith and fair dealing, breach of the implied covenant to
market, and claims for an accounting, unjust enrichment, and injunctive relief.
The purported class is comprised of current and former owners, during the
period January 2000 to the present, who have private property royalty interests
burdening the oil and gas leases held by the defendant, excluding the
Commissioner of Public Lands, the United States of America, and those private
royalty interests that are not unitized as part of the Bravo Dome Unit.

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The
case was tried to a jury in the trial court in September 2008. The plaintiffs
sought $6.8 million in actual damages as well as punitive damages. The jury
returned a verdict finding that Kinder Morgan did not breach the settlement
agreement and did not breach the claimed duty to market carbon dioxide. The
jury also found that Kinder Morgan breached a duty of good faith and fair
dealing and found compensatory damages of $0.3 million and punitive damages of
$1.2 million. On October 16, 2008, the trial court entered judgment on the
verdict.

On
January 6, 2009, the district court entered orders vacating the judgment and
granting a new trial in the case. Kinder Morgan filed a petition with the New
Mexico Supreme Court, asking that court to authorize an immediate appeal of the
new trial orders. No action has yet been taken by the New Mexico Supreme Court
on that petition. Subject to potential further review by New Mexico Supreme
Court, the district court scheduled a new trial to occur beginning on October
19, 2009.

In
addition to the matters listed above, audits and administrative inquiries
concerning Kinder Morgan CO2s payments on carbon dioxide produced
from the McElmo Dome and Bravo Dome Units are currently ongoing. These audits
and inquiries involve federal agencies and the States of Colorado and New
Mexico.

Commercial
Litigation Matters

Union
Pacific Railroad Company Easements

SFPP,
L.P. and Union Pacific Railroad Company (the successor to Southern Pacific
Transportation Company and referred to in this note as UPRR) are engaged in a
proceeding to determine the extent, if any, to which the rent payable by SFPP
for the use of pipeline easements on rights-of-way held by UPRR should be
adjusted pursuant to existing contractual arrangements for the ten year period
beginning January 1, 2004 (Union Pacific
Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder
Morgan Operating L.P. D, Kinder Morgan G.P., Inc., et al.,Superior
Court of the State of California for the County of Los Angeles, filed July 28,
2004). In February 2007, a trial began to determine the amount payable for
easements on UPRR rights-of-way. The trial is ongoing and is expected to
conclude in the second quarter of 2009.

SFPP
and UPRR are also engaged in multiple disputes over the circumstances under
which SFPP must pay for a relocation of its pipeline within the UPRR right of
way and the safety standards that govern relocations. In July 2006, a trial
before a judge regarding the circumstances under which SFPP must pay for
relocations concluded, and the judge determined that SFPP must pay for any
relocations resulting from any legitimate business purpose of the UPRR. SFPP
has appealed this decision, and in December 2008, the appellate court affirmed the decision.
In addition, UPRR contends that it has complete
discretion to cause the pipeline to be relocated at SFPPs expense at any time
and for any reason, and that SFPP must comply with the more expensive American
Railway Engineering and Maintenance-of-Way standards. Each party is seeking
declaratory relief with respect to its positions regarding relocations.

It
is difficult to quantify the effects of the outcome of these cases on SFPP
because SFPP does not know UPRRs plans for projects or other activities that
would cause pipeline relocations. Even if SFPP is successful in advancing its
positions, significant relocations for which SFPP must nonetheless bear the
expense (i.e. for railroad purposes, with the standards in the federal Pipeline
Safety Act applying) would have an adverse effect on our financial position and
results of operations. These effects would be even greater in the event SFPP is
unsuccessful in one or more of these litigations.

United
States of America, ex rel., Jack J. Grynberg v. K N Energy (Civil Action No.
97-D-1233, filed in the U.S. District Court, District of Colorado).

This
multi-district litigation proceeding involves four lawsuits filed in 1997
against numerous Kinder Morgan companies. These suits were filed pursuant to
the federal False Claims Act and allege underpayment of royalties due to
mismeasurement of natural gas produced from federal and Indian lands. The
complaints are part of a larger series of similar complaints filed by Mr.
Grynberg against 77 natural gas pipelines (approximately 330 other defendants)
in various courts throughout the country which were consolidated and
transferred to the District of Wyoming.

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In
May 2005, a Special Master appointed in this litigation found that because
there was a prior public disclosure of the allegations and that Grynberg was
not an original source, the Court lacked subject matter jurisdiction. As a
result, the Special Master recommended that the Court dismiss all the Kinder
Morgan defendants. In October 2006, the United States District Court for the
District of Wyoming upheld the dismissal of each case against the Kinder Morgan
defendants on jurisdictional grounds. Grynberg has appealed this Order to the
Tenth Circuit Court of Appeals. Briefing was completed and oral argument was
held on September 25, 2008. No decision has yet been issued.

Prior
to the dismissal order on jurisdictional grounds, the Kinder Morgan defendants
filed Motions to Dismiss and for Sanctions alleging that Grynberg filed his
Complaint without evidentiary support and for an improper purpose. On January
8, 2007, after the dismissal order, the Kinder Morgan defendants also filed a
Motion for Attorney Fees under the False Claim Act. On April 24, 2007 the Court
held a hearing on the Motions to Dismiss and for Sanctions and the Requests for
Attorney Fees. A decision is still pending on the Motions to Dismiss and for
Sanctions and the Requests for Attorney Fees.

Leukemia
Cluster Litigation

Richard
Jernee, et al v. Kinder Morgan Energy Partners, et al, No. CV03-03482 (Second
Judicial District Court, State of Nevada, County of Washoe) (Jernee).

Floyd
Sands, et al v. Kinder Morgan Energy Partners, et al, No. CV03-05326 (Second
Judicial District Court, State of Nevada, County of Washoe) (Sands).

On
May 30, 2003, plaintiffs, individually and on behalf of Adam Jernee, filed a
civil action in the Nevada State trial court against us and several Kinder
Morgan related entities and individuals and additional unrelated defendants.
Plaintiffs in the Jernee matter claim that defendants negligently and
intentionally failed to inspect, repair and replace unidentified segments of
their pipeline and facilities, allowing harmful substances and emissions and
gases to damage the environment and health of human beings. Plaintiffs claim
that Adam Jernees death was caused by leukemia that, in turn, is believed to
be due to exposure to industrial chemicals and toxins. Plaintiffs purport to
assert claims for wrongful death, premises liability, negligence, negligence
per se, intentional infliction of emotional distress, negligent infliction of
emotional distress, assault and battery, nuisance, fraud, strict liability
(ultra hazardous acts), and aiding and abetting, and seek unspecified special,
general and punitive damages.

On
August 28, 2003, a separate group of plaintiffs, represented by the counsel for
the plaintiffs in the Jernee matter, individually and on behalf of Stephanie
Suzanne Sands, filed a civil action in the Nevada State trial court against the
same defendants and alleging the same claims as in the Jernee case with respect
to Stephanie Suzanne Sands. The Jernee case has been consolidated for pretrial
purposes with the Sands case. In May 2006, the court granted defendants
motions to dismiss as to the counts purporting to assert claims for fraud, but
denied defendants motions to dismiss as to the remaining counts, as well as
defendants motions to strike portions of the complaint. Defendant Kennametal,
Inc. has filed a third-party complaint naming the United States and the United
States Navy (the United States) as additional defendants.

In
response, the United States removed the case to the United States District
Court for the District of Nevada and filed a motion to dismiss the third-party
complaint. Plaintiff has also filed a motion to dismiss the United States
and/or to remand the case back to state court. By order dated September 25,
2007, the United States District Court granted the motion to dismiss the United
States from the case and remanded the Jernee and Sands cases back to the Second
Judicial District Court, State of Nevada, County of Washoe. The cases will now
proceed in the State Court. Based on the information available to date, our own
preliminary investigation, and the positive results of investigations conducted
by State and Federal agencies, we believe that the remaining claims against us
in these matters are without merit and intend to defend against them
vigorously.

Pipeline
Integrity and Releases

From time
to time, our pipelines experience leaks and ruptures. These leaks and ruptures
may cause explosions, fire, damage to the environment, damage to property
and/or personal injury or death. In connection with these incidents, we may be
sued for damages caused by an alleged failure to properly mark the locations of
our pipelines

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and/or to
properly maintain our pipelines. Depending upon the facts and circumstances of
a particular incident, state and federal regulatory authorities may seek civil
and/or criminal fines and penalties.

Pasadena
Terminal Fire

On
September 23, 2008, a fire occurred in the pit 3 manifold area of our Pasadena,
Texas terminal facility. One of our employees was injured and subsequently
died. In addition, the pit 3 manifold was severely damaged. The cause of the
incident is currently under investigation by the Railroad Commission of Texas
and the United States Occupational Safety and Health Administration. The
remainder of the facility returned to normal operations within 24 hours of the
incident.

Walnut
Creek, California Pipeline Rupture

On
November 9, 2004, excavation equipment operated by Mountain Cascade, Inc., a
third-party contractor on a water main installation project hired by East Bay
Municipal Utility District, struck and ruptured an underground petroleum pipeline
owned and operated by SFPP, L.P. in Walnut Creek, California. An explosion
occurred immediately following the rupture that resulted in five fatalities and
several injuries to employees or contractors of Mountain Cascade. Following
court ordered mediation, we have settled with plaintiffs in all of the wrongful
death cases and the personal injury and property damages cases. On January 12,
2009, the Contra Costa Superior Court granted summary judgment in favor of
Kinder Morgan G.P. Services Co., Inc. in the last remaining civil suit  a
claim for indemnity brought by co-defendant Camp, Dresser & McKee, Inc. The
only remaining pending matter is our appeal of a civil fine of $140,000 issued
by the California Division of Occupational Safety and Health.

Rockies
Express Pipeline LLC Wyoming Construction Incident

On
November 11, 2006, a bulldozer operated by an employee of Associated Pipeline
Contractors, Inc, (a third-party contractor to Rockies Express Pipeline LLC,
referred to in this note as REX), struck an existing subsurface natural gas pipeline
owned by Wyoming Interstate Company, a subsidiary of El Paso Pipeline Group.
The pipeline was ruptured, resulting in an explosion and fire. The incident
occurred in a rural area approximately nine miles southwest of Cheyenne,
Wyoming. The incident resulted in one fatality (the operator of the bulldozer)
and there were no other reported injuries. The cause of the incident was
investigated by the U.S. Department of Transportation Pipeline and Hazardous
Materials Safety Administration, referred to in this report as the PHMSA. In
March 2008, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty
and Proposed Compliance Order (NOPV) to El Paso Corporation in which it
concluded that El Paso failed to comply with federal law and its internal policies
and procedures regarding protection of its pipeline, resulting in this
incident.

To
date, PHMSA has not issued any NOPVs to REX, and we do not expect that it will
do so. Immediately following the incident, REX and El Paso Pipeline Group
reached an agreement on a set of additional enhanced safety protocols designed
to prevent the reoccurrence of such an incident.

In
September 2007, the family of the deceased bulldozer operator filed a wrongful
death action against us, REX and several other parties in the District Court of
Harris County, Texas, 189 Judicial District, at case number 2007-57916. The
plaintiffs seek unspecified compensatory and exemplary damages plus interest,
attorneys fees and costs of suit. We have asserted contractual claims for
complete indemnification for any and all costs arising from this incident,
including any costs related to this lawsuit, against third parties and their
insurers. On March 25, 2008, we entered into a settlement agreement with one of
the plaintiffs, the decedents daughter, resolving any and all of her claims
against us, REX and its contractors. We were indemnified for the full amount of
this settlement by one of REXs contractors. On October 17, 2008, the remaining
plaintiffs filed a Notice of Nonsuit, which dismissed the remaining claims
against all defendants without prejudice to the plaintiffs ability to re-file
their claims at a later date. The remaining plaintiffs re-filed their Complaint
against REX, KMP and several other parties on November 7, 2008, Cause No.
2008-66788, currently pending in the District Court of Harris County, Texas,
189 Judicial District. The parties are currently engaged in discovery.

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Charlotte,
North Carolina

On
November 27, 2006, the Plantation Pipeline experienced a release of
approximately 4,000 gallons of gasoline from a Plantation Pipe Line Company
block valve on a delivery line into a terminal owned by a third party company.
The line was repaired and put back into service within a few days. Remediation
efforts are continuing under the direction of the North Carolina Department of
Environment and Natural Resources (the NCDENR), which issued a Notice of
Violation and Recommendation of Enforcement against Plantation on January 8, 2007.
Plantation continues to cooperate fully with the NCDENR.

Although
Plantation does not believe that penalties are warranted, it has engaged in
settlement discussions with the EPA regarding a potential civil penalty for the
November 2006 release as part of broader settlement negotiations with the EPA
regarding this spill and three other historical releases from Plantation,
including a February 2003 release near Hull, Georgia. Plantation has entered
into a consent decree with the Department of Justice and the EPA for all four
releases for approximately $0.7 million, plus some additional work to be
performed to prevent future releases. The proposed consent decree was filed in
U.S. District Court and is awaiting entry by the court.

In addition,
in April 2007, during pipeline maintenance activities near Charlotte, North
Carolina, Plantation discovered the presence of historical soil contamination
near the pipeline, and reported the presence of impacted soils to the NCDENR.
Subsequently, Plantation contacted the owner of the property to request access
to the property to investigate the potential contamination. The results of that
investigation indicate that there is soil and groundwater contamination which
appears to be from an historical turbine fuel release. The groundwater
contamination is underneath at least two lots on which there is current
construction of single family homes as part of a new residential development.
Further investigation and remediation are being conducted under the oversight
of the NCDENR. Plantation reached a settlement with the builder of the
residential subdivision. Plantation continues to negotiate with the owner of
the property to address any potential claims that it may bring.

Barstow,
California

The
United States Department of Navy has alleged that historic releases of methyl
tertiary-butyl ether, referred to in this report as MTBE, from Calnev Pipe Line
Companys Barstow terminal (i) has migrated underneath the Navys Marine Corps
Logistics Base in Barstow; (ii) has impacted the Navys existing groundwater
treatment system for unrelated groundwater contamination not alleged to have
been caused by Calnev; and (iii) could affect the MCLBs water supply system.
Although Calnev believes that it has certain meritorious defenses to the
Navys claims, it is working with the Navy to agree upon an Administrative
Settlement Agreement and Order on Consent for CERCLA Removal Action to
reimburse the Navy for $0.5 million in past response actions, plus perform
other work to ensure protection of the Navys existing treatment system and
water supply.

Oil
Spill Near Westridge Terminal, Burnaby, British Columbia

On July 24,
2007, a third-party contractor installing a sewer line for the City of Burnaby
struck a crude oil pipeline segment included within our Trans Mountain pipeline
system near its Westridge terminal in Burnaby, BC, resulting in a release of
approximately 1,400 barrels of crude oil. The release impacted the surrounding
neighborhood, several homes and nearby Burrard Inlet. No injuries were
reported. To address the release, we initiated a comprehensive emergency
response in collaboration with, among others, the City of Burnaby, the BC
Ministry of Environment, the National Energy Board, and the National
Transportation Safety Board. Cleanup and environmental remediation is near
completion. The incident
is currently under investigation by Federal and Provincial agencies. We do not expect
this matter to have a material adverse impact on our results of operations or cash flows.

On
December 20, 2007 we initiated a lawsuit entitled Trans Mountain Pipeline
LP, Trans Mountain Pipeline Inc. and Kinder Morgan Canada Inc. v. The City of
Burnaby, et al., Supreme Court of British Columbia, Vancouver Registry No.
S078716. The suit alleges that the City of Burnaby and its agents are liable in
damages including, but not limited to, all costs and expenses incurred by us as
a result of the rupture of the pipeline and subsequent release of crude oil.
Defendants have denied liability and discovery has begun.

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Although
no assurance can be given, we believe that we have meritorious defenses to the
actions set forth in this note and, to the extent an assessment of the matter
is possible, if it is probable that a liability has been incurred and the
amount of loss can be reasonably estimated, we believe that we have established
an adequate reserve to cover potential liability.

Additionally,
although it is not possible to predict the ultimate outcomes, we
also believe, based on our experiences to date, that the ultimate resolution of
these matters will not have a material adverse impact on our business,
financial position, results of operations or cash flows. As of December 31, 2008,
and December 31, 2007, we have recorded a total reserve for legal fees,
transportation rate cases and other litigation liabilities in the amount of
$234.8 million and $247.9 million, respectively. The reserve is primarily
related to various claims from lawsuits arising from our Pacific operations
pipeline transportation rates, and the contingent amount is based on both the
circumstances of probability and reasonability of dollar estimates. We
regularly assess the likelihood of adverse outcomes resulting from these claims
in order to determine the adequacy of our liability provision.

Environmental
Matters

Exxon
Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC.
and ST Services, Inc.

On
April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court
of New Jersey, Gloucester County. The lawsuit relates to environmental
remediation obligations at a Paulsboro, New Jersey liquids terminal owned by
ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp.
from 1989 through September 2000, later owned by Support Terminals. The
terminal is now owned by Pacific Atlantic Terminals, LLC, (PAT) and it too is a
party to the lawsuit.

The
complaint seeks any and all damages related to remediating all environmental
contamination at the terminal, and, according to the New Jersey Spill
Compensation and Control Act, treble damages may be available for actual
dollars incorrectly spent by the successful party in the lawsuit. The parties
are currently involved in mandatory mediation and met in June and October 2008.
No progress was made at any of the mediations. The mediation judge will now refer the case back to the litigation court
room.

On
June 25, 2007, the New Jersey Department of Environmental Protection, the
Commissioner of the New Jersey Department of Environmental Protection and the
Administrator of the New Jersey Spill Compensation Fund, referred to
collectively as the plaintiffs, filed a complaint against ExxonMobil
Corporation and Kinder Morgan Liquids Terminals LLC, f/k/a GATX Terminals
Corporation. The complaint was filed in Gloucester County, New Jersey. Both
ExxonMobil and we filed third party complaints against Support Terminals
seeking to bring Support Terminals into the case. Support Terminals filed
motions to dismiss the third party complaints, which were denied. Support
Terminals is now joined in the case and it filed an Answer denying all claims.

The
plaintiffs seek the costs and damages that the plaintiffs allegedly have
incurred or will incur as a result of the discharge of pollutants and hazardous
substances at the Paulsboro, New Jersey facility. The costs and damages
that the plaintiffs seek include cleanup costs and damages to natural
resources. In addition, the plaintiffs seek an order compelling the defendants
to perform or fund the assessment and restoration of
those natural resource damages that are the result of the defendants
actions. As in the case brought by ExxonMobil against GATX Terminals, the
issue is whether the plaintiffs claims are within the scope of the
indemnity obligations between GATX Terminals (and therefore, Kinder Morgan
Liquids Terminals) and Support Terminals. The court may consolidate the two
cases.

Mission
Valley Terminal Lawsuit

In
August 2007, the City of San Diego, on its own behalf and purporting to
act on behalf of the People of the state of California, filed a lawsuit against
us and several affiliates seeking injunctive relief and unspecified damages
allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater
beneath the citys stadium property in San Diego arising from historic
operations at the Mission Valley terminal facility. The case was filed in the
Superior Court of California, San Diego County, case number
37-2007-00073033-CU-OR-CTL. On September 26, 2007, we removed the case to the
United States District Court, Southern District of California, case number
07CV1883WCAB. On October 3, 2007, we filed a Motion to Dismiss all counts of
the Complaint. The court denied in part and granted in part the Motion to
Dismiss and gave the City leave to amend their complaint. The City submitted
its Amended Complaint and we filed an Answer. The parties have commenced with discovery.
This site

199

has been, and currently is, under the regulatory oversight and order of
the California Regional Water Quality Control Board.

In June
2008, we received an Administrative Civil Liability Complaint from the
California Regional Water Quality Control Board (RWQCB) for violations and
penalties associated with permitted surface water discharge from the
remediation system operating at the Mission Valley terminal facility. In
December 2008, we settled the Administrative Civil Liability Complaint with the
RWQCB, paying a civil penalty of $0.2 million.

Other
Environmental

We
are subject to environmental cleanup and enforcement actions from time to time.
In particular, the federal Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA) generally imposes joint and several liability for
cleanup and enforcement costs on current or predecessor owners and operators of
a site, among others, without regard to fault or the legality of the original
conduct. Our operations are also subject to federal, state and local laws and
regulations relating to protection of the environment. Although we believe our
operations are in substantial compliance with applicable environmental law and
regulations, risks of additional costs and liabilities are inherent in
pipeline, terminal and carbon dioxide field and oil field operations, and there
can be no assurance that we will not incur significant costs and liabilities.
Moreover, it is possible that other developments, such as increasingly
stringent environmental laws, regulations and enforcement policies thereunder,
and claims for damages to property or persons resulting from our operations,
could result in substantial costs and liabilities to us.

We
are currently involved in several governmental proceedings involving air, water
and waste violations issued by various governmental authorities related to
compliance with environmental regulations. As we receive notices of
non-compliance, we negotiate and settle these matters. We do not believe that
these violations will have a material adverse affect on our business.

We
are also currently involved in several governmental proceedings involving
groundwater and soil remediation efforts under administrative orders or related
state remediation programs issued by various regulatory authorities related to
compliance with environmental regulations associated with our assets. We have
established a reserve to address the costs associated with the cleanup.

In
addition, we are involved with and have been identified as a potentially
responsible party in several federal and state superfund sites. Environmental
reserves have been established for those sites where our contribution is
probable and reasonably estimable. In addition, we are from time to time
involved in civil proceedings relating to damages alleged to have occurred as a
result of accidental leaks or spills of refined petroleum products, natural gas
liquids, natural gas and carbon dioxide. See Pipeline Integrity and Releases
above for additional information with respect to ruptures and leaks from our
pipelines.

General

Although it
is not possible to predict the ultimate outcomes, we believe that
the resolution of the environmental matters set forth in this note will not
have a material adverse effect on our business, financial position, results of
operations or cash flows. However, we are not able to reasonably estimate when
the eventual settlements of these claims will occur and changing circumstances
could cause these matters to have a material adverse impact. As of December 31,
2008, we have accrued an environmental reserve of$78.9 million, and we
believe the establishment of this environmental reserve is adequate such that
the resolution of pending environmental matters will not have a material
adverse impact on our business, cash flows, financial position or results of
operations. As of December 31, 2007, our environmental reserve totaled $92.0
million. Additionally, many factors may change in the future affecting our
reserve estimates, such as (i) regulatory changes; (ii) groundwater and land
use near our sites; and (iii) changes in cleanup technology.

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Other

We
are a defendant in various lawsuits arising from the day-to-day operations of
our businesses. Although no assurance can be given, we believe, based on our
experiences to date, that the ultimate resolution of such items will not have a
material adverse impact on our business, financial position, results of
operations or cash flows.

17.
Regulatory MattersThe tariffs
we charge for transportation on our interstate common carrier pipelines are
subject to rate regulation by the FERC, under the Interstate Commerce Act. The
Interstate Commerce Act requires, among other things, that interstate petroleum
products pipeline rates be just and reasonable and nondiscriminatory. Pursuant
to FERC Order No. 561, effective January 1, 1995, interstate petroleum products
pipelines are able to change their rates within prescribed ceiling levels that
are tied to an inflation index. FERC Order No. 561-A, affirming and clarifying
Order No. 561, expanded the circumstances under which interstate petroleum
products pipelines may employ cost-of-service ratemaking in lieu of the
indexing methodology, effective January 1, 1995. For each of the years ended
December 31, 2008, 2007 and 2006, the application of the indexing methodology
did not significantly affect tariff rates on our interstate petroleum products
pipelines.

Below is a
brief description of our ongoing regulatory matters, including any material
developments that occurred during 2008. This note also contains a description
of any material regulatory matters initiated during 2008 in which we are involved.

FERC
Order No. 2004/690/717

Since
November 2003, the FERC issued Orders No. 2004, 2004-A, 2004-B, 2004-C, and
2004-D, adopting new Standards of Conduct as applied to natural gas pipelines.
The primary change from existing regulation was to make such standards
applicable to an interstate natural gas pipelines interaction with many more
affiliates (referred to as energy affiliates). The Standards of Conduct
require, among other things, separate staffing of interstate pipelines and
their energy affiliates (but support functions and senior management at the
central corporate level may be shared) and strict limitations on communications
from an interstate pipeline to an energy affiliate.

However,
on November 17, 2006, the United States Court of Appeals for the District of
Columbia Circuit, in Docket No. 04-1183, vacated FERC Orders 2004, 2004-A,
2004-B, 2004-C, and 2004-D as applied to natural gas pipelines, and remanded
these same orders back to the FERC.



On
October 16, 2008, the FERC issued a Final Rule in Order 717 revising the FERC
Standards of Conduct for natural gas and electric transmission providers by
eliminating Order No. 2004s concept of Energy Affiliates and corporate
separation in favor of an employee functional approach as used in Order No.
497. A
transmission provider is prohibited from disclosing to a marketing function
employee non-public information about the transmission system or a transmission
customer. The final rule also retains the long-standing no-conduit rule, which
prohibits a transmission function provider from disclosing non-public
information to marketing function employees by using a third party conduit.
Additionally, the final rule requires that a transmission provider provide
annual training on the Standards of Conduct to all transmission function
employees, marketing function employees, officers, directors, supervisory
employees, and any other employees likely to become privy to transmission
function information. This rule became effective November 26, 2008.

Notice
of Inquiry  Financial Reporting

On
February 15, 2007, the FERC issued a notice of inquiry seeking comment on the
need for changes or revisions to the FERCs reporting requirements contained in
the financial forms for gas and oil pipelines and electric utilities. Initial
comments were filed by numerous parties on March 27, 2007, and reply comments
were filed on April 27, 2007.

On
September 20, 2007, the FERC issued for public comment in Docket No. RM07-9 a
proposed rule which would revise its financial forms to require that additional
information be reported by natural gas companies. The proposed rule would
require, among other things, that natural gas companies: (i) submit additional
revenue information, including revenue from shipper-supplied gas; (ii) identify
the costs associated with affiliate transactions; and (iii) provide additional
information on incremental facilities and on discounted and negotiated rates.
The FERC proposed an effective date of January 1, 2008, which means that forms
reflecting the new requirements for 2008 would be filed in early 2009. Comments
on the proposed rule were filed by numerous parties on November 13, 2007.

On
March 21, 2008 the FERC issued a Final Rule regarding changes to the Form 2,
2-A and 3Q. The revisions were designed to enhance the forms usefulness by
updating them to reflect current market and cost information relevant to
interstate pipelines and their customers. The rule is effective January 1, 2008
with the filing of the revised Form 3-Q beginning with the first quarter of
2009. The revised Form 2 and 2-A for calendar year 2008 material would be filed
by April 30, 2009. On June 20, 2008, the FERC issued an Order Granting in Part
and Denying in Part Rehearing and Granting Request for Clarification. No substantive
changes were made to the March 21, 2008 Final Rule.

Notice
of Inquiry  Fuel Retention Practices

On
September 20, 2007, the FERC issued a Notice of Inquiry seeking comment on
whether it should change its current policy and prescribe a uniform method for
all interstate gas pipelines to use in recovering fuel gas and gas lost and
unaccounted for. The Notice of Inquiry included numerous questions regarding
fuel recovery issues and the effects of fixed fuel percentages as compared with
tracking provisions. Comments on the Notice of Inquiry were filed by numerous
parties on November 30, 2007. On November 20, 2008, the FERC issued an order
terminating the inquiry.

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Notice
of Proposed Rulemaking  Promotion of a More Efficient Capacity Release
Market-Order 712

On
November 15, 2007, the FERC issued a notice of proposed rulemaking in Docket
No. RM 08-1-000 regarding proposed modifications to its Part 284 regulations
concerning the release of firm capacity by shippers on interstate natural gas
pipelines. The FERC proposes to remove, on a permanent basis, the rate ceiling
on capacity release transactions of one year or less. Additionally, the FERC
proposes to exempt capacity releases made as part of an asset management
arrangement from the prohibition on tying and from the bidding requirements of
section 284.8. Initial comments were filed by numerous parties on January 25,
2008.

On
June 19, 2008, the FERC issued a final rule in Order 712 regarding changes to
the capacity release program. The FERC permitted market based pricing for
short-term capacity releases of a year or less. Long-term capacity releases and
a pipelines sale of its own capacity remain subject to a price cap. The ruling
would facilitate asset management arrangements by relaxing the FERCs
prohibitions on tying and on bidding requirements for certain capacity
releases. The FERC further clarified that its prohibition on tying does not
apply to conditions associated with gas inventory held in storage for releases
for firm storage capacity. Finally, the FERC waived the prohibition on tying
and bidding requirements for capacity releases made as part of state-approved
retail open access programs. The final rule became effective on July 30, 2008.

On
November 20, 2008, the FERC issued an order generally denying requests for
rehearing and/or clarification that had been filed. The FERC reaffirmed its
final rule, Order 712, and denied requests for rehearing stating the removal of
the rate ceiling for short-term capacity release transactions is designed to
extend to capacity release transactions, the pricing flexibility already
available to pipelines through negotiated rates without compromising the
fundamental protection provided by the availability of recourse rate service.
Additionally, the FERC clarified several areas of the rule as it relates to
asset management arrangements.

Notice
of Proposed Rulemaking  Natural Gas Price Transparency

On
April 19, 2007, the FERC issued a notice of proposed rulemaking in Docket Nos.
RM07-10-000 and AD06-11-000 regarding price transparency provisions of Section
23 of the Natural Gas Act and the Energy Policy Act. In the notice, the FERC
proposed to revise its regulations to (i) require that intrastate pipelines
post daily the capacities of, and volumes flowing through, their major receipt
and delivery points and mainline segments in order to make available the
information to track daily flows of natural gas throughout the United States; and
(ii) require that buyers and sellers of more than a de minimis volume of
natural gas report annual numbers and volumes of relevant transactions to the
FERC in order to make possible an estimate of the size of the physical U.S.
natural gas market, assess the importance of the use of index pricing in that
market, and determine the size of the fixed-price trading market that produces
the information. The FERC believes these revisions to its regulations will
facilitate price transparency in markets for the sale or transportation of
physical natural gas in interstate commerce. Initial comments were filed on
July 11, 2007 and reply comments were filed on August 23, 2007. In addition,
the FERC conducted an informal workshop in this proceeding on July 24, 2007, to
discuss implementation and other technical issues associated with the proposals
set forth in the NOPR.

In
addition, on December 21, 2007, the FERC issued a new notice of proposed
rulemaking in Docket No. RM08-2-000 regarding the daily posting provisions that
were contained in Docket Nos. RM07-10-000 and AD06-11-000. The new NOPR
proposes to exempt from the daily posting requirements those non-interstate
pipelines that (i) flow less than ten million MMBtus of natural gas per year;
(ii) fall entirely upstream of a processing plant; and (iii) deliver more than
95% of the natural gas volumes they flow directly to end-users. However, the
new NOPR expands the proposal to require that both interstate and non-exempt
non-interstate pipelines post daily the capacities of, volumes scheduled at,
and actual volumes flowing through, their major receipt and delivery points and
mainline segments. Initial comments were filed by numerous parties on March 13,
2008. A Technical Conference was held on April 3, 2008. Numerous reply comments
were received on April 14, 2008.

On
December 26, 2007, the FERC issued Order No. 704 in this docket implementing
only the annual reporting provisions of the NOPR with minimal changes to the
original proposal. The order became effective February 4, 2008. The initial
report is due May 1, 2009 for calendar year 2008. Subsequent reports are due by
May 1 of each year for the previous calendar year. Order 704 will require most,
if not all of our natural gas pipelines to report

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annual volumes
of relevant transactions to the FERC. Technical workshops were held on April
22, 2008 and May 19, 2008. The FERC issued Order 704-A on September 18, 2008.
This order generally affirmed the rule, while clarifying what information
certain natural gas market participants must report in Form 552. The revisions
pertain to the reporting of transactions occurring in calendar year 2008. The
first report is due May 1, 2009 and each May 1st thereafter for subsequent
calendar years. Order 704-A became effective October 27, 2008.

On
November 20, 2008, the FERC issued Order 720, which is the final rule in the
Docket No. RM08-2-000 proceeding. The final rule established new reporting
requirements for interstate and major non-interstate pipelines. A major
non-interstate pipeline is defined as a pipeline who delivers annually more
than 50 million MMBtu of natural gas measured in average deliveries for the
previous three calendar years. Interstate pipelines will be required to post
no-notice activity at each receipt and delivery point three days after the day
of gas flow. Major non-interstate pipelines will be required to post design
capacity, scheduled volumes and available capacity at each receipt or delivery
point with a design capacity of 15,000 MMbtus of natural gas per day or greater
when gas is scheduled at the point. The final rule became effective January 27,
2009 for interstate pipelines. Non-major interstate pipelines must comply with
the requirements of Order 720 within 150 days following the issuance of an
order addressing the pending request for rehearing.

FERC
Equity Return Allowance

On
April 17, 2008, the FERC adopted a new policy under Docket No. PL07-2-000 that
will allow master limited partnerships to be included in proxy groups for the
purpose of determining rates of return for both interstate natural gas and oil
pipelines. Additionally, the policy statement concluded that (i) there should
be no cap on the level of distributions included in the FERCs current
discounted cash flow methodology; (ii) the Institutional Brokers Estimated
System forecasts should remain the basis for the short-term growth forecast
used in the discounted cash flow calculation; (iii) there should be an
adjustment to the long-term growth rate used to calculate the equity cost of
capital for a master limited partnership, specifically the long term growth
rate would be set at 50% of the gross domestic product; and (iv) there should
be no modification to the current respective two-thirds and one-third
weightings of the short-term and long-term growth factors. Additionally, the
FERC decided not to explore other methods for determining a pipelines equity
cost of capital at this time. The policy statement will govern all future gas
and oil rate proceedings involving the establishment of a return on equity, as
well as those cases that are currently pending before either the FERC or an
administrative law judge. On May 19, 2008, an application for rehearing was
filed by The American Public Gas Association. On June 13, 2008, the FERC
dismissed the request for rehearing.

Notice
of Proposed Rulemaking - Rural Onshore Low Stress Hazardous Liquids Pipelines

On
September 6, 2006, the U.S. Department of Transportation Pipeline and Hazardous
Materials Safety Administration, referred to in this report as the PHMSA,
published a notice of proposed rulemaking (PHMSA 71 FR 52504) that proposed to
extend certain threat-focused pipeline safety regulations to rural onshore
low-stress hazardous liquid pipelines within a prescribed buffer of previously
defined U.S. states. Low-stress hazardous liquid pipelines, except those in
populated areas or that cross commercially navigable waterways, have not been
subject to the safety regulations in PHMSA 49 C.F.R. Part 195.1. According to
the PHMSA, unusually sensitive areas are areas requiring extra protection
because of the presence of sole-source drinking water resources, endangered
species, or other ecological resources that could be adversely affected by
accidents or leaks occurring on hazardous liquid pipelines.

The
notice proposed to define a category of regulated rural onshore low-stress
lines (rural lines operating at or below 20% of specified minimum yield
strength, with a diameter of eight and five-eighths inches or greater, located
in or within a quarter-mile of a U.S. state) and to require operators of these
lines to comply with a threat-focused set of requirements in Part 195 that
already apply to other hazardous liquid pipelines. The proposed safety
requirements addressed the most common threatscorrosion and third party
damageto the integrity of these rural lines. The proposal is intended to
provide additional integrity protection, to avoid significant adverse
environmental consequences, and to improve public confidence in the safety of
unregulated low-stress lines.

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Since
the new notice is a proposed rulemaking in which the PHMSA will consider
initial and reply comments from industry participants, it is not clear what
impact the final rule will have on the business of our intrastate and
interstate pipeline companies.

Kinder
Morgan Liquid Terminals  U.S. Department of Transportation Jurisdiction

With
regard to several of our liquids terminals, we are working with the U.S.
Department of Transportation, referred to in this report as the DOT, to
supplement our compliance program for certain of our tanks and internal piping.
We anticipate the program will call for incremental capital spending over the next
several years to improve and/or add to our facilities. These improvements will
enhance the tanks and piping previously considered outside the jurisdiction of
DOT to conduct DOT jurisdictional transfers of products. Our original estimate
called for an incremental $3 million to $5 million of annual capital spending
over the next six to ten years for this work; however, we continue to assess
the amount of capital that will be required and the amount may exceed our
original estimate.

Natural
Gas Pipeline Expansion Filings

TransColorado
Pipeline

On
April 19, 2007, the FERC issued an order approving TransColorado Gas
Transmission Company LLCs application for authorization to construct and
operate certain facilities comprising its proposed Blanco-Meeker Expansion
Project. This project provides for the transportation of up to approximately
250 million cubic feet per day of natural gas from the Blanco Hub area in San
Juan County, New Mexico through TransColorados existing interstate pipeline
for delivery to the Rockies Express Pipeline at an existing point of
interconnection located in the Meeker Hub in Rio Blanco County, Colorado.
Construction commenced on May 9, 2007, and the project was completed and
entered service January 1, 2008.

Rockies
Express Pipeline-Currently Certificated Facilities

We
own a 51% ownership interest in West2East Pipeline LLC, a limited liability
company that is the sole owner of Rockies Express Pipeline LLC, and operate the
Rockies Express Pipeline. ConocoPhillips owns a 24% ownership interest in
West2East Pipeline LLC and Sempra Energy holds the remaining 25% interest. When
construction of the entire Rockies Express Pipeline project is completed, our
ownership interest will be reduced to 50% at which time the capital accounts of
West2East Pipeline LLC will be trued up to reflect our 50% economics in the
project. According to the provisions of current accounting standards, because
we will receive 50% of the economics of the Rockies Express project on an
ongoing basis, we are not considered the primary beneficiary of West2East
Pipeline LLC and thus, we account for our investment under the equity method of
accounting.

On
August 9, 2005, the FERC approved the application of Rockies Express Pipeline
LLC, formerly known as Entrega Gas Pipeline LLC, to construct 327 miles of
pipeline facilities in two phases. For phase I (consisting of two pipeline
segments), Rockies Express was granted authorization to construct and operate
approximately 136 miles of pipeline extending northward from the Meeker Hub,
located at the northern end of our TransColorado pipeline system in Rio Blanco
County, Colorado, to the Wamsutter Hub in Sweetwater County, Wyoming (segment
1), and then construct approximately 191 miles of pipeline eastward to the
Cheyenne Hub in Weld County, Colorado (segment 2). Construction of segments 1
and 2 has been completed, with interim service commencing on segment 1 on
February 24, 2006, and full in-service of both segments on February 14, 2007.
For phase II, Rockies Express was authorized to construct three compressor
stations referred to as the Meeker, Big Hole and Wamsutter compressor stations.
The Meeker and Wamsutter stations went into service in January 2008.
Construction of the Big Hole compressor station commenced in the second quarter
of 2008, and the expected in-service date for this compressor station is the
second quarter of 2009.

Rockies
Express Pipeline-West Project

On
April 19, 2007, the FERC issued a final order approving the Rockies Express
application for authorization to construct and operate certain facilities
comprising its proposed Rockies Express-West Project. This project is the
first planned segment extension of the Rockies Express facilities described
above, and is comprised of approximately 713 miles of 42-inch diameter pipeline
extending from the Cheyenne Hub to an interconnection with

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Panhandle
Eastern Pipe Line located in Audrain County, Missouri. The project also
includes certain improvements to existing Rockies Express facilities located to
the west of the Cheyenne Hub. Construction on Rockies Express-West commenced on
May 21, 2007, and 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 project commenced deliveries to
Panhandle Eastern Pipe Line at Audrain County, Missouri on the remaining 210
miles of pipe on May 20, 2008. The Rockies Express-West pipeline segment
transports approximately 1.5 million cubic feet per day of natural gas across
five states: Wyoming, Colorado, Nebraska, Kansas and Missouri.

Rockies
Express replaced certain pipe to reflect a higher class location and conducted
further hydrostatic testing of portions of its system during September 2008 to
satisfy U.S. Department of Transportation testing requirements to operate at
its targeted higher operating pressure. This pipe replacement and hydrostatic
testing, conducted from September 3, 2008 through September 26, 2008, resulted
in the temporary outage of pipeline delivery points and an overall reduction of
firm capacity available to firm shippers. By the terms of the Rockies Express
FERC Gas Tariff, firm shippers are entitled to daily reservation revenue credits
for non-force majeure and planned maintenance outages. The
estimated impact of these revenue credits is included in our 2008 results of
operations.

Rockies
Express Meeker to Cheyenne Expansion Project

Pursuant
to certain rights exercised by Encana Gas Marketing USA as a result of its
foundation shipper status on the former Entrega Gas Pipeline LLC facilities,
Rockies Express is requesting authorization to construct and operate certain
facilities that will comprise its Meeker, Colorado to Cheyenne, Wyoming
expansion project. The proposed expansion will consist of additional natural
gas compression at its Big Hole compressor station located in Moffat County,
Colorado and its Arlington compressor station located in Carbon County, Wyoming.
Upon completion, the additional compression will permit the transportation of
an additional 200 million cubic feet per day of natural gas from (i) the Meeker
Hub located in Rio Blanco County, Colorado northward to the Wamsutter Hub
located in Sweetwater County, Wyoming; and (ii) the Wamsutter Hub eastward to
the Cheyenne Hub located in Weld County, Colorado. The expansion is fully
contracted and is expected to be operational in April 2010. The total estimated
cost for the proposed project is approximately $78 million. Rockies Express
submitted a FERC application seeking approval to construct and operate this
expansion on February 3, 2009.

Rockies
Express Pipeline-East Project

On
April 30, 2007, Rockies Express filed an application with the FERC requesting a
certificate of public convenience and necessity that would authorize
construction and operation of the Rockies Express-East Project. The Rockies
Express-East Project will be comprised of approximately 639 miles of 42-inch
diameter pipeline commencing from the terminus of the Rockies Express-West
pipeline to a terminus near the town of Clarington in Monroe County, Ohio and
will be capable of transporting approximately 1.8 billion cubic feet per day of
natural gas.

By
order issued May 30, 2008, the FERC authorized the certificate to construct the
Rockies Express Pipeline-East Project. Construction commenced on the Rockies
Express-East pipeline segment on June 26, 2008. Delays in securing permits and
regulatory approvals, as well as weather-related delays, have caused Rockies
Express to set revised project completion dates. Rockies Express-East is
currently projected to commence service on April 1, 2009 to interconnects
upstream of Lebanon, followed by service to the Lebanon Hub in Warren County,
Ohio beginning June 15, 2009, with final completion and deliveries to
Clarington, Ohio commencing by November 1, 2009.

On
October 31, 2008, Rockies Express filed an amendment to its certificate
application, seeking authorization to revise its tariff-based recourse rates
for transportation service on the REX East Project facilities to reflect
updated construction costs for the project. The proposed amendment is pending
FERC approval.

Current
market conditions for consumables, labor and construction equipment along with
certain provisions in the final regulatory orders have resulted in increased
costs for the project and have impacted certain projected completion dates. Our
current estimate of total completed cost on the Rockies Express Pipeline is now
approximately $6.2 billion (consistent with our January 21, 2009 fourth quarter
earnings press release).

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Kinder Morgan Interstate Gas Transmission Pipeline

On
August 6, 2007, Kinder Morgan Interstate Gas Transmission Pipeline, referred to
in this report as KMIGT, filed, in FERC Docket CP07-430, for regulatory
approval to construct and operate a 41-mile natural gas pipeline, referred to
in this report as the Colorado Lateral, from the Cheyenne Hub to markets in and
around Greeley, Colorado. When completed, the Colorado Lateral will provide
firm transportation of up to 55 million cubic feet per day to a local utility
under long-term contract. The FERC issued a draft environmental assessment on
the project on January 11, 2008, and comments on the project were received
February 11, 2008. On February 21, 2008, the FERC granted the certificate application.
On July 8, 2008, in response to a rehearing request by Public Service Company
of Colorado, referred to in this report as PSCo, the FERC granted rehearing and
denied KMIGT recovery in initial transportation rates $6.2 million in costs
associated with non-jurisdictional laterals constructed by KMIGT to serve
Atmos. The recourse rate adjustment does not have any material effect on the
negotiated rate paid by Atmos to KMIGT or the economics of the project. On July
25, 2008, KMIGT filed an amendment to its certificate application, seeking
authorization to revise its initial rates for transportation service on the
Colorado Lateral to reflect updated construction costs for jurisdictional
mainline facilities. The FERC approved the revised initial recourse rates
on August 22, 2008.

PSCo,
a competitor serving markets off the Colorado Lateral, also filed a complaint
before the State of Colorado Public Utilities Commission (CoPUC) against
Atmos, the anchor shipper on the project. The CoPUC conducted a hearing on
April 14, 2008 on the complaint. On June 9, 2008, PSCo also filed before the
CoPUC seeking a temporary cease and desist order to halt construction of the
lateral facilities being constructed by KMIGT to serve Atmos. Atmos filed a
response to that motion on June 24, 2008. By order dated June 27, 2008 an
administrative law judge for the CoPUC denied PSCos request for a cease and
desist order. On September 4, 2008, an administrative law judge for the CoPUC
issued an order wherein it denied PSCos claim to exclusivity to serve Atmos
and the Greeley market area but affirmed PSCos claim that Atmos acquisition
of the delivery laterals is not in the ordinary course of business and requires
separate approvals. Accordingly, Atmos may require a certificate of public
convenience and necessity related to the delivery lateral facilities from
KMIGT. While the need for approvals by Atmos before the CoPUC remains pending,
service on the subject facilities commenced in November, 2008.

On
December 21, 2007, KMIGT filed, in Docket CP 08-44, for approval to expand its
system in Nebraska to serve incremental ethanol and industrial load. No
protests to the application were filed and the project was approved by the
FERC. Construction commenced on April 9, 2008. These facilities went into
service in October 2008.

Kinder Morgan Louisiana Pipeline

On
September 8, 2006, in FERC Docket No. CP06-449-000, we filed an application
with the FERC requesting approval to construct and operate our Kinder Morgan
Louisiana Pipeline. The natural gas pipeline will extend approximately 135
miles from Chenieres Sabine Pass liquefied natural gas terminal in Cameron
Parish, Louisiana, to various delivery points in Louisiana and will provide
interconnects with many other natural gas pipelines, including Natural Gas
Pipeline Company of America LLC. The project is supported by fully subscribed
capacity and long-term customer
commitments with Chevron and Total. The entire estimated project cost is now
expected to be approximately $950 million (consistent with our January 21, 2009
fourth quarter earnings press release), and it is expected to be fully
operational during the third quarter of 2009.

On
March 15, 2007, the FERC issued a preliminary determination that the
authorizations requested, subject to some minor modifications, will be in the
public interest. This order does not consider or evaluate any of the
environmental issues in this proceeding. On April 19, 2007, the FERC issued the
final environmental impact statement, or EIS, which addressed the potential
environmental effects of the construction and operation of the Kinder Morgan
Louisiana Pipeline. The final EIS was prepared to satisfy the requirements of
the National Environmental Policy Act. It concluded that approval of the Kinder
Morgan Louisiana Pipeline project would have limited adverse environmental
impacts. On June 22, 2007, the FERC issued an order granting construction and
operation of the project. Kinder Morgan Louisiana Pipeline officially accepted
the order on July 10, 2007.

On
July 11, 2008, Kinder Morgan Louisiana Pipeline filed an amendment to its
certificate application, seeking authorization to revise its initial rates for
transportation service on the Kinder Morgan Louisiana Pipeline system to

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reflect updated construction costs for the
project. The amendment was accepted by the FERC on August 14, 2008. On December
30, 2008, KMLP filed a second amendment to its certificate application, seeking
authorization to revise its initial rates for transportation service on the
KMLP system to reflect an additional increase in projected construction costs
for the project. The filing is still pending.

Midcontinent Express Pipeline

On
October 9, 2007, in Docket No. CP08-6-000, 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 approximately 500-mile Midcontinent Express Pipeline natural gas
transmission system.

The
Midcontinent Express Pipeline will create long-haul, firm transportation
takeaway capacity either directly or indirectly connected to natural gas
producing regions located in Texas, Oklahoma and Arkansas. The pipeline will
originate in southeastern Oklahoma and traverse east through Texas, Louisiana,
Mississippi, and terminate at an interconnection with the Transco Pipeline near
Butler, Alabama. The Midcontinent Express Pipeline is a 50/50 joint venture between
us and Energy Transfer Partners, L.P., and it has a total capital cost of
approximately $2.2 billion, including the expansion capacity.

On
July 25, 2008, the FERC approved the application made by Midcontinent Express
Pipeline to construct and operate the 500-mile Midcontinent Express Pipeline
natural gas transmission system along with the lease of 272 million cubic feet
of capacity on the Oklahoma intrastate system of Enogex Inc. Initial design
capacity for the pipeline was 1.5 billion cubic feet of natural gas per day,
which was fully subscribed with long-term binding commitments from creditworthy
shippers. A successful binding open season was completed in July 2008 which
will increase the main segment of the pipelines capacity to 1.8 billion cubic
feet per day, subject to regulatory approval.

Midcontinent
Express Pipeline accepted the FERC Certificate on July 30, 2008. Mobilization
for construction of the pipeline began in the third quarter, and subject to the
receipt of regulatory approvals, interim service on the first portion of the
pipeline is expected to be available by the second quarter of 2009 with full in
service in the third quarter of 2009. On January 9, 2009, Midcontinent Express
filed an amendment to its original certificate application requesting
authorization to revise its initial rates for transportation service on the
pipeline system to reflect an increase in projected construction costs for the
project. The filing is still pending.

On
January 30, 2009, MEP filed a certificate application in Docket No. CP09-56-000
requesting authorization to increase the capacity in Zone 1 from 1.5 Bcf to 1.8
Bcf/d. The Application is still pending.

Kinder Morgan Texas Pipeline LLC

On
May 30, 2008, Kinder Morgan Texas Pipeline LLC filed in Docket No. PR08-25-000
a petition seeking market-based rate authority for firm and interruptible
storage services performed under section 311 of the Natural Gas Policy Act of
1978 (NGPA) at the North Dayton Gas Storage Facility in Liberty County, Texas,
and at the Markham Gas Storage Facility in Matagorda County, Texas. On October
3, 2008, FERC approved this petition effective May 30, 2008.

18.
Recent Accounting
  PronouncementsEITF 04-5

In
June 2005, the Emerging Issues Task Force reached a consensus on Issue No.
04-5, or EITF 04-5, Determining Whether a General Partner, or the General
Partners as a Group, Controls a Limited Partnership or Similar Entity When the
Limited Partners Have Certain Rights. EITF 04-5 provides guidance for purposes
of assessing whether certain limited partners rights might preclude a general
partner from controlling a limited partnership.

For
general partners of all new limited partnerships formed, and for existing
limited partnerships for which the partnership agreements are modified, the
guidance in EITF 04-5 is effective after June 29, 2005. For general

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partners in
all other limited partnerships, the guidance is effective no later than the
beginning of the first reporting period in fiscal years beginning after
December 15, 2005 (January 1, 2006 for us). The adoption of EITF 04-5 did not
have an effect on our consolidated financial statements.

Nonetheless,
as a result of EITF 04-5, as of January 1, 2006, our financial statements are
consolidated into the consolidated financial statements of Knight.
Notwithstanding the consolidation of our financial statements into the
consolidated financial statements of Knight pursuant to EITF 04-5, Knight is not
liable for, and its assets are not available to satisfy, the obligations of us
and/or our subsidiaries and vice versa. Responsibility for payments of
obligations reflected in our or Knights financial statements is a legal
determination based on the entity that incurs the liability. The determination
of responsibility for payment among entities in our consolidated group of
subsidiaries was not impacted by the adoption of EITF 04-5.

FIN
48

In
July 2006, the FASB issued Interpretation (FIN) No. 48, Accounting for
Uncertainty in Income Taxesan Interpretation of FASB Statement No. 109, which
became effective January 1, 2007. FIN 48 addressed the determination of how tax
benefits claimed or expected to be claimed on a tax return should be recorded
in the financial statements. Under FIN 48, we must recognize the tax benefit
from an uncertain tax position only if it is more likely than not that the tax
position will be sustained on examination by the taxing authorities, based not
only on the technical merits of the tax position based on tax law, but also the
past administrative practices and precedents of the taxing authority. The tax
benefits recognized in the financial statements from such a position are
measured based on the largest benefit that has a greater than fifty percent
likelihood of being realized upon ultimate resolution. Our adoption of FIN No.
48 on January 1, 2007 did not result in a cumulative effect adjustment to
Partners Capital on our consolidated balance sheet. For more information
related to FIN 48, see Note 5.

SFAS No. 157

For
information on SFAS No. 157, see Note 14 SFAS No. 157.

SFAS
No. 159

On
February 15, 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities. This Statement provides companies with an
option to report selected financial assets and liabilities at fair value. The
Statements objective is to reduce both complexity in accounting for financial
instruments and the volatility in earnings caused by measuring related assets
and liabilities differently. The Statement also establishes presentation and
disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities.

SFAS
No. 159 requires companies to provide additional information that will help
investors and other users of financial statements to more easily understand the
effect of the companys choice to use fair value on its earnings. It also
requires entities to display the fair value of those assets and liabilities for
which the company has chosen to use fair value on the face of the balance
sheet. The Statement does not eliminate disclosure requirements included in
other accounting standards, including requirements for disclosures about fair
value measurements included in SFAS No. 157 (disclosed in Note 14 SFAS No.
157) and in SFAS No. 107 Disclosures
about Fair Value of Financial Instruments (disclosed in Note 9 Fair
Value of Financial Instruments).

This
Statement was adopted by us effective January 1, 2008, at which time no
financial assets or liabilities, not previously required to be recorded at fair
value by other authoritative literature, were designated to be recorded at fair
value. As such, the adoption of this Statement did not have any impact on our
consolidated financial statements.

SFAS
141(R)

On
December 4, 2007, the FASB issued SFAS No. 141R (revised 2007), Business
Combinations. Although this statement amends and replaces SFAS No. 141, it
retains the fundamental requirements in SFAS No. 141 that (i) the purchase
method of accounting be used for all business combinations; and (ii) an
acquirer be identified for each business combination. SFAS No. 141R defines the
acquirer as the entity that obtains control of one or more

208

businesses in
the business combination and establishes the acquisition date as the date that
the acquirer achieves control. This Statement applies to all transactions or
other events in which an entity (the acquirer) obtains control of one or more
businesses (the acquiree), including combinations achieved without the transfer
of consideration; however, this Statement does not apply to a combination
between entities or businesses under common control.

Significant
provisions of SFAS No. 141R concern principles and requirements for how an
acquirer (i) recognizes and measures in its financial statements the
identifiable assets acquired, the liabilities assumed, and any noncontrolling
interest in the acquiree; (ii) recognizes and measures the goodwill acquired in
the business combination or a gain from a bargain purchase; and (iii)
determines what information to disclose to enable users of the financial
statements to evaluate the nature and financial effects of the business
combination.

This
Statement applies prospectively to business combinations for which the
acquisition date is on or after the beginning of the first annual reporting
period beginning on or after December 15, 2008 (January 1, 2009 for us). The
adoption of this Statement did not have a material impact on our consolidated
financial statements.

SFAS
No. 160

On
December 4, 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements  an amendment of ARB No. 51. This Statement
changes the accounting and reporting for noncontrolling interests in
consolidated financial statements. A noncontrolling interest, sometimes
referred to as a minority interest, is the portion of equity in a subsidiary
not attributable, directly or indirectly, to a parent.

Specifically,
SFAS No. 160 establishes accounting and reporting standards that require (i)
the ownership interests in subsidiaries held by parties other than the parent
to be clearly identified, labeled, and presented in the consolidated balance
sheet within equity, but separate from the parents equity; (ii) the equity
amount of consolidated net income attributable to the parent and to the
noncontrolling interest to be clearly identified and presented on the face of
the consolidated income statement (consolidated net income and comprehensive
income will be determined without deducting minority interest, however,
earnings-per-share information will continue to be calculated on the basis of
the net income attributable to the parents shareholders); and (iii) changes in
a parents ownership interest while the parent retains its controlling
financial interest in its subsidiary to be accounted for consistently and
similarlyas equity transactions.

This
Statement is effective for fiscal years, and interim periods within those
fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for us).
SFAS No. 160 is to be applied prospectively as of the beginning of the fiscal
year in which it is initially applied, except for its presentation and
disclosure requirements, which are to be applied retrospectively for all
periods presented. The adoption of this Statement did not have a material
impact on our consolidated financial statements.

SFAS
No. 161

On
March 19, 2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities. This Statement amends SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities and is intended
to help investors better understand how derivative instruments and hedging
activities affect an entitys financial position, financial performance and
cash flows through enhanced disclosure requirements. The enhanced disclosures
include, among other things, (i) a tabular summary of the fair value of
derivative instruments and their gains and losses; (ii) disclosure of
derivative features that are credit-riskrelated to provide more information
regarding an entitys liquidity; and (iii) cross-referencing within footnotes
to make it easier for financial statement users to locate important information
about derivative instruments.

This
Statement is effective for financial statements issued for fiscal years and
interim periods beginning after November 15, 2008 (January 1, 2009 for us).
This Statement expands and enhances disclosure requirements only, and as such,
the adoption of this Statement did not have any impact on our consolidated
financial statements.

209

EITF
07-4

In
March 2008, the Emerging Issues Task Force reached a consensus on Issue No.
07-4, or EITF 07-4, Application of the Two-Class Method under FASB Statement
No. 128, Earnings per Share, to Master Limited Partnerships. EITF 07-4
provides guidance for how current period earnings should be allocated between
limited partners and a general partner when the partnership agreement contains
incentive distribution rights.

This
Issue is effective for fiscal years beginning after December 15, 2008 (January
1, 2009 for us), and interim periods within those fiscal years. The guidance in
this Issue is to be applied retrospectively for all financial statements presented;
however, the adoption of this Issue did not have any impact on our consolidated
financial statements.

FASB
Staff Position No. FAS 142-3

On
April 25, 2008, the FASB issued FASB Staff Position FAS 142-3 Determination of
the Useful Life of Intangible Assets. This Staff Position amends the factors
that should be considered in developing renewal or extension assumptions used
to determine the useful life of a recognized intangible asset under SFAS No.
142, Goodwill and Other Intangible Assets. This Staff Position is effective
for financial statements issued for fiscal years beginning after December 15,
2008 (January 1, 2009 for us), and interim periods within those fiscal years.
The adoption of this Staff Position did not have a material impact on our
consolidated financial statements.

SFAS
No. 162

On
May 9, 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. This
Statement is intended to improve financial reporting by identifying a
consistent framework, or hierarchy, for selecting accounting principles to be
used in preparing financial statements that are presented in conformity with
U.S. generally accepted accounting principles, referred to in this note as
GAAP, for nongovernmental entities.

Statement
No. 162 establishes that the GAAP hierarchy should be directed to entities
because it is the entity (not its auditor) that is responsible for selecting
accounting principles for financial statements that are presented in conformity
with GAAP. Statement No. 162 is effective 60 days following the U.S. Securities
and Exchange Commissions approval of the Public Company Accounting Oversight
Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally
Accepted Accounting Principles, and is only effective for nongovernmental
entities. We do not expect the adoption of this Statement to have any effect on
our consolidated financial statements.

FASB
Staff Position No. EITF 03-6-1

On
June 16, 2008, the FASB issued FASB Staff Position FAS EITF 03-6-1,
Determining Whether Instruments Granted in Share-Based Payment Transactions
Are Participating Securities. This Staff Position clarifies that share-based
payment awards that entitle their holders to receive nonforfeitable dividends
before vesting should be considered participating securities. As participating
securities, these instruments should be included in the calculation of basic
earnings per share. This Staff Position is effective for financial statements
issued for fiscal years beginning after December 15, 2008 (January 1, 2009 for
us), and interim periods within those fiscal years. The adoption of this Staff
Position did not have an impact on our consolidated financial statements.

FASB
Staff Position No. FAS 157-3

On
October 10, 2008, the FASB issued FASB Staff Position FAS 157-3 Determining
the Fair Value of a Financial Asset When the Market for that Asset is Not
Active. This Staff Position provides guidance clarifying how SFAS No. 157,
Fair Value Measurements should be applied when valuing securities in markets
that are not active. This Staff Position applies the objectives and framework
of SFAS No. 157 to determine the fair value of a financial asset in a market
that is not active, and it reaffirms the notion of fair value as an exit price
as of the measurement date. Among other things, the guidance also states that
significant judgment is required in valuing

210

financial assets.
This Staff Position became effective upon issuance, and did not have any
material effect on our consolidated financial statements.

EITF
08-6

On
November 24, 2008, the Financial Accounting Standards Board ratified the
consensus reached by the Emerging Issues Task Force on Issue No. 08-6, or EITF
08-6, Equity Method Investment Accounting Considerations. EITF 08-6 clarifies certain accounting and impairment
considerations involving equity method investments. This Issue is
effective for fiscal years beginning on or after December 15, 2008 (January 1,
2009 for us), and interim periods within those fiscal years. The guidance in
this Issue is to be applied prospectively for all financial statements
presented. The adoption of this Issue did not have any impact on our
consolidated financial statements.

FASB
Staff Position No. FAS 140-4 and FIN 46(R)-8

On
December 11, 2008, the FASB issued FASB Staff Position FAS 140-4 and FIN
46(R)-8 Disclosures by Public Entities (Enterprises) about Transfers of
Financial Assets and Interests in Variable Interest Entities. This Staff
Position requires enhanced disclosure and transparency by public entities about
their involvement with variable interest entities and their continuing involvement
with transferred financial assets. The disclosure requirements in this Staff
Position are effective for annual and interim periods ending after December 15,
2008 (December 31, 2008 for us). The adoption of this Staff Position did not
have any impact on our consolidated financial statements.

FASB
Staff Position No. FAS 132(R)-1

On
December 30, 2008, the FASB issued FASB Staff Position FAS 132(R)-1,
Employers Disclosures About Postretirement Benefit Plan Assets. This Staff
Position is effective for financial statements ending after December 15, 2009
(December 31, 2009 for us) and requires additional disclosure of pension and
post retirement benefit plan assets regarding (i) investment asset classes;
(ii) fair value measurement of assets; (iii) investment strategies; (iv) asset
risk; and (v) rate-of-return assumptions. We do not expect this Staff Position
to have a material impact on our consolidated financial statements.

Securities
and Exchange Commissions Final Rule on Oil and Gas Disclosure Requirements

On
December 31, 2008, the Securities and Exchange Commission issued its final rule
Modernization of Oil and Gas Reporting, which revises the disclosures
required by oil and gas companies. The SEC disclosure requirements for oil and
gas companies have been updated to include expanded disclosure for oil and gas
activities, and certain definitions have also been changed that will impact the
determination of oil and gas reserve quantities. The provisions of this final
rule are effective for registration statements filed on or after January 1,
2010, and for annual reports for fiscal years ending on or after December 31,
2009. We do not expect this final rule to have a material impact on our
consolidated financial statements.

211

19.
Quarterly Financial Data (Unaudited)Operating
 Revenues

Operating
 Income

Income from
 Continuing
 Operations

Income from
 Discontinued
 Operations

Net Income(In millions)2008First
Quarter

$
2,720.3

$
419.4

$
346.2

$
0.5

$
346.7Second
Quarter


3,495.7


406.2


361.4


0.8


362.2Third
Quarter


3,232.8


407.9


329.8





329.8Fourth
Quarter


2,291.5


318.0


266.1





266.12007First
Quarter

$
2,171.7

$
(75.5
)
$
(156.6
)
$
7.1

$
(149.5
)Second
Quarter


2,366.4


314.6


227.3


5.4


232.7Third
Quarter


2,230.8


311.4


205.2


8.6


213.8Fourth
Quarter


2,448.8


257.2


140.5


152.8


293.3Income
 (loss) from
 Continuing
 Operations

Income (loss)
 from
 Discontinued
 Operations

Net IncomeBasic Limited
 Partners income (loss) per Unit:2008First
Quarter

$
0.63

$


$
0.63Second
Quarter


0.64


0.01


0.65Third
Quarter


0.48





0.48Fourth
Quarter


0.19





0.192007First
Quarter

$
(1.27
)
$
0.03

$
(1.24
)Second
Quarter


0.34


0.02


0.36Third
Quarter


0.21


0.03


0.24Fourth
Quarter


(0.12
)

0.62


0.50Diluted Limited
 Partners income (loss) per Unit:2008First
Quarter

$
0.63

$


$
0.63Second
Quarter


0.64


0.01


0.65Third
Quarter


0.48





0.48Fourth
Quarter


0.19





0.192007First
Quarter(a)

$
(1.27
)
$
0.04

$
(1.23
)Second
Quarter


0.34


0.02


0.36Third
Quarter


0.21


0.03


0.24Fourth
Quarter


(0.12
)

0.62


0.50(a)
2007
 first quarter includes an expense of $377.1 million attributable to a
 goodwill impairment charge recognized by Knight, as discussed in Notes 3 and 8.20.
Supplemental Information on Oil and Gas
 Producing Activities (Unaudited)The
Supplementary Information on Oil and Gas Producing Activities is presented as
required by SFAS No. 69, Disclosures about Oil and Gas Producing Activities.
The supplemental information includes capitalized costs related to oil and gas
producing activities; costs incurred for the acquisition of oil and gas
producing activities, exploration and development activities; and the results
of operations from oil and gas producing activities.

Supplemental
information is also provided for per unit production costs; oil and gas
production and average sales prices; the estimated quantities of proved oil and
gas reserves; the standardized measure of discounted future net cash flows
associated with proved oil and gas reserves; and a summary of the changes in
the standardized measure of discounted future net cash flows associated with
proved oil and gas reserves.

212

Our
capitalized costs consisted of the following (in millions):

Capitalized Costs Related to Oil and Gas Producing
Activities

December 31,2008

2007

2006Consolidated
 Companies(a)Wells and equipment,
 facilities and other

$
2,106.9

$
1,612.5

$
1,369.5Leasehold


348.9


348.1


347.4Total proved oil and gas
 properties


2,455.8


1,960.6


1,716.9Accumulated depreciation
 and depletion


(1,064,3
)

(725.5
)

(470.2
)Net capitalized costs

$
1,391.5

$
1,235.1

$
1,246.7(a)
Amounts relate to Kinder
 Morgan CO2
 Company, L.P. and its consolidated subsidaries. Includes capitalized asset
 retirement costs and associated accumulated depreciation. There are no
 capitalized costs associated with unproved oil and gas properties for the
 periods reported.Our
costs incurred for property acquisition, exploration and development were as
follows (in millions):

Costs Incurred in Exploration, Property Acquisitions
and Development

Year Ended December 31,2008

2007

2006Consolidated
 Companies(a)Property Acquisition Proved oil
and gas properties

$


$


$
36.6Development


495.2


244.4


261.8(a)
Amounts relate to Kinder
 Morgan CO2
 Company, L.P. and its consolidated subsidaries. There are no capitalized
 costs associated with unproved oil and gas properties for the periods
 reported. All capital expenditures were made to develop our proved oil and
 gas properties and no exploration costs were incurred for the periods
 reported.Our
results of operations from oil and gas producing activities for each of the
years 2008, 2007 and 2006 are shown in the following table (in millions):

Results of Operations for Oil and Gas Producing
Activities

Year Ended December 31,2008

2007

2006Consolidated
Companies(a)Revenues(b)

$
785.5

$
589.7

$
524.7Expenses:Production costs


308.4


243.9


208.9Other operating
expenses(c)


99.0


56.9


66.4Depreciation, depletion and
amortization expenses


342.2


258.5


169.4Total
expenses


749.6


559.3


444.7Results of operations for oil
and gas producing activities

$
35.9

$
30.4

$
80.0(a)
Amounts relate to Kinder
Morgan CO2 Company, L.P.
and its consolidated subsidaries.(b)
Revenues include losses
 attributable to our hedging contracts of $693.3 million, $434.2 million and
 $441.7 million for the years ended December 31, 2008, 2007 and 2006,
 respectively.(c)
Consists primarily of
 carbon dioxide expense.The
table below represents estimates, as of December 31, 2008, of proved crude oil,
natural gas liquids and natural gas reserves prepared by Netherland, Sewell and
Associates, Inc. (independent oil and gas consultants) of Kinder Morgan CO2 Company, L.P. and its consolidated
subsidiaries interests in oil and gas properties, all of which are located in
the state of Texas. This data has been prepared using constant prices and
costs, as discussed in subsequent paragraphs of this document. The estimates of
reserves and future revenue in this document conforms to the guidelines of the
United States Securities and Exchange Commission.

We
believe the geologic and engineering data examined provides reasonable
assurance that the proved reserves are recoverable in future years from known
reservoirs under existing economic and operating conditions. Estimates

213

of proved
reserves are subject to change, either positively or negatively, as additional
information becomes available and contractual and economic conditions change.

Proved
oil and gas reserves are the estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, that is, prices and costs as
of the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations or declines based upon future conditions. Proved developed reserves
are the quantities of crude oil, natural gas liquids and natural gas expected
to be recovered through existing investments in wells and field infrastructure
under current operating conditions. Proved undeveloped reserves require
additional investments in wells and related infrastructure in order to recover
the production.

During
2008, we filed estimates of our oil and gas reserves for the year 2007 with the
Energy Information Administration of the U. S. Department of Energy on Form
EIA-23. The data on Form EIA-23 was presented on a different basis, and
included 100% of the oil and gas volumes from our operated properties only,
regardless of our net interest. The difference between the oil and gas reserves
reported on Form EIA-23 and those reported in this report exceeds 5%.

Reserve Quantity InformationConsolidated Companies(a)Crude Oil
 (MBbls)

NGLs
 (MBbls)

Nat. Gas
 (MMcf)(b)Proved developed
 and undeveloped reserves:As of December 31, 2005


141,951


18,983


2,153Revisions of
previous
 estimates(c)


(4,615
)

(6,858
)

(1,408
)Production


(13,811
)

(1,817
)

(461
)Purchases of
reserves in place


453


25


7As of December 31, 2006


123,978


10,333


291Revisions of
previous
 estimates(d)


10,361


2,784


1,077Production


(12,984
)

(2,005
)

(290
)As of December 31, 2007


121,355


11,112


1,078Revisions of
previous
 estimates(e)


(29,536
)

(2,490
)

695Production


(13,240
)

(1,762
)

(499
)As of December 31, 2008


78,579


6,860


1,274Proved developed
 reserves:As of December 31, 2005


78,755


9,918


1,650As of December 31, 2006


69,073


5,877


291As of December 31, 2007


70,868


5,517


1,078As of December 31, 2008


53,346


4,308


1,274(a)
Amounts relate to Kinder Morgan
CO2
 Company, L.P. and its consolidated subsidaries.(b)
Natural gas reserves are
computed at 14.65
 pounds per square inch absolute and 60 degrees fahrenheit.(c)
Based on lower than expected
recoveries of a
 section of the SACROC unit carbon dioxide flood project.(d)
Associated with an expansion of
the carbon
 dioxide flood project area of the SACROC unit.(e)
Predominantly due to lower
product prices
 used to determine reserve volumes.The
standardized measure of discounted cash flows and summary of the changes in the
standardized measure computation from year-to-year are prepared in accordance
with SFAS No. 69. The assumptions that underly the computation of the
standardized measure of discounted cash flows may be summarized as follows:

 the standardized measure
includes
 our estimate of proved crude oil, natural gas liquids and natural gas
 reserves and projected future production volumes based upon year-end economic
 conditions; pricing is applied based
upon
 year-end market prices adjusted for fixed or determinable contracts that are
 in existence at year-end; future development and
production
 costs are determined based upon actual cost at year-end;214

the standardized measure
includes projections of future abandonment costs based upon actual costs at year-end;
 anda discount factor of 10%
per year
 is applied annually to the future net cash flows.Our
standardized measure of discounted future net cash flows from proved reserves
were as follows (in millions):

Standardized Measure of Discounted Future
 Net Cash Flows From
 Proved Oil and Gas ReservesAs of December 31,2008


2007


2006Consolidated
 Companies(a)Future cash inflows from
 production

$
3,498.0

$
12,099.5

$
7,534.7Future production
costs


(1,671.6
)

(3,536.2
)

(2,617.9
)Future development
costs(b)


(910,3
)

(1,919.2
)

(1,256.8
)Undiscounted future net cash
flows


916.1


6,644.1


3,660.010% annual discount


(257.7
)

(2,565.7
)

(1,452.2
)Standardized measure of
discounted future net cash flows

$
658.4

$
4,078.4

$
2,207.8(a)
Amounts
 relate to Kinder Morgan CO2 Company, L.P. and its consolidated
 subsidaries.(b)
Includes abandonment costs.The
following table represents our estimate of changes in the standardized measure
of discounted future net cash flows from proved reserves (in millions):

Changes in the Standardized Measure of
 Discounted Future Net Cash Flows FromProved Oil and Gas Reserves2008


2007


2006Consolidated
 Companies(a)Present value as of January
1

$
4,078.4

$
2,207.8

$
3,075.0Changes during
the year:Revenues less
production and other costs(b)


(1,012.4
)

(722.1
)

(690.0
)Net changes in
prices, production and other costs(b)


(3,076.9
)

2,153.2


(123.0
)Development
costs incurred


495.2


244.5


261.8Net changes in
future development costs


231.1


(547.8
)

(446.0
)Purchases of
reserves in place








3.2Revisions of
previous quantity estimates(c)


(417.1
)

510.8


(179.5
)Accretion of
discount


392.9


198.1


307.4Timing
differences and other


(32.8
)

33.9


(1.1
)Net change for
the year


(3,420.0
)

1,870.6


(867.2
)Present value as of December
31

$
658.4

$
4,078.4

$
2,207.8(a)
Amounts
 relate to Kinder Morgan CO2 Company, L.P. and its consolidated
 subsidaries.(b)
Excludes
 the effect of losses attributable to our hedging contracts of $639.3 million,
 $434.2 million and $441.7 million for the years ended December 31, 2008, 2007
 and 2006, respectively.(c)
2008
 revisions are predominantly due to lower product prices used to determine
 reserve volumes.  2007 revisions are associated with an expansion of the carbon
 dioxide flood project area for the SACROC unit. 2006 revisions are based on
 lower than expected recoveries from a section of the SACROC unit carbon
 dioxide flood project.215

SIGNATURES

Pursuant to
the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

KINDER MORGAN ENERGY PARTNERS, L.P.
 Registrant (a Delaware Limited Partnership)By: KINDER MORGAN G.P., INC.,its sole General PartnerBy: KINDER MORGAN MANAGEMENT, LLC,
 
 the Delegate of Kinder Morgan G.P., Inc.By: /s/ KIMBERLY A. DANGKimberly A. Dang,Vice President and Chief Financial Officer(principal financial and accounting officer)Date: February 23, 2009Pursuant to
the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons in the capacities and on the dates
indicated.

Signature

Title

Date/s/ KIMBERLY A. DANG

Vice President and Chief Financial Officer of Kinder Morgan Management, LLC,
Delegate of Kinder Morgan G.P., Inc. (principal
 financial officer and principal
 accounting officer)

February 23, 2009Kimberly A. Dang/s/ RICHARD D. KINDER

Chairman of the Board and Chief

February 23, 2009Executive Officer of Kinder MorganRichard D. Kinder

Management, LLC, Delegate ofKinder Morgan G.P., Inc. (principal
 executive officer)/s/ GARY L. HULTQUIST

Director of Kinder Morgan

February 23, 2009Management, LLC, Delegate ofGary L. Hultquist

Kinder Morgan G.P., Inc./s/ C. BERDON LAWRENCE

Director of Kinder Morgan

February 23, 2009Management, LLC, Delegate ofC. Berdon Lawrence

Kinder Morgan G.P., Inc./s/ PERRY M. WAUGHTAL

Director of Kinder Morgan

February 23, 2009Management, LLC, Delegate ofPerry M. Waughtal

Kinder Morgan G.P., Inc./s/ C. PARK SHAPER

Director and President of

February 23, 2009Kinder Morgan Management, LLC,C. Park Shaper

Delegate of Kinder Morgan G.P., Inc.216